Edgar Filing: TOTAL SA

Annual Report on Form 20-F

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 20-F

(Mark One)

¨	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

¨	SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report

Commission file number: 1-10888

TOTAL S.A.

(Exact Name of Registrant as Specified in Its Charter)


N/A		Republic of France
(Translation of Registrant’s Name into English)		(Jurisdiction of Incorporation or Organization)

TOTAL S.A.

2, place de la Coupole

La Défense 6

92400 Courbevoie

France

(Address of Principal Executive Offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act.

Title of each class

Name of each exchange on which registered

Shares

American Depositary Shares

New York Stock Exchange*

New York Stock Exchange

*	Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

2,425,767,953 Shares, par value €2.50 each, as of December 31, 2006

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨

Indicate by check mark which financial statement item the registrant has elected to follow. Item 17 ¨ Item 18 x

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

TABLE OF CONTENTS


		Page

CERTAIN TERMS		iii

ABBREVIATIONS		iv

CONVERSION TABLE		iv
Item 1.	Identity of Directors, Senior Management and Advisers	1
Item 2.	Offer Statistics and Expected Timetable	1
Item 3.	Key Information	1
	Selected Financial Data	1
	Exchange Rate Information	3
	Risk Factors	4
Item 4.	Information on the Company	7
	History and Development of the Company	7
	Business Overview	8
	Other Matters	47
Item 4A.	Unresolved Staff Comments	55
Item 5.	Operating and Financial Review and Prospects	55
Item 6.	Directors, Senior Management and Employees	69
	Directors and Senior Management	69
	Compensation	76
	Corporate Governance	78
	Employees, Share Ownership, Stock Options and Restricted Share Grants	83
Item 7.	Major Shareholders and Related Party Transactions	94
Item 8.	Financial Information	94
Item 9.	The Offer and Listing	98
Item 10.	Additional Information	100
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	113
Item 12.	Description of Securities Other than Equity Securities	119
Item 13.	Defaults, Dividend Arrearages and Delinquencies	119
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	119
Item 15.	Controls and Procedures	119
Item 16A.	Audit Committee Financial Expert	120
Item 16B.	Code of Ethics	120
Item 16C.	Principal Accountant Fees and Services	120
Item 16D.	Exemptions from the Listing Standards for Audit Committees	121
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	121
Item 17.	Financial Statements	122
Item 18.	Financial Statements	122
Item 19.	Exhibits	123

Basis of Presentation

In general, financial information included in this Annual Report is presented according to International Financial Reporting Standards (IFRS) as adopted by the European Union (EU) as of December 31, 2006. As of December 31, 2006, December 31, 2005 and December 31, 2004, TOTAL’s consolidated financial statements would not have been different if presented under “IFRS as published by the IASB” or under “IFRS as adopted by the EU”.

Statements Regarding Competitive Position

Statements made in “Item 4. Information on the Company” referring to TOTAL’s competitive position are based on the Company’s belief, and in some cases rely on a range of sources, including investment analysts’ reports, independent market studies and TOTAL’s internal assessments of market share based on publicly available information about the financial results and performance of market participants.

Additional Information

This Annual Report on Form 20-F reports information primarily regarding TOTAL’s business and operations and financial information relating to the fiscal year ended December 31, 2006. For more recent updates regarding TOTAL, you may read and copy any reports, statements or other information TOTAL files with the Securities and Exchange Commission. All of TOTAL’s Securities and Exchange Commission filings made after December 31, 2001 are available to the public at the Securities and Exchange Commission web site at http://www.sec.gov and from certain commercial document retrieval services. See also “Item 10. Additional Information — Documents on Display”.

CERTAIN TERMS

Unless the context indicates otherwise, the following terms have the meanings shown below:

“acreage”

The total area, expressed in acres, over which TOTAL has interests in exploration or production.

“ADRs”

American Depositary Receipts evidencing ADSs.

“ADSs”

American Depositary Shares representing the shares of TOTAL S.A.

“barrels”

Barrels of crude oil, including condensate and natural gas liquids.

“Company”

TOTAL S.A.

“condensate”

Light hydrocarbon substances produced with natural gas which condense into liquid at normal temperatures and pressures associated with surface production equipment.

“crude oil”

Crude oil, including condensate and natural gas liquids.

“Group”

TOTAL S.A. and its subsidiaries and affiliates. The terms TOTAL and Group are used interchangeably.

“hydrocracker”

A refinery unit which uses a catalyst and extraordinary high pressure, in the presence of surplus hydrogen, to shorten molecules.

“LNG”

Liquefied natural gas.

“LPG”

Liquefied petroleum gas.

“proved reserves”

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not of escalations based upon future conditions. The full definition of “proved reserves” which we are required to follow in presenting such information in our financial results and elsewhere in reports we file with the Securities and Exchange Commission is found in Rule 4-10 of Regulation S-X under the U.S. Securities Act of 1933, as amended.

“proved developed reserves”

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing natural forces and mechanisms of primary recovery are included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. The full definition of “proved developed reserves” which we are required to follow in presenting such information in our financial results and elsewhere in reports we file with the Securities and Exchange Commission is found in Rule 4-10 of Regulation S-X under the U.S. Securities Act of 1933, as amended.

“proved undeveloped reserves”

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion, but does not include reserves attributable to any acreage for which an

iii

application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. The full definition of “proved undeveloped reserves” which we are required to follow in presenting such information in our financial results and elsewhere in reports we file with the Securities and Exchange Commission is found in Rule 4-10 of Regulation S-X under the U.S. Securities Act of 1933, as amended.

“steam cracker”

A petrochemical plant that turns naphta and light hydrocarbons into ethylene, propylene, and other chemical raw materials.

“TOTAL”

TOTAL S.A. and its subsidiaries and affiliates. We use such term interchangeably with the term Group. When we refer to the parent holding company alone, we use the term TOTAL S.A. or the Company.

“trains”

Facilities for converting, liquefying, storing and off-loading natural gas.

“TRCV”

An aggregate margin for topping, reforming, cracking, visbreaking in Western Europe developed and used internally by TOTAL’s management as an indicator of refining margins.

“turnarounds”

Temporary shutdowns of facilities for maintenance, overhaul and upgrading.

ABBREVIATIONS


b	barrel	k	thousand
cf	cubic feet	M	million
boe	barrel of oil equivalent	B	billion
t	metric ton	W	watt
m³	cubic meter	GWh	gigawatt-hour
/y	per year	TWh	terawatt-hour
		Wp	watt peak

CONVERSION TABLE


1 acre	= 0.405 hectares

1 b	= 42 U.S. gallons

1 boe	= 1 b of crude oil	= 5,494 cf of gas in 2006^(a)

		= 5,483 cf of gas in 2005

		= 5,497 cf of gas in 2004

1 b/d of crude oil	= approximately 50 t/y of crude oil

1 Bm³/y	= approximately 0.1 Bcf/d

1 m³	= 35.3147 cf

1 kilometer	= approximately 0.62 miles

1 ton	= 1 t	= 1,000 kilograms (approximately 2,205 pounds)

1 ton of oil	= 1 t of oil	= approximately 7.5b of oil (assuming a specific gravity of 37° API)

1 t of LNG	= approximately 8.9 boe	= approximately 48 Mcf of gas

1 Mt/y LNG		= approximately 133 Mcf/d

(a)

Natural gas is converted to barrels of oil equivalent using a ratio of cubic feet of natural gas per one barrel. This ratio is based on the actual average equivalent energy content of the TOTAL’s natural gas reserves during the applicable periods, and is subject to change. The tabular conversion rate is applicable to TOTAL’s natural gas reserves on a group-wide basis.

Cautionary Statement Concerning Forward-Looking Statements

TOTAL has made certain forward-looking statements in this document and in the documents referred to in, or incorporated by reference into, this Annual Report. Such statements are subject to risks and uncertainties. These statements are based on the beliefs and assumptions of the management of TOTAL and on the information currently available to such management. Forward-looking statements include information concerning forecasts, projections, anticipated synergies, and other information concerning possible or assumed future results of TOTAL, and may be preceded by, followed by, or otherwise include the words “believes”, “expects”, “anticipates”, “intends”, “plans”, “targets”, “estimates” or similar expressions.

Forward-looking statements are not assurances of results or values. They involve risks, uncertainties and assumptions. TOTAL’s future results and share value may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results and values are beyond TOTAL’s ability to control or predict. Except for its ongoing obligations to disclose material information as required by applicable securities laws, TOTAL does not have any intention or obligation to update forward-looking statements after the distribution of this document, even if new information, future events or other circumstances have made them incorrect or misleading.

You should understand that various factors, certain of which are discussed elsewhere in this document and in the documents referred to in, or incorporated by reference into, this document, could affect the future results of TOTAL and could cause results to differ materially from those expressed in such forward-looking statements, including:

•

material adverse changes in general economic conditions or in the markets served by TOTAL, including changes in the prices of oil, natural gas, refined products, petrochemical products and other chemicals,

•

changes in currency exchange rates and currency devaluations,

•

the success and the economic efficiency of oil and natural gas exploration, development and production programs, including without limitation, those that are not controlled and/or operated by TOTAL,

•

uncertainties about estimates of changes in proven and potential reserves and the capabilities of production facilities,

•

uncertainties about the ability to control unit costs in exploration, production, refining and marketing (including refining margins) and chemicals,

•

changes in the current capital expenditure plans of TOTAL,

•

the ability of TOTAL to realize anticipated cost savings, synergies and operating efficiencies,

•

the financial resources of competitors,

•

changes in laws and regulations, including tax and environmental laws and industrial safety regulations,

•

the quality of future opportunities that may be presented to or pursued by TOTAL,

•

the ability to generate cash flows or obtain financing to fund growth and the cost of such financing,

•

the ability to obtain governmental or regulatory approvals,

•

the ability to respond to challenges in international markets, including political or economic conditions, including international armed conflict, and trade and regulatory matters,

•

the ability to complete and integrate appropriate acquisitions, strategic alliances and joint ventures,

•

changes in the political environment that adversely affect exploration, production licenses and contractual rights or impose minimum drilling obligations, price controls, nationalization or expropriation, and regulation of refining and marketing, chemicals and power generating activities,

•

the possibility that other unpredictable events such as labor disputes or industrial accidents will adversely affect the business of TOTAL, and

•

the risk that TOTAL will inadequately hedge the price of crude oil or finished products.

For additional factors, you should read the information set forth under “Item 3. Risk Factors”, “Item 4. Information on the Company — Other Matters”, “Item 5. Operating and Financial Review and Prospects” and “Item 11. Quantitative and Qualitative Disclosures about Market Risk”.

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable

ITEM 3. KEY INFORMATION

SELECTED FINANCIAL DATA

The following table presents selected consolidated financial data for TOTAL on the basis of International Financial Reporting Standards (IFRS) as adopted by the European Union for the three-year period ended December 31, 2006 and in accordance with generally accepted accounting principles applicable in the United States (“U.S. GAAP”) for the five-year period ended December 31, 2006. The historical consolidated financial statements of TOTAL for these periods, from which the financial data presented below for such periods are derived, have been audited by Ernst & Young Audit and KPMG S.A., independent registered public accounting firms and the Company’s auditors. All such data should be read in conjunction with the Consolidated Financial Statements and the Notes thereto included elsewhere herein.

The presentation of financial information is made on the following basis: Pursuant to IFRS 1, “First-time adoption of International Financial Reporting Standards”, the Group has chosen to apply the exemption not to restate business combinations that occurred before January 1, 2004. Consequently, the 1999 Total/PetroFina and the 2000 TotalFina/Elf Aquitaine combinations have been treated as pooling-of-interests under IFRS. Under U.S. GAAP, both combinations are treated as purchases. The Company acquired the remaining shares of PetroFina in the first quarter of 2002 leading to a decrease in minority interests in that quarter (PetroFina was 99.6% owned as of December 31, 2001).

SELECTED CONSOLIDATED FINANCIAL DATA


(M€, except per share data)	2006			2005			2004		2003^(d)		2002^(d)
INCOME STATEMENT DATA
Amounts in accordance with IFRS
Revenues from sales		132,689			117,057			95,325		n/a		n/a
Operating Income		24,130			24,169			17,026		n/a		n/a
Net income, Group share		11,768			12,273			10,868		n/a		n/a
Basic earnings per Share^(f)		5.13			5.23			4.50		n/a		n/a
Diluted earnings per Share^(f)		5.09			5.20			4.48		n/a		n/a
Amounts in accordance with U.S. GAAP^(a)
Sales		132,689			117,057			95,325		85,585		84,883
Net income		11,400			11,597	^(b)		7,221		6,103		6,264
Basic earnings per Share^(f)		4.97			4.94	^(b)		2.99		2.45		2.40
Diluted earnings per Share^(f)		4.93			4.91	^(b)		2.98		2.44		2.38

CASH FLOW STATEMENT DATA^(c)(e)
Amounts in accordance with IFRS
Cash flows provided by operating activities		16,061			14,669			14,662		n/a		n/a
Investments		11,852			11,195			8,904		n/a		n/a
Amounts in accordance with U.S. GAAP^(a)
Cash flows provided by operating activities		16,061			14,303			14,055		12,144		10,574
Investments		11,852			10,829			8,294		7,385		8,225

BALANCE SHEET DATA^(e)
Amounts in accordance with IFRS
Total assets		105,223			106,144			86,767		n/a		n/a
Non-current financial debt		14,174			13,793			11,289		n/a		n/a
Minority interests		827			838			810		n/a		n/a
Shareholders’ equity – Group share		40,321			40,645			31,608		n/a		n/a
Amounts in accordance with U.S. GAAP^(a)
Total assets		139,155			140,972			122,237		120,151		124,873
Non-current debt, net of current portion		14,232			13,573			11,140		10,883		9,533
Minority interests		830			835			645		666		731
Shareholders’ equity		71,884			73,055			65,108		66,527		69,096

DIVIDENDS
Dividend per share (euros)^(f)	€	1.87	^(g)	€	1.62		€	1.35	€	1.18	€	1.03
Dividend per share (dollars)^(f)	$	2.46	^(g)	$	1.99		$	1.74	$	1.41	$	1.18

(a)

For information concerning the differences between IFRS and U.S. GAAP, see Note 34 to the Consolidated Financial Statements included elsewhere herein.

(b)

Including changes in accounting policies, as described in Note 34 to the Consolidated Financial Statements included elsewhere herein.

(c)

See Consolidated Statement of Cash Flows included in the Consolidated Financial Statements included elsewhere herein.

(d)

Comparative information for 2003 and 2002 include Arkema which was spun off on May 12, 2006.

(e)

Comparative balance sheets and cash flow information include Arkema which was spun off on May 12, 2006.

(f)

Historical figures regarding per share information for 2005, 2004, 2003 and 2002 have been recalculated to reflect the four-for-one stock split on May 18, 2006.

(g)

Subject to approval by the shareholders’ meeting on May 11, 2007.

EXCHANGE RATE INFORMATION

For information regarding the effects of currency fluctuations on TOTAL’s results, see “Item 5. Operating and Financial Review and Prospects”.

Most currency amounts in this Annual Report on Form 20-F are expressed in euros (“euros” or “€”) or in U.S. dollars (“dollars” or “$”). For the convenience of the reader, this Annual Report on Form 20-F presents certain translations into dollars of certain euro amounts. Unless otherwise stated, the translation of euros to dollars has been made at the noon buying rate in New York City for cable transfers in euros as certified for customs purposes by The Federal Reserve Bank of New York (the “Noon Buying Rate”) for December 29, 2006, of $1.32 per € 1.00 (or € 0.76 per $1.00).

The following tables set out the average dollar/euro exchange rate for the years indicated, based on the Noon Buying Rate expressed in dollars per € 1.00. Such rates are not used by TOTAL in preparation of its Consolidated Financial Statements included elsewhere herein. No representation is made that the euro could have been converted into dollars at the rates shown or at any other rates for such periods or at such dates.

DOLLAR/EURO EXCHANGE RATES


Year		Average Rate^(a)
2002		0.95
2003		1.13
2004		1.25
2005		1.24
2006		1.26

(a)

The average of the Noon Buying Rate expressed in dollars/euro on the last business day of each full month during the relevant year.

The table below shows the high and low dollar/euro exchange rates for the previous six months based on the Noon Buying Rate expressed in dollars per euro.

DOLLAR/EURO EXCHANGE RATES


Period	High	Low
October 2006	1.28	1.25
November 2006	1.33	1.27
December 2006	1.33	1.31
January 2007	1.33	1.29
February 2007	1.32	1.29
March 2007	1.34	1.31
April 2007 (through April 9)	1.34	1.34

The Noon Buying Rate on April 9, 2007 for the dollar against the euro was $1.34 /€

RISK FACTORS

The Group and its businesses are subject to various risks relating to changing competitive, economic, political, legal, social, industry, business and financial conditions. These conditions along with TOTAL’s approaches to managing certain of these risks are described below and discussed in greater detail elsewhere in this Annual Report, particularly under the headings “Item 4. Information on the Company — Business Overview — Other Matters”, “Item 5. Operating and Financial Review and Prospects” and “Item 11. Quantitative and Qualitative Disclosures about Market Risk”.

A substantial or extended decline in oil or natural gas prices would have a material adverse effect on our results of operations.

Prices for oil and natural gas historically have fluctuated widely due to many factors over which we have no control. These factors include:

•

global and regional economic and political developments in resource-producing regions, particularly in the Middle East, Africa and South America;

•

global and regional supply and demand;

•

the ability of the Organization of Petroleum Exporting Countries (OPEC) and other producing nations to influence global production levels and prices;

•

prices of alternative fuels which affect our realized prices under our long-term gas sales contracts;

•

governmental regulations and actions;

•

global economic conditions;

•

war or other international conflicts;

•

cost and availability of new technology;

•

changes in demographics, including population growth rates and consumer preferences; and

•

adverse weather conditions (such as hurricanes) that can disrupt supplies or interrupt operations of our facilities.

Substantial or extended declines in oil and natural gas prices would adversely affect our results of operations by reducing our profits. For the year 2007, we estimate that a decrease of $1.00 per barrel in the price of Brent crude would have the effect of reducing our annual operating income by approximately 0.38 B€ (calculated with a base case exchange rate of $1.25 per €1.00). Lower oil and natural gas prices over prolonged periods may also reduce the economic viability of projects planned or in development, causing us to cancel or postpone capital expansion projects, and may reduce liquidity, thereby potentially decreasing our ability to

finance capital expenditures. If we are unable to follow through with capital expansion projects, our opportunities for future revenue and profitability growth would be reduced, which could materially impact our financial condition.

We face foreign exchange risks that could adversely affect our results of operations.

Our business faces foreign exchange risks because a large percentage of our revenues and cash receipts are denominated in U.S. dollars, the international currency of petroleum sales, while a significant portion of our operating expenses and income taxes accrue in euro and other currencies. Movements between the U.S. dollar and euro or other currencies may adversely affect our business by negatively impacting our booked revenues and income. For the year 2007, we estimate that a decrease in the dollar/euro exchange rate of €0.10/$ would have, without the use of hedging techniques, a corresponding negative effect on our annual operating income of approximately 2.2 B€.

Our long-term profitability depends on cost effective discovery and development of new reserves; if we are unsuccessful, our results of operations and financial condition would be materially and adversely affected.

A significant portion of our revenues and the majority of our operating income are derived from the sale of crude oil and natural gas which we extract from underground reserves discovered and developed as part of our Upstream business. In order for this business to continue to be profitable, we continuously need to replace depleted reserves with new proved reserves. Furthermore, we need to accomplish such replacement in a manner that allows subsequent production to be economically viable. However, our ability to discover or acquire and develop new reserves successfully is uncertain and can be negatively affected by a number of factors, including:

•

unexpected drilling conditions, including pressure or irregularities in geological formations;

•

equipment failures or accidents;

•

our inability to develop new technologies that permit access to previously inaccessible fields;

•

adverse weather conditions;

•

compliance with unanticipated governmental requirements;

•

shortages or delays in the availability or delivery of appropriate equipment;

•

industrial action; and

•

problems with legal title.

Any of these factors could lead to cost overruns and impair our ability to make discoveries or complete a development project, or to make production economical. If we fail to discover and develop new reserves cost-effectively on a consistent basis, our results of operations, including profits, and our financial condition would be materially and adversely affected.

Our crude oil and natural gas reserve data are only estimates, and subsequent downward adjustments are possible. If actual production from such reserves is lower than current estimates indicate, our results of operations and financial condition would be negatively impacted.

Our proved reserves figures are estimates reflecting applicable reporting regulations. Proved reserves are estimated using geological and engineering data to determine with reasonable certainty whether the crude oil or natural gas in known reservoirs is recoverable under existing economic and operating conditions. This process involves making subjective judgments. Consequently, estimates of reserves are not exact measurements and are subject to revision. They may be negatively impacted by a variety of factors which could cause such estimates to be adjusted downward in the future, or cause our actual production to be lower than our currently reported proved reserves indicate. The main factors which may cause our proved reserves estimates to be adjusted downward, or actual production to be lower than the amounts implied by our currently reported proved reserves, include:

•

a decline in the price of oil or gas, making reserves no longer economically viable to exploit and therefore not classifiable as proved;

•

an increase in the price of oil or gas, which may reduce the reserves that we are entitled to under production sharing and buyback contracts;

•

changes in tax rules and other government regulations that make reserves no longer economically viable to exploit;

•

the quality and quantity of our geological, technical and economic data, which may prove to be inaccurate;

•

the actual production performance of our reservoirs; and

•

engineering judgments.

Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect over time. Results of drilling, testing and production after the date of the estimates may require substantial downward revisions in our reserve data. Any downward adjustment would indicate lower future production amounts and may adversely affect our results of operations, including profits as well as our financial condition.

We have significant production and reserves located in politically, economically and socially unstable areas, where the likelihood of material disruption of our operations is relatively high.

A significant portion of our oil and gas production occurs in unstable regions around the world, most significantly Africa, but also the Middle East, Asia/Far East and South America. Approximately 31%, 17%, 11% and 10%, respectively, of our 2006 production came from these four regions. In recent years, a number of the countries in these regions have experienced varying degrees of one or more of the following: economic instability, political volatility, civil war, violent conflict and social unrest. In Africa, certain of the countries in which we have production has recently suffered from some of these conditions. In particular, shutdowns of production in the Niger Delta due to security concerns led to a 2% decrease in our oil and gas production in 2006. The Middle East in general has recently suffered increased political volatility in connection with violent conflict and social unrest. A number of countries in South America where we have production and other facilities, including Argentina, Bolivia and Venezuela, have suffered from political or economic instability and social unrest and related problems. In the Far East, Indonesia has suffered the majority of these conditions. Any of these conditions alone or in combination could disrupt our operations in any of these regions, causing substantial declines in production. Furthermore, in addition to current production, we are also exploring for and developing new reserves in other regions of the world that are historically characterized by political, social and economic instability, such as the Caspian Sea region where we have a number of large projects currently underway. The occurrence and magnitude of incidents related to economic, social and political instability are unpredictable. It is possible that they could have a material adverse impact on our production and operations in the future.

We are subject to stringent environmental, health and safety laws in numerous jurisdictions around the world and may incur material costs to comply with these laws and regulations.

We incur, and expect to continue to incur, substantial capital and operating expenditures to comply with increasingly complex laws and regulations covering the protection of the natural environment and the promotion of worker health and safety, including:

•

costs to prevent, control, eliminate or reduce certain types of air and water emissions, including those costs incurred in connection with government action to address concerns of climate change,

•

remedial measures related to environmental contamination or accidents at various sites, including those owned by third parties,

•

compensation of persons claiming damages caused by our activities or accidents, and

•

costs in connection with the decommissioning of drilling platforms and other facilities.

If our established financial reserves prove not to be adequate, environmental costs could have a material effect on our results of operations and our financial position. Furthermore, in the countries where we operate or expect to operate in the near future, new laws and regulations, the imposition of tougher license requirements, increasingly strict enforcement or new interpretations of existing laws and regulations or the discovery of previously unknown contamination may also cause us to incur material costs resulting from actions taken to comply with such laws and regulations, including:

•

modifying operations,

•

installing pollution control equipment,

•

implementing additional safety measures, and

•

performing site clean-ups.

As a further result of any new laws and regulations or other factors, we may also have to curtail or cease certain operations, which could diminish our productivity and materially and adversely impact our results of operations, including profits.

Our operations throughout the developing world are subject to intervention by various governments, which could have an adverse effect on our results of operations.

We have significant exploration and production, and in some cases refining, marketing or chemicals operations, in developing countries whose governmental and regulatory framework is subject to unexpected change and where the enforcement of contractual rights is uncertain. In addition, our exploration and production activity in such countries is often done in conjunction with state-owned entities, for example as part of a joint venture, where the state has a significant degree of control. In recent years, in various regions globally, we have seen governments and state-owned enterprises exercising greater authority and imposing more stringent conditions on companies pursuing exploration and production activities in their respective countries, increasing the costs and uncertainties of our business operations, which is a trend we expect to continue. Potential increasing intervention by governments in such countries can take a wide variety of forms, including:

•

the award or denial of exploration and production interests;

•

the imposition of specific drilling obligations;

•

price and/or production quota controls;

•

nationalization or expropriation of our assets;

•

unilateral cancellation or modification of our license or contract rights;

•

increases in taxes and royalties, including retroactive claims;

•

the establishment of production and export limits;

•

the renegotiation of contracts;

•

payment delays; and

•

currency exchange restrictions or currency devaluation.

Imposition of any of these factors by a host government in a developing country where we have substantial operations, including exploration, could cause us to incur material costs or cause our production to decrease, potentially having a material adverse effect on our results of operations, including profits.

We have activities in certain countries which are subject to U.S. sanctions and our activities in Iran could lead to sanctions under relevant U.S. legislation.

We currently have investments in Iran and, to a lesser extent, Syria and Sudan. U.S. legislation and regulations currently impose sanctions on these countries.

In the case of Iran, in 1996 the United States adopted the Iran Libya Sanctions Act (referred to as “ILSA”) implementing sanctions against those countries with the objective of denying Iran and Libya the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction. In September 2006, ILSA was amended and extended until December 2011. Pursuant to this statute, which now concerns only Iran (Iran Sanctions Act, referred to as “ISA”), upon receipt by the United States of information indicating potential violations, the President of the United States is authorized to initiate an investigation into the possible imposition of sanctions (from a list that includes denial of financing by the U.S. Export-Import Bank and limitations on the amount of loans or credits available from U.S. financial institutions) against persons found, in particular, to have knowingly made investments of $20 million or more in any 12-month period in the petroleum sector in Iran. In May 1998, the U.S. government waived the application of sanctions for TOTAL’s investment in the South Pars gas field in Iran. This waiver, which has not been modified since it was granted, does not address TOTAL’s other activities in Iran, although TOTAL has not been notified of any related sanctions.

At the end of 1996, the Council of the European Union adopted Council Regulation No. 2271/96 which prohibits TOTAL from complying with any requirement

or prohibition based on or resulting directly or indirectly from certain enumerated legislation, including ILSA. It also prohibits TOTAL from extending its waiver for South Pars to other activities. In each of the years since the passage of ILSA, TOTAL has made investments in Iran (excluding South Pars) in excess of $20 million. In 2006, TOTAL’s average daily production in Iran amounted to 20 kboe/d, approximately 1% of its average daily worldwide production. TOTAL expects to continue to invest amounts significantly in excess of $20 million per year in Iran in the foreseeable future. TOTAL cannot predict interpretations of or the implementation policy of the U.S. government under ISA with respect to its current or future activities in Iran. It is possible that the United States may determine that these or other activities constitute activity prohibited by ISA and

will subject TOTAL to sanctions. TOTAL does not believe that enforcement of ISA, including the imposition of the maximum sanctions under current applicable law and regulations, would have a material adverse effect on its results of operations or financial condition.

Furthermore, the United States currently imposes economic sanctions, which are administered by the U.S. Treasury Department’s Office of Foreign Assets Control and which apply to U.S. persons, with the objective of denying certain countries, including Iran, Syria and Sudan, the ability to support international terrorism and, additionally in the case of Iran and Syria, to pursue weapons of mass destruction and missile programs. TOTAL does not believe that these sanctions are applicable to any of its activities in these countries.

ITEM 4. INFORMATION ON THE COMPANY

History and development

TOTAL S.A., a French société anonyme (limited company) incorporated in France on March 28, 1924, together with its subsidiaries and affiliates, is the fourth largest publicly-traded integrated oil and gas company in the world⁽¹⁾.

With operations in more than 130 countries, TOTAL engages in all aspects of the petroleum industry, including Upstream operations (oil and gas exploration, development and production, LNG) and Downstream operations (refining, marketing and the trading and shipping of crude oil and petroleum products).

TOTAL also produces base chemicals (petrochemicals and fertilizers) and specialty chemicals for the industrial and consumer markets. In addition, TOTAL has interests in the coal mining and power generation sectors, as well as a financial interest in Sanofi-Aventis.

TOTAL began its Upstream operations in the Middle East in 1924. Since that time, the Company has grown and expanded its operations worldwide. Early in 1999 the Company acquired control of PetroFina S.A. and in

early 2000, the Company acquired control of Elf Aquitaine S.A. (hereafter referred to as “Elf Aquitaine” or “Elf”). The Company currently owns 99.5% of Elf Aquitaine shares and, since early 2002, 100% of PetroFina shares.

The Company, which operated under the name TotalFina from June 1999 to March 2000, and then under the name TotalFinaElf, has been operating under the name TOTAL since the shareholders’ meeting of May 6, 2003.

The Company’s principal office is 2, place de la Coupole, La Défense 6, 92400 Courbevoie, France. Its telephone number is +33 1 47 44 45 46.

TOTAL S.A. is registered in France with the Nanterre Trade Register under the registration number 542 051 180.

(1)

Based on market capitalization as of December 31, 2006.

Business Overview

TOTAL’s worldwide operations are conducted through three business segments: Upstream, Downstream, and Chemicals. The table below gives information on the

geographic breakdown of TOTAL’s activities and is taken from Note 5 to the Consolidated Financial Statements included in this Annual Report.


(M€)	France	Rest of Europe	North America	Africa	Far East and rest of the world	Total
2006
Non-Group sales^(a)	36,890	70,992	13,031	10,086	22,803	153,802
Plant, property and equipment, intangible assets, net	5,860	14,066	4,318	10,595	10,442	45,281
Capital expenditures	1,919	2,355	881	3,326	3,371	11,852
2005
Non-Group sales⁽^a)	34,362	53,727	17,663	8,304	23,551	137,607
Plant, property and equipment, intangible assets, net	6,300	14,148	4,748	9,546	10,210	44,952
Capital expenditures	1,967	2,178	1,691	2,858	2,501	11,195
2004
Non-Group sales⁽^a)	29,888	45,523	16,765	6,114	18,552	116,842
Plant, property and equipment, intangible assets, net	5,724	13,859	3,096	7,322	8,081	38,082
Capital expenditures	2,125	2,060	762	2,004	1,953	8,904

(a)

Non-Group sales from continuing operations.

Upstream

TOTAL’s Upstream segment includes Exploration & Production and Gas & Power activities. The Group has exploration and production activities in 42 countries and produces oil or gas in 30 countries. The Group’s Gas &

Power division conducts activities downstream from production related to natural gas, liquefied natural gas (LNG) and liquefied petroleum gas (LPG) as well as power generation and trading, and other activities.

Exploration & Production

Exploration and development

TOTAL’s Upstream segment intends to continue to combine long-term growth and profitability at the levels of the best in the industry.

TOTAL evaluates exploration opportunities based on a variety of geological, technical, political and economic factors (including taxes and licence terms), as well as on projected oil and gas prices. Discoveries and extensions of existing discoveries accounted for approximately 77% of the 2,460 Mboe added to the Upstream segment’s proved reserves during the three-year period ended December 31, 2006 (before deducting production and sales of reserves in place and adding any acquisitions of reserves in place during this period). The remaining 23% comes from revisions.

TOTAL continued to follow an active exploration program in 2006, with exploration investments of consolidated subsidiaries amounting to 1,214 M€

(including unproved property acquisition costs, excluding the acquisition of an interest in the Ichthys project in Australia). The principal exploration investments were made in Nigeria, the UK, Angola, the United States, Libya, Venezuela, Norway, Algeria, Congo, Kazakhstan, Canada, Indonesia, Australia, Argentina, Cameroon, Mauritania, Gabon, China, Azerbaijan and Thailand. In 2005, TOTAL’s exploration investments amounted to 644 M€, principally in Nigeria, Angola, the UK, Norway, Congo, the United States, Libya, Algeria, Argentina, Kazakhstan, Colombia, Indonesia and the Netherlands. In 2004, the Group’s exploration investments amounted to 651 M€, principally in the United States, Nigeria, Angola, the UK, Libya, Algeria, Congo, Kazakhstan, Norway, Bolivia, the Netherlands, Colombia and Indonesia.

The development expenditures of the Group’s consolidated Exploration & Production subsidiaries

amounted to 6.0 B€ in 2006 (including a share in the Ichthys project in Australia), primarily in Norway, Angola, Nigeria, Kazakhstan, Indonesia, Congo, Yemen, Qatar, the UK, Canada, Australia, the United States, Venezuela, Azerbaijan and Gabon. 2005 development expenditures amounted to 5.2 B€. The principal development investments for 2005 were carried out in Norway, Angola, Nigeria, Kazakhstan, Indonesia, the UK, Qatar, Congo, Azerbaijan, Gabon, Canada and Yemen. In 2004, development expenditures amounted to 4.1 B€ and were made principally in Norway, Angola, Nigeria, Indonesia, Kazakhstan, the UK, Qatar, Azerbaijan, the United States, Gabon, Congo, Libya, Trinidad & Tobago, Venezuela and Iran.

Reserves

The definitions used for proved, proved developed and proved undeveloped oil and gas reserves are in accordance with the applicable U.S. Securities & Exchange Commission regulation, Rule 4-10 of Regulation S-X. Proved reserves are estimated using geological and engineering data to determine with reasonable certainty whether the crude oil or natural gas in known reservoirs is recoverable under existing economic and operating conditions.

This process involves making subjective judgments. Consequently, estimates of reserves are not exact measurements and are subject to revision.

The estimation of proved reserves is controlled by the Group through established validation guidelines. Reserves evaluations are established annually by senior level geoscience and engineering professionals (assisted by a central reserves group with significant technical experience) including reviews with and validation by senior management.

Significant features of the reserves estimation process include:

•

internal peer reviews of technical evaluations also to ensure that the SEC definitions and guidance are followed, and

•

a requirement that management make significant funding commitments toward the development of the reserves prior to booking.

TOTAL’s oil and gas reserves are reviewed annually to take into account, among other things, production levels, field reassessments, the addition of new reserves from discoveries and acquisitions, disposals of reserves and other economic factors. Unless otherwise indicated, references to TOTAL’s proved reserves, proved developed reserves, proved undeveloped reserves and production reflect the entire Group’s share of such reserves or production. TOTAL’s worldwide proved reserves include the proved reserves of its consolidated subsidiaries as well as its proportionate share of the

proved reserves of equity affiliates and of two companies accounted for by the cost method.

For further information concerning changes in TOTAL’s proved reserves as of December 31, 2006, 2005 and 2004, see “Supplemental Oil and Gas Information (Unaudited)”.

Rule 4-10 of Regulation S-X requires the use of the year-end price, as well as existing operating conditions, to determine reserve quantities. Reserves at year-end 2006 have been determined based on the Brent price on December 31, 2006 ($58.93/b).

As of December 31, 2006, TOTAL’s combined proved reserves of crude oil and natural gas were 11,120 Mboe (of which 50% were proved developed reserves). Liquids represented approximately 58% of these reserves and natural gas the remaining 42%. These reserves are located primarily in Europe (Norway, the UK, the Netherlands, Italy and France), Africa (Nigeria, Angola, Congo, Gabon, Libya, Algeria and Cameroon), Asia/Far East (Indonesia, Myanmar, Thailand and Brunei), North America (Canada and the United States), the Middle East (Qatar, United Arab Emirates, Yemen, Oman, Iran and Syria), South America (Venezuela, Argentina, Bolivia, Trinidad & Tobago and Colombia), and the Commonwealth of Independent States (CIS) (Kazakhstan, Azerbaijan and Russia).

As of December 31, 2005, TOTAL’s combined proved reserves of crude oil and natural gas were 11,106 Mboe (of which 50% were proved developed reserves). Liquids represented approximately 59% of these reserves and natural gas the remaining 41%. These reserves were located primarily in Europe (Norway, the UK, the Netherlands, Italy and France), Africa (Nigeria, Angola, Congo, Gabon, Libya, Algeria and Cameroon), Asia/Far East (Indonesia, Myanmar, Thailand and Brunei), North America (Canada and the United States), the Middle East (United Arab Emirates, Qatar, Yemen, Oman, Iran and Syria), South America (Venezuela, Argentina, Bolivia, Trinidad & Tobago and Colombia), and the CIS (Kazakhstan, Azerbaijan and Russia).

As of December 31, 2004, TOTAL’s combined proved reserves of crude oil and natural gas were 11,148 Mboe (of which 51% were proved developed reserves). Liquids represented approximately 63% of these reserves and natural gas the remaining 37%. These reserves were located primarily in Europe (Norway, the UK, the Netherlands, Italy and France), Africa (Nigeria, Angola, Congo, Gabon, Algeria, Libya and Cameroon), Asia/Far East (Indonesia, Myanmar, Thailand and Brunei), North America (the United States and Canada), the Middle East (United Arab Emirates, Qatar, Oman, Iran, Syria and Yemen), South America (Venezuela, Argentina, Bolivia, Trinidad & Tobago and Colombia) and the CIS (Kazakhstan, Azerbaijan and Russia).

Proved reserves are the estimated quantities of TOTAL’s entitlement under concession contracts, production sharing contracts or buyback agreements. These estimated quantities may vary depending on oil and gas prices.

An increase in the year-end price has the effect of reducing proved reserves associated with production sharing or buyback agreements (which represent approximately 30% of TOTAL’s reserves as of December 31, 2006). Under such contracts, TOTAL is

entitled to receive a portion of the production, calculated so that its sale should cover expenses incurred by the Group. With higher oil prices, the volume of entitlement necessary to cover the same amount of expenses is lower. This reduction is partially offset by an extension of the duration over which fields can be produced economically. However, the increase in reserves due to extensions is smaller than the decrease in reserves under production sharing or buyback agreements. For this reason, a higher year-end price translates, on the whole, into a decrease in TOTAL’s reserves.

The table below sets forth the amount of TOTAL’s worldwide proved reserves as of the dates indicated (including both developed and undeveloped reserves).


TOTAL’s proved reserves^(a)(b)	Liquids (Mb)	Natural Gas (Bcf)	Total (Mboe)
December 31, 2004	7,003	22,785	11,148
Change from December 31, 2003	(4.4%)	2.3%	(2.2%)
December 31, 2005	6,592	24,750	11,106
Change from December 31, 2004	(5.9%)	8.6%	(0.4%)
December 31, 2006	6,471	25,539	11,120
Change from December 31, 2005	(1.8%)	3.2%	0.1%

(a)

Includes TOTAL’s proportionate share of the proved reserves of equity affiliates and of two companies accounted for by the cost method. See “Supplemental Oil and Gas Information (Unaudited)”.

(b)

Reserves as of December, 31 2006 are calculated based on a Brent crude price of $58.93/b, reserves as of December, 31 2005 are calculated based on a Brent crude price of $58.21/b and reserves as of December, 31 2004 are calculated based on a Brent crude price of $40.47/b, pursuant to Rule 4-10 of Regulation S-X.

Production

For the full year 2006, average daily hydrocarbon production was 2,356 kboe/d compared to 2,489 kboe/d in 2005, a decrease of 5% due to the following elements: -2% due to the price effect, -1% due to changes in the portfolio, -2% due to shutdowns in the Niger Delta area. Excluding these items, the positive impact of new field start-ups was offset by normal declines and shutdowns in the North Sea. In 2004, average production amounted to 2,585 kboe/d. Liquids accounted for approximately 64% and natural gas accounted for approximately 36% of TOTAL’s combined liquids and natural gas production in 2006 on an oil equivalent basis.

The table on the next page sets forth by geographic area TOTAL’s average daily production of crude oil and natural gas for each of the last three years.

Consistent with industry practice, TOTAL often holds a percentage interest in its acreage rather than a 100% interest, with the balance being held by joint venture partners (which may include other international oil companies, state oil companies or government entities). TOTAL frequently acts as operator (the party responsible for technical production) on acreage in which it holds an interest. See

“Presentation of Production Activities by Geographic Area” for a description of TOTAL’s principal producing fields in the upstream sector.

As in 2005 and 2004, substantially all of the crude oil production from TOTAL’s Exploration & Production activities in 2006 was marketed by the Trading & Shipping activities of its Downstream segment. See “Downstream—Trading & Shipping”.

The majority of TOTAL’s natural gas production is sold under long-term contracts. However, its North American production is sold on a spot basis as is part of its production from the UK, Norway and Argentina. The long-term contracts under which TOTAL sells its natural gas and LNG production usually provide for a price related to, among other factors, average crude oil and other petroleum product prices as well as, in some cases, a cost of living index. Although the price of natural gas and LNG tends to fluctuate in line with crude oil prices, there is a delay before changes in crude oil prices are reflected in long-term natural gas prices. Because of the relationship between the contract price of natural gas and crude oil prices, contract prices are not generally affected by short-term market fluctuations in the spot price of natural gas. See “Supplemental Oil and Gas Information (unaudited)”.

Production by geographic area


	2006			2005			2004
Consolidated subsidiaries	Liquids (kb/d)	Natural Gas (Mcf/d)	Total (kboe/d)	Liquids (kb/d)	Natural Gas (Mcf/d)	Total (kboe/d)	Liquids (kb/d)	Natural Gas (Mcf/d)	Total (kboe/d)
Africa	603	479	694	672	418	751	693	440	776
Algeria	35	129	59	38	141	64	42	160	72
Angola	108	24	112	144	23	148	159	27	164
Cameroon	13	2	13	12	2	12	13	—	13
Congo	93	22	97	91	20	95	87	21	90
Gabon	82	27	87	94	26	98	99	27	104
Libya	84	—	84	84	—	84	62	—	62
Nigeria	188	275	242	209	206	250	231	205	271
Asia/Far East	29	1,282	253	29	1,254	248	31	1,224	245
Brunei	3	65	15	3	54	13	3	58	14
Indonesia	20	891	182	20	890	182	22	854	177
Myanmar	—	121	15	—	109	13	—	110	14
Thailand	6	205	41	6	201	40	6	202	40
CIS	7	2	8	8	2	9	9	—	9
Azerbaijan	< 1	< 1	< 1	—	—	—	—	—	—
Russia	7	2	8	8	2	9	9	—	9
Europe	365	1,970	728	390	2,063	770	424	2,218	832
France	6	124	30	7	117	29	9	143	35
Netherlands	1	247	44	1	283	51	1	330	59
Norway	237	726	372	247	734	383	263	775	406
United Kingdom	121	873	282	135	929	307	151	970	332
Middle East	88	11	90	98	28	103	110	39	117
Iran	20	—	20	23	—	23	26	—	26
Qatar	29	3	29	31	3	31	31	1	31
Syria	16	2	17	22	18	25	30	32	36
U.A.E.	14	6	15	14	7	16	16	6	17
Yemen	9	—	9	8	—	8	7	—	7
North America	7	47	16	9	174	41	16	241	61
Canada	1	—	1	< 1	—	< 1	—	—	—
United States	6	47	15	9	174	41	16	241	61
South America	119	598	226	143	586	247	128	474	213
Argentina	11	375	78	11	351	74	11	325	70
Bolivia	3	97	21	3	97	21	3	82	18
Colombia	13	43	22	19	38	26	24	32	30
Trinidad & Tobago	9	2	9	12	2	13	—	—	—
Venezuela	83	81	96	98	98	113	90	35	95
Total consolidated production	1,218	4,389	2,015	1,349	4,525	2,169	1,411	4,636	2,253
Equity and non-consolidated affiliates
Africa^(a)	25	4	25	24	4	25	37	4	37
Middle East^(b)	263	281	316	248	251	295	247	254	295
Total equity and non-consolidated affiliates	288	285	341	272	255	320	284	258	332
Worldwide production	1,506	4,674	2,356	1,621	4,780	2,489	1,695	4,894	2,585

(a)

Primarily attributable to TOTAL’s share of CEPSA’s production in Algeria.

(b)

Primarily attributable to TOTAL’s share of production from concessions in the U.A.E.

Presentation of production activities by geographic area

The table below sets forth, by geographic area, TOTAL’s principal producing fields, the year in which TOTAL’s activities commenced, the principal type of production, the Group’s interest in each field and whether TOTAL is operator of the field.


Main producing fields at December 31, 2006^(a)
	Year of entry into the country	Main Group-operated producing fields (Group share %)	Main non-Group-operated producing fields (Group share %)	Liquids (L) or Gas (G)
Africa
Algeria	1952		Hamra (100.00%)	L
			Ourhoud (19.41%)^(b)	L
			RKF (48.83%)^(b)	L
			Tin Fouye Tabankort (35.00%)	L, G
Angola	1953	Girassol, Jasmim, Dalia (Block 17) (40.00%)		L
		Blocks 3-85, 3-91 (50.00%)		L
			Cabinda (Block 0) (10.00%)	L
			Kuito, BBLT (Block 14) (20.00%)	L
			Block 2-85 (27.50%)	L
Cameroon	1951	Bavo-Asoma (25.50%)		L
		Boa Bakassi (25.50%)		L
		Ekundu Marine (25.50%)		L
		Kita Edem (25.50%)		L
		Kole Marine (25.50%)		L
		Bakingili (25.50%)		L
			Mokoko - Abana (10.00%)	L
			Mondoni (25.00%)	L
Congo	1928	Nkossa (53.50%)		L
		Sendji (55.25%)		L
		Tchendo (65.00%)		L
		Tchibeli-Litanzi-Loussima (65.00%)		L
		Tchibouela (65.00%)		L
		Yanga (55.25%)		L
			Loango (50.00%)	L
			Zatchi (35.00%)	L
Gabon	1928	Gonelle (100.00%)		L
		Baudroie Nord (50.00%)		L
		Atora (40.00%)		L
		Avocette (57.50%)		L
		Anguille (100.00%)		L
		Torpille (100.00%)		L
			Rabi Kounga (47.50%)	L
Libya	1959	Al Jurf (37.50%)		L
		Mabruk (75.00%)		L
			El Sharara (7.50%)	L
			NC 186 (9.60%)	L
Nigeria	1962	OML 58 (40.00%)		L, G
		OML 99 Amenam-Kpono (30.40%)		L, G
		OML 100 (40.00%)		L
		OML 102 (40.00%)		L
			Shell Petroleum Development Company fields (SPDC 10.00%)	L, G
			Bonga (12.50%)	L, G


	Year of entry into the country	Main Group-operated producing fields (Group share %)	Main non-Group-operated producing fields (Group share %)	Liquids (L) or Gas (G)
Asia/Far East-Pacific
Brunei	1986	Maharaja Lela
		Jamalulalam (37.50%)		L, G
Indonesia	1968	Bekapai (50.00%)		L, G
		Handil (50.00%)		L, G
		Peciko (50.00%)		L, G
		Tambora/Tunu (50.00%)		L, G
			Badak (1.05%)	L, G
			Nilam (9.29%)	G
			Nilam (10.58%)	L
Myanmar	1992	Yadana (31.24%)		G
Thailand	1990		Bongkot (33.33%)	L, G
CIS
Azerbaijan	1996		Shah Deniz (10.00%)	L, G
Russia	1989	Kharyaga (50.00%)		L
Europe
France	1939	Lacq (100.00%)		L, G
Netherlands	1964	F15a (32.47%)		G
		J3c Unit (29.05%)		G
		K1a Unit (42.37%)		G
		K4a (50.00%)		G
		K4b/K5a (26.06%)		G
		K5b (25.00%)		G
		K6/L7 (56.16%)		G
		L4a (55.66%)		G
			Unit Markham fields (14.75%)	G
Norway	1965	Skirne (40.00%)		G
			Aasgard (7.68%)	L, G
			Ekofisk (39.90%)	L, G
			Eldfisk (39.90%)	L, G
			Embla (39.90%)	L, G
			Glitne (21.80%)	L
			Heimdal (26.33%)	G
			Hod (25.00%)	L
			Huldra (24.33%)	L, G
			Kristin (6.00%)	L, G
			Kvitebjørn (5.00%)	L, G
			Mikkel (7.65%)	L, G
			Oseberg (10.00%)	L, G
			Sleipner East (10.00%)	L, G
			Sleipner West/Alpha North (9.41%)	L, G
			Snorre (6.18%)	L
			Statfjord East (2.80%)	L
			Sygna (2.52%)	L
			Tor (48.20%)	L, G
			Tordis (5.60%)	L
			Troll (3.69%)	L, G
			Tune (10.00%)	L


	Year of entry into the country	Main Group-operated producing fields (Group share %)	Main non-Group-operated producing fields (Group share %)	Liquids (L) or Gas (G)
			Vale (24.24%)	L, G
			Valhall (15.72%)	L
			Vigdis (5.60%)	L
			Visund (7.70%)	L, G
United Kingdom	1962	Alwyn North, Dunbar, Ellon, Grant, Nuggets (100.00%)		L, G
		Elgin-Franklin (EFOG 46.17%)^(c)		L, G
		Forvie Nord (100.00%)		L, G
		Glenelg (49.47%)		L, G
		Otter (54.30%)		L
			Alba (12.65%)	L
			Armada (12.53%)	G
			Bruce (43.25%)	L, G
			Caledonia (12.65%)	L
			Markham unitized fields (7.35%)	G
			ETAP (Mungo, Monan) (12.43%)	L, G
			Keith (25.00%)	L, G
			Nelson (11.53%)	L
			SW Seymour (25.00%)	L
Middle East
Iran	1954	Dorood (55.00%)^(d)		L
			South Pars 2 & 3 (40.00%)^(e)	L, G
			Balal (46.75%)^(f)	L
			Sirri (60.00%)^(g)	L
Oman	1937		Various fields onshore (Block 6) (4.00%)^(h)	L
			Mukhaizna field (Block 53) (2.00%)⁽ⁱ⁾	L
Qatar	1936	Al Khalij (100.00%)		L
			North Field - NFB (20.00%)	L, G
Syria	1988	Jafra/Qahar (100.00%)^(j)		L
Yemen	1987	Kharir/Atuf (Block 10) (28.57%)		L
			Al Nasr (Block 5) (15.00%)	L
U.A.E.	1939	Abu Dhabi - Abu Al Bu Khoosh (75.00%)		L
			Abu Dhabi offshore (13.33%)^(k)	L
			Abu Dhabi onshore (9.50%)^(l)	L
			Dubai offshore (27.50%)^(m)	L
North America
Canada	1999	Joslyn (84.00%)		L
			Surmont (50.00%)	L
United States	1957	Aconcagua (50.00%)⁽ⁿ⁾		G
		Matterhorn (100.00%)		L, G
		Virgo (64.00%)		G
			Camden Hills (16.67%)⁽ⁿ⁾	G
South America
Argentina	1978	Aguada Pichana (27.27%)		L, G
		Canadon Alfa Complex (37.50%)		L, G
		Aries (37.50%)		L, G
		Carina (37.50%)		L, G
		Hidra (37.50%)		L
		San Roque (24.71%)		L, G


	Year of entry into the country	Main Group-operated producing fields (Group share %)	Main non-Group-operated producing fields (Group share %)	Liquids (L) or Gas (G)
South America
Bolivia	1995		San Alberto (15.00%)	L, G
			San Antonio (15.00%)	L, G
Colombia	1973		Cupiagua (19.00%)	L, G
			Cusiana (19.00%)	L, G
Trinidad & Tobago	1996
			Angostura (30.00%)	L
Venezuela	1980		Zuata (Sincor) (47.00%)	L
			Yucal Placer (69.50%)	G

(a)

The Group’s interest in the local entity is approximately 100% in all cases except Total Gabon (57.98%), Total E&P Cameroun (75.80%), and certain entities in the UK, Algeria, Abu Dhabi and Oman (see notes (b) through (m) below).

(b)

In Algeria, TOTAL has an indirect 19.38% interest in the Ourhoud field and a 48.83% indirect interest in the RKF field via its participation in CEPSA (equity affiliate).

(c)

TOTAL has a 35.8% indirect interest in Elgin Franklin via its participation in EFOG.

(d)

TOTAL is the operator of the development of Dorood field with a 55.00% interest in the foreign consortium.

(e)

TOTAL has transferred operatorship to NIOC for phases 2 & 3 of the South Pars field. The Group has a 40.00% interest in the foreign consortium.

(f)

TOTAL has transferred operatorship to the National Iranian Oil Company (NIOC) for the Balal field. The Group has a 46.75% interest in the foreign consortium.

(g)

TOTAL has transferred operatorship to NIOC for the Sirri A & E fields. The Group has a 60.00% interest in the foreign consortium.

(h)

TOTAL has a direct participation of 4.00 % in Petroleum Development Oman LLC, operator of Block 6, in which TOTAL has an indirect participation of 4.00 % via Pohol (equity affiliate). TOTAL also has a 5.54% interest in the Oman LNG facility (trains 1 and 2), and an indirect participation of 2.04% via OLNG in QalhatLNG (train 3).

(i)

TOTAL has a direct participation of 2.00 % in Block 53.

(j)

Operated by DEZPC which is 50.00% owned by TOTAL and 50.00% owned by SPC.

(k)

Via ADMA (equity affiliate), TOTAL has a 13.33% interest and participates in the operating company, Abu Dhabi Marine Operating Company.

(l)

Via ADPC (equity affiliate), TOTAL has a 9.50% interest and participates in the operating company, Abu Dhabi Company for Onshore Oil Operation.

(m)

TOTAL has a 25.00% indirect interest via Dubai Marine Areas (equity affiliate) plus a 2.50% direct interest via TOTAL E&P Dubai.

(n)

Asset sold early in 2007.

Africa

TOTAL has been present in Africa since 1928. The African continent is one of the Group’s fastest growing production zones. Its exploration and production operations are primarily located in the countries bordering the Gulf of Guinea and in North Africa.

Highlights of 2006 included:

•

in Angola, first oil of the Dalia project on Block 17, with a planned production (in 100%) of 240 kboe/d, as well as the start-up of the Benguela Belize Lobito Tomboco, and Landana North fields on Block 14;

•

and, in Nigeria, taking interests in the Brass LNG liquefied natural gas project as well as in offshore Blocks OML 112 and OML 117.

In addition, several discoveries were made over the course of the year (Angola: Blocks 17 and 32, Cameroon: Dissoni, Congo: third discovery on MTPS and Mobi Marine 2, Libya: NC191/NC186).

TOTAL’s production in Africa averaged 720 kboe/d in 2006 (including its share in the production of equity affiliates), making TOTAL one of the leading international oil companies, based on production, in the region. Projects in Africa accounted for 31% of the Group’s total production in 2006.

Algeria

The Group has been present in Algeria since 1952. Its production comes from the Hamra (100%) and Tin Fouyé Tabankort (TFT) (35%) fields, as well as, through the Group’s 48.83% interest in CEPSA, from the Ourhoud and Rhourde El Khrouf (RKF) fields. TOTAL’s share of production amounted to 80 kboe/d in 2006, down from the volumes recorded in previous years (85 kboe/d in 2005 and 105 kboe/d in 2004), due, in particular, to the impact of higher oil prices on production entitlements.

On the TFT field, additional development continued with drilling in the West Zone, where production began in September 2005, and with the award of the principal contracts for the project to install compression units, which are expected to be commissioned in 2008.

Exploration and appraisal work, including drilling as well as 2D and 3D seismic campaigns, continued on the Timimoun permit (63.75%, operator). The Hassi Mahdjib 3 exploration well (MJB3) made a discovery early in 2006.

After conducting seismic work in 2005, TOTAL did not extend the Béchar prospecting contract (northwest of Timimoun) as a research contract. This contract was awarded in November 2004 and expired in November 2006. The Rhourde Es Sid permit in the Berkhine basin was relinquished late in 2004 after two exploration wells had been drilled.

In addition, while the details for applying the tax on oil company profits introduced in December 2006 have not been finalized, a provision was made for the anticipated impact of this tax.

Angola

TOTAL has been present in Angola since 1953 and is currently one of the most prominent oil companies in the country.

The Group has onshore, deep-offshore and ultra-deep-offshore interests through six production permits (three operated: Blocks 17, 3, and FS/FST; three non-operated: Blocks 0, 14, and 2) and three exploration permits (Block 32, operator; and Blocks 31 and 33).

The Group’s production comes principally from Block 17 (40%, operator), Block 0 (10%) and Block 14 (20%). On Block 17, Dalia began production in December 2006 and is expected to reach a production plateau of 240 kboe/d. On Block 14, the Benguela Belize Lobito Tomboco (BBLT) platform began production in January 2006. 20 discoveries have been made on Blocks 31 and 32.

TOTAL’s production in Angola (including its share in the production of equity affiliates) reached 117 kboe/d in 2006, compared to 152 kboe/d in 2005 and 168 kboe/d in 2004. TOTAL’s production entitlement for oil and gas is determined according to the terms contained in production sharing contracts. The volumes received depend, among other factors, on cumulative prices in prior years. As a result, in 2006 TOTAL’s production entitlement was reduced due to significantly higher oil prices. Also in 2006, the project to connect the Rosa field was completed during the planned shutdown of Girassol for heavy maintenance, which occurs every five years. Production was stopped for 38 days during this maintenance.

In 2006, TOTAL participated in the call for tenders regarding previously-relinquished shares of deep-offshore blocks. In 2007, the Group completed negotiations to acquire interests in Block 17/06 and Block 15/06. The last license on Block 3/80 expired in July 2006.

Deep-offshore Block 17 is TOTAL’s principal producing asset in Angola. It is composed of four major production zones: Girassol, which has been in production since December 2001, Dalia, which has been in production since December 2006, Pazflor, where development studies are underway, and CLOV, which is based on the Cravo, Lirio, Orquidea, and Violeta discoveries. The “stand alone” development design for CLOV is being studied after the successful drilling of the Orquidea-2 well in the summer of 2006.

On the Girassol structure, production (in 100%) from the Girassol and Jasmim fields reached 210 kb/d on average in 2006, despite the planned maintenance of the FPSO (Floating Production, Storage and Offloading) facility, which occurs every five years. Production from the Rosa field is expected to begin in the first half 2007. Since the Rosa field is being developed by connection to the Girassol FPSO, located approximately 15 kilometers away, this development (which was approved in July 2004) should allow the extension of Girassol’s 250 kb/d plateau production (in 100%).

On the second production zone, Dalia field began production in December 2006. This development was launched in 2003 and is based on a system of sub-sea wells connected to a new FPSO facility with a production capacity of 240 kb/d.

Basic engineering studies for the development of Pazflor, the third production zone made up of the Perpetua, Zinia, Hortensia, and Acacia fields in the eastern portion of Block 17, continued in 2006. These studies plan for the development, scheduled to begin in 2007, of a FPSO facility with a production capacity of 200 kb/d.

The successful Orquidea-2 appraisal well confirmed the Group’s interest in developing the Cravo, Lirio, Orquidea and Violeta fields, through a fourth FPSO facility on Block 17. Basic engineering studies for the development of this new production zone (CLOV) should be launched in 2007.

On Block 0 (10%), where the Sanha Bomboco project began production late in 2004, work continued on a project intended to stop gas flaring and improve liquids recovery with the construction of processing facilities on Takula and the approval of the Nemba project.

On Block 14 (20%), production increased significantly with the start-ups of Benguela Belize (January 2006), and Lobito and Landana North (June 2006). The Group expects that production will continue to increase through the ramp-up of production of BBLT and the start-up of production at Tombua Landana (scheduled for 2009). The Lucapa discovery made in November 2006 added to the Group’s estimate of the Block’s potential resources.

On Block 32 (30%, operator), the series of discoveries (Gindungo in 2003, Canela and Cola in 2004, Gengibre and Mostarda in 2005) continued with the drilling of the successful Salsa, Manjericao, and Caril wells in 2006, further confirming the Group’s interest in the block. Development studies, launched in 2005 and conceived around a zone in the central-eastern portion of the block, continued in 2006. Three new discoveries in 2006 also confirmed the Group’s interest in developing Block 31 (5%). After drilling two new dry wells on Block 33 (15%), the Group’s partners decided not to extend the exploration period. However, negotiations to retain the Calulu PDA (Pre-Development Area) are still ongoing.

In 2005, TOTAL and its partners decided to launch basic engineering studies for the Angola LNG project (13.6%), which is being designed to prepare for the marketing of natural gas reserves from Angola. The shareholders are expected to approve the project in 2007.

The Republic of Angola and the Republic of Congo, along with the partners on Block 14 in Angola and the Haute Mer permit in Congo, have formed a joint development area (JDA) that covers the portions of these permits that are adjacent. TOTAL holds a combined interest of 36.75% in this area through its subsidiaries in Congo (26.75%) and in Angola (10%).

Cameroon

TOTAL has been present in Cameroon since 1951 and operates production of 60 kb/d, amounting to nearly 70% of the country’s production. Since 2005, new contracts signed with the Republic of Cameroon have been production sharing contracts. TOTAL’s share of production amounted to 13 kb/d in 2006, compared to 12 kb/d in 2005 and 13 kb/d in 2004.

TOTAL’s acreage is located entirely in the Rio Del Rey Basin, covering an area of 1,440 km². The Group operates six concessions (25.5%, operator of Kole, Ekundu, Boa, Bavo, Kita and Sandy Gas) and two production sharing contracts (Dissoni, 50%, operator, and Bomana, 100%, operator). TOTAL is also a partner in four concessions: Lipenja-Erong (10%), Mokoko-Abana (10%), Mondoni (25%) and South Asoma (25%).

In March 2006, TOTAL signed an exploration and production sharing contract for the Bomana block (100%). In April 2006, the Group signed renewals for three operated concessions, Bavo-Asoma, Kita-Edem and Sandy Gas, for a 25-year period and at the same time renewed its non-operated concession for Mokoko-Abana. Blocks PH 60 (50%, operator) and PH 59 (50%) were relinquished in August 2006, when these concessions reached their term.

The natural decline of mature fields is expected to be compensated by the start-up of new zones or new discoveries, such as Bakingili (25.5%, operator), where production started in 2005, and the Dissoni Delta, where production is expected to begin late in 2008. The Group launched development studies concerning the Rio Del Rey gas resources to determine the feasibility of a project to export gas to the Equatorial Guinea LNG plant.

The Group’s interest in developing the Dissoni Delta zone was confirmed by the DIM 2 appraisal well. A deep well (Njonji) is scheduled to be drilled in 2007 in the turbidite layer of this permit. A 3D seismic was acquired on Bomana/Edem in 2006.

Congo

TOTAL, the largest operator of production in Congo, has been present in the country since 1928. TOTAL’s share of production, primarily offshore, reached 97 kboe/d in 2006, compared to 95 kboe/d in 2005 and 90 kboe/d in 2004. Highlights for 2006 included discoveries on the Mer Très Profonde Sud (MTPS, 40%, operator) and the Moho-Bilondo (53.5%, operator) permits. The first phase of development for the Moho-Bilondo project was launched in 2005.

TOTAL holds interests in several exploration and production permits. The principal producing fields that it operates are Nkossa (53.5%), Tchibouela (65%), Kombi-Likalala-Libondo (65%) and Tchibeli-Litanzi-Loussima (65%). The Republic of Congo and the Republic of Angola, along with the partners on the Haute Mer permit and Block 14 in Angola, have formed a joint development area that covers the portions of these permits that are adjacent. TOTAL holds a combined interest of 36.75% in this zone through its subsidiaries in Congo (26.75%) and in Angola (10%). TOTAL is operator of the Djeno terminal (63%).

The Moho-Bilondo project is under development, with production expected to begin in the first half 2008. The production plateau is expected to reach 90 kb/d. Studies are underway for the development of previously discovered fields on the other existing permits, either as satellites to existing facilities (Libondo on PEX) or as stand-alone projects (Boatou on Haute-Mer C).

Aurige Nord Marine 1, Pegasus North Marine 1 and Andromeda Marine 1, three discoveries made on the MTPS permit in 2006, 2004 and 2000, respectively, may form the basis for a future development project. Additional drilling operations are planned to begin in April 2007. On the Moho-Bilondo permit, the Mobi Marine 2 well identified two new structures. Drilling for the Moho North 1 well began in December 2006.

Gabon

Total Gabon is one of the Group’s oldest subsidiaries in sub-Saharan Africa. The Group’s share of production in 2006 was 87 kboe/d, compared to 98 kboe/d in 2005 and 104 kboe/d in 2004, due to the natural decline of mature fields.

Total Gabon is a Gabonese company whose shares are listed on the Eurolist by Euronext exchange in Paris. TOTAL holds 58%, the Republic of Gabon 25% and the public float is 17%.

Total Gabon holds 26 permits, of which 17 are concessions under a Convention d’Etablissement and 9 are production sharing contracts. The Olonga exploration permit and the Roussette operation permit

were relinquished in 2006. The main producing fields are Rabi Kounga (47.5%), Gonelle (100%), Baudroie Nord (50%, operator), Atora (40%, operator), Avocette (57.5%, operator), Anguille (100%) and Torpille (100%).

In 2004, Total Gabon signed an exploration and production sharing contract for the Aloumbé permit, specifically focused on natural gas exploration. A second exploration phase, with a drilling program, started in 2006, after completing the reprocessing of seismic data and the interpretation of geophysical/geological data.

In 2006, Total Gabon signed an exploration and production sharing contract for a new deep-offshore permit, Diaba, covering an area of 9,075 km² off the southern coast of Gabon. Under this agreement, Total Gabon has an 85% interest in the permit while the Republic of Gabon has the remaining 15%.

In 2006, Total Gabon also conducted a hydraulic fracturation test in the Anguille concession as part of redevelopment studies for the field.

Total Gabon and the government of Gabon are currently negotiating to extend the Convention d’Etablissement, which expires on June 30, 2007.

Libya

The Group’s share of production in 2006 reached 84 kboe/d, the same level as in 2005, and up from 62 kboe/d in 2004. Production comes from the Mabruk field (75%, operator), offshore Block C 137 (75%⁽¹⁾, operator), and Block NC 186-187-190 (24%⁽¹⁾) and NC 115 (30%⁽¹⁾).

Work continued on the complementary development project for the Mabruk field, agreed to in 2004, and the new facilities are expected to begin operations in 2007. The Libyan authorities signed an amendment to the Mabruk agreement early in 2005, leading to preliminary drilling to develop the deeper Dahra and Garian zones.

Drilling designed to maintain the production plateau at 40 kboe/d continued on the Al Jurf field of Block C 137. A second development phase is currently being studied.

On Block NC 186, the Group is continuing to develop several previously discovered structures. Structures B and H, which are currently being developed, are expected to enter into production in 2007. The I, J, and

K discoveries were made in 2005 and 2006. Approval for the development of the I structure is expected to be obtained in 2007.

On Block NC 115, the development of the El Sharara field also continued. The J and O structures began production in 2004, and at the same time their capacities increased. Two successful exploration wells were drilled in 2005 (structures P and R). Structure R, an extension of structure I from Block NC 186, is expected to be developed at the same time as structure I, beginning in 2007.

In the Murzuk Basin, in 2006 the Group made a discovery on Block NC 191 (100%, operator). Late in 2005, TOTAL (60%, operator) obtained a new permit in the Cyrenaic Basin (Block 42 2/4).

Mauritania

The Group has conducted exploration and production activities in Mauritania since 2003. In January 2005, TOTAL signed two production sharing contracts with the Mauritanian government for onshore Blocks Ta7 and Ta8 in the Taoudenni Basin, representing a combined total of 58,000 km². Following an aerial survey to obtain magnetic and gravimetric data performed in 2005 and 2006, a 3,000 km 2D seismic campaign was launched in July 2006 for an expected duration of 15 to 18 months.

Morocco

Since the termination of the survey agreement on the Dakhla offshore zone late in 2004, the Group has had no further exploration and production activities in Morocco.

Nigeria

TOTAL has been present in Nigeria since 1962. It operates six production permits (OML) out of the 43 in which it holds an interest, and five exploration permits (OPL) out of six in which it has an interest. The Group’s share of production reached 242 kboe/d in 2006, compared to 250 kboe/d in 2005 and 271 kboe/d in 2004. Highlights of 2004, 2005 and 2006 included discoveries and the acquisition of acreage.

Security concerns in the Niger delta region, including armed attacks on certain sites, kidnappings and damage to facilities, led the Shell Petroleum Development Company (SPDC, in which TOTAL holds 10%) to stop production at certain facilities. At present, it is not possible for the Group to predict when production at these facilities will resume. TOTAL’s average share of the production from SPDC decreased by nearly 50 kboe/d for the year 2006 due to these events.

(1)

Participation in the foreign consortium

The fields operated by TOTAL, OML 58, 100, 102 (40%, operator) and OML 99—Amenam (30.4%, operator), contributed approximately 50% of the Group’s Nigerian production in 2004 and 2005, and 60% in 2006. Production from the offshore Amenam field began in 2003 and reached its production plateau of 125 kb/d in the summer of 2004. TOTAL’s production also comes from its interests in SPDC, in the Ekanga field (40%) and in the Bonga field (12.5%) where production started in November 2005 and reached its plateau production of 210 kboe/d early in 2006.

TOTAL confirmed its interest in developing gas production on the OML 112-117 permit, which it acquired in 2005 with the successful drilling of the IMA 12 well. Extensive studies have been carried out on the OPL 215 permit, acquired in 2005. The Group’s appraisal of the Egina field (OML 130), which began in 2004, continued from 2005 through 2007 with the drilling of one exploration well and three appraisal wells. In 2007, the Group announced that the Egina field was expected to be developed on a stand-alone basis. TOTAL also conducted drilling operations in its “Triangular Bulge” zone permits (OPL 221, 222, and 223). The results of these efforts are currently being assessed.

Within the framework of the joint venture between NNPC (Nigerian National Petroleum Corporation) and TOTAL, the authorities approved the “OML 58 Upgrade” development plan in July 2006. This new project is expected to begin operations in 2009 and to supply Nigeria LNG’s (NLNG) sixth liquefaction train. After evaluating the bids it had received, late in 2006 the Group gave its final approval for a new development project (Ofon II) on the OML 102 permit. The Nigerian authorities had previously approved the development of this project in 2005. This new phase, whose launch is scheduled for 2009, is expected to produce an additional 70 kboe/d (in 100%). TOTAL also continued to develop the Amenam Phase II project in 2005 and 2006. This project, which produces associated gas from the Amenam field to supply NLNG, entered into operation late in 2006.

On fields where TOTAL is not the operator, several projects, including Bonga North and Southwest, are undergoing engineering studies. The Afam project (gas and condensates for domestic supply) and the Gbaran Ubie project (gas and condensates to supply future NLNG trains) are under construction, as are the Soku, Bonny Terminal and Forcados Yokri projects.

TOTAL is also actively pursuing development work on its deep-offshore discoveries. Development of the Akpo field on OML 130 (24%, operator) is continuing. The principal engineering and construction contracts for the development of Akpo, which were signed in 2005, are currently being executed, with a goal of reaching a

production plateau of 225 kboe/d (in 100%). Production on the Akpo project is expected to begin late in 2008.

TOTAL also aquired a 40% interest in OMLs 112 and 117 in 2006 and conducted conceptual development studies for the IMA gas field on these permits. The Group intends to use the gas produced from this field to supply the LNG plants in which TOTAL is a shareholder. In 2006, TOTAL continued to increase its acreage, acquiring (pending final approval by the authorities) an interest in OPL 247.

TOTAL holds a 15% interest in the NLNG gas liquefaction plant. At this plant, a fourth train came on line in November 2005, followed by a fifth train which began operations in February 2006. In 2004, NLNG’s shareholders decided to invest in a sixth train, which is scheduled to be commissioned in 2007. The company began studies for a seventh train, with a capacity of 8.5 Mt, in July 2005, which continued in 2006.

In 2006, TOTAL acquired a 17% interest in the Brass LNG project, which plans to build two trains, each with a capacity of 5 Mt/year. The Group also agreed to supply approximately two-thirds of the second train’s requirements. The final investment decision for this project is expected to be taken in 2007.

Sudan

Late in 2004, TOTAL (32.5%, operator) updated its production sharing contract for Block B (118,000 km² in southeast Sudan).

To counter a claim by the White Nile Company, which publicly claimed to have rights to the area covered by the permit held by TOTAL and its partners, the Group sought to enforce its rights in an English court. In May 2006, the High Court of London ordered White Nile to disclose the contracts upon which its claims are based to TOTAL. This ruling was confirmed by the Court of Appeal in January 2007.

TOTAL opened an office in Khartoum in 2005 and a branch office in Juba, southern Sudan, in 2006. The Group has initiated bidding processes to check the area for landmines and to conduct 1,200 km of 2D seismic work on the Jonglei Basin.

Once the authorities in Sudan and in South Sudan have established legal and security conditions in the area that are suitable for the development of industrial activities in South Sudan, TOTAL will consider proceeding with a 2D seismic survey and the drilling of two wells on Block B.

Asia/Far East-Pacific

In 2006, TOTAL’s production in Asia/Far East-Pacific, principally from Indonesia, amounted to 253 kboe/d, compared to 248 kboe/d in 2005 and 245 kboe/d in 2004, an increase of 2% over the period. Asia/Far East-Pacific represented 11% of the Group’s overall production for the year 2006. Highlights for the 2004 to 2006 period included the acquisition of interests in several exploration permits in Australia, Bangladesh and Indonesia, the acquisition of a 24% interest in the Ichthys LNG project in Australia in partnership with INPEX, and the signature of an agreement with China National Petroleum Corporation for the appraisal, development and production of natural gas on the Sulige South block in China.

Australia

After acquiring interests in two blocks (WA-297P, WA-269P) early in 2005, in 2006 TOTAL increased its offshore interests in both exploration and development of previously discovered fields in northwest Australia.

In February 2006, with the same partners as for Block WA-269P (30%), TOTAL acquired a 30% share in the two adjacent blocks, WA-369P and WA-370P, located in the Carnarvon basin near the Pluto field. A 3D seismic campaign on these blocks was completed in 2006 and four wells are scheduled to be drilled in 2007 and 2008.

Also in 2006, TOTAL acquired a 25% share in adjacent blocks WA-301P, WA-303P, WA-304P, and WA-305P, located in the Browse basin. A well is scheduled to be drilled on Block WA-303P in 2007.

In addition, in August 2006 TOTAL acquired a 24% interest in Block WA-285P, also in the Browse basin. The Ichthys gas and condensates field, in the same basin, has already had six successful wells drilled since 2000. This field is expected to be developed to produce an estimated 6 Mt/y to 10 Mt/y of LNG, condensates and LPG. In 2006, this project received Major Project Facilitation Status, which should contribute to obtaining governmental approvals, expected in 2008. The environmental evaluation of the development scheme was launched in May 2006, and exploration and appraisal drilling are planned for 2007.

In January 2007, TOTAL acquired an 80% interest, as operator, for the lower levels of Block AC/P-37. A seismic campaign is scheduled for 2007.

Bangladesh

Late in 2005, TOTAL signed an agreement to acquire 60% of two offshore exploration blocks, 17 and 18, located southeast of Bangladesh. The government approved this agreement on March 14, 2007.

Brunei

TOTAL is the operator of the Maharaja Lela Jamalulalam field, located offshore on Block B of Brunei Darussalam (37.5%, operator). The Group’s share of production amounted to 15 kboe/d in 2006, compared to 13 kboe/d in 2005 and 14 kboe/d in 2004. After completing studies in 2006, TOTAL is planning to drill several exploration wells on this block in 2007.

TOTAL is also the operator of deep-offshore exploration Block J (60%), for which a production sharing contract was signed in March 2003. Exploration operations on the 5,000 km²² block have been suspended since May 2003 due to a border dispute with Malaysia.

China

Early in 2006, TOTAL and China National Petroleum Corporation signed a production sharing contract for the appraisal, development, and production of natural gas resources on the South Sulige block covering an area of approximately 2,390 km² in the Ordos Basin in the Inner Mongolia province. The agreement was approved by the Chinese authorities and became effective in May 2006. The appraisal work outlined in the contract (seismic acquisition, well testing) began in September 2006.

Indonesia

TOTAL has been present in Indonesia since 1968. Indonesia represented 8% of the Group’s production in 2006, amounting to 182 kboe/d, the same level as in 2005, compared to 177 kboe/d in 2004. TOTAL operates two offshore blocks in the Kalimantan East zone, the Mahakam permit (50%, operator), and the Tengah permit (22.5%).

TOTAL’s operations in Indonesia are primarily concentrated on the Mahakam permit, which covers several fields including Peciko and Tunu, the largest gas fields in the Kalimantan East zone.

TOTAL delivers its natural gas production to PT Badak, the Indonesian company that operates the Bontang LNG plant. The overall capacity of the eight liquefaction trains of the Bontang plant is 22 Mt/y, one of the largest in the world⁽¹⁾. The LNG produced is primarily sold under long-term contracts with Japanese, South Korean and Taiwanese purchasers that mainly use it for power generation. In 2006, the production operated by TOTAL on the Mahakam permit amounted to 2,648 Mcf/d, and the gas delivered by TOTAL to Bontang accounted for more than 70% of the plant’s supply.

(1)

Source: Wood MacKenzie, Deutsche Bank.

In 2006, TOTAL acquired a 49% share in the offshore East Sepanjang block, located northeast of the island of Java. A seismic acquisition campaign is scheduled and an exploration well is expected to be drilled.

Pursuant to a call for tenders launched by the Indonesian Ministry of Mines and Energy in 2006, early in 2007 TOTAL was awarded the South East Mahakam exploration block (50%, operator), located in the Mahakam delta.

TOTAL also has a 50% interest in the Saliki exploration block, which is adjacent to the Mahakam permit.

Late in 2006, a gas discovery, Tunu Great South-1, was made between the Tunu and Peciko fields on the Mahakam permit.

After the commissioning of onshore compression units in 2005, and the launch the same year of the fifth phase regarding the installation of a new platform and the drilling of additional wells, the development of the Peciko field continued in 2006 with the decision to invest in new compression capacities.

On the neighboring Tunu field, the tenth phase of development is underway and four additional platforms became operational in 2006. The 11^th development phase, to install onshore compression units, was launched in 2005 and is continuing. A new phase for drilling additional wells was agreed upon late in 2006.

The project to extend the Tambora field, launched in 2004, advanced with the commissioning of three new platforms by mid-2006.

Phase 1 of the new Sisi-Nubi offshore development was launched in 2005 and is ongoing. Gas from Sisi-Nubi is expected to be produced early in 2008 through existing processing facilities.

Malaysia

Since 2001, TOTAL has held a 42.5% interest in the deep-offshore Block SKF permit. After drilling an exploration well in 2004, TOTAL reevaluated the exploration potential of the permit and requested an extension of the exploration period to carry out additional work, which was obtained in March 2007.

Myanmar

TOTAL is the operator of the Yadana field (31.2%). The Group’s share of production was 15 kboe/d in 2006, compared to 13 kboe/d in 2005 and 14 kboe/d in 2004. This field, located on offshore Blocks M5 and M6, produces natural gas, which is principally delivered to PTT (Thailand’s state-owned company) and used in Thai power plants.

Pakistan

TOTAL (40%, operator) held two ultra-deep offshore exploration blocks in the Oman Sea. TOTAL relinquished

its interests in these two blocks in 2005 after the Group drilled a dry exploration well in 2004.

Thailand

The Group’s primary asset in Thailand is the Bongkot gas and condensates field (33.3%), where its production reached 41 kboe/d in 2006, compared to 40 kboe/d in 2005 and 2004. PTT (Thailand’s state-owned company) purchases all the condensates and natural gas produced.

Phase 3C of development, completed late in 2005, modified two existing platforms and installed a new well platform and a desulphurization platform. Production from phase 3E, launched early in 2005 to create three well platforms, began mid-February 2007. A new development phase, 3F, for three new well platforms was launched early in 2006. Production from this phase of development is planned to begin mid-2008.

Early in 2007, three new gas discoveries, Ton Chan-1X, Ton Chan-2X and Ton Rang-2X on Blocks 15 and 16 of the Bongkot field confirmed the Group’s interest in this concession. The development plan for these three new discoveries is being prepared, with production anticipated for as early as 2009.

Commonwealth of Independent States (CIS)

TOTAL’s production for 2006 was 8 kboe/d, accounting for 0.3% of the Group’s overall production. Production in 2004 and 2005 came entirely from Russia and amounted to 9 kboe/d for each year. Highlights for 2006 included the start-up of the Shah Deniz project in Azerbaijan.

Azerbaijan

TOTAL’s presence in Azerbaijan dates back to 1996 and is centered on the Shah Deniz field (10%). After phase 1 of development of this gas and condensate field was launched in 2003, production from the first well began in December 2006. The first gas sales to Azerbaijan were made late in 2006.

The South Caucasus Pipeline Company (SCPC), in which TOTAL holds a 10% interest, completed the construction of a gas pipeline to transport gas from Shah Deniz to the Turkish and Georgian markets. This gas pipeline was gradually brought onstream and became operational in November 2006.

Construction of the 1,770 km BTC (Baku-Tbilissi-Ceyhan) oil pipeline, with an operating capacity of 1 Mb/d, began in August 2002 and was completed in 2006. This pipeline, owned by BTC Co. (in which TOTAL has a 5% interest), links Baku to the Mediterranean Sea. The first delivery to Ceyhan (Turkey) was made in June 2006.

Kazakhstan

TOTAL has been present in Kazakhstan since 1992, where it is a partner on the North Caspian Sea permit which contains the Kashagan field. TOTAL holds an 18.52% interest in this permit after closing the sale of 1.85% to KazMunayGas, the state-owned company of the Republic of Kazakhstan, in April 2005.

The Kazakh authorities approved the development plan for this field in February 2004, allowing work to be done on the first of several successive phases of development. Infrastructure and civil engineering work has accelerated and most of the major contracts regarding the manufacture and construction of both onshore and offshore facilities have been awarded. The facilities are currently being evaluated to optimize their dependability while improving safety. Drilling of development wells was launched in 2004 and continued in 2005 and 2006, with production now scheduled to begin near the end of 2010. The size of the Kashagan field may eventually allow production to be increased to more than 1 Mb/d (in 100%).

The North Caspian permit includes other structures that are smaller than Kashagan: Aktote, Kairan, Kalamkas and Kashagan Southwest. These structures are in the appraisal phase. The first appraisal well on the Aktote structure, drilled in 2004, confirmed and helped to define this discovery. Appraisal operations continued in 2005, with the completion of a 3D seismic acquisition on the Aktote and Kairan zones as well as the drilling of the Kalamkas 2 well. In 2006, two new appraisal wells were drilled on Kalamkas and Kairan. The Kalamkas-3 well was positive and the results for the Kairan 2 well are being evaluated. A long-duration test is expected to start on Kairan 2 during the first half 2007.

Russia

TOTAL has been present in Russia since 1989. The Group’s principal activity is on the Kharyaga field (50%, operator) in the Nenets territory. The Group’s production was 8 kboe/d in 2006, compared to 9 kboe/d in 2005 and 2004.

On the Kharyaga field, phase 2 of development was completed in 2005, targeting a production plateau of 30 kboe/d (in 100%). Pre-project studies for phase 3 were carried out in 2006. Late in 2005, TOTAL and the Russian Federation reached an amicable agreement to resolve a dispute over the interpretation of the production sharing agreement. As a result, the request for arbitration in Stockholm was withdrawn. In 2006, the production sharing contract was implemented normally, with profit oil being shared among the state and investors.

The preliminary technical results from the Russian Black Sea partnership led the Group to withdraw from the Shatsky permit in 2004 and the Tuapse permits in 2005.

In 2004, the Group entered into negotiations to acquire 25% of Novatek, the country’s second leading gas producer. The transaction was not completed as the required approval from the authorities was not obtained. In 2005, TOTAL was pre-selected by Gazprom, along with four other foreign companies, to potentially participate in the giant Shtokman gas production project in the Barents Sea. In October 2006, Gazprom announced that the project would not proceed under the proposed contractual framework, since the Russian Federation no longer wished to share acreage with independent oil companies. Other contractual arrangements are being studied for this project.

Europe

TOTAL’s production in Europe amounted to 728 kboe/d in 2006, representing 31% of the Group’s overall production. Highlights of the period from 2004 to 2006 include start-up of the Skime, Kvitebjørn and Kristin fields in Norway, an increase in the Group’s interest in the PL211 license (Victoria), new developments on existing fields (Ekofisk Area Growth, structure J and West Flank of Oseberg, and the North Flank of Valhall) and the approval by the Norwegian Parliament of the Tyrihans development plan. In the UK, satellites of the Alwyn (Forvie North, Nuggets N4) and Elgin-Franklin (Glenelg) facilities began production. In both the UK and Norway, several discoveries (including Jura West in the UK) were made and new exploration licenses awarded. In Italy, TOTAL signed an agreement with the Basilicate region to start developing the Tempa Rossa field.

France

The Group has operated fields in France since 1939, with its most significant activity being the development and operation of the Lacq gas field, which began in 1957.

The Group’s principal natural gas fields, Lacq (100%) and Meillon (100%), located in southwest France, and several smaller natural gas and oil fields in the same region as well as in the Paris Basin, produced 30 kboe/d in 2006, compared to 29 kboe/d in 2005 and 35 kboe/d in 2004.

The Lacq 2005 project, which is focused on reinforcing industrial safety standards and optimizing gas processing procedures at the Lacq and Meillon fields, was successfully completed in 2005. Under the simplified treatment method, the gas treatment unit now delivers commercial gas, a liquid naphtha cut, condensates and liquid sulfur.

After conducting an initial pilot test in 2006 on the SPREX process (de-acidifying gas by using cryogenics), a pilot program for capturing and injecting carbon dioxide is being studied. This program would modify a gas burning plant to operate in an oxy-combustion environment and the carbon dioxide produced would be re-injected in a depleted field. This program could begin operation in 2008.

The restoration of certain sites and the re-industrialization of the Lacq platform are ongoing. Construction of a bio-ethanol unit by Agengoa Bioenergy began in 2006.

Italy

The Tempa Rossa field, discovered in 1989, is TOTAL’s principal asset. It is located on the unitized Gorgoglione concession in the southern Apennins, in the Basilicate region.

In 2002, TOTAL’s share in this concession increased from 25% to 50% as the operator of the development phase sold its interest. TOTAL is now the operator for all phases of the Tempa Rossa project.

A preliminary agreement was reached with the Basilicate region in 2004. This initial agreement was the basis for the final agreement (Accordo Quadro) signed between the Basilicate region, TOTAL, and the other partners in September 2006. This agreement, combined with the approval of the development plan proposed by the Basilicate region in May 2006 allows development of the field to begin.

In 2006, bids for the main purchasing and construction contracts were evaluated, and contracts may be awarded once the project is approved.

Prior to this, partners asked for the crude transport arrangements to be formalized. Discussions are ongoing with the operator of the Val d’Agri-Tarente pipeline and the operator of the Tarente refinery. This could lead to the signature of a preliminary agreement in the first half 2007.

Start-up of production is scheduled for 2010, with a plateau rate of 50 kb/d.

TOTAL has interests in other exploration permits in the southern Apennins region: Teana (80%, operator), Aliano (60%, operator), Fosso Valdienna (31.7%), Serra San Bernardo (10%) and Tempa Moliano (31.7%).

The Netherlands

TOTAL has been present in the Netherlands for more than forty years, where it is the second largest gas operator. The Group’s share of production amounted to 44 kboe/d in 2006, compared to 51 kboe/d in 2005 and 59 kboe/d in 2004.

TOTAL holds 22 offshore production permits, of which 18 are operated by the Group, two operated offshore exploration permits and one onshore exploration permit. TOTAL sold certain onshore assets in 2004 (including the Zuidwal and Leeuwarden concessions) in an effort to streamline its portfolio. The remaining production assets operated onshore were sold in January 2005. The Lemmer Marknesse exploration permit was also relinquished in March 2006.

Several development wells were drilled over the past three years. During this period, the first phase in the reorganization of Block L7 was launched, along with major maintenance work. The L4G structure, developed in 2005 and 2006, began production in August 2006. The development of structure K5F was approved, with production scheduled to begin early in 2008.

TOTAL’s principal operated offshore fields, K1, K4/K5, K6, and L4/L7, contributed 80% of the Group’s Dutch production in 2004, 2005, and 2006.

TOTAL also holds interests in the Dutch offshore transport network (NOGAT, WGT, and the WGT extension).

Late in 2006, the Group was awarded a new exploration permit covering offshore Block L3.

Three development wells were drilled in 2005: K5-EC-5 and K4-BE-4 (two very-long offset wells), and L4-G (a re-entry well). At the same time, the diversion of the gas evacuated from the K6-GT platform, in anticipation of the future redevelopment of Zone K6/L7, was completed.

In 2006, the K4-A5 well was drilled and began production. The F15-A6 well was drilled and is in the process of being connected.

Major maintenance work was carried out in 2005 and 2006 on the K6 facilities, with the support of the Seafox self-elevating platform.

The Luttelgeest exploration well was drilled in 2004. The F12-4 exploration well was drilled in 2005 and 2006. The Zuidwal A-10 appraisal well was drilled in 2004 and 2005.

Norway

Since the late sixties, the Group has played a major role in the development of a large number of fields in the Norwegian North Sea. TOTAL holds interests in 66 production permits on the Norwegian continental shelf, ten of which it operates. Norway is the largest contributor to the Group’s production, with an average of 372 kboe/d in 2006, compared to 383 kboe/d in 2005 and 406 kboe/d in 2004.

The largest contribution to this production, for the most part non-operated, comes from the Ekofisk area (39.9%) in southern Norway, which accounts for approximately 45% of the Group’s production in the country. This area is made up of four producing fields with a combined average production of 169 kboe/d for 2006. The Ekofisk Area Growth project (EAG) to install a new platform and drill a series of wells, began in October 2005 and contributed to 2006 production, although the project encountered certain delays and technical difficulties.

TOTAL operates the Skirne/Byggve gas and condensates field (40%), which accounts for 3% of the Group’s production in Norway. The Frigg field (77%, operator) was closed in October 2004 after 27 years in production. TOTAL is leading a significant multi-year decommissioning and site restoration program at this site.

The Oseberg area (10%) in the central North Sea accounts for slightly over 9% of the subsidiary’s production and consists of several platforms and projects, including structure J, which began production in June 2005, the West Flank oil field, which began production in February 2006, and the Tune gas field, in production since 2002.

The Sleipner area (West 9.4% and East 10%) including Glitne (21.8%), also in the central North Sea, represents nearly 9% of production in the country, while the Troll (3.7%) oil and gas field contributes 7.5%. Among other significant non-operated producing fields are those located in the Tampen area, including Snorre (6.2%) and Visund (7.7%), which started gas production in October 2005 (six years after oil production began). The Valhall area (including Valhall 15.7%) and Kvitebjørn (5%) started production in October 2004.

The sub-sea development of the Vilje oil field (24.2%) and the innovative development of Tordis IOR (5.6%) in the Tampen area in the North Sea are underway. Production is scheduled to begin in 2007.

3D seismic OBC (ocean bottom cable) work was performed in 2005-2006 in the northern zone of the North Sea on the Hild discovery, which the Group operates and on the Kvitebjørn gas field (PL193). A new 3D seismic was completed on the zone covering Tommeliten Alpha (PL044).

On the Haltenbanken area, in the Norwegian Sea, the Åsgard oil field (7.7%) contributes 7.5% of the Group’s production and Kristin (6%), the sub-sea high-pressure/high-temperature field, began production in November 2005. In February 2006, the development of the Tyrihans oil, gas and condensates field (23.2%) was approved by the authorities. Production is scheduled to begin in

2009, with an initial estimated plateau rate of 70 kboe/d (in 100%), to be reached in 2011.

In 2006, TOTAL increased its interest in the PL211 license (in the Haltenbanken area) to 40% and became its operator. This license covers the Victoria discovery, which is not yet developed. The Group also disposed of a 3.3% interest in the Tyrihans field. As a result, the Group now has a 23.2% interest in this field.

In the Barents Sea, the Group is involved in the Snøhvit project, which includes the development of the Snøhvit natural gas field (18.4%) and the construction of liquefaction facilities on Melkoya Island. Production is expected to begin in the third quarter of 2007, with a ramp-up over several months.

TOTAL has an 8.1% interest in the Norwegian dry gas transport system, Gassled, after taking into account the incorporation of the new Langeled pipeline toward the UK.

The Group participated in all of the recent licensing rounds and acquired several exploration permits. In June 2004, TOTAL acquired a 40% interest, as operator, in Blocks 6406/7 and 8 (including, in particular, the Hans prospect) in the Haltenbanken zone. In 2006, during the 19^th licensing round, TOTAL also acquired two additional licenses in the Haltenbanken zone, including one which the Group operates (PL389, 100%).

In January 2006, TOTAL was awarded the four blocks (two operated, two non-operated) it had requested in the APA2005 (Awards in Predefined Areas) licensing campaign. Of the two operated blocks, one (PL041C, 49%) is located near the Hild discovery and the other (PL379, 100%) in the Haltenbanken area, south of the Onyx zone. The Onyx SW well discovered hydrocarbons in 2005. TOTAL also tendered for and obtained the Victoria South extension in the APA2006 campaign, which it will operate on behalf of the PL211 association with a 40% interest.

The Group disposed of its share in Enoch (PL048) in 2005 and its share in Peik (PL088), which is partially located in the UK, in the first quarter 2007.

Various exploration and appraisal projects were performed under several permits in 2005 and 2006, including the Onyx SW discovery (PL255) in 2005 and the successful Tornerose (PL110 B), Morvin (PL 134B) and Kvitebjørn-Valemon (PL193) appraisals in 2006.

The government changed the tax treatment of net financial interests, effective as of January 1, 2007.

United Kingdom

TOTAL has been present in the UK since 1962. The Group’s production amounted to 282 kboe/d in 2006, down from 307 kboe/d in 2005 and 332 kboe/d in 2004. The UK contributes approximately 12% of the Group’s oil and gas production, coming principally from three major zones: Alwyn, Elgin-Franklin and Bruce.

The Elgin-Franklin zone, which has been in production since 2001, has made a significant contribution to the Group’s activities in the UK. This project, one of the largest investments made in the British North Sea in the past twenty years, constituted a technical milestone, combining the development of the deepest reservoirs in the North Sea (5,500 m) with temperature and pressure conditions among the highest in the world.

In 2007, TOTAL obtained two permits as operator (Blocks 206/3 and 206/4, 36%) west of the Shetland Islands and another permit (Block 3/8f, 100%) north of Dunbar from the 24^th licensing round launched by the UK Department of Trade & Industry.

In 2005, TOTAL acquired the right to obtain a 25% interest in two zones located near Elgin-Franklin by drilling an appraisal well on the Kessog structure. Drilling began near the end of 2006. Depending on the results of this appraisal well, TOTAL has an option to increase its interest in these zones (Blocks 30/1b and 30/1c) to 50%.

The Forvie Central well discovered small oil and gas columns. The Jura West well (Block 3/15) discovered gas on more than 300 meters of Brent quality reservoirs and is believed to be a significant discovery. This well is expected to be connected to the Forvie North sub-sea collector, which is connected to the NAB processing platform on the Alwyn North field. Production is expected to begin in 2008.

TOTAL disposed of its share in Peik (PL088), which is partially located in Norway, in the first quarter 2007.

Development of the Elgin (Glenelg – 49.5%, operator) and Franklin (West Franklin – 46.2%, operator) satellites began in 2005, with the drilling of the Glenelg long-offset well, which reached its final depth late in 2005. Both wells have been completed. The Glenelg well began production in March 2006. Production from the West Franklin well, which was drilled in 2006, is expected to start in the second quarter of 2007.

The development of the Maria field (Block 16/29a) is continuing, with production scheduled to begin in the second half 2007.

In December 2005, the UK Department of Trade & Industry and the Norwegian Ministry of Petroleum approved the removal of the surface modules from the

MCP01 platform. Work on this multi-year program to decommission the Frigg facilities and restore the site continues.

Late in 2005, the British government decided to increase the Supplementary Corporation Tax on oil and gas operations. As a result, the Corporation Tax (CT) increased from 40% to 50%. For fields subject to the Petroleum Revenue Tax, the overall tax burden increased from 70% to 75%. This tax increase, which was adopted mid-2006, became effective at the beginning of 2006.

Middle East

TOTAL has been developing long-term partnerships in the Middle East for eighty years. TOTAL’s 2006 share of production in the Middle East (including the production of equity affiliates and unconsolidated subsidiaries) increased by 2% compared to 2005, primarily due to the increase in production from the United Arab Emirates. It reached 406 kboe/d in 2006 (representing 17% of the Group’s overall production), compared to 398 kboe/d in 2005 and 412 kboe/d in 2004. Between 2003 and 2006, TOTAL has developed its LNG activities, launching the Yemen LNG project and acquiring an interest in the Qatargas II project.

Iran

TOTAL signed the first buyback contract for the development of the Sirri A&E fields in 1995. The Group’s production amounted to 20 kb/d in 2006, down from 2005 (23 kb/d) and 2004 (26 kb/d), due principally to both the effect of the increase in oil prices and the end of reimbursement for certain buyback contracts (Balal and Sirri). The Group’s share of production comes from four buyback contracts, on the Sirri, South Pars, Balal, and Dorood fields.

The Sirri A&E fields (60% interest in foreign consortium) have been operated by the state-owned National Iranian Oil Company (NIOC) since 2001. The Group’s reimbursement under this contract should be completed in 2007, as the final amounts due by NIOC were agreed upon late in 2006.

Average production (in 100%) from phases 2 and 3 of the offshore South Pars gas and condensate field (40% interest in foreign consortium) was slightly less than 2,000 Mcf/d and 90 kboe/d in 2006, equal to production in 2005 but down from 2004, due to major maintenance work that began in 2005, continued in 2006 and is now complete. Production operations have been conducted by NIOC since 2004.

The development of the Balal offshore oil field (through a 46.8% interest in a foreign consortium) was completed, and the facilities were transferred to NIOC in 2004.

The development of the Dorood field (through a 55% interest in a foreign consortium) is nearly completed, with the additional adjustment work needed following start-up underway.

In 2004, TOTAL signed several agreements with its partners creating the framework for the Pars LNG liquefied natural gas future project and its principal commercial terms. These agreements outline the relationship between the Pars LNG plant (40%), in charge of the liquefaction activities, and Block 11 of South Pars (80%), expected to supply gas to the liquefaction plant. The project calls for the initial construction of two trains, each with a capacity of 5 Mt/y of LNG, to be followed by the construction of a third train with the same capacity. It is expected that the purchasers of LNG from the project will also become partners in the project.

Pursuant to the agreed framework, engineering studies for the natural gas liquefaction plant and the development of Block 11 of South Pars were launched in 2005 and the bidding process to award the principal supply and construction contracts began in July 2006.

Kuwait

Since 1997, the Group has been providing technical assistance for the upstream activities of state-owned Kuwait Oil Company (KOC) under an agreement renewed late in 2006.

The Group also holds a 20% interest in the consortium formed to participate in the bidding process opened to international oil companies for production activities on oil fields in northern Kuwait.

Oman

TOTAL is present in Oman on Blocks 6 and 53, and in the Oman LNG/Qalhat LNG gas liquefaction plant. Production averaged 35 kboe/d in 2006, compared to 36 kboe/d in 2005 and 40 kboe/d in 2004.

On Block 6, operated by Petroleum Development Oman (PDO), in which TOTAL holds a 4% interest, oil production (in 100%) averaged 589 kb/d in 2006, down from 631 kb/d in 2005.

Development of the Mukhaizna heavy oil field on Block 53 (2%) was launched in 2006 pursuant to the production sharing contract signed in 2005. Production for 2006 averaged 9.5 kb/d (in 100%).

The two liquefaction trains of Oman LNG (5.54%) produced 6.7 Mt in 2006. The third liquefaction train, commissioned late in 2005 and owned by a new company, Qalhat LNG, produced 2.2 Mt in 2006 (2.04%, Group interest through Oman LNG).

Qatar

TOTAL has been present in Qatar since 1936 and holds interests in the Al Khalij field, the North field, the Dolphin project, the Qatargas I liquefaction plant and the second train of Qatargas II. TOTAL’s production in Qatar (including its share in the production of equity affiliates) averaged 58 kboe/d in 2006, compared to 57 kboe/d in 2005 and 2004.

After the third phase of development on the North zone was completed on the Al Khalij field (100%) in 2004, efforts to maintain production contributed to production of 42 kb/d (in 100%) in 2006.

TOTAL holds a 20% interest in the upstream operations of Qatargas I, which produces natural gas and condensates on a block in the North field. The Group also owns a 10% interest in the Qatargas I liquefaction plant. A debottlenecking project was completed in June 2005, raising the production capacity for the three trains to nearly 10 Mt/y. Production in 2006 reached 9.9 Mt, compared to 9 Mt in 2005.

In December 2001, the Group signed a contract with state-owned Qatar Petroleum providing for the sale of 2,000 Mcf/d of gas from the North field, produced by the Dolphin project (24.5%), for a 25-year period. This gas is expected to be transported to the United Arab Emirates through a 360 km gas pipeline. The final development plan was approved in December 2003 by the Qatari authorities and the construction contracts were awarded in 2004. Construction progressed on both the Ras Laffan Industrial City site and the offshore section. Production is scheduled to begin in the summer of 2007.

In February 2005, TOTAL signed a memorandum of understanding to acquire a 16.7% interest in the second train of Qatargas II. This integrated project intends to develop two new LNG trains, each with an annual capacity of 7.8 Mt. In July 2006, TOTAL signed four contracts to purchase 5.2 Mt/y of LNG on behalf of the Group. In December 2006, TOTAL formalized its acquisition of the 16.7% in the second train of Qatargas II. The project is scheduled to begin operations in the winter of 2008/2009.

In July 2005, TOTAL announced a project to locate a Research Center in the Qatari Scientific and Technical Complex, which is expected to be completed in 2007.

Saudi Arabia

TOTAL has a 30% interest in a joint venture with state-owned Saudi Aramco for natural gas exploration in a 200,000 km² area in southern Rub Al-Khali. An initial five-year period of work began in January 2004. A 137,800 km² gravimetric survey was performed in 2004.

An 18,250 km 2D seismic campaign, launched in 2004 on the same site, continued in 2005 before being completed late in 2006. A drilling rig was mobilized mid-2006 and the first exploration well was completed without encountering producible hyrdocarbons.

Syria

TOTAL has been present in Syria since 1988 and is the operator of nearly 10% of the country’s production.

The Deir Ez Zor permit (100%, operated by DEZPC, 50% of which is held by TOTAL) is the Group’s only remaining asset in Syria since the expiration of the BOT (build, operate, transfer) contract for the Deir Ez Zor gas and condensates reprocessing plant (50%) whose facilities were transferred to state-owned SGC (Syrian Gas Company) on January 1, 2006.

In 2006, the Group’s production from the Deir Ez Zor permit was 17 kboe/d, down from that in 2005. The decline of this field is being mitigated by a campaign of additional drilling on the principal fields, Jafra and Qahar, and by the start-up of oil production on the Tabiyeh field.

United Arab Emirates

TOTAL’s activities in the United Arab Emirates are located in Abu Dhabi and Dubai, where the Group’s presence dates back to 1939 and 1954, respectively. TOTAL’s production in 2006 reached 267 kboe/d, compared to 249 kboe/d in 2005, and 246 kboe/d in 2004.

In Abu Dhabi, TOTAL holds a 75% interest (operator) in the Abu Al Bu Khoosh field. TOTAL is also a 9.5% shareholder in the Abu Dhabi Company for Onshore Oil Operations (ADCO), which operates the Asab, Bab, Bu Hasa, Sahil and Shah onshore fields, as well as a 13.3% shareholder in Abu Dhabi Marine (ADMA), which operates the Umm Shaif and Lower Zakum offshore fields.

TOTAL holds a 15% interest in Abu Dhabi Gas Industries (GASCO), a company that produces butane, propane, and condensates from the associated gases produced by onshore fields. TOTAL also holds 5% of the Abu Dhabi Gas Liquefaction Company (ADGAS), a company that produces LNG, LPG, and condensates from the natural gas produced by offshore fields.

The Group also has a 33.3% interest in Ruwais Fertilizer Industries (FERTIL), which produces ammonia and urea from methane supplied by the Abu Dhabi National Oil Company (ADNOC).

In Dubai, TOTAL holds a 27.5% interest in the Fateh, Falah and Rashid fields through the combination of its 50% interest in Dubai Marine Areas Limited (DUMA, which holds 50% of the concession offshore Dubai), and its 2.5% interest held directly by Total E&P Dubai. An agreement was reached to relinquish this concession at the beginning of April 2007.

TOTAL is also a shareholder (24.5%) in Dolphin Energy Limited, which is expected, in the summer of 2007, to begin the United Arab Emirates marketing of the natural gas produced by the Dolphin project in Qatar. Natural gas sales agreements for this project were signed in 2003 and 2005, and the Qatari authorities approved the final development plan in December 2003.

Yemen

TOTAL has been present in Yemen since 1987 and operates approximately 10% of the country’s production. The Group has interests in the country’s two oil basins, as the operator on Block 10 (Masila Basin, East Shabwa permit 28.57%) and as a partner on Block 5 (Marib Basin, Jannah permit 15%).

A new production record was set in 2006 on the East Shabwa permit, with 40 kb/d (in 100%), 25 kb/d of which came from the “basement” zone, whose development was launched in 2003. Production increased 21% compared to 2005, and 66% compared to 2004. Development of the basement is expected to continue through 2007 and 2008 in order to take full advantage of this discovery.

TOTAL’s production also comes from its share in the Jannah permit, where production averaged 45 kb/d (in 100%) in 2006, stable compared to the previous years.

The Yemen LNG liquefied natural gas project, operated by Yemen LNG, a company in which TOTAL (39.62%) is the principal shareholder, was officially launched in August 2005. This project calls for the construction of two liquefaction trains with a combined capacity of 6.9 Mt/y. Operations are expected to begin late in 2008.

Yemen LNG signed three long-term LNG sales contracts in 2005, one each with Total Gas & Power Ltd (2 Mt/y) and with Suez (2.5 Mt/y) for deliveries to the United States over a 20-year period to begin in 2009, and the third with Kogas (2 Mt/y) to be delivered to South Korea, also for a 20-year period.

North America

Since 2004, TOTAL has strengthened its position in Canadian oil sands by increasing its share in the Surmont permit and acquiring Deer Creek Energy Ltd. The first phase of Deer Creek Energy’s Joslyn project began production in November 2006. In

November 2005, TOTAL signed an agreement to exchange four mature onshore fields in South Texas for a 17% stake in the deep-offshore Tahiti field in the Gulf of Mexico, which is scheduled to begin production in mid-2008. In 2006, two successful wells were drilled on the Alaminos Canyon 856 permit. Production for the year 2006 amounted to 16 kboe/d, less than 1% of the Group’s total production. The Group’s production in North America decreased from 61 kboe/d in 2004 to 41 kboe/d in 2005, principally due to shutdowns related to hurricane damage in the Gulf of Mexico.

Canada

In Canada, the Group is participating in oil sands projects in Athabasca, Alberta. The Surmont (50%) and Joslyn permits are its principal assets. Deer Creek Energy Ltd, acquired in 2005, operates the Joslyn permit, with an 84% interest.

In 1999, TOTAL began participating in a pilot project on the Surmont permit in Athabasca to extract bitumen using Steam Assisted Gravity Drainage (SAGD). In December 2003, the partners approved the first phase of development, with a planned capacity of 27 kb/d of bitumen (in 100%). Engineering and construction activities are ongoing. Production is expected to begin in the summer of 2007. TOTAL had an interest of 43.5% in the project as of December 2002, and increased this interest to 50% in April 2005. In August 2005, TOTAL acquired 50% of the OSL 001 permit, immediately to the north of Surmont. And in November 2005, TOTAL also acquired 50% of the OSL 006 permit, immediately to the south of Surmont. These two permits have now been included in the Surmont project.

In 2005, TOTAL acquired 83% of Deer Creek Energy Ltd (which holds 84% of the Joslyn permit) through a public tender launched in August. TOTAL acquired the remaining 17% of Deer Creek Energy Ltd through a squeeze-out procedure. Certain minority shareholders are contesting in local courts the compensation they were awarded through this procedure. The Joslyn permit, located approximately 140 km north of Surmont, will principally (approximately 90%) be developed using mining techniques. The Joslyn project is expected to be developed in several phases. The first phase, using SAGD, began production in November 2006. The mining development phases are scheduled to begin in 2013, with a planned initial production plateau of 100 kb/d anticipated to be increased to 200 kb/d in a subsequent phase. It is estimated that the combined production from the entire project will amount to approximately two billion barrels of bitumen over a 30-year period.

In December 2004, TOTAL acquired 100% of the OSL 874 permit located about 40 km west of Surmont. In August 2005, it acquired 100% of the OSL 354 permit

located about 50 km north of Joslyn. In January 2006, it acquired 100% of the OSP 674 permit. And in September 2006, TOTAL acquired 100% of the OSL 457 (located near the OSP 674 permit) and OSL 841 permits (located 30 km north of the OSL 354 permit).

In July 2004, TOTAL acquired a 40% interest in three exploration permits located in the Akue area in northeastern British Columbia.

Mexico

TOTAL is conducting various studies in cooperation with Mexico’s state-owned PEMEX under a technical cooperation agreement signed in December 2003.

United States

TOTAL has been present in the United States since 1957. In 2006, the Group’s production decreased to 15 kboe/d, compared to 41 kboe/d in 2005 and 61 kboe/d in 2004. Production in 2006 came principally from three deep-offshore fields in the Gulf of Mexico: Virgo (64%, operator), Aconcagua (50%, operator) and Matterhorn (100%, operator).

Production from these fields was affected by Hurricane Katrina in 2005. Production on Matterhorn was shut down from August 2005 to August 2006 and production on Virgo was shut down from August 2005 to May 2006.

In November 2005, TOTAL signed an agreement to exchange four onshore fields in southern Texas for a 17% stake in the deep-offshore Tahiti field in the Gulf of Mexico. Tahiti is scheduled to begin production mid-2008, with an anticipated production capacity (in 100%) of 125 kb/d and 70 Mcf/d. This transaction closed in January 2006.

In February 2006, the Group signed and closed an agreement to sell two mature fields, Bethany and Maben, located, respectively, in eastern Texas and in Mississippi.

In August 2006, TOTAL increased its interest in the Chinook project from 15% to 33.33%. Development plans for this project are currently being discussed.

In December 2006, TOTAL signed an agreement to sell its interests in the Aconcagua and Camden Hills fields, as well as its interest in the Canyon Express System (25.8%, operator). This transaction closed in January 2007.

In 2006, two successful wells were drilled on the Alaminos Canyon 856 permit (70%, operator), confirming the extension of the Great White field.

In 2006, TOTAL was also awarded 27 new deep-offshore blocks (Keathley and Garden Banks) after bidding in Louisiana and Texas.

South America

The Group’s production in South America in 2006 amounted to 226 kboe/d, compared to 247 kboe/d in 2005 and 213 kboe/d in 2004. South America accounted for approximately 10% of the Group’s overall production for 2006. Carina in Argentina began production in 2005 and Yucal Placer in Venezuela began production in 2004. The Group is involved in ongoing discussions with Venezuelan authorities regarding legal and tax changes in the country. TOTAL’s acquisition of a 49% interest in the offshore exploration Block 4 of the Plataforma Deltana was formally approved by the Venezuelan authorities in January 2006. In Colombia in 2006, the Group agreed to acquire 50% of the Niscota exploration block. In Bolivia, TOTAL signed new exploration-production contracts with the Bolivian government and increased its interest in Block XX West (operator) to 75%.

Argentina

TOTAL has been present in Argentina since 1978 and operates approximately 25% of the country’s gas production. In 2006, TOTAL produced 78 kboe/d, a 5% increase compared to 2005 (74 kboe/d). Production increased by 6% in 2005 compared to 2004 (70 kboe/d).

TOTAL holds interests in Argentina’s two major basins: Neuquén (the San Roque and Aguada Pichana fields) and Tierra del Fuego (notably Carina and Canadon-Alfa).

In 2005, TOTAL acquired interests in two new exploration blocks in the Neuquén Basin: Las Tacanas (50%, operator) and Chasquivil (50%, operator).

On the San Roque field (24.7%, operator), a medium-pressure compression project launched in 2003 was commissioned in August 2006. The development of the Rincon Chico North discovery and the low-pressure compression project were launched in January 2006, with production scheduled to begin in February 2008 and May 2008, respectively. These projects are expected to extend the field’s production plateau.

On the Aguada Pichana field (27.3%, operator), a low-pressure compression project was launched in 2005 and is expected to begin operations in June 2007. Development of the first phase of the Aguada Pichana North discovery was launched in September 2006 and production is scheduled to begin in March 2008. These projects are expected to extend the field’s production plateau.

In the Austral Basin, the Group continued to develop the Carina-Aries project offshore Tierra del Fuego (37.5%, operator). The project was reactivated in 2003 and

offshore infrastructure construction was completed in 2004 while onshore infrastructure construction was completed in 2005. Drilling of the first wells on Carina was completed in 2005 and drilling of wells on Aries was completed in January 2006. The Carina field came onstream in June 2005 while the Aries field started production in January 2006. A fourth medium-pressure compressor is expected to start-up in August 2007 to debottleneck the facilities and to increase the capacity to inject gas from the Tierra del Fuego basin into the San Martin gas pipeline from 12 Mm³/d to 15 Mm³/d.

Bolivia

TOTAL holds six permits in Bolivia: San Alberto and San Antonio, both in production (15%) and four permits in the exploration or appraisal phase: Blocks XX West (75%, operator), Aquio and Ipati (80%, operator) and Rio Hondo (50%). In October 2006, TOTAL acquired an additional 34% of Block XX West, adding to the 41% interest it already held.

In 2006, the Group’s production remained stable at 21 kboe/d, the same as in 2005, compared to 18 kboe/d in 2004.

The San Alberto and San Antonio fields have been in production since 2001 and 2003, respectively. TOTAL is also a partner with Transierra (11%), operator of the Gasyrg gas pipeline, in service since 2003, and owns 9% of the Rio Grande compression station.

A successful exploration well, Incahuasi X1, was drilled on the Ipati block in 2004.

Pursuant to the decree of May 1, 2006 regarding the nationalization of hydrocarbons, TOTAL signed six new exploration and production contracts in October 2006 for all blocks in which it has an interest. Although these contracts were approved by the Bolivian legislature on December 3, 2006, they will not become effective until an additional legislative ratification has been completed.

The new contracts retain certain terms from production sharing agreements while providing for a 50% production tax and profit sharing between YPFB (Yacimientos Petroliferos Fiscales Bolivianos, the state-owned Bolivian oil company) and the foreign partner, after reimbursement of investments and costs.

Brazil

In 2005, TOTAL increased its interest in the Curio discovery zone on Block BC2 from 35% to 41.2%.

In June 2005, Petrobras became the operator of Curio. An additional appraisal period of one year was obtained, with the obligation to drill one well in 2007.

Colombia

TOTAL holds a 19% interest in the Cusiana and Cupiagua fields, where the Group’s share of production reached 22 kboe/d in 2006, compared to 26 kboe/d in 2005 and 30 kboe/d in 2004.

In order to renew the Group’s exploration acreage in Colombia, TOTAL relinquished the Tangara permit late in 2006. An agreement to acquire 50% of the Niscota exploration block was concluded in September 2006.

Trinidad & Tobago

TOTAL holds a 30% interest in Block 2C (Grand Angostura field) where production amounted to 9 kboe/d in 2006, compared to 13 kboe/d in 2005. TOTAL also has an 8.5% share in the adjacent Block 3A, where an oil discovery (Ruby-1) was under evaluation early in 2007.

Venezuela

TOTAL has been present in Venezuela since 1980 and is one of the main partners of PDVSA (Petróleos de Venezuela S.A.), a state-owned company, in particular for oil production in the Orinoco Basin.

The Group holds interests in the Sincor (47%) and Yucal Placer (69.5%) projects as well as in the offshore exploration Block 4 of the Plataforma Deltana (49%). TOTAL’s average production amounted to 96 kboe/d in 2006, 113 kboe/d in 2005, and 95 kboe/d in 2004.

Late in 2004, work undertaken during the first major maintenance shutdown on Sincor’s upgrader, which started operations in March 2002, increased its treatment capacity to more than 200 kb/d of extra heavy oil. Drilling operations resumed in October 2005 and intensified in 2006 with four drilling rigs.

On the Yucal Placer field, the initial production phase of 120 Mcf/d, which began in 2004, is producing results in line with projections. Development studies to increase production to 300 Mcf/d are underway.

TOTAL’s acquisition of a 49% interest in the offshore exploration Block 4 of the Plataforma Deltana was officially approved by authorities in January 2006. This interest may be reduced subsequently should the state- owned PDVSA choose to exercise its 35% option on the block.

On March 31, 2006, the Venezuelan government terminated all operating contracts signed in the 1990s and decided to transfer the management of fields concerned to new mixed companies to be created with the state-owned company PDVSA (Petroleos de Venezuela S.A.) as the majority owner. The government and the Group did not reach an agreement on the terms of the transfer of the Jusepin field under the initial timetable. However, subsequent negotiations have led to a settlement, announced in March 2007, under which the government has committed to pay the Group $137.5 million.

The Venezuelan government has modified the initial agreement for the Sincor project several times. In May 2006, the hydrocarbons law was amended with immediate effect to establish a new extraction tax, calculated on the same basis as for royalties, and bringing the overall tax rate to 33.33%. In September 2006, the corporate income tax was modified to increase the rate on oil activities (excluding natural gas) to 50%. This new tax rate will come into effect in 2007.

The government has also expressed its intention to apply this law to the “Strategic Associations” which operate the extra-heavy oil projects in the Orinoco region. On January 18, 2007, the Venezuelan National Assembly appoved a law granting, for an 18-month period, the Venezuelan president the power to govern by decree in various subjects, in particular regarding hydrocarbons. On February 26, 2007, the Venezuelan president signed a decree providing for the transformation of the Strategic Associations from the Faja region, including the Sincor project, into mixed companies with the government having a minimum interest of 60%. The legislation further states that operations must be transferred to the PDVSA companies no later than April 30, 2007 and sets a four-month period (with an additional two months for approval by the National Assembly), from the date of the decree, for private companies to agree to the terms and conditions of their participation in the newly created mixed companies. Discussions with the Venezuelan government regarding the Sincor project are underway.

In 2006, the Group received two corporation tax adjustment notices. The first concerned the company holding the Group’s interest in the Jusepin operating contract, for which the 2001-2004 examination was closed in the first half 2006, whereas the examination for 2005 is still under way. The second is related to the company which holds the Group’s interest in the Sincor project, for which the Group is awaiting a response from the tax authorities regarding the observations provided by the Group concerning 2001.

Interests in pipelines

The table below sets forth TOTAL’s interests in crude oil and natural gas pipelines throughout the world:

As of December 31, 2006
Pipeline(s)

Origin

Destination

%
interest

TOTAL
operator

Liquids

Gas

FRANCE

TIGF

Network South West

100.00

NORWAY

Frostpipe (inhibited)

Lille-Frigg, Froy

Oseberg

36.25

Gassled^(a)

8.09

Heimdal to Brae Condensate Line

Heimdal

Brae

16.76

Kvitebjorn pipeline

Kvitebjorn

Mongstad

5.00

Norpipe Oil

Ekofisk Treatment center

Teeside (UK)

34.93

Oseberg Transport System

Oseberg, Brage and Veslefrikk

Sture

8.65

Sleipner East Condensate Pipe

Sleipner East

Karsto

10.00

Troll Oil Pipeline I and II

Troll B and C

Vestprosess (Mongstad refinery)

3.70

NETHERLANDS

Nogat pipeline

F15A

Den Helder

23.19

West Gas Transport

K13A-K4K5

Den Helder

4.66

WGT Extension

Markham

K13-K4K5

23.00

UNITED KINGDOM

Bruce Liquid Export Line

Bruce

Forties (Unity)

43.25

Central Area Transmission

Cats Riser Platform

Teeside

0.57

System (CATS)

Central Graben

Elgin-Franklin

ETAP

46.17

Liquid Export Line (LEP)

Frigg System: UK line

Frigg UK, Alwyn North,
Bruce, and others

St.Fergus (Scotland)

100.00

Interconnector

Bacton

Zeebrugge (Belgium)

10.00

Ninian Pipeline System

Ninian

Sullom Voe

16.00

Shearwater Elgin

Elgin-Franklin

Bacton

25.73

Area Line (SEAL)

Shearwater

GABON

Mandji Pipe

Mandji fields

Cap Lopez Terminal

100.00

^(b)

Rabi Pipe

Rabi

Cap Lopez Terminal

100.00

^(b)

SOUTH AMERICA

Argentina

Gas Andes

Neuquen Basin (Argentina)

Santiago (Chile)

56.50

TGN

Network (Northern Argentina)

15.40

TGM

TGN

Uruguyana (Brazil)

32.68

Bolivia

Transierra

Yacuiba (Bolivia)

Rio Grande (Bolivia)

11.00

Brazil

TBG

Bolivia-Brazil border

Porto Alegre via Sao Paulo

9.67

TSB (project)

TGM (Argentina)

TBG (Porto Alegre)

25.00

Colombia

Ocensa

Cusiana, Cupiagua

Covenas Terminal

15.20

Oleoducto de Alta Magdalena

Magdalena Media

Vasconia

0.96

Oleoducto de Colombia

Vasconia

Covenas

9.55

United States

Canyon Express^(c)

Aconcagua

Williams platform

25.8

ASIA

Yadana

Yadana (Myanmar)

Ban-I Tong (Thai border)

31.24

REST OF THE WORLD

BTC

Baku (Azerbaijan)

Ceyhan ( Turkey)

5.00

SCP

Baku (Azerbaijan)

Georgia/Turkey Border

10.00

Dolphin (project)

Ras Laffan (Qatar)

Taweelah (U.A.E.)

24.50

(a)

Gassled: unitization of Norwegian gas pipelines through a new joint-venture in which TOTAL has an interest of 8.086%. In addition to the direct share in Gassled, TOTAL has a 14.4% interest in the joint-stock company Norsea Gas AS, which holds 2.839% in Gassled.

(b)

Interest of Total Gabon. The Group has a financial interest of 58% in Total Gabon.

(c)

Asset sold early in 2007.

Gas & Power

The Gas & Power division encompasses the marketing, trading, transport and storage of natural gas and liquefied natural gas (LNG), LNG re-gasification, and the maritime transport and trading of liquefied petroleum gas (LPG). It also includes power generation from combined cycle plants and renewable energies, the trading and marketing of electricity as well as the production and marketing of coal. TOTAL is continuing to develop its global presence in each of these activities.

Natural Gas

In 2006, TOTAL pursued its strategy of developing its activities downstream from natural gas production to optimize access for the Group’s present and future gas production and reserves to traditional (organized around long-term contracts between producers and integrated gas companies) as well as newly (or soon to be) deregulated markets.

The majority of TOTAL’s natural gas production is sold under long-term contracts. However, a part of its UK, Norwegian and Argentine production as well as substantially all of its North American production are sold on a spot basis.

The long-term contracts under which TOTAL sells its natural gas production usually provide for a price related to, among other factors, average crude oil and other petroleum product prices, as well as, in some cases, a cost of living index. Although the price of natural gas tends to fluctuate in line with crude oil prices, there tends to be a delay before changes in crude oil prices are reflected on long-term natural gas prices.

The general trend towards the deregulation of natural gas markets worldwide tends to allow customers to more freely access suppliers, leading to new marketing structures that are more flexible than traditional long-term contracts.

In this context, TOTAL is developing its trading, marketing and logistic activities to offer its natural gas production to new customers, primarily in the industrial and commercial markets, who are looking for more flexible supply arrangements.

Europe

TOTAL has been active in the downstream sector of the gas value chain for more than 60 years. Natural gas transport, marketing and storage activities were initially developed to complement the Group’s domestic production in Lacq (France). Today, TOTAL’s objective is to become a leading supplier of gas to European industrial and commercial customers.

Since April 2005, the Group’s transport and storage activities in southwest France have been brought under a wholly-owned subsidiary, TIGF, which operates a regulated transport network of 4,905 km of pipes and two storage units with a combined usable capacity of 85 Bcf (2.4 Bm³), approximately 20% of the overall natural gas storage capacity in France⁽¹⁾.

Highlights of 2006 included the inauguration of the Euskadour pipeline (TIGF, 100% of the portion in France). This pipeline, whose construction was approved in 2003, is the second pipeline to connect the Atlantic coasts of Spain and France.

In 2006, TOTAL sold 243 Bcf (6.9 Bm³) of natural gas to French customers through its marketing subsidiary Total Énergie Gaz (TEGAZ), compared to 260 Bcf (7.4 Bm³) in 2005 and 268 Bcf (7.6 Bm³) in 2004.

In Spain, since 2001, TOTAL has marketed gas in the industrial and commercial sectors through its participation in CEPSA Gas Comercializadora. This company is held by TOTAL (35%), CEPSA (35%) and the Algerian national company Sonatrach (30%). Taking into account TOTAL’s 48.83% interest in CEPSA, TOTAL has a direct and indirect interest of approximately 52% in this company. In 2006, CEPSA Gas Comercializadora sold approximately 119 Bcf (3.4 Bm³) of natural gas, compared to approximately 63 Bcf (1.8 Bm³) in 2005 and 35 Bcf (1 Bm³) in 2004. CEPSA is participating in studies for the Medgaz gas pipeline project, planned to directly connect Algeria and Spain, through its 20% interest, which give TOTAL an indirect interest of 10% in the project. The Group relinquished its direct participation in the project in 2006.

In the UK, TOTAL’s subsidiary Total Gas & Power Ltd sells gas and power to the industrial and commercial markets. This subsidiary also conducts global gas, electricity and LNG trading activities. In 2006, Total

(1)

Source: International Gas Union 2006.

Gas & Power Ltd marketed 135 Bcf (3.8 Bm³) of natural gas to industrial and commercial customers, compared to 189 Bcf (5.4 Bm³) in 2005 and in 2004. Electricity sales in 2006 amounted to 3.2 TWh in 2006, compared to 1.7 TWh in 2005 and 1.3 TWh in 2004. In addition, TOTAL holds a 10% interest in Interconnector UK Ltd, a gas pipeline connecting Bacton in the UK to Zeebrugge in Belgium.

The Americas

In the United States, TOTAL sold approximately 925 Bcf (26.2 Bm³) of natural gas in 2006, compared to 621 Bcf (17.6 Bm³) in 2005 and 530 Bcf (15 Bm³) in 2004, supplied by its own production and external sources.

In Mexico, Gas del Litoral, a company in which TOTAL holds a 25% interest, sold approximately 25.5 Bcf (0.7 Bm³) of natural gas in 2006.

In South America, TOTAL owns interests in several natural gas transport companies in Argentina, Chile and Brazil, including 15.4% in Transportadora de Gas del Norte (TGN), which operates a gas transport network covering the northern half of Argentina, 56.5% of the companies which own the GasAndes pipeline connecting the TGN network to the Santiago del Chile region and 9.7% of Transportadora Gasoducto Bolivia-Brasil (TBG), whose gas pipeline supplies southern Brazil from the Bolivian border. These different assets represent a total integrated network of approximately 9,000 km serving the Argentine, Chilean and Brazilian markets from gas-producing basins in Bolivia and Argentina, where the Group has natural gas reserves.

The actions taken by the Argentine government after the 2001 economic crisis and the subsequent energy crisis put TOTAL’s Argentine subsidiaries in difficult financial and operational situations. In 2006, TOTAL continued its efforts to preserve the value of these subsidiaries’ assets. In particular, TGN’s debt was restructured after approval by 99.4% of the company’s creditors. This restructuring reduced TGN’s debt from $657 million to $454 million and diluted shareholders’ interests, with TOTAL’s interest decreasing from 19.2% to 15.4%.

Asia

TOTAL markets natural gas, transported through pipelines from Indonesia, Thailand and Myanmar and in the form of LNG, in Japan, South Korea, Taiwan and India. The Group is also developing new LNG outlets in emerging markets.

In India, highlights of 2006 included the marketing of 0.8 Bm³ of natural gas from the Hazira terminal. This represents, after re-gasification, the equivalent of approximately 600,000 tons of LNG which was supplied through the international LNG spot market.

In Japan, TOTAL holds a 3% stake in DME-Development and a 6% stake in DME-International, along with nine Japanese corporate partners. These companies aim to develop a new process to obtain DiMethyl Ether (DME), an environmentally-friendly liquid fuel, by conversion of natural gas into carbon monoxide and hydrogen followed by a chemical transformation of this synthetic gas. A pilot plant with a capacity of 100 t/d of DME was built in Kushiro, on the Hokkaido Island, where several tests were performed between 2004 and 2006. The various tests conducted at the plant since then have enabled DME-Development to confirm the potential of this new technology. DME production since the start-up of the plant totaled 20,000 tons as of the end of 2006. In 2006, DME-International continued to pursue feasibility studies for the construction of commercial production units.

Liquefied Natural Gas (LNG)

The Gas & Power division conducts LNG activities downstream from liquefaction plants⁽¹⁾: LNG shipping, re-gasification, storage and marketing. TOTAL has entered into agreements to obtain long-term access to LNG re-gasification capacity on the three continents which are the largest consumers of natural gas: North America (United States and Mexico), Europe (France and the UK) and Asia (India). With these agreements in place, TOTAL is positioned to develop new natural gas liquefaction projects, notably in the Middle East.

Europe

In June 2006, TOTAL acquired a 30.3% interest in the Société du Terminal Méthanier de Fos Cavaou (STMFC). This terminal is scheduled to start receiving LNG deliveries at the end of 2007. In the future, the terminal is expected to have a re-gasification capacity of 8.25 Bm³/y (6.1 Mt/y), of which 2.25 Bm³/y (1.7 Mt/y) have been reserved by Total Gas & Power Ltd.

In December 2006, in connection with its entry in the Qatargas II project, TOTAL acquired an 8.35% interest in the South Hook LNG re-gasification terminal project in the UK.

(1)

The Exploration & Production division conducts natural gas liquefaction activities.

In addition, as part of the Snøhvit project (Norway), Total Gas & Power Ltd signed an agreement in 2004 to purchase 1 Bm³/y (0.7 Mt/y) of LNG intended mainly for marketing in North America and Europe. TOTAL holds an 18.4% interest in the Snøhvit liquefaction plant currently under construction. The first deliveries are expected in the last quarter 2007. TOTAL (through its subsidiary Total Norge) has chartered an LNG tanker, the Arctic Lady, to transport this LNG. This tanker was built by Mitsubishi Heavy Industries in Nagasaki (Japan) and was delivered to TOTAL in April 2006.

North America

In Mexico, the construction of the Altamira re-gasification terminal, in which TOTAL holds a 25% interest, was completed on schedule during the summer of 2006. This new terminal, located on the east coast of Mexico, has an initial LNG re-gasification capacity of 6.7 Bm³ per year (1.7 Bm³ TOTAL share), and started its commercial operations at the end of September 2006.

In the United States, under an agreement signed in November 2004 to reserve re-gasification capacity at the Sabine Pass LNG terminal in Louisiana, TOTAL has reserved a re-gasification capacity of 10 Bm³ (1 Bcf per day), beginning in April 2009 for a renewable 20-year period. The construction of this terminal, which began in April 2005, is due to be completed in 2008. The LNG to supply Sabine Pass is expected to come from LNG purchase agreements providing for shipments from various producing projects in which TOTAL holds interests, in particular in the Middle East, Norway and West Africa.

Asia-Pacific

The Hazira re-gasification terminal, located on the west coast of the Gujarat state in India, was inaugurated in April 2005. It has an initial capacity of approximately 3.4 Bm³ per year. Since May 2005, TOTAL has held a 26% interest in this merchant terminal whose activities include taking delivery of LNG, re-gasification and natural gas marketing. TOTAL has agreed to provide up to 26% of the LNG for the Hazira terminal. Due to market conditions, in 2005 and 2006 the Hazira terminal was essentially operated on the basis of short-term (spot) contracts, both for the sale of gas on the Indian market and the purchase of LNG from international markets. Twelve cargos were delivered in 2006, compared to three in 2005.

Middle East

In Qatar, pursuant to heads of agreement signed in February 2005, TOTAL signed purchase contracts in July 2006 for up to 5.2 Mt/y of LNG from Qatargas II

(second train) over a 25-year period. This LNG is expected to be marketed in France, the UK and North America. In December 2006, TOTAL concluded an agreement to acquire a 16.7% interest in the second train of Qatargas II.

In Yemen, through its wholly-owned subsidiary Total Gas & Power Ltd, TOTAL, signed an agreement in July 2005 with Yemen LNG Ltd (in which TOTAL has a 39.62% interest) to purchase 2 Mt/y of LNG over a 20-year period, beginning in 2009, to be delivered to the United States.

In Iran, as part of the agreements for the Pars LNG project (in which TOTAL has a 40% interest), Total Gas & Power Ltd signed a long-term purchase agreement for approximately 3 Mt/y of LNG. This agreement is conditioned upon the final investment decision for the project regarding the construction of two liquefaction trains, each with a capacity of 5 Mt/y.

Africa

In Nigeria, train 4 of Nigeria LNG Ltd, (NLNG) a company in which TOTAL holds a 15% interest, began operations in November 2005, followed by train 5 in February 2006. These two additional trains, with a liquefaction capacity of 4 Mt/y of LNG each, increased the total nominal capacity of the plant to 17.9 Mt/y. TOTAL took delivery of its first LNG shipment from Nigeria in January 2006, under a contract providing for 0.23 Mt/y of LNG over a 20-year period.

In July 2004, in connection with NLNG’S decision to build a sixth gas liquefaction train at its Bonny plant (Nigeria), TOTAL, through its subsidiary Total Gas & Power, purchased an additional 0.9 Mt/y of LNG over a 20-year period to be added to the initial 0.23 Mt/y from other trains. Deliveries from train 6 are scheduled to start in 2007. TOTAL also conducted negotiations for a LNG purchase contract for an additional 1.375 Mt/y over a 20-year period to be supplied by another new train (train 7). The agreement is expected to be signed in the first half 2007 and is subject to final investment decision for the new train, which has a planned capacity of 8.5 Mt/y and is scheduled to begin deliveries early in the next decade.

In October 2006, TOTAL acquired a 17% interest in the Brass LNG project to construct two liquefaction trains, each with a capacity of 5 Mt/y, scheduled to begin deliveries in 2011. In connection with the acquisition of this interest, in July 2006 TOTAL signed a preliminary agreement with Brass LNG Ltd setting forth the principal terms for a LNG purchase contract for 1.65 Mt/y over a 20-year period, destined mainly for North America and Western Europe. As is the case for the purchase contract for train 7 of NLNG, this purchase contract for Brass LNG would also be subject to final investment decision for the project, which is scheduled to begin deliveries early in the next decade.

Trading

TOTAL’s subsidiary Total Gas & Power Ltd has been trading LNG cargos since 2001. This activity provides TOTAL with flexibility in the supply of gas to its main customers. Suppliers are the main liquefaction plants which produced more LNG than they were required to deliver under their long-term sales agreements (Nigeria, Oman, Abu Dhabi, Algeria and Egypt). The customers for these cargoes are located primarily in France, Spain and Asia (India, Japan and Taiwan). TOTAL sold nineteen spot cargos in 2006, compared to thirteen in 2005 and seven in 2004.

Liquefied Petroleum Gas (LPG)

The Gas & Power division conducts LPG (butane and propane) trading and marketing activities.

In 2006, TOTAL traded and sold 5.8 Mt of LPG (butane and propane) worldwide (compared to 5 Mt in 2005 and 4.8 Mt in 2004), of which approximately 1.2 Mt in the Middle East and Asia, approximately 1 Mt in Europe on small coastal trading vessels and approximately 3.7 Mt on large vessels in the Atlantic and Mediterranean regions. Nearly half of these quantities originated from fields or refineries operated by the Group. LPG trading involves the use of six time-charters and approximately sixty spot charters. In 2006, this activity represented approximately 11% of worldwide seaborne LPG trade⁽¹⁾.

In 2006, TOTAL continued the construction, launched in November 2003, of a LPG importation and storage unit located in Visakhapatnam, on the east coast of India in the state of Andhra Pradesh. This terminal is expected to start commercial operations mid-2007 and has a planned storage capacity of 60,000 tons and a planned off-take capacity of 1.2 Mt/y. TOTAL has a 50% interest in this project in partnership with Hindustan Petroleum Company Ltd.

Electricity and Cogeneration

As a refiner and petrochemicals producer, TOTAL has interests in several cogeneration facilities. Cogeneration is a process whereby the steam produced to turn turbines to generate electricity is then captured and used for industrial purposes. TOTAL also participates in another type of cogeneration, which combines power generation with water desalination, and in gas-fired electricity generation, as part of its strategy of pursuing opportunities at all levels of the gas value chain.

The Taweelah A1 cogeneration plant in Abu Dhabi, which combines power generation and water desalination, has been in operation since May 2003 and is owned and operated by Gulf Total Tractebel Power Cy, in which TOTAL has a 20% interest. Taweelah A1 currently has a total power generation capacity of 1,430 MW and a water desalination capacity of 385,000 m³ per day. Near the end of 2006, it was decided to develop an additional 250 MW of capacity, which is expected to enter into operation in 2009.

In Thailand, TOTAL owns 28% of Eastern Power and Electric Company Ltd (EPEC) which has operated the combined cycle gas power plant of Bang Bo, with a capacity of 350 MW, since March 2003.

In Argentina, in November 2006 TOTAL sold its 63.9% interest in Central Puerto SA, a company which owns and operates gas-fired power stations in Buenos Aires and in the Neuquén region. In December 2006, TOTAL also sold its 70% interest in Hidroneuquen, a company owning a 59% interest in Hidroeléctrica Piedra del Aguila, a hydroelectric dam located in the Neuquén region.

In Nigeria, TOTAL and its partner, the state-owned NNPC, are participating in two projects to construct gas-fired power generation units. These projects are part of the Nigerian government’s policy to develop power generation, stop gas flaring and privatize the power generation sector:

•

The Afam project, part of the SPDC joint venture in which TOTAL holds a 10% interest, concerns the upgrading of the Afam V power plant capacity, to 276 MW, and the development of the Afam VI power plant, with a planned capacity of approximately 600 MW; and

•

The OML 58 project, part of the EPNL joint venture in which TOTAL holds a 40% interest (operator), concerns the development of a new 400 MW combined-cycle power plant near the city of Obite.

In the UK, in September 2005 TOTAL sold its 40% interest in Humber Power Ltd, which owns a gas-fired combined cycle power station.

Renewable Energy

As part of its sustainable development policy, TOTAL is developing its position in renewable energy, with a particular focus on solar-photovoltaic energy, where the Group has been present since 1983, and wind power. In

(1)

Source: Poten & Partners – LPG IN WORLD MARKETS – Yearbook 2006.

addition, since 2005 TOTAL, has been participating in the development of marine energy, a third possibility for renewable energy.

Solar-photovoltaic power

In solar power (silicon-crystal technology), TOTAL manufactures photovoltaic cells (Photovoltech), manufactures solar panels and designs solar systems (TENESOL). The Group is also involved in financing projects for rural electrification (Temasol in Morocco and KES in South Africa).

In January 2006, TOTAL increased its interest in Photovoltech, a company specialized in manufacturing photovoltaic cells, from 42.5% to 47.8%. Photovoltech sales amounted to approximately 44 M€ in 2006, compared to 25 M€ in 2005. Due to strong demand for and the successful marketing of its products, Photovoltech is planning to increase its total production capacity from 20 MWp/y to 80 MWp/y by the end of 2007. Civil engineering for the new production facilities to increase capacity began in the fall of 2006.

TOTAL holds a 50% interest in TENESOL, its partnership with EDF, which designs, manufactures, markets and operates solar-photovoltaic power systems. TENESOL’s consolidated sales decreased by approximately 8% between 2005 and 2006, amounting to approximately 134 M€ in 2006, compared to 145 M€ in 2005, the equivalent of an installed capacity of 33 MWp. Its principal markets are for network connections in Europe (Germany and Spain) and for decentralized rural electrification and telecommunication systems in the French Overseas Territories. TENESOL owns two solar panel manufacturing plants: TENESOL Manufacturing in South Africa, with an annual production capacity of 35 MWp, and TENESOL Technologies in the region of Toulouse, France, with an annual production capacity of 15 MWp.

TOTAL is pursuing decentralized rural electrification activities by responding to a call for tenders from authorities in several countries, including Mali, Morocco, Senegal and South Africa.

In South Africa, an ongoing project to equip 15,000 households, led by Kwazulu Energy Service Company (TOTAL, 35%), had equipped nearly 9,000 households by the end of 2006.

In Morocco, Temasol, in which TOTAL has indirect interests through Total Maroc (32.2%) and TENESOL (35.6%), continued work on a project awarded in May 2002 to equip 16,000 households. In 2004, Temasol was also awarded a project to equip 37,000 households. In

2005, it was awarded part of a project to equip an additional 5,500 households. At the end of 2006, approximately 24,000 of the total of 58,500 households covered by these projects were equipped, compared to 20,000 at the end of 2005 and 10,000 at the end of 2004.

Wind power

TOTAL currently operates a wind farm in Mardyck (near its Flanders refinery in northern France) and is conducting development studies for onshore and offshore projects in France, the UK and Spain.

Mardyck, commissioned in November 2003, has a capacity of 12 MW and produced approximately 25.2 GWh of electricity in 2006, compared to 26.4 GWh in 2005. It is designed to allow comparison of different technologies at the same site in order to prepare for possible larger scale offshore or onshore projects in the future.

In December 2005, after a tender invitation, TOTAL was selected by the French Ministry of Industry for an onshore wind power project with a planned capacity of 90 MW to be built in Aveyron region. Pursuant to the terms of the bid, the project is subject to obtaining a construction permit. The public consultation for this project began in January 2007, and the wind farm is expected to begin operations in 2009. Work on this project will be conducted by the Éoliennes de Mounès company, in which TOTAL has a 50% interest.

TOTAL is also preparing for the development of a wind farm with a 120 MW capacity offshore Dunkirk, France. This project, in which TOTAL holds a 50% interest, should benefit from the power purchase terms set in the tariff order released on July 10, 2006.

Marine energy

In marine energy, TOTAL acquired a 10% interest in a pilot project located offshore Santona, on the northern coast of Spain, in June 2005. In 2006, the project decided to build and test its first buoy, which should allow the project’s final size and planned generation capacity to be determined. This pilot project is expected to provide information necessary to assess the technical and economic potential of this technology.

TOTAL has a 21.5% interest in Scotrenewables Marine Power, a company located in the Orkney islands in Scotland. This company is developing tidal current energy converter technology.

Coal

For more than 25 years, TOTAL has exported steam coal from its mines located in South Africa, primarily to Europe and Asia. Today, TOTAL owns and operates three mines and is examining several other mining projects. The Group also trades and markets steam coal through its trading subsidiaries Total Coal International (Atlantic zone), Total Energy resources (Pacific zone) and CDF Énergie (France).

TOTAL sold approximately 9.2 Mt of coal worldwide in 2006 (compared to 9.5 Mt in 2005 and 11.3 Mt in 2004), of which 4.4 Mt was South African steam coal produced by the Group. Approximately 75% of the Group’s South African coal production was sold to European utility companies and approximately 12% was sold in Asia.

The Group’s South African coal is exported through the port of Richard’s Bay, the world largest coal terminal, of which 5.7% is owned by TOTAL. On the South African

domestic market, sales amounted to 0.6 Mt in 2006, primarily intended for the industrial and metallurgic sectors.

In parallel, Total Coal South Africa is developing new mines. This included construction of the Forzando South mine, which was completed near the end of 2006 and which is expected to reach its planned production capacity of 1.2 Mt/y over the next two years.

TOTAL is also active in coal trading through its wholly-owned subsidiary Total Energy Resources (TER) in Hong Kong and through a representative office established in Jakarta in September 2004. Of the 2.6 Mt of coal traded in 2006, 62% was sold in Asia.

In France, TOTAL, through its subsidiary CDF Énergie, is an important steam coal distributor in the industrial sector (paper, cement, agro-food, residential heating, etc.), with sales of 2.2 Mt in 2006, originating from diverse sources outside the Group, compared to 2 Mt in 2005.

Downstream

The Downstream segment conducts TOTAL’s refining, marketing, trading and shipping activities.

Refining & Marketing

As of December 31, 2006, TOTAL’s worldwide refining capacity was 2,700 thousand barrels per day (kb/d). The Group’s refined products sales worldwide remained stable at 3,786 kb/d (including trading activities), compared to 3,792 kb/d in 2005 and 3,761 kb/d in 2004. TOTAL is the largest refiner/marketer⁽¹⁾ in Western Europe and, with a market share of 11%, the largest marketer in Africa⁽²⁾. As of December 31, 2006, TOTAL’s marketing network consisted of 16,534 retail stations worldwide (compared to 16,976 in 2005 and 16,857 in 2004), of which approximately 50% are owned by the Group. TOTAL’s refineries also allow the Group to produce a broad range of specialty products, such as lubricants, liquefied petroleum gas (LPG), jet fuel, special fluids, bitumen and petrochemical feedstock.

Since 2004 TOTAL has pursued a sustained refining investment program to respond to changes in the oil market. This program, initiated through the construction of a distillate hydrocracker (DHC) at the Group’s refinery

in Normandy, France, continued in 2006 with the launch of engineering studies for two major projects: the construction of a full-conversion refinery in Saudi Arabia and the construction of a deep conversion unit at the Port Arthur, Texas, refinery. Under this program, the Group plans to invest an average of 1 B€ per year in refining over the 2006-2010 period (excluding capitalization of turnarounds).

For its marketing activities, the Group’s strategy is to strengthen its positions in Europe and Africa and to pursue targeted growth in certain other markets, in particular in Asia.

Refining

As of December 31, 2006, TOTAL held interests in 27 refineries (including 13 that it operates), located in Europe, the United States, the French West Indies, Africa and China.

(1)

Source: Oil and Gas Journal, December 18, 2006.

(2)

Company sources, PFC Energy, December 2006.

TOTAL’s activities in Western Europe have a refining capacity of 2,342 kb/d, accounting for more than 85% of the Group’s refining capacity and making TOTAL the leading refiner in this region. TOTAL operates 12 refineries in Western Europe. Six are located in France, one in Belgium, one in Germany, two in the UK, one in Italy and one in the Netherlands. TOTAL also has minority interests in another German refinery (Schwedt) as well as interests in four Spanish refineries through its holding in CEPSA.

In the United States, TOTAL operates the Port Arthur, Texas, refinery near the Gulf of Mexico, which has a production capacity of 174 kb/d.

TOTAL, Sinochem and PetroChina have been in partnership for more than ten years in the WEPEC refinery located in Dalian, whose annual refining capacity averages 219 kb/d. TOTAL holds a 22.41% interest in this refinery.

From 2006 to 2010, TOTAL plans to invest approximately 5 B€ in refining, excluding capitalization of turnarounds. Nearly 40% is designated for projects to increase refining capacities and for conversion projects to upgrade heavier crudes. Nearly 20% is designated for developing units and desulphurization to process high-sulphur crudes. Finally, approximately 30% is designated for modernizing refining sites, improving safety and energy efficiency and reducing environmental impacts.

•

Concerning growth and conversion, two major projects were initiated in Saudi Arabia and the United States in the first half 2006.

TOTAL and The Saudi Arabian Oil Company (Saudi Aramco) signed a Memorandum of Understanding (MOU) related to a project for the construction and operation of a refinery with a capacity of 400 kb/d in Jubail, Saudi Arabia. This full-conversion refinery is being designed to process Arabian Heavy crude and produce high-quality refined products adapted for all markets, mainly for exportation. A comprehensive joint Front-End Engineering and Design (FEED) study was undertaken in July 2006. Saudi Aramco and TOTAL agreed to form a joint venture company in which Saudi Aramco and TOTAL would each hold a 35% ownership interest. The remaining 30% is expected to be listed on the Saudi stock exchange, subject to the approval of the relevant authorities, at the end of the FEED (beginning of 2008). Start-up of the refinery is scheduled for 2011.

TOTAL launched studies for the construction of a deep conversion unit or “coker” at the Port Arthur refinery in the United States. This project is being

designed to upgrade heavy crudes and produce lighter products for a structurally short American fuel market.

•

Performance investments are designed to adapt TOTAL’s refineries to changes in the European oil market: growing demand for diesel and increasing supply of high-sulphur crudes.

The first project of this type is the construction of a distillate hydrocracker (DHC) at the Normandy refinery in France. This unit, whose construction began in the spring of 2004, came onstream successfully in 2006. The project represented a total investment of approximately 550 M€ over the 2003-2006 period, and also included the construction of a hydrogen production unit.

The Group also decided to construct a desulphurization unit at the Lindsey (Immingham) refinery in the UK. This investment is being designed to raise the portion of high-sulphur crude that the plant can process from 10% to 70%. The unit is scheduled to begin operating in 2009. A second project to construct a desulphurization unit at the Donges refinery in France is currently being studied. Commissioning is planned for 2010. A third project to construct a desulphurization unit at the Leuna refinery in Germany is also being studied.

In addition, CEPSA⁽¹⁾ has announced investments to improve the performance of its refineries, including the construction of a 2.1 Mt hydrocracker⁽²⁾ unit at the Huelva refinery in Spain. This unit is scheduled to begin operating near the end of 2009.

•

Investments are being made to modernize refining sites, improve safety and energy efficiency and reduce environmental impacts.

At the Dalian (China) refinery, a modernization program was launched to respond to changes in the volumes and quality of products demanded on national and international markets. A distillate hydrocracker with a planned capacity of 1.5 Mt/y is under construction and is scheduled to begin operating in the summer of 2007. A desulphurization unit with a 2 Mt/y capacity is also under construction. This investment should allow the refinery to meet new diesel specifications.

In 2006, two refineries operated by TOTAL were affected by major turnarounds, compared to six in 2005 and five in 2004. Ten refineries are scheduled for major turnarounds, spread throughout 2007.

(1)

Group’s share in CEPSA: 48.83% as of December 31, 2006.

(2)

To which should be added a crude distillation unit (CDU), a vacuum distillation unit (VDU) and a steam methane reformer (SMR).

Crude oil refining capacity

The table below sets forth TOTAL’s share of the daily crude oil refining capacity of its refineries.


As of December 31,^(a) (kb/d)	2006	2005	2004
Refineries operated by the Group
Normandy (France)	331	331	328
Provence (France)	158	158	155
Flandres (France)	141	159	160
Donges (France)	230	229	231
Feyzin (France)	116	118	119
Grandpuits (France)	99	99	99
Antwerp (Belgium)	350	350	352
Leuna (Germany)	227	225	227
Rome (Italy)^(b)	64	64	52
Immingham (UK)	221	221	223
Milford Haven (UK)^(c)	74	73	73
Vlissingen (Netherlands)^(d)	81	84	84
Port Arthur, Texas (United States)	174	174	176
Subtotal	2,266	2,285	2,279
Other refineries in which the Group has an interest^(e)	434	423	413
Total	2,700	2,708	2,692

(a)

For refineries not 100% owned by TOTAL, the indicated capacity represents TOTAL’s proportionate share of the overall refining capacity of the refinery.

(b)

TOTAL’s interest was 71.9% as of December 31, 2006 and 2005; TOTAL’s interest was 57.5% as of December 31, 2004.

(c)

TOTAL’s interest is 70%.

(d)

TOTAL’s interest is 55%.

(e)

Fourteen refineries in which TOTAL has interests ranging from 16.7% to 55.6% (seven in Africa, four in Spain, one in Germany, one in Martinique and one in China) and the Reichstett refinery in France in 2004.

Refined products

The table below sets forth by product category TOTAL’s net share of the quantities produced at TOTAL’s refineries.


(kb/d)	2006	2005	2004
Gasoline	532	534	580
Avgas and jet fuel	179	191	188
Kerosene and diesel fuel	660	639	712
Fuel oils and heating oils	582	593	552
Other products	455	406	419
Total^(a)	2,408	2,363	2,451

(a)

Including TOTAL’s share in CEPSA: 48.83% since October 2006, compared to its previous interest of 45.3%.

Utilization rate

(crude refining)


2006		2005		2004
88	%	88	%	92	%

Marketing

The Group is one of the leading marketers in the combined six largest European markets (France, Spain, Benelux, the UK, Germany and Italy)⁽¹⁾. TOTAL is also the largest marketer in Africa, with a market share of 11%, after acquiring distribution affiliates in 14 African countries in 2005 and 2006.

Sales of refined products^(a)

The table below sets forth by geographic area TOTAL’s average daily volumes of refined petroleum products sold for the years indicated.


(kb/d)	2006	2005	2004
France	837	852	882
Rest of Europe^(a)	1,438	1,444	1,495
United States	264	256	257
Africa	274	260	245
Rest of the World	153	151	129
Total excluding Trading	2,966	2,963	3,008
Trading (Balancing and Export Sales)	820	829	753
Total including Trading	3,786	3,792	3,761

(a)

Including TOTAL’s net share in CEPSA: 48.83% since October 2006, compared to its previous interest of 45.3%.

Retail stations

The table below sets forth by geographic area the number of retail stations in TOTAL’s network.


As of December 31,	2006	2005	2004
France^(a)	5,220	5,459	5,626
Rest of Europe (excluding CEPSA)	4,628	4,937	5,003
CEPSA^(b)	1,672	1,677	1,697
Africa	3,562	3,505	3,199
Rest of the World	1,452	1,398	1,332
Total	16,534	16,976	16,857

(a)

Retail stations under the TOTAL and Elf brands and approximately 2,000 retail stations under the Elan brand.

(b)

Including all the retail stations within the CEPSA network.

(1)

Company data, based on quantities sold.

Western Europe

In Europe, TOTAL has a network of retail stations in France, Belgium, Luxembourg, the Netherlands, Germany, the UK, Portugal, Italy and, through its 48.83% interest in CEPSA, Spain and Portugal.

In France, the TOTAL-branded network has a diverse selection of products (such as the Bonjour convenience stores) and strong customer loyalty programs. As of December 31, 2006, the TOTAL-branded network consisted of approximately 2,600 retail stations in France, while the Elf-branded network included nearly 300 retail stations. Elf-branded retail stations offer quality fuels and basic services at prices that are particularly competitive. TOTAL also markets fuels at nearly 2,000 Elan-branded retail stations, generally located in rural areas.

In Germany, a major network reorganization program was completed in 2006, with the closing of 40 retail stations and the development of non-fuel sales. In the UK, a program launched in 2003 to rationalize sites and increase non-fuel sales continued in 2006. Non-fuel sales increased following the opening of approximately 20 Bonjour convenience stores. As of December 31, 2006, TOTAL had a network of 475 AS24-branded retail stations in 20 European countries. This network, dedicated to professional transporters, opened 43 new retail stations in 2006, mainly in Central and Eastern Europe.

TOTAL is among the leaders in Europe for fuel-payment cards, with approximately 3.5 million cards issued in 16 European countries. In 2006, more than 4.7 Mm³ of motor fuels were sold and paid by card, compared to 4.5 Mm³ in 2005 and 4.4 Mm³ in 2004.

In 2006, TOTAL continued to enlarge its distribution in Europe of two new high-performance fuels branded TOTAL EXCELLIUM 98 and TOTAL EXCELLIUM diesel. These new generation fuels reduce fuel consumption and carbon dioxide emissions. With the launch of the EXCELLIUM range, TOTAL has acquired a significant share of the market for next generation fuels in Europe.

In 2005, TOTAL began distributing an urea-based additive called AdBlue intended for professional transporters in Europe. As of December 31, 2006, more than 130 TOTAL and AS24 retail stations were equipped to distribute bulk and conditioned urea. Between now and 2009, TOTAL expects to progressively expand its distribution of AdBlue to include a network of approximately 400 retail stations in 27 European countries.

Africa

TOTAL is present in more than 40 African countries and has interests in seven refineries.

In 2005, TOTAL strengthened its position in Africa through the acquisition of distribution affiliates in 14 African countries (Djibouti, Eritrea, Ethiopia, Ghana, Guinea Conakry, Liberia, Malawi, Mauritius, Mozambique, Sierra Leone, Chad, Togo, Zambia and Zimbabwe). This acquisition, completed in 2006, includes 500 retail stations and 29 terminals and depots with an overall capacity of 380,000 m³. Through this agreement, TOTAL has strengthened its presence in West Africa, consolidating its positions in East Africa and become the largest marketer of petroleum products in Africa.

Asia

TOTAL is present in nearly 20 Asian countries.

Building upon their experience together at the Dalian refinery, in 2005 TOTAL and Sinochem decided to develop two retail station network partnerships in China. A joint-venture agreement, signed in March 2005, is designed to develop a network of 200 retail stations in Beijing and in the area north of the city. At the end of December 2006, 22 retail stations were operating. A second joint-venture agreement for the creation of a network of 300 retail stations in the provinces of Shanghai, Jiangsu and Zhejiang in eastern China was signed in September 2005. The first retail station opened in November 2006. These investments represent a major step forward in TOTAL’s strategy of expanding its petroleum products marketing operations in China.

In July 2006, TOTAL strengthened its positions in the Pacific area through the acquisition of assets in Fiji, Samoa and Tonga. The acquisition includes a network of retail stations, approximately ten terminals and depots, as well as sales and distribution of fuel, lubricants, aviation and marine petroleum products. TOTAL also acquired assets in Cambodia in December 2006 to strengthen its existing activities. Both acquisitions remain subject to any necessary approval by the relevant authorities in each country.

In 2006, after the distribution of petroleum products was partially opened to foreign companies in Indonesia, TOTAL decided to develop a pilot network of five retail stations in Jakarta.

Other countries

TOTAL has activities in Turkey and in the Caribbean.

In 2004, TOTAL strengthened its positions in the Caribbean with the creation of two new subsidiaries in Jamaica and Puerto Rico. These new subsidiaries complement TOTAL’s existing activities in Haiti, the French West Indies, Cuba and Costa Rica.

Specialties

TOTAL produces a wide range of refined petroleum products at its refineries and other facilities. TOTAL is among the leading companies in the European specialty products market, particularly in the bitumen, jet fuel and lubricant markets.

TOTAL markets lubricant in more than 150 countries. In 2006, TOTAL strengthened its positions in the lubricants market by signing supply agreements with car manufacturers Nissan and Honda. In September 2006, TOTAL entered into a joint-venture agreement with Veolia Group (TOTAL 35%) to build a 120 kt capacity oil recycling plant in France. Commissioning of the plant is scheduled for 2008. In 2005, TOTAL and the Romanian company Lubrifin signed a joint-venture agreement (TOTAL 51%) to produce and market lubricants and greases intended for the automotive and industrial markets.

TOTAL continued to develop its LPG distribution activities on a worldwide scale, and is the fourth largest international distributor⁽¹⁾.

Bio-fuels and hydrogen

The Group plays an active part in the promotion of renewable energies and alternative fuels.

In 2006, TOTAL consolidated its position as an important oil and gas company active in biofuels in Europe by producing and incorporating 500 kt of ETBE⁽²⁾ in seven refineries⁽³⁾ (compared to 360 kt in 2005 and 310 kt in 2004) and incorporating 420 kt of VOME⁽⁴⁾ in diesel fuels at nine European refineries and several

storage sites (compared to 310 kt in 2005 and 210 kt in 2004). In 2005, TOTAL signed a VOME supply contract with Sofiprotéol and Diester Industry for periodically increasing quantities reaching 600 kt/y.

In November 2006, TOTAL and several other parties (car manufacturers, oil companies, agricultural representatives, ethanol producers) signed the Superethanol E85 Development Charter, a charter to develop superethanol in France (fuel with up to 85% of ethanol from agricultural production, also called “flexfuel”). As part of this charter, TOTAL undertook to equip 200 to 275 retail stations to distribute flexfuel by the end of 2007. The rate at which Superethanol is adopted by the market will depend both on the creation of appropriate tax incentives and the marketing of suitable vehicles.

In 2006, TOTAL continued its research and testing programs for fuel cell and hydrogen fuels technologies. In this area, TOTAL entered into cooperation agreements for automotive applications (with BMW in March 2006, Renault in 2003 and Delphi in 2001) and for stationary applications (with Electrabel and Idatech in 2004). Under its partnership with BVG, the largest public transport company in Germany and the bus operator in Berlin, TOTAL created a Center of Excellence for Hydrogen in Berlin. The first consumer hydrogen fueling station opened in Berlin in March 2006. As part of the partnership with BMW, a second hydrogen fueling station opened in December 2006 near the car manufacturer’s Innovation and Research Center. The construction of a third hydrogen fueling station in Europe is under study. TOTAL is also an active participant in the hydrogen technology platform program launched by the European Commission at the end of 2003, intended to promote the development of this technology in Europe.

(1)

Company sources, on the basis of volumes sold.

(2)

ETBE: Ethyl-Tertio-Butyl-Ether.

(3)

Including Algeciras and Huelva refineries (CEPSA).

(4)

VOME: Vegetable-Oil-Methyl-Esther.

Trading & Shipping

The Trading & Shipping sector:

•

sells and markets the Group’s crude oil production,

•

provides a supply of crude oil for the Group’s refineries,

•

imports and exports the appropriate petroleum products for the Group’s refineries to be able to adjust their production to the needs of local markets,

•

charters appropriate ships for these activities, and

•

undertakes trading on various derivatives markets.

Although Trading & Shipping’s main focus is serving the Group, its know-how and expertise also allow Trading & Shipping to extend the scope of its activities beyond meeting the strict needs of the Group.

Trading

TOTAL is one of the world’s major traders of crude oil and refined products on the basis of volumes traded.

The table below sets forth selected information with respect to TOTAL’s worldwide sales and source of supply of crude oil for each of the last three years.


(kb/d, except %)	2006	2005	2004
Sales of crude oil
Total Sales	4,112	4,465	4,720
Sales to Downstream segment^(a)	2,074	2,111	2,281
Sales to external customers	2,038	2,354	2,439
Sales to external customers as a percentage of total sales	50%	53%	52%
Supply of crude oil
Total supply	4,112	4,465	4,720
Produced by the Group^(b)(c)	1,473	1,615	1,686
Purchased from external suppliers	2,639	2,850	3,034
Production by the Group as a percentage of total supply	36%	36%	36%

(a)

Excludes share of CEPSA, in which TOTAL has a 48.83% interest since October 2006, compared to its previous 45.3% interest.

(b)

Includes condensates and natural gas liquids.

(c)

Includes TOTAL’s proportionate share of the production of equity affiliates.

The Trading division operates extensively on physical and derivatives markets, both organized and over the counter. In connection with its trading activities, TOTAL, like most other oil companies, uses derivative energy instruments to adjust its exposure to fluctuations in the price of crude oil and refined products.

The Trading division undertakes certain physical transactions on a spot basis, but also enters into term

and exchange arrangements and uses derivative instruments such as futures, forwards, swaps and options. These operations are entered into with various counterparties.

All of TOTAL’s trading activities are subject to strict internal controls and trading limits.

In 2006, the principal market components stood at high levels:


		2006	2005	2004	min 2006			max 2006
Brent ICE Futures — 1^st Line^(a)	($/b)	66.11	55.25	38.04	57.87	(2-Nov	)	78.30	(7-Aug	)
Gasoil ICE Futures — 1^st Line^(a)	($/t)	580.4	507.9	347.5	510.5	(12-Jan	)	668.8	(10-Aug	)
VLCC Ras Tanura Chiba — BITR^(b)	($/t)	14.52	13.91	19.97	8.35	(6-Apr	)	27.21	(25-Jan	)

^(a)1^st line: Quotation for first month nearby delivery ICE Futures.

^(b)VLCC: Very Large Crude Carrier. Data estimated from BITR’s market quotations. BITR: Baltic International Tanker Routes.

Throughout 2006, the Trading division maintained a level of activity similar to levels attained in 2004 and 2005, trading physical volumes of crude oil and refined products amounting to an average of approximately 5 Mb/d.

Shipping

The principal activity of the Shipping division is to arrange the transportation of crude oil and refined products necessary for Group activities. The Shipping division provides the wide range of shipping services required by the Group to develop its activities and maintains a rigorous safety policy. Like a certain number of other oil companies and shipowners, the Group uses freight-rate derivative contracts in its shipping activity in order to adjust its exposure to freight-rate fluctuations.

In 2006, the Shipping division of the Group chartered 3,170 voyages to transport approximately 127 Mt of oil. As of December 31, 2006, the Group employs a fleet made up of sixty-three vessels chartered under long-term or medium-term agreements (including six LPG tankers). The fleet is modern, with an average age of approximately five years and is predominately comprised of double-hulled vessels.

Throughout 2006, world crude tanker tonnage increased by 4.9%.This was the fourth consecutive year of high-growth in terms of available crude tonnage (+7.5% in

2005, +4.5% in 2004 and +5 % in 2003). Tonnage demand in 2006 was less sustained than the year before, due to the slowdown in the growth of global oil demand.

These trends reinforce a structural surplus of available tonnage, particularly in a situation where the orderbook reaches a historical record, both in absolute value (124 million deadweight tons) and as a percentage of the active fleet (30% of the global fleet, between 30% and 65% according to the different tanker segments).

On the crude tanker segments, after the seasonal rise observed during the last quarter 2005, the chartering markets significantly dropped throughout the year 2006, apart from some volatile peaks. Following a strengthening of freight rates during the second and third quarter, the rates have significantly fallen since August, particularly for VLCCs. The situations in both the crude and the petroleum products freight markets during the last quarter 2006 are thus not comparable to the historical level observed at the end of 2004 and 2005.

The large number of deliveries expected in 2007, which should not be offset by the demolition of ships, should lead to an increase in tonnage supply (5.8%)⁽¹⁾ greater than the increase in ton-miles (3%)⁽¹⁾.

Chemicals

TOTAL is one of the world’s largest integrated chemical producers.⁽²⁾

The Chemicals segment is organized into Base Chemicals activities (petrochemicals and fertilizers) and Specialties activities, which include the Group’s rubber processing, resins, adhesives and electroplating activities.

On May 12, 2006, TOTAL S.A.’s shareholders approved the spin-off of Arkema which included, since October 2004, vinyl products, industrial intermediates and performance products.

Since May 18, 2006, Arkema has been listed on the Eurolist by Euronext exchange in Paris.

Base Chemicals

TOTAL’s Base Chemicals activities encompass petrochemicals and fertilizers.

Sales reached 12.01 B€ in 2006, compared to 10.25 B€ in 2005 and 8.86 B€ in 2004. Demand remained strong throughout the year due to the favorable economic environment. In 2006, naphtha prices were very volatile,

increasing markedly during the first half of the year before decreasing significantly during the second half. As a result, margins markedly improved during the latter part of the year. Adjusted net operating income from Base Chemicals activities increased by more than 9% in 2006 compared to 2005 and by 9% in 2005 compared to 2004.

(1)

Source: PIRA.

(2)

Company data, based on annual sales.

Petrochemicals

TOTAL’S PRODUCTION CAPACITIES BY

MAIN PRODUCT GROUPS AND REGIONS


	2006				2005	2004
As of December 31, (kt/y)	Europe	North America	Asia and Middle East^(c)	Worldwide	Worldwide	Worldwide
Olefins^(a)	5,185	1,195	655	7,035	7,005	7,055
Aromatics	2,600	930	725	4,255	4,125	4,040
Polyethylene	1,315	440	280	2,035	2,035	2,130
Polypropylene	1,205	1,070	145	2,420	2,420	2,305
Styrenics^(b)	1,240	1,350	515	3,105	3,175	3,110

(a)

Ethylene, propylene and butadiene.

(b)

Styrene, polystyrene and elastomers (activity discontinued at the end of 2006).

(c)

Including minority interests in Qatar and 50% of Samsung-Total Petrochemicals capacities in Daesan (South Korea).

TOTAL’s petrochemicals activities include olefins and aromatics (base petrochemicals) as well as polyethylene, polypropylene and styrenics. On October 1, 2004, Total Petrochemicals was created to regroup these activities.

TOTAL’s main petrochemicals sites are located in Belgium (Antwerp, Feluy), France (Gonfreville, Carling, Lavéra, Feyzin), and the United States (Port Arthur, Houston and Bayport in Texas, Carville in Louisiana) as well as in Singapore and China (Foshan). Most of these sites are either adjacent to or connected by pipelines to Group refineries. As a result, most of TOTAL’s petrochemicals activities are closely integrated with the Group’s refining operations.

In August 2003, TOTAL entered into a 50/50 joint venture with Samsung General Chemicals. This joint venture, named Samsung-Total Petrochemicals, has an integrated site at Daesan in South Korea where it produces a wide range of petrochemicals products and polymers which are marketed in Asia.

TOTAL’s objective is to reinforce its position among the leaders in petrochemicals. In mature markets, TOTAL intends to improve the competitiveness of its existing large sites. In the faster growing Asian markets, TOTAL’s strategy is to expand its activities, either from plants located within the more dynamic markets or from sites located in countries benefiting from favorable access to raw materials.

Samsung-Total Petrochemicals’ launch of a major program to expand and upgrade its site at Daesan is part of this strategy. This investment targets a significant expansion of the capacities of the steam cracker and of the styrene plant, as well as the construction of a new polypropylene line. Construction on these plants is continuing, and they are expected to be brought onstream in 2007 and 2008, respectively.

In Qatar, where the Group has had a long-term presence via its interest in Qapco, TOTAL, through its affiliate Qatofin, is participating in the construction of an ethane-based steam cracker at Ras Laffan and of a new low-density polyethylene plant at Mesaïeed. These two units are scheduled to be brought onstream at the end of 2008.

At all sites, safety and environmental improvements were in line with the yearly targets set by the Group.

Base petrochemicals

Base petrochemicals encompass the olefins and aromatics produced by steamcracking petroleum cuts, mainly naphtha, as well as propylene and aromatics produced in the refineries of the Group. The economic environment for these activities is extremely volatile and margins are strongly influenced by the evolution of the price of naphtha.

2006 was characterized by important fluctuations in the price of naphtha and a strong global demand in steam cracker derivatives, reflecting the healthy economical environment.

In addition, a number of unplanned outages within the industry disturbed the supply of aromatics in North America and olefins in Europe, while the start-up of some petrochemical plants in the Middle East was significantly delayed. These factors, combined with strong demand and the decrease in the price of naphtha in the second half of the year, contributed to keeping margins at high levels throughout the second half 2006.

Olefins production increased 1% in 2006 compared to 2005, after having decreased by 1% in 2005 compared to 2004.

Polyethylene

Polyethylene is a plastic produced by the polymerization of ethylene manufactured in the Group’s steam crackers. It is principally intended for the packaging, automotive, food, cable and pipe markets. Margins are strongly influenced by the level of demand and by competition from expanding production in the Middle East, which takes advantage of favorable access to raw materials (ethylene made from ethane).

In 2006, strong world demand helped absorb new production brought onstream in the Middle East and in China as well as contributing to maintaining margins in spite of the increase in the price of raw materials. Sales in Europe were negatively affected by limited availability of ethylene. Nevertheless, TOTAL’s sales volumes globally increased 1.4% in 2006 compared to 2005, after having decreased by 3% in 2005 compared to 2004.

Polypropylene

Polypropylene is a plastic produced by the polymerization of propylene manufactured in Group steam crackers and refineries and principally intended for the packaging, appliance, car industry, carpet and household and sanitary goods markets. Margins are primarily influenced by the level of demand and the availability and price of propylene.

In 2006, polypropylene demand was strong in Europe, where supply and demand were generally balanced, and margins remained satisfactory. However in the United States, both demand and margins were negatively affected by the volatility and high price of propylene. In Asia, demand and margins improved in the second semester after a weak start of the year. Sales volumes increased by 1.8% in 2006 compared to 2005, after having increased by 6.6% between 2005 and 2004.

Styrenics

This business unit encompasses styrene monomer and polystyrene. The elastomers activity was shut down at the end of 2006.

Most of the styrene produced by the Group is used in the production of polystyrene. Polystyrene is a plastic principally used in packaging, domestic appliances, electronics and audio-video. Margins are strongly influenced by the level of polystyrene demand as well as by the price of benzene, the principal raw material.

In 2006, the increase in world styrene demand was relatively weak, approximately 2%, and demand decreased again in Europe.

World polystyrene demand varied little after the effect of the increased competition of other materials, plastics and paper. Margins were affected by the high prices of raw materials, ethylene and benzene, and by the high costs of energy. Nevertheless, TOTAL’s polystyrene sales volumes increased by 0.3% in 2006 compared to 2005, after having decreased by 2% in 2005 compared to 2004.

Fertilizers

The Fertilizers business unit (Grande Paroisse) manufactures and markets nitrogen fertilizers manufactured using natural gas, and complex fertilizers manufactured using nitrogen, phosphorus and potassium products. Margins are strongly influenced by the price of natural gas.

In 2006, Grande Paroisse’s sales decreased by 11% compared to 2005 after having increased by 7% in 2005 compared to 2004. The activity was negatively affected by turnarounds and various technical problems incurred in the Group’s nitrogen plants, and also by the weak demand for fertilizers during the first part of the year. Furthermore, the increase in the price of natural gas had a negative impact on margins.

In July 2006, Grande Paroisse stopped its French production of complex fertilizers due to the continuously declining market for those products and closed its plants in Bordeaux, Basse Indre, Rouen and Granville. Besides, Zuyd Chemie - the Netherlands affiliate of Grande Paroisse - was sold to Rosier, of which Elf Aquitaine holds a 57% share, to create a more competitive player in the Benelux market.

Grande Paroisse also unveiled an important plan intended to support its nitrogen derivatives production and announced the construction of a new urea plant at Grandpuits as well as a new world-class nitric acid plant in Rouen. The plants are scheduled to be put onstream in 2008, concurrent with the shutdown of the fertilizers plant in Oissel and four small obsolete acid nitric lines in Rouen and Mazingarbe.

Grande Paroisse continued to face the consequences of the explosion which struck its Toulouse plant on September 21, 2001 and made payments, under the French law presumption of civil responsibility, over and above the compensation paid by insurance companies, reaching a cumulative amount approaching 1,227 M€ as of December 31, 2006.

Specialties

TOTAL’s Specialties sector includes rubber processing (Hutchinson), resins (Cray Valley, Sartomer and Cook Composites & Polymers), adhesives (Bostik) and electroplating (Atotech). The sector covers consumer and industrial markets for which customer-oriented marketing and service as well as innovation are key drivers. The Group markets specialty products in more than 55 countries. Its strategy is to continue its international expansion by combining internal growth and targeted acquisitions while concentrating on growing markets and focusing on the distribution of new products with high added value.

In 2006, the Specialties sector benefited from a generally favorable environment and particularly from stronger demand in Europe. In 2006, sales reached 7.10 B€, an increase by nearly 9% compared to 2005, after having increased by 8% in 2005 compared to 2004. The adjusted net operating income from the Specialties activities increased by 10% in 2006 compared to 2005, after having increased by 14% in 2005 compared to 2004.

Rubber processing

Hutchinson manufactures and markets products obtained from rubber processing for the automotive and aerospace industries as well as for consumer markets.

Sales increased by approximately 5% in 2006 compared to 2005, after having increased by approximately 4% in 2005 compared to 2004. In 2006, the automotive industry sales increased by 4% compared to 2005 despite a difficult environment in Europe and in the United States. In 2006, sales from the industrial division increased by approximately 10% compared to 2005, weaker demand from the defense industry in the United States was offset by growth from other segments. Sales from the consumer goods sector increased by approximately 2% due to higher consumer demand in Europe.

Early in 2006, Hutchinson strengthened its industrial division by acquiring the French company Jehier, a manufacturer of various insulating components for the aerospace and defense industries. Throughout 2006, Hutchinson continued to develop in expanding markets such as Central and Eastern Europe, South America and China.

Resins

TOTAL produces and markets resins for adhesives, inks, paints, coatings and structural materials through its three subsidiaries Cray Valley, Sartomer and Cook Composites & Polymers.

In 2006, TOTAL’s resins activities improved its results, benefiting from the favorable environment. Sales grew by approximately 8% in 2006 compared to 2005, after having increased by 13% in 2005 compared to 2004.

In 2006, Cray-Valley decided to debottleneck its tackifying resins plant in Beaumont, Texas, United States, acquired in 2005. Sartomer started the expansion of its photocure plant in Villers-Saint-Paul, France and pursued the construction of a new monomers and oligomers plant near Guangzhou, China. Cray-Valley pursued the streamlining of its resin coatings production in Europe and closed its plant in Tönisworth (Germany), whose production is being transferred to other Cray-Valley plants in Zwickau (Germany) and Boretto (Italy).

Adhesives

TOTAL’s adhesives subsidiary, Bostik, is one of the worldwide leaders in its sector, based on sales, with leading positions in the industrial, hygiene, construction and consumer and professional distribution markets.

In 2006, sales increased by 15% compared to 2005, after having increased by 6% in 2005 compared to 2004. The increase in sales recorded in 2006 stems partly from acquisitions made in the second half 2005 and early in 2006, and partly from healthy global economic conditions. The activity was sustained in the Asia-Pacific zone, remained well oriented in the United States and improved significantly in Europe. Nevertheless, margins were negatively affected by the increase in the prices of raw materials.

In 2006, Bostik strengthened its position in the construction and distribution segments by acquiring Sealocrete and Wetherby (UK) and Paso (Germany). Bostik also acquired Pegaso (Mexico) in the industrial segment and the laminated adhesives activities of Du Pont in Germany, as well as purchasing the minority shareholders’ shares of ASA (Australia).

Electroplating

Atotech, which encompasses TOTAL’s electroplating activities, is the second largest company in this market, based on worldwide sales⁽¹⁾. Its activity is divided between the electronic and the general metal finishing sectors.

In 2006, sales grew by approximately 19% compared to 2005, after having increased by 7% in 2005 compared to 2004. Electroplating activity benefited from the

growth of the electronics industry in Asia and also from strong demand for general metal finishing.

In 2006, Atotech strengthened its general metal finishing activities by acquiring the shares of Kunz GmbH (Germany), a company specialized in anti-corrosion coating technologies intended for automotive uses.

Atotech also expanded the production capacity of its Neuruppin (Germany) and Guangzhou (China) plants and commissioned a new industrial complex gathering both manufacturing and technical center facilities at Jang-An (South Korea).

Other Matters

Various factors, including certain events or circumstances discussed below, have affected or may affect our business and results.

Exploration and production legal considerations

TOTAL’ s exploration and production activities are conducted in many different countries and are therefore subject to an extremely broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as land tenure, production rates, royalties, environmental protection, exports, taxes and foreign exchange. The terms of the concessions, licenses, permits and contracts governing the Group’s ownership of oil and gas interests vary from country to country. These concessions, licenses, permits and contracts are generally granted by or entered into with a government entity or a state-owned company and are sometimes entered into with private owners. These arrangements usually take the form of concessions or production sharing agreements.

The “oil concession agreement” remains the classic model for agreements entered into with States: the oil company owns the assets and the facilities and is entitled to the entire production. In exchange, the operating risks, costs and investments are the oil company’s responsibility and it agrees to remit to the State, as owner of the subsoil resources, a production-based royalty, income tax, and possibly other taxes that may apply under the local tax legislation.

The “production sharing contract” (PSC) involves a more complex legal framework than the concession agreement: it defines the terms and conditions of production sharing and sets the rules governing the cooperation between the company or consortium in

possession of the license and the host State, which is generally represented by a state company. The latter can thus be involved in operating decisions, cost accounting and production allocation. The consortium agrees to undertake and finance all exploration, development and production activities at its own risk. In exchange, it is entitled to a portion of the production, known as “cost oil”, the sale of which should cover all of these expenses (investments and operating costs). The balance of production, known as “profit oil”, is then shared in varying proportions with the State or the state company.

In some instances, concession agreements and PSCs coexist, sometimes in the same country. Even though other contractual structures still exist, TOTAL’s license portfolio is comprised mainly of concession agreements. In all countries, the authorities of the host state, often assisted by international accounting firms, perform joint venture and PSC cost audits and ensure the observance of contractual obligations.

In some countries, TOTAL has also signed contracts called “contracts for risk services” which are similar to production sharing contracts, with the main difference being that the repayment of expenses and the compensation for services are established on a monetary basis. Current contracts for risk services are backed by a compensation agreement (“buyback”), which allows TOTAL to receive part of the production equal to the cash value of its expenses and compensation.

Hydrocarbon exploration activities and production activities are subject to permits, which can be different for each of these activities. These permits are granted for limited periods of time and include an obligation to return a large portion – in case of failure the entire portion – of the permit area at the end of the exploration period.

(1)

Based on Company data.

In general, TOTAL is required to pay income tax on income generated from its production and sale activities under its concessions or licenses. In addition, depending on the country, TOTAL’s production and sale activities may be subject to a range of other taxes, fees and withholdings, including special petroleum taxes and fees. The taxes imposed on oil and gas production and sale activities may be substantially higher than those imposed on other businesses.

Industrial and environmental considerations

TOTAL’s activities involve certain industrial and environmental risks which are inherent to the production of products that are flammable, explosive or toxic. Its activities are therefore subject to extensive government regulations concerning environmental protection and industrial safety in most countries. For example, in Europe, TOTAL operates sites that meet the criteria of the European Union Seveso II directive for classification as high-risk sites. Other sites operated by TOTAL in other parts of the world involve similar risks.

The broad scope of TOTAL’s activities, which include drilling, oil and gas production, on-site processing, transportation, refining, petrochemicals activities, storage and distribution of petroleum products, production of base chemical products and specialty chemicals, involve a wide range of operational risks. Among these risks are those of explosion, fire or leakage of toxic products. In the transportation area, the type of risks depends not only on the hazardous nature of the products transported, but also on the transportation methods used (mainly pipelines, maritime, river-maritime, rail, road), the volumes involved, and the sensitivity of the regions through which the transport passes (population density, environmental considerations).

Most of these activities involve environmental risks related to emissions into the air, water or soil and the creation of waste, and also require environmental site restoration after production is discontinued.

Certain branches or activities face specific risks. In oil and gas exploration and production, there are risks related to the physical characteristics of an oil or gas field. These include eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks generating toxic risks and risks of fire or explosion. All these events could possibly damage or even destroy crude oil or natural gas wells as well as related equipment and other property, cause injury or even death, lead to an interruption of activity or cause environmental damage. In addition, since exploration and production activities may take place on sites that are ecologically sensitive (tropical forest, marine environment, etc.), each site

requires a specific approach to minimize the impact on the related ecosystem, biodiversity and human health.

TOTAL’s activities in the Chemicals segment and, to a lesser extent, the Downstream segment may also have health, safety and environmental risks related to the overall life cycle of the products manufactured. These risks can arise from the intrinsic characteristics of the products involved, which may, for example, be flammable, toxic, or linked to the greenhouse gas effect. Risks of facility contamination and off-site impacts may also arise from emissions and discharges resulting from processing or refining, and from recycling or disposing of materials and wastes at the end of their useful life.

Health, safety and environment regulations

TOTAL is subject in general to extensive and increasingly strict environmental regulation in the European Union. Significant directives which apply to its operations and products, particularly refining and marketing, but also its chemicals and, to a lesser extent, its upstream business, are:

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The directive for a system of Integrated Pollution Prevention and Control (IPPC), a cost/benefit framework used to comprehensively assess the environmental quality standards, prior environmental impacts, and potential additional emissions limits on, large industrial plants, including our refineries and chemical sites.

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Air Quality Framework Directive and related directives on ambient air quality assessment and management, which, among other things, limit emissions for sulfur dioxide, oxides of nitrogen, particulate matter, lead, carbon monoxide, benzene and ozone.

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The Sulfur Content Directive, under which sulfur in diesel fuel is limited to 0.2% beginning July 2000, and 0.1% beginning January 2008. Beginning January 2003, sulfur in heavy fuel oil is limited to 1%, with certain exceptions for combustion plants provided that local air quality standards are met.

•

The Large Combustion Plant Directive, a directive which limits certain emissions from large combustion plants, including sulfur dioxide, nitrogen oxides and particulates; this directive will become effective in 2008.

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Automobile emission directives which control and limit exhaust emissions from cars and other motor vehicles. Under these directives, emission controls will continue to become more stringent over time. From 2005, maximum sulfur levels for gasoline and diesel fuels are 50 ppm and, from 2009, a maximum sulfur content of 10 ppm will be mandatory throughout the EU.

•

The directive, adopted in September 2003, implementing the Kyoto Protocol within the

European Union by establishing a system for greenhouse gas emissions quotas. This system, which entered into effect in January 2005, requires the Member States of the European Union to prepare quotas for industrial activities, in particular the energy sector, and to deliver carbon dioxide emissions permits based on these quotas.

•

The Major Hazards Directive, which requires emergency planning, public disclosure of emergency plans, assessment of hazards, and effective emergency management systems.

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The Framework Directive on Waste Disposal, intended to ensure that waste is recovered or disposed of without endangering human health and without using processes or methods which could unduly harm the environment. Numerous related directives regulate specific categories of waste.

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Maritime oil spill directives, a number of which were passed in the wake of the Erika spill. Recent regulations require that tankers have double hulls and mandate improvements to navigation practices in the English Channel.

•

Numerous water directives impose water quality standards based on the various uses of inland and coastal waters, including ground water, by setting limits on the discharges of many dangerous substances and by imposing information gathering and reporting requirements.

•

Adopted and effective in 2003, a comprehensive framework water directive has begun progressively replacing the numerous existing directives with a comprehensive set of requirements, including additional regulation obliging member countries to classify all water courses according to their biological, chemical and ecological quality; and to completely ban the discharges of approximately 30 toxic substances by 2017.

•

Numerous directives regulating the classification, labeling and packaging of chemical substances and their preparation as well as restricting and banning the use of certain chemical substances and products. The European Commission is still in the process of adopting a new system for Registration, Evaluation and Authorization of Chemicals (REACH) which will partially replace or complement the existing rules in this area. REACH is expected to require the registration of up to 100,000 chemicals, including intermediaries and polymers. Detailed economic studies are currently underway to evaluate the costs to the chemicals industry of implementing this new system.

In March 2004, the European Union adopted a Directive on Environmental Liability. Member States have three years from the time of adoption to transpose the directive into their national legislation. The directive seeks to implement a strict liability approach for damage to biodiversity from high-risk operations. Citizens’ right to know about activities which potentially harm the environment is ensured through a 1990 directive regarding access to environmental information. In January 2003, this directive was replaced by a subsequent right-to-know directive which goes beyond the previous directive in setting the timescale in which information must be provided and imposing fines for non-compliance. The directive also increases public disclosure of emissions to the environment.

A directive implementing the Aarhus Convention concerning certain public participation rights in a variety of activities affecting the environment was adopted in May 2003.

In the United States, where TOTAL’s operations are less extensive than in Europe, it is also subject to significant environmental and safety regulation. Of particular relevance to TOTAL’s lines of business are:

•

The Comprehensive Environmental Response, Compensation, and Liability Act (also known as CERCLA or Superfund), under which waste generators, former and current site owners and operators, and certain other parties can be held jointly and severally liable for the entire cost of remediating abandoned, non-operating or other sites contaminated by spills or waste disposal regardless of fault or the amount of waste sent to a site. The U.S. Environmental Protection Agency has authority, under Superfund, to order responsible parties to clean up sites and may seek from responsible parties recovery of the government response costs and natural resource damages. Additionally, each state has separate laws similar to CERCLA and state environmental agencies have broad authority under these laws and under CERCLA to impose investigation and remediation obligations and liability for releases to the environment.

•

National and international maritime oil spill laws, regulations and conventions, including the Oil Pollution Act of 1990 which imposes significant oil spill prevention requirements, spill response planning obligations, ship design requirements (including in certain instances double hull requirements), operational restrictions and spill liability for tankers and barges transporting oil, offshore oil platform facilities and onshore terminals.

•

The Clean Air Act and its regulations, which require, among other things, stricter phased-in fuel specifications and sulphur reductions, enhanced emissions controls and monitoring at major sources of volatile organic compounds, nitrogen oxides, and other specific and hazardous air pollutants; stringent air emission limits, and construction and operating permits for major sources at chemical plants, refineries, marine and distribution terminals and other facilities; and risk management plans for the handling and storage of hazardous substances.

•

The Clean Water Act, which regulates the discharge of wastewater and other pollutants from both onshore and offshore operations and, among other things, requires industrial facilities to obtain permits for most surface water discharges, install control equipment and treatment systems, implement operational controls and preventative measures, including spill prevention and control plans and practices to control stormwater runoff.

•

The Resource Conservation and Recovery Act (RCRA) regulates the storage, handling, treatment, transportation and disposal of hazardous and non-hazardous wastes and imposes corrective action requirements on regulated activities that mandate the investigation and remediation of potentially contaminated areas at these facilities.

Other significant U.S. environmental legislation includes the Toxic Substances Control Act which regulates the development, testing, import, export and introduction of new chemical products into commerce and the Emergency Planning and Community Right-to-Know Act which requires emergency planning and spill notification as well as public disclosure of chemical usage and emissions. In addition, the Occupational Safety and Health Act, which imposes workplace safety and health, training and extensive process standards to reduce the risks of chemical exposure and injury to employees, has a significant impact on U.S. operations due to the comprehensive nature of its regulations which directly affect numerous aspects of refinery and chemical plant operations.

Environmental regulation in the U.S. is extensive and subject to future changes. In particular increased concern over climate change on the part of the public, government officials and corporations may result in future mandatory carbon and other emissions restrictions. Certain U.S. states, including California, along with a number of cities and counties have enacted or are in the process of enacting mandatory greenhouse restrictions. Regulation at the federal level may occur in the future.

Proceedings instituted by governmental authorities are pending or known to be contemplated against certain U.S.-based subsidiaries of TOTAL under applicable environmental laws which could result in monetary

sanctions in excess of $100,000. No individual proceeding is, nor are the proceedings as a group, expected to have a material adverse effect on TOTAL’s consolidated financial position or profitability.

Risk evaluation

Prior to developing their activities and then on a regular basis during the operations, business units evaluate the related industrial and environmental risks, taking into account the regulatory requirements of the countries where these activities are located.

On sites with significant technological risks, analyses are performed for new developments, updated in case of planned significant modifications of existing equipment, and periodically re-evaluated. To harmonize these analyses and reinforce risk management, TOTAL has developed a group-wide methodology which is being implemented progressively throughout the sites it operates. In France, three pilot sites are developing Risk Management Plans in application of the French law of July 30, 2003. These plans will implement various urbanization measures to reduce risks to urban environments surrounding industrial sites. The texts implementing these aspects of the law of July 30, 2003 were published at the end of 2005 and during 2006.

Similarly, environmental impact studies are done prior to any industrial development with a thorough initial site analysis, taking into account any special sensitivities and plans to prevent and reduce the impact of accidents. These studies also take into account the impact of the activities on the local population, based on a common methodology. In countries where prior authorization and supervision is required, the projects are not undertaken without informing the relevant authorities of the studies.

For new products, risk characterizations and evaluations are performed. Furthermore, life cycle analyses for related risks are performed on certain products to study all the stages of a product’s life cycle from its conception until the end of its existence.

TOTAL’s entities actively monitor regulatory developments to comply with local and international rules and standards for the evaluation and management of industrial and environmental risks.

The Group’s contingencies and asset retirement obligations are described in Note 19 to the Consolidated Financial Statements. Future expenses related to asset retirement obligations are accounted in accordance with the principles described in paragraph Q of Note 1 to the Consolidated Financial Statements.

Risk management

Risk evaluations lead to the establishment of management measures that are designed to prevent and decrease the environmental impacts, to minimize the risks of accidents and to limit their consequences. These measures may be put into place through equipment design itself, reinforcing safety devices, designs of structures to be built and protections against the consequences of environmental risks. Risk evaluations may be accompanied, on a case by case basis, by an evaluation of the cost of risk control and impact reduction measures.

TOTAL is working to minimize industrial and environmental risks inherent to its activities by putting in place performance procedures and quality, safety and environmental management systems, as well as by moving towards obtaining certification for or assessment of its management systems (including International Safety Rating System, ISO 14001, European Management and Audit Scheme), by performing strict inspections and audits, training staff and heightening awareness of all the parties involved, and by an active investment policy.

More specifically, following up on the 2002-2005 plan, an action plan was defined for the 2006-2009 period. This plan is focused on two initiatives for improvement: reducing the frequency and seriousness of on-the-job accidents and managing industrial risks. The results related to reducing on-the-job accidents are in line with goals, with a significant decrease in the rate of accidents (with or without time-lost) per million hours worked by nearly 70% between the end of 2001 and the end of 2006. In terms of industrial risks, this plan’s initiatives include specific organization and behavioral plans as well as plans to minimize risks and increase safety for people and equipment.

Several environmental action plans have been put in place in different activities of the Group covering periods through 2012. These plans are designed to improve environmental performance, particularly regarding the use of natural resources, air and water pollution, waste production and treatment, and site decontamination. They also contain quantified objectives to reduce greenhouse gas emissions, water pollution and sulphur dioxide emissions and to improve energy efficiency. As part of its efforts to reduce greenhouse gases and combat climate change, in December 2006 the Group committed to reducing gas flaring at its Exploration & Production sites by 50% compared to 2005 volumes by 2012. The Group also expects that 75% of its major sites will receive ISO 14001 certification by 2007. These activities are monitored through periodic, coordinated reporting by all Group entities.

Although the Group believes that, according to its current estimates, contingencies or liabilities related to health, safety and environmental concerns would not have a material impact on its consolidated financial situation, its cash flow or its income, due to the nature of such concerns it is impossible to predict if in the future these types of commitments or liabilities could have a material adverse effect on the Group’s activities.

Asbestos

Like many other industrial groups, TOTAL is involved in claims related to occupational diseases caused by asbestos exposure. The circumstances described in these claims generally concern activities prior to the beginning of the 1980s, long before the complete ban on the use of asbestos in most of the countries where the Group operates (January 1, 1997 in France). The Group’s various activities are not particularly likely to lead to significant exposure to asbestos related risks, since this material was generally not used in manufacturing processes, except in limited cases. The main potential sources of exposure are related to the use of certain insulating components in industrial equipment. These components are being gradually eliminated from the Group’s equipment through asbestos-elimination plans that have been underway for several years. However, considering the long period of time that may elapse before the harmful results of exposure to asbestos manifest themselves (up to 40 years), we anticipate that claims may be filed in the years to come. Asbestos related issues have been subject to close monitoring in all branches of the Group. As of December 31, 2006, the Group estimates that the ultimate cost of all asbestos related claims paid or pending is not likely to have a material adverse effect on the financial situation of the Group.

Oil and gas exploration and production operations

Oil and gas exploration and production require high levels of investment and are associated with particular risks and opportunities. These activities are subject to risks related specifically to the difficulties of exploring underground, to the characteristics of hydrocarbons, as well as relating to the physical characteristics of an oil and gas field. The first stage of exploration involves geologic risks. For example, exploratory wells may not result in the discovery of hydrocarbons, or in amounts that would be insufficient to allow for economic development. Even if an economic analysis of estimated hydrocarbon reserves justifies the development of a discovery, the reserves can prove lower than the estimates during the production process, thus adversely affecting the economic development.

Almost all the exploration and production activities of TOTAL are accompanied by a high level of risk of loss of the invested capital. It is impossible to guarantee that new resources of crude oil or of natural gas will be discovered in sufficient amounts to replace the reserves currently being developed, produced and sold to enable TOTAL to recover the capital it has invested.

The development of oil and gas fields, the construction of facilities and the drilling of production or injection wells require advanced technology in order to extract and exploit fossil fuels with complex properties over several decades. The deployment of this technology in such a difficult environment makes cost projections uncertain. TOTAL’s activities can be limited, delayed or cancelled as a result of numerous factors, such as administrative delays, particularly in terms of the host states’ approval processes for development projects, shortages, late delivery of equipment, weather conditions (the production of four fields situated in the Gulf of Mexico were affected by hurricane damage, principally by Hurricane Ivan in September 2004 and, to a lesser degree, by Hurricane Katrina at the end of August 2005). Some of these risks may also affect TOTAL’s projects and facilities further down the oil and gas chain.

Economic or political factors

The oil sector is subject to domestic regulations and the intervention of governments in such areas as:

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the award of exploration and production interests;

•

authorizations by governments or by a state-controlled partner, especially for development projects, annual programs or the selection of contractors or suppliers;

•

the imposition of specific drilling obligations;

•

environmental protection controls ;

•

control over the development and abandonment of a field causing restrictions on production;

•

calculating the costs that may be recovered from the relevant authority and what expenditures are deductible from taxes; and

•

possible, though exceptional, nationalization, expropriation or modification of contract rights.

The oil industry is also subject to the payment of royalties and taxes, which may be high compared with those imposed with respect to other commercial activities and which may be subject to material modifications by the governments of certain countries.

Substantial portions of TOTAL’s oil and gas reserves are located in certain countries, which may be considered

politically and economically unstable. These reserves and the related operations are subject to certain risks, including:

•

the establishment of production and export limits;

•

the renegotiation of contracts;

•

the expropriation or nationalization of assets;

•

risks relating to changes of local governments or resulting changes in business customs and practices;

•

payment delays;

•

currency exchange restrictions;

•

depreciation of assets due to the devaluation of local currencies or other measures taken by governments that might have a significant impact on the value of activities; and

•

losses and impairment of operations due to armed conflicts, civil unrest or the actions of terrorist groups.

TOTAL, like other major international oil companies, has a geographically diverse portfolio of reserves and operational sites, which allows it to conduct its business and financial affairs so as to reduce its exposure to such political and economic risks. However, there can be no assurance that such events will not adversely affect the Group.

Geopolitical situation in the Middle East

In 2006, the Middle East represented 17% of the Group’s production of oil and gas and 7% of the Group’s operating income. The Group produces oil and gas in the United Arab Emirates, Iran, Oman, Qatar, Syria and Yemen. TOTAL cannot predict developments of the geopolitical situation in the Middle East and its potential consequences on the Group’s activities in this area.

Regulations concerning Iran

In September 2006, the U.S. legislation implementing sanctions against Iran and Libya (Iran and Libya Sanction Act, referred to as ILSA), was amended and extended until December 2011. Pursuant to this statute which now concerns only Iran (Iran Sanctions Act, referred to as “ISA”) upon receipt by the United States of information indicating potential violations, the President of the United States is authorized to initiate an investigation into the possible imposition of sanctions (from a list that includes denial of financing by the U.S. Export-Import Bank and limitations on the amount of loans or credits available from U.S. financial institutions) against persons found, in particular, to have knowingly made investments of $20 million or more in any 12 month period in the petroleum sector in Iran. In May 1998, the U.S. government waived the application of sanctions for TOTAL’s investment in the South Pars gas field in Iran.

This waiver, which has not been modified since it was granted, does not address TOTAL’s other activities in Iran, although TOTAL has not been notified of any related sanctions.

In November 1996, the Council of the European Union adopted Council Regulation No. 2271/96 which prohibits TOTAL from complying with any requirement or prohibition based on or resulting directly or indirectly from certain enumerated legislation, including ILSA. It also prohibits TOTAL from extending its waiver for South Pars to other activities.

In each of the years since the passage of ILSA (now ISA), TOTAL has made investments in Iran (excluding South Pars) in excess of $20 million. In 2006, TOTAL’s average daily production in Iran amounted to 20 kboe/d, approximately 1% of its average daily worldwide production. TOTAL expects to continue to invest amounts significantly in excess of $20 million per year in Iran in the foreseeable future. TOTAL cannot predict interpretations of or the implementation policy of the U.S. government under ISA with respect to its current or future activities in Iran. It is possible that the United States may determine that these or other activities constitute activity prohibited by ISA and will subject TOTAL to sanctions.

TOTAL does not believe that enforcement of ISA, including the imposition of the maximum sanctions under the current law and regulations, would have a material negative effect on its results of operations or financial condition.

Furthermore, the United States currently imposes economic sanctions, which are administrated by the U.S. Treasury Department’s Office of Foreign Assets Control and which apply to U.S. persons, with the objective of denying certain countries, including Iran, Syria and Sudan, the ability to support international terrorism and, additionally in the case of Iran and Syria, to pursue weapons of mass destruction and missile programs. TOTAL does not believe that these sanctions are applicable to any of its activities in these countries.

On February 27, 2007, pursuant to resolution 1737 of the Security Council of the United Nations, dated December 23, 2006, the European Union adopted sanctions that restrict the travel of certain individuals associated with Iranian nuclear proliferation activities as well as restricting trade and financing related to these activities. Additionally, a new French decree entered into effect on February 8, 2007 to reinforce the monitoring of financial relations between France and Iran. In addition, the Security Council of the United Nations adopted resolution 1747 on March 24, 2007, which extends the scope of resolution 1737. The Group believes that these measures, under their current terms, are not applicable to TOTAL’s activities in Iran.

Geopolitical and economic situation in South America

In 2006, South America represented 10% of the Upstream segment’s oil and gas production and 5% of the Group’s operating income. The Group produces in Argentina, Bolivia, Colombia, Trinidad & Tobago, and Venezuela.

Circumstances related to the Group’s activities in Argentina, Bolivia and Venezuela are described in more detail above under “—Upstream”.

Competition

The Group is subject to intense competition within the oil sector and between the oil sector and other sectors aiming to fulfill the energy needs of the industry and of individuals. TOTAL is subject to competition from other oil companies in the acquisition of assets and licenses for the exploration and production of oil and natural gas. Competition is particularly strong with respect to the acquisition of undeveloped resources of oil and natural gas, which are in great demand. Competition is also intense in the sale of manufactured products based on crude and refined oil.

In this respect, the main international competitors of TOTAL are ExxonMobil, Royal Dutch Shell, BP and Chevron. At the end of 2006, TOTAL ranked fourth among these international oil companies in terms of market capitalization⁽¹⁾.

Insurance and risk management

Organization

TOTAL has its own insurance and reinsurance company, Omnium Insurance and Reinsurance Company (OIRC). OIRC is totally integrated into the Group’s insurance management and acts as a centralized global operations tool for covering the Group’s risks. It allows the Group to implement its insurance program, notwithstanding the varying regulatory environments in the range of countries where the Group is present.

Certain countries require the purchase of insurance from a local insurance company. When a subsidiary company of the Group is subject to these constraints and is able to obtain insurance from a local company meeting Group standards, OIRC attempts to obtain a retrocession of the covered risks. As a result, OIRC negotiates reinsurance contracts with the subsidiaries’ local insurance companies, which transfer almost all of

(1)

Source: Reuters.

the risk (between 97.5% and 100%) to OIRC. When a local insurer covers the risks at a lower level than that defined by the Group, OIRC provides additional coverage in an attempt to standardize coverage Group-wide. On the other hand, certain countries require insurance in excess of what the Group may deem necessary under Group-wide standards. In these cases, OIRC also provides the additional coverage necessary to satisfy these legal obligations and the Group does not need to turn to an outside insurer.

At the same time, OIRC negotiates a reinsurance program at the Group level with mutual insurance companies for the oil industry and commercial reinsurers. OIRC permits the Group to manage price variations in the insurance market, by taking on a greater or lesser amount of risk corresponding to the price trends in the insurance market.

In 2006, the amount of risk retained by OIRC after reinsurance was $50 million per property insurance incident.

Risk and insurance management policy

In this context, the Group risk and insurance management policy is to work with the relevant internal department of each subsidiary to:

•

define scenarios of major disaster risks by analyzing those events whose consequences would be the most significant for third parties, for employees and for the Group;

•

assess the potential financial impact on the Group in case these disasters occur;

•

implement measures to limit the possibility such events occur and the scope of damage in case of their occurrence; and

•

manage the level of risk from such events that is covered internally by the Group and that which is transferred to the insurance market.

Insurance policy

The Group has worldwide tort and property insurance coverage for all its subsidiaries.

These programs are contracted with first-class insurers (or reinsurers and mutual insurance companies of the oil industry through OIRC).

The amounts insured depend on the financial risks defined in the disaster scenarios discussed above and the coverage terms offered by the market (available capacities and price conditions).

More specifically, for:

•

Third Party Liability insurance: since the maximum financial risk cannot be evaluated using a systemic approach, the amounts insured are based on market conditions and industry practice, in particular, the oil industry. The insurance cap in 2006 for general and product liability was $750 million.

•

Property damages insurance: the amounts insured by sector and by site are based on estimated costs and reconstruction scenarios under the identified worst-case disaster scenarios and on insurance market conditions.

For example, for the highest estimated risk of the Group (the Alwyn field in the UK), the insurance cap was $1.1 billion in 2006.

Moreover, deductibles for material damages fluctuate between 0.1 M€ and 10 M€ depending on the level of risk, and are carried by the subsidiary.

In 2006, as a result of less favorable insurance terms available on the market, the Group did not renew its loss-of-operations coverage. However, in 2007 the Group was able to obtain this coverage for its principal refining and petrochemical sites once again.

The policy described above is given as an example of past practice over a certain period of time and cannot be considered to represent future conditions. The Group’s insurance policy may be changed at any time depending on the market conditions, specific circumstances and on management’s assessment of incurred risks and the adequacy of their coverage. The Group cannot guarantee that it will not suffer any uninsured loss.

Organizational Structure

TOTAL S.A. is the parent company of the TOTAL Group. As of December 31, 2006, there were 718 consolidated subsidiaries, of which 614 were fully consolidated, 13 were proportionately consolidated, and 91 were accounted for under the equity method. For a list of the Principal Subsidiaries of the Company, see Note 33 to the Consolidated Financial Statements.

Property, Plants and Equipment

TOTAL has freehold and leasehold interests in numerous countries throughout the world, none of which is material to TOTAL. See “— Business Overview — Upstream” for a description of TOTAL’s reserves and sources of crude oil and natural gas.

ITEM 4A. UNRESOLVED STAFF COMMENTS

None.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect its future performance. It should be read in conjunction with the Consolidated Financial Statements included elsewhere in this Annual Report. The Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union, which differ in certain respects from U.S. GAAP.

For a description of such differences and a reconciliation of net income and shareholders’ equity to U.S. GAAP, see Note 34 to the Consolidated Financial Statements. This section contains forward-looking statements which are subject to risks and uncertainties. For a list of important factors that could cause actual results to differ materially from those expressed in the forward-looking statements, see “Cautionary Statement Concerning Forward-Looking Statements” on page v.

Overview

TOTAL’s operating results are generally affected by a variety of factors, including changes in crude oil prices and refining margins, which are both generally denominated in dollars, and in exchange rates, particularly the value of the euro against the dollar. Higher crude oil prices generally have a positive effect on the operating income of TOTAL, since its Upstream oil and gas business benefits from the resulting increase in revenues realized from production. Lower crude oil prices generally have a corresponding negative effect. The effect of changes in crude oil prices on TOTAL’s Downstream activities depends upon the speed at which the prices of refined petroleum products adjust to reflect such changes. TOTAL’s operating results are also affected by general economic and political conditions as well as changes in governmental laws and regulations. For more information, see “Item 3. Key Information — Risk Factors” and “Item 4. Information on the Company — Other Matters”.

Pursuant to IFRS, 2006, 2005 and 2004 income statement figures for the Group and the Chemicals segment, with the exception of the Group’s net income, as well as the return on average capital employed (ROACE)⁽¹⁾ for the Chemicals segment, have been recalculated to exclude contributions from the activities of Arkema to the Chemicals segment, which were spun-off in May 2006. These activities are treated as

“discontinued operations”, the results of which are presented on the corresponding line in the income statement.

2004-2006 results

In 2006, TOTAL’s operating income was 24,130 M€, stable compared to 24,169 M€ in 2005 and up from 17,026 M€ in 2004. In 2006, the positive impacts of higher hydrocarbon prices and, to a lesser extent, performance improvements in the Downstream and Chemicals segments were offset by the negative impact of prices on the Downstream segment’s inventory valuation (under the First-In, First-Out method in accordance with IFRS), lower refining margins, lower production volumes, portfolio changes and higher costs (including exploration costs). The 42% increase in operating income in 2005 compared to 2004 was mainly due to the positive impacts of higher hydrocarbon prices, higher European refining margins, generally more favorable market conditions for Chemicals and the lower negative impacts of restructuring and impairment charges on operating income in 2005 compared to 2004. Hurricanes in the Gulf of Mexico had a negative impact on operating income for all segments in 2005. The positive impact of ongoing self-help programs in 2005 offset the negative impacts of higher costs in the Upstream segment and strikes in France.

(1)

ROACE = adjusted net operating income divided by the average capital employed. For more information on ROACE, see “—Results 2004-2006—Business Segment Reporting” below and Note 2 to the Consolidated Financial Statements.

TOTAL’s net income (Group share) was 11,768 M€ in 2006⁽¹⁾ compared to 12,273 M€ in 2005 and 10,868 M€ in 2004. The 4% decrease in net income in 2006 compared to 2005 was mainly due to the after tax impact of prices on inventory valuation (-1.4 B€), the impact of lower volumes and higher costs (-0.8 B€) and the impact of changes in tax rates (-0.4 B€) which were only partially offset by the impacts of a more favorable environment (+1.5 B€), gains from the sale of certain non-strategic financial assets (+0.3 B€) and productivity gains (+0.3 B€). The 13% increase in net income in 2005 compared to 2004 was mainly due to the increase in operating income, which was partially offset by the net negative difference in 2005 compared to 2004 of the impact of items related to TOTAL’s equity share of Sanofi-Aventis and a higher effective tax rate.

The Group’s total expenditures⁽²⁾ were 11,852 M€ in 2006 compared to 11,195 M€ in 2005, and 8,904 M€ in 2004. In 2006, expenditures included approximately 0.8 B€ for acquisitions, principally Ichthys LNG and Tahiti, while expenditures in 2005 included 1.1 B€ in the Upstream segment for the acquisition of Deer Creek Energy Ltd.

Total divestments in 2006 amounted to 2,278 M€ compared to 1,088 M€ in 2005 and 1,192 M€ in 2004. In 2006, divestments included the sale of Upstream assets in the United States and in France as well as the reimbursement of carried investments on Akpo in Nigeria and the sale of non-strategic financial assets. Divestments in 2005 included the sale of 1.85% of the Kashagan permit to KazMunayGas and the sale of TOTAL’s interest in Humber Power in the UK.

In each of the three years, the main source of funding for expenditures was cash from operating activities.

Outlook

In the Upstream segment, TOTAL intends to pursue its strategy of profitable organic growth with the objective of increasing hydrocarbon production by more than 5% per year on average over the period 2006 to 2010⁽³⁾, including production growth of 6% in 2007⁽⁴⁾. This growth is also expected to be particularly significant for

the Group’s LNG activities, which are expected to grow by 13% per year on average. TOTAL’s portfolio of projects offers strong visibility through 2010, due in particular to the number of exploration successes in recent years and to major new projects in LNG and heavy oil.

In the Downstream segment, the Group intends to upgrade its refineries by adding conversion and desulphurization projects and by implementing programs to modernize and improve the reliability of its units.

In petrochemicals, TOTAL’s objective is to continue to increase its polymers production, particularly in Asia and the Middle East, while improving the competitiveness of its operations in mature markets.

Implementing the Group’s growth strategy depends on a sustained investment program. The 2007 budget for investments is approximately 12.8 B€⁽⁵⁾, 75% of which is intended for the Upstream segment.

The net-debt-to-equity ratio⁽⁶⁾ for the Group is targeted to remain in the range of 25% to 30%.

TOTAL intends to pursue a dynamic dividend policy, in line with its strategy for profitable growth over the long term. Future dividends will, however, depend on the Company’s earnings, financial position and other factors⁽⁷⁾. In addition to dividends, the Company expects to continue to buy back its shares using cash flow from operations that is available after paying the dividend and funding the investment program.

Highlights for 2007 are expected to include the ramp-up of production at the Dalia field in Angola and at the distillate hydrocracker at Normandy as well as the start-up of major Upstream projects such as Rosa in Angola and Dolphin in Qatar.

Since the beginning of 2007, the oil and gas market environment has remained generally favorable with oil and gas prices at relatively high levels and refining margins in Europe comparable to the average level of 2006.

(1)

Net income under U.S. GAAP amounted to 11,400 M€ in 2006 compared to 11,597 M€ in 2005 and 7,221 M€ in 2004. For all periods presented, the difference in net income under IFRS and under U.S. GAAP reflected the difference in accounting treatment primarily of goodwill and purchase accounting related to Elf Aquitaine and Petrofina acquisitions and to the Sanofi-Aventis merger, derivative instruments and hedging activities, impairment of assets and employee benefits.

(2)

Total expenditures include intangible assets and property, plant and equipment additions; acquisitions of subsidiaries, net of cash acquired; investments in equity affiliates and other securities; and increases in non-current loans.

(3)

Based on a Brent price of $60/b in 2007 and $40/b thereafter.

(4)

Excluding the effect of portfolio changes.

(5)

Excluding acquisitions and based on $1.25/€.

(6)

This ratio comprises the sum of the Group’s current borrowings and bank overdrafts and its non-current debt, net of cash and cash equivalents and short-term investments, divided by the sum of shareholder’s equity, redeemable preferred shares issued by consolidated subsidiaries and minority interest after expected dividends.

(7)

The payment and amount of dividends are subject to the recommendation of the Board of Directors and resolution by the company’s shareholders. For more information, see “Item 8. Financial Information—Dividend Policy”.

Critical Accounting Policies

A summary of the Group’s accounting policies is included in Note 1 to the Consolidated Financial Statements. Management believes that the application of these policies on a consistent basis enables the Group to report useful and reliable information about the Group’s financial condition and results of operations.

The preparation of financial statements in accordance with IFRS requires management to make estimates and apply assumptions that affect the reported amounts of assets, liabilities and contingent liabilities at the date of preparation of the financial statements and reported income and expenses for the period. Management reviews these estimates and assumptions on an on-going basis, by reference to past experience and various other factors considered as reasonable which form the basis for assessing the book value of assets and liabilities. Actual results may differ significantly from these estimates, if different assumptions or circumstances apply.

Lastly, where the accounting treatment of a specific transaction is not addressed by any accounting standards or interpretation, management applies judgment to define and apply accounting policies that will lead to relevant and reliable information, so that the financial statements:

•

give a true and fair view of the Group’s financial position, financial performance and cash flow;

•

reflect the substance of transactions;

•

are neutral;

•

are prepared on a prudent basis; and

•

are complete in all material aspects.

The following summary provides further information about the critical accounting policies, which could have a significant impact for the results of the Group and should be read in conjunction with Note 1 to the Consolidated Financial Statements.

The assessment of critical accounting policies below is not meant to be an all-inclusive discussion of the uncertainties of financial results that could occur as a result of the application of the Company’s accounting policies. Materially different financial results could occur upon application of different accounting policies. Likewise, materially different results could occur upon the adoption of new accounting standards by various rule-making bodies.

Successful efforts method of oil and gas accounting

The Group follows the successful efforts method of accounting for its oil and gas activities. The Group’s oil and gas reserves are estimated by the Group’s petroleum engineers in accordance with industry standards and SEC regulations. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on available reservoir data and prices and costs in the accounting period during which the estimate is made and are subject to future revision. The Group reassesses its oil and gas reserves at least once a year on all its properties.

Exploration leasehold acquisition costs are capitalized when acquired. During the exploration phase, management exercises judgment on the probability that prospects ultimately would partially or fully fail to find proved oil and gas reserves. On this basis a leasehold impairment charge may be determined. This position is assessed and adjusted throughout the contractual period of the leasehold based in particular on the results of exploratory activity, and the impairment may be adjusted prospectively.

When a discovery is made, exploratory drilling costs continue to be capitalized pending determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. The length of time necessary for this determination depends on the specific technical or economic difficulties in assessing the recoverability of the reserves. If a determination is made that the well did not encounter oil and gas in economically viable quantities, the well costs are expensed and are reported in exploration expense.

Exploratory drilling costs are temporarily capitalized pending determination of whether the well has found proved reserves if both of the following conditions are met:

•

the well has found a sufficient quantity of reserves to justify, if appropriate, its completion as a producing well, assuming that the required capital expenditure is made; and

•

satisfactory progress toward ultimate development of the reserves is being achieved, with the Company making sufficient progress assessing the reserves and the economic and operating viability of the project.

The Company evaluates the progress made on the basis of regular project reviews which take into account the following factors:

•

First, if additional exploratory drilling or other exploratory activities (such as seismic work or other significant studies) are either underway or firmly planned, the Company deems there to be satisfactory progress. For these purposes, exploratory activities are considered firmly planned only if they are included in the Company’s three-year exploration plan/budget. At December 31, 2006, the Company had capitalized 342 M€ of exploratory drilling costs on this basis.

•

In cases where exploratory activity has been completed, the evaluation of satisfactory progress takes into account indicators such as the fact that costs for development studies are incurred in the current period, or that governmental or other third-party authorizations are pending or that the availability of capacity on an existing transport or processing facility awaits confirmation. At December 31, 2006, exploratory drilling costs capitalized on this basis amounted to 77 M€ and mainly related to three projects.

See paragraph N of Note 34 to the Consolidated Financial Statements for additional information.

The successful efforts method, among other things, requires that the capitalized costs for proved oil and gas properties (which include the costs of drilling successful wells) be amortized on the basis of reserves that are produced in a period as a percentage of the total estimated proved reserves. The impact of changes in estimated proved reserves are dealt with prospectively by amortizing the remaining book value of the asset over the expected future production. If proved reserve estimates are revised downward, earnings could be affected by higher depreciation expense or an immediate write-down of the property’s book value. Conversely, if the oil and gas quantities were revised upwards, future per-barrel depreciation and depletion expense would be lower.

Valuation of long-lived assets

In addition to oil and gas assets that could become impaired under the application of successful efforts accounting, other assets could become impaired and require write-down if circumstances warrant. Conditions that could cause an asset to become impaired include

lower-than-forecasted commodity sales prices, changes in the Group’s business plans or a significant adverse change in the local or national business climate. The amount of an impairment charge would be based on estimates of an asset’s fair value compared with its book value. The fair value is usually based on the present values of expected future cash flows using assumptions commensurate with the risks involved in the asset group. The expected future cash flows used for impairment reviews are based on judgmental assessments of future production volumes, prices and costs, considering information available at the date of review.

Asset retirement obligations and environmental remediation

When legal and contractual obligations require it, the Group, upon application of International Accounting Standard (IAS) 37 and IAS 16, records provisions for the future decommissioning of production facilities at the end of their economic lives. Management makes judgments and estimates in recording liabilities. Most of these removal obligations are many years in the future and the precise requirements that will have to be met when the removal event actually occurs are uncertain. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public expectations.

The Group also makes judgments and estimates in recording costs and establishing provisions for environmental clean-up and remediation costs which are based on current information on costs and expected plans for remediation. For environmental provisions, actual costs can differ from estimates because of changes in laws and regulations, public expectations, discovery and analysis of site conditions and changes in clean-up technology.

Pensions and post-retirement benefits

Accounting for pensions and other post-retirement benefits involves judgments about uncertain events, including estimated retirement dates, salary levels at retirement, mortality rates, rates of return on plan assets, determination of discount rates for measuring plan obligations, healthcare cost-trend rates and rates of utilization of healthcare services by retirees. These assumptions are based on the environment in each country. The assumptions used are reviewed at the end of each year and may vary from year-to-year, based on the evolution of the situation, which will affect future results of operations. Any differences between these assumptions and the actual outcome will also impact future results of operations.

The significant assumptions used to account for pensions and other post-retirement benefits are determined as follows:

Discount and inflation rates reflect the rates at which the benefits could be effectively settled, taking into account the duration of the obligation. Indications used in selecting the discount rate include rates of annuity contracts and rates of return on high-quality fixed-income investments (such as government bonds). The inflation rates reflect market conditions observed on a country-by-country basis.

Salary increase assumptions (when relevant) are determined by each entity. They reflect an estimate of the actual future salary levels of the individual employees involved, including future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority, promotion and other factors.

Healthcare cost trend assumptions (when relevant) reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends including healthcare inflation, changes in healthcare utilization, and changes in health status of the participants.

Demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for the individual employees involved, based principally on available actuarial data.

Determination of expected rates of return on assets is made through compound averaging. For each plan, there are taken into account the distribution of investments among bonds, equities and cash and the expected rates of return on bonds, equities and cash. A weighted-average rate is then calculated.

The effect pensions had on results of operations, cash flow and liquidity is set out in Note 18 to the Consolidated Financial Statements. Net periodic benefit charge in 2006 amounted to 297 M€ and the Company’s contributions to pension plans were 617 M€. In 2006, the Group covered certain employee pension benefit plans through insurance companies for an amount of 269 M€.

Differences between projected and actual costs and between the projected return and the actual return on plan assets routinely occur and are called actuarial gains and losses. The Group applies the corridor method to amortize its actuarial losses and gains. This method amortizes the net cumulative actuarial gains and losses that exceed 10% of the greater of (i) the present value of the defined benefit obligation and (ii) the fair value of plan assets, over the average expected remaining working lives of the employees participating in the plan.

The unrecognized actuarial losses of pension benefits as of December 31, 2006 were 423 M€ compared to 777 M€ as of December 31, 2005. The decrease in unrecognized actuarial losses was due to an increase in discount rates in 2006 and was partially offset by actuarial gains due to an increase in the value of plan assets. As explained above, pension accounting principles allow that such actuarial losses be deferred and amortized over future periods, in the Company’s case a period of 15 years.

While the Company has not completed its calculations for 2007, it is considering an increased weighted-average return for the year (6.26% compared to the 2006 rate of 6.14%), mainly due to the increase in discount rates in 2006. The Company does not believe that it will be significantly modifying its discount rate in the near future.

The Company’s estimates indicate that a 1% increase or decrease in the expected rate of return on pension plan assets would have caused a 63 M€ decrease or increase, respectively, in the 2006 net periodic pension cost. The estimated impact on the benefit charge of the amortization of the unrecognized actuarial losses of 423 M€ as of December 31, 2006, is 16 M€ for 2007, compared to 26 M€ in 2006.

Income tax computation

The computation of the Group’s income tax expense requires the interpretation of complex tax laws and regulations in many taxing jurisdictions around the world, the determination of expected outcomes from pending litigation, and the assessment of audit findings that are performed by numerous taxing authorities. Actual income tax expense may differ from management’s estimates.

Results 2004-2006


As of and for the year ended December 31, (M€, except per share data)	2006	2005	2004
Sales^(a)	153,802	137,607	116,842
Operating Income^(a)	24,130	24,169	17,026
Net income (Group share)	11,768	12,273	10,868
Diluted earnings per share^(b)	5.09	5.20	4.48
Total expenditures	11,852	11,195	8,904
Total divestments	2,278	1,088	1,192
Cash flow from operating activities	16,061	14,669	14,662

(a)

Pursuant to IFRS 5, excludes contributions from Arkema.

(b)

Recalculated to reflect the four-for-one stock split on May 18, 2006.

Group Results 2006 vs. 2005

The average oil market environment in 2006 was marked by higher oil prices, with the average Brent oil price increasing 19% to $65.10/b from $54.50/b in 2005, while refining margins decreased, with the European refining margins indicator used by TOTAL’s management (TRCV) down 31% to $28.90/t in 2006 from $41.60/t in 2005. The environment for Chemicals activities was generally comparable over the two years. The average dollar/euro exchange rate was $1.26/€ in 2006 compared to $1.24/€ in 2005.

TOTAL’s consolidated sales increased by 12% to 153.8 B€ in 2006 from 137.6 B€ in 2005.

In 2006, TOTAL’s operating income was 24,130 M€, stable compared to 24,169 M€ in 2005. The positive impacts of higher hydrocarbon prices and, to a lesser extent, performance improvements in the Downstream and Chemicals segments were offset by the negative impacts of prices on the Downstream segment’s inventory valuation (under the First-In, First-Out method in accordance with IFRS), lower refining margins, lower production volumes, portfolio changes and higher costs.

TOTAL’s net income (Group share) was 11,768 M€ compared to 12,273 M€ in 2005. The 4% decrease in net income in 2006 compared to 2005 was mainly due to the after tax impact of prices on inventory valuation (-1.4 B€), the impact of lower volumes and higher costs (-0.8 B€) and the impact of changes in tax rates (-0.4 B€), which were only partially offset by the impacts of a more favorable environment (+1.5 B€), gains from the sale of certain non-strategic financial assets (+0.3 B€) and productivity gains (+0.3 B€).

The effective tax rate for the Group was 56% in 2006 compared to 53% in 2005. The higher rate was mainly due to the increase in UK petroleum taxes, higher hydrocarbon prices, and the larger share of the more heavily taxed Upstream segment in the results.

In 2006, the Group bought back 75.9 million of its shares⁽¹⁾⁽²⁾ for 3,975 M€. The number of fully-diluted shares at December 31, 2006 was 2,285 million compared to 2,344 million at December 31, 2005.

Diluted earnings per share, based on 2,312 million fully-diluted weighted-average shares, decreased 2% to €5.09 in 2006 from €5.20⁽²⁾ in 2005, less than the decrease in net income due to the accretive effect of the share buybacks.

Group Results 2005 vs. 2004

The 2005 oil market environment was more favorable than in 2004. The average Brent oil price increased by 42% to $54.5/b in 2005 from $38.3/b in 2004 and the TRCV refining margins indicator rose sharply to $41.60/t from $32.80/t in 2004. The average dollar/euro exchange rate was unchanged at $1.24/€ . The environment for Chemicals activities was generally more favorable in 2005 than in 2004.

TOTAL’s consolidated sales increased by 18% to 137.6 B€ in 2005 from 116.8 B€ in 2004.

Operating income increased by 42% to 24,169 M€ in 2005 from 17,026 M€ in 2004. The 42% increase in operating income reflects the positive impact of higher hydrocarbon prices, the stronger refining environment and improved market conditions for Chemicals activities.

(1)

Excludes 2.3 million shares reserved for restricted share grants pursuant to the decision of the Board on July 18, 2006.

(2)

Recalculated to reflect the four-for-one stock split on May 18, 2006.

Productivity improvements in the Downstream and Chemicals segments were more than offset by less favorable conditions for marketing activities, the impact of hurricanes in the Gulf of Mexico on the Group’s activities, higher costs in the Upstream segment and the impact of strikes in France. Asset impairment and restructuring charges and provisions, mainly in the Chemicals segment, had a negative impact on operating income of 90 M€ in 2005. In 2004, asset impairment and restructuring charges and provisions had a negative impact of 328 M€ on operating income.

TOTAL’s net income (Group share) was 12,273 M€ in 2005 compared with 10,868 M€ in 2004. The 13% increase in net income in 2005 compared to 2004 was mainly due to the increase in operating income, which was partially offset by the net negative difference between the 542 M€ negative impact on net income in 2005 of TOTAL’s equity share of the amortization of intangibles related to the Sanofi-Aventis merger and of special items recorded by Sanofi-Aventis and the positive impact of 2,286 M€ on net income in 2004 due to a gain on dilution related to the Sanofi-Aventis merger (after taking into account TOTAL’s equity share of the amortization of intangible assets also related to the Sanofi-Aventis merger), as well as the negative impact of the higher effective tax rate in 2005.

Over the course of 2005, the Group bought back 73.2⁽¹⁾ million of its shares, or nearly 3% of its share capital, for 3,485 M€. Diluted earnings per share increased to €5.20^(a) in 2005 from €4.48^(a) in 2004^(a), an increase of 16%, which was higher than the increase in net income due to the accretive effect of share buybacks.

Business Segment Reporting

The financial information for each business segment is reported on the same basis as that used internally by the chief operating decision maker in assessing segment performance and the allocation of segment resources. Due to their particular nature or significance, certain transactions qualified as “special items” are excluded from the business segment figures. In general, special items relate to transactions that are significant, infrequent or unusual. However, in certain instances, certain transactions such as restructuring costs or assets disposals, which are not considered to be representative of the normal course of business, may be qualified as special items although they may have

occurred in prior years or are likely to recur in following years.

In accordance with IAS 2, the Group values inventories of petroleum products in the financial statements according to the FIFO (First-In, First-Out) method and other inventories using the weighted-average cost method. The adjusted results of the Downstream segment and Chemicals segment are presented according to the replacement cost method in order to facilitate the comparability of the Group’s results with those of its competitors, mainly North American. In the replacement cost method, which approximates the LIFO (Last-In, First-Out) method, the variation of inventory value in the income statement is determined by the average prices of the period rather than the historical value. The inventory valuation effect is the difference between the results according to the FIFO method and the replacement cost method. The adjusted business segment results (adjusted operating income and adjusted net operating income) are defined as replacement cost results, adjusted for special items. For further information on the adjustments affecting operating income on a segment-by-segment basis, and for a reconciliation of segment figures to figures reported in the Company’s audited consolidated financial statements, see Note 4 to the Consolidated Financial Statements.

In addition, the Group measures performance at the segment level on the basis of net operating income and adjusted net operating income. Net operating income comprises operating income at the segment level after deducting the amortization and the depreciation of intangible assets other than leasehold rights, translation adjustments and gains or losses on the sale of assets, as well as all other income and expenses related to capital employed (dividends from non-consolidated companies, equity in income in affiliates, capitalized interest expenses), and after income taxes applicable to the above. The income and expenses not included in net operating income which are included in net income are only interest expenses related to long-term liabilities net of interest earned on cash and cash equivalents, after applicable income taxes (net cost of net debt and minority interests). Adjusted net operating income excludes the effect of the adjustments (special items and the inventory valuation effect) described above.

For further discussion on the calculation of net operating income and the calculation of ROACE, see Note 2 to the Consolidated Financial Statements.

(1)

Amounts recalculated to reflect the four-for-one stock split on May 18, 2006.

Upstream results


(M€)	2006		2005		2004
Non-Group sales	20,782		20,888		15,037
Operating income	20,307		18,421		12,844
Equity in income (loss) of affiliates and other items	1,211		587		148
Tax on net operating income	(12,764	)	(10,979	)	(7,281	)
Net operating income	8,754		8,029		5,711
Adjustments affecting net operating income	(45	)	—		148
Adjusted net operating income^(a)	8,709		8,029		5,859
Total expenditures	9,001		8,111		6,202
Total divestments	1,458		692		637

ROACE	35%		40%		36%

(a)

Adjusted for special items.

2006 vs. 2005

Upstream segment sales (excluding sales to other segments) were 20,782 M€ in 2006 compared to 20,888 M€ in 2005. The increase in TOTAL’s average liquids price realization to $61.80/b in 2006 from $51.00/b in 2005 was globally in line with the increase in the average price of Brent oil, which was $65.10/b in 2006 compared to $54.50/b in 2005. TOTAL’s average gas price realization increased to $5.91/MBtu in 2006 from $4.77/Mbtu in 2005, comparatively greater than the percentage increase for liquids price realizations due to the delayed impact of oil prices on gas price formulas under long-term contracts, mainly in Europe, and strong LNG prices in Asia.

For 2006, adjusted net operating income for the Upstream segment was 8,709 M€ compared to 8,029 M€ in 2005, an increase of 8%. The contribution of income from equity affiliates rose sharply, reflecting mainly the growth in LNG activities, particularly the larger contribution from trains 4 and 5 at Nigeria LNG. The increase of 0.7 B€ compared to 2005 was mainly due to the 2 B€ positive impact of higher hydrocarbon prices, partially offset by the negative impact of lower production volumes and effects of portfolio changes, (approximately 0.5 B€), higher production costs (approximately 0.4 B€, including 0.2 B€ for exploration) and the impact of changes in tax terms (approximately 0.4 B€).

The exclusion of special items (which in 2006 comprised capital gains on asset disposals) had a negative impact of 45 M€ on adjusted net operating income for the

Upstream segment in 2006. There were no adjustments affecting Upstream net operating income in 2005.

ROACE for the Upstream segment was 35% in 2006 compared to 40% in 2005. The decline was mainly due to an increase in the level of capital employed for work-in-progress assets, which reflects the sustained level of investments being made to fuel future growth.

In 2006, Upstream net operating income amounted to 8,754 M€ (for 2005, 8,029 M€) from operating income of 20,307 M€ (for 2005, 18,421 M€), with the difference resulting primarily from taxes on net operating income of 12,764 M€ (for 2005, 10,979 M€), partially offset by income from equity affiliates and other items of 1,211 M€ (for 2005, 587 M€). The increase in taxes in 2006 occured primarily in the UK and Venezuela.

Oil and gas production in 2006 was 2,356 kboe/d compared to 2,489 kboe/d in 2005, a decrease of 5% due principally to the impacts of the price effect⁽¹⁾ (-2%), shutdowns of production in the Niger Delta area because of security issues (-2%) and changes in the Group’s perimeter (-1%). Excluding these items, the positive impact of new field start-ups was offset by normal production declines at mature fields and shutdowns in the North Sea.

The Upstream segment’s proved reserves at December 31, 2006 increased slightly to 11,120 Mboe

from 11,106 at December 31, 2005. At current rates of production, these reserves represent approximately

(1)

The “price effect” refers to the impact of hydrocarbon prices on entitlement volumes from production sharing and buyback contracts.

13 years of production. See “Item 4. Information on the Company — Exploration & Production — Reserves ” for a table showing changes in proved reserves by year and “Supplemental Oil and Gas Information (Unaudited)” contained elsewhere herein for additional information on proved reserves, including tables showing changes in proved reserves by region.

Total expenditures of the Upstream segment increased by 11% to 9,001 M€ in 2006 from 8,111 M€ in 2005. In 2006, expenditures mainly included the following projects: Kashagan (Kazakhstan), Yemen LNG (Yemen), Ekofisk and Snøhvit (Norway), Dalia and Rosa (Angola), Akpo (Nigeria), Tunu/Tambora (Indonesia), Moho Bilondo (Congo), Dolphin and Qatargas II (Qatar), Surmont and Joslyn (Canada) and Tahiti (United States).

Strategically, TOTAL plans to continue to increase the weight of the Upstream segment within its overall activities. The Group’s priority is to increase its hydrocarbon production, notably through the development of large projects, including conventional oil and gas, midstream gas, LNG, and enhanced recovery projects, while maintaining high profitability.

2005 vs. 2004

Upstream segment sales (excluding sales to other segments) were 20,888 M€ in 2005 compared to 15,037 M€ in 2004, reflecting the positive impact of higher hydrocarbon prices, which were only partially offset by a decline in production volumes notably due to hurricanes in the Gulf of Mexico and maintenance in the North Sea.

Adjusted net operating income from the Upstream segment increased by 37% to 8,029 M€ in 2005 from 5,859 M€ in 2004. This nearly 2.2 B€ increase in adjusted net operating income from the Upstream segment was due to an estimated positive impact of 2.4 B€ from the stronger oil and gas market environment which was partially offset by an estimated negative impact of approximately 0.15 B€ from lower production, excluding the effect of higher hydrocarbon prices on entitlement volumes under production sharing and buyback contracts, that was essentially due to hurricanes in the Gulf of Mexico, and by other factors, including higher costs, with an estimated negative impact of less than 0.1 B€.

There were no adjustments affecting Upstream net operating income in 2005. In 2004, the exclusion of special items (comprised primarily of asset impairment charges) had a positive impact of 148 M€ on adjusted net operating income.

Upstream ROACE was 40% in 2005 compared to 36% in 2004, reflecting primarily the increase in adjusted net operating income.

In 2005, net operating income amounted to 8,029 M€ (for 2004, 5,711 M€) from operating income of 18,421 M€ (for 2004, 12,844 M€), with the difference resulting primarily from taxes on net operating income of 10,979 M€ (for 2004, 7,281 M€), offset by income from equity affiliates and other items of 587 M€ (for 2004, 148 M€).

Oil and gas production declined by 3.7% to 2,489 kboe/d in 2005 from 2,585 kboe/d in 2004. Adjusted for the negative impact of higher oil and gas prices on entitlement volumes from production sharing and buyback contracts and excluding the impact of the hurricanes in the Gulf of Mexico, the Group’s production remained stable in 2005 compared to 2004. Production growth mainly from Venezuela, Libya, Indonesia, Trinidad & Tobago and Argentina was offset by decreases in the North Sea (due, in particular, to the decommissioning of Frigg) and Syria.

The Upstream segment’s proved reserves declined by 0.4% to 11,106 Mboe at December 31, 2005 from 11,148 Mboe at December 31, 2004. This slight decline includes the negative impact of the higher year-end 2005 price on the calculation of proved reserves.

Total expenditures of the Upstream segment increased by 31% to 8,111 M€ in 2005 from 6,202 M€ in 2004. In 2005, expenditures mainly included the following projects: Kashagan in Kazakhstan; Ekofisk and Snøhvit in Norway; Dalia, Rosa and BBLT in Angola; Tunu-Tambora in Indonesia; Dolphin in Qatar; Forvie in the UK; Akpo and Bonga in Nigeria. In 2005, 1.1 B€ was dedicated to the acquisition of Deer Creek Energy Ltd in Canada. In 2004, capital expenditures were made mainly in France, Angola, Nigeria, Norway, Kazakhstan, the United States and Venezuela.

Downstream results


(M€)	2006		2005		2004
Non-Group sales	113,887		99,934		86,896
Operating income	3,372		5,096		3,638
Equity in income (loss) of affiliates and other items	384		422		95
Tax on net operating income	(1,125	)	(1,570	)	(1,131	)
Net operating income	2,631		3,948		2,602
Adjustments affecting net operating income	153		(1,032	)	(271	)
Adjusted net operating income^(a)	2,784		2,916		2,331
Total expenditures	1,775		1,779		1,675
Total divestments	428		204		200
ROACE	23%		28%		25%

(a)

Adjusted for special items and the inventory valuation effect.

2006 vs. 2005

Downstream segment sales (excluding sales to other segments) increased to 113,887 M€ in 2006 compared to 99,934 M€ in 2005.

In 2006, refined product sales averaged 3,786 kbd, stable compared to 2005. 2006 refinery throughput increased 2% to 2,454 kb/d compared to 2,410 kb/d in 2005. The refinery utilization rate for 2006 remained at 88%, the same as in 2005. There are more major turnarounds scheduled for 2007 than there were in 2006, but most of these turnarounds will only partially affect the refineries involved.

For 2006, adjusted net operating income for the Downstream segment decreased 5% to 2,784 M€ compared to 2,916 M€ in 2005. The decrease was due to a weaker refining environment, partially offset by favorable market effects, which had a negative impact estimated at 0.5 B€. Performance improvement contributed 0.2 B€ and volumes recuperated from losses in 2005 (due to strikes in France and the aftermath of Hurricane Rita in the United Sates) added an estimated 0.2 B€.

The adjustment for the inventory valuation effect had a positive impact on adjusted net operating income of 327 M€ in 2006 compared to a negative impact of 1,032 M€ in 2005. The exclusion of special items in 2006 (relating to capital gains on the sale of certain non-strategic financial interests) had a negative impact of 174 M€ on Downstream adjusted net operating income, while there were no Downstream special items in 2005.

ROACE for the Downstream segment was 23% in 2006 compared to 28% in 2005 due principally to weaker refining margins.

In 2006, Downstream net operating income declined to 2,631 M€ (for 2005, 3,948 M€) from operating income of 3,372 M€ (for 2005, 5,096 M€), with the difference

resulting primarily from taxes on net operating income of 1,125 M€ (for 2005, 1,570 M€), partially offset by income from equity affiliates and other items of 384 M€ (for 2005, 422 M€).

Total expenditures by the Downstream segment were 1,775 M€ in 2006 compared to 1,779 M€ in 2005. Downstream investments in 2006 included approximately 1 B€ in refining (excluding turnarounds).

2005 vs. 2004

Downstream segment sales (excluding sales to other segments) increased to 99,934 M€ in 2005 compared to 86,896 M€ in 2004.

Refinery throughput declined by 3% to 2,410 kb/d in 2005 from 2,496 kb/d in 2004. The refinery utilization rate fell to 88% in 2005 from 92% in 2004 largely due to the effect of strikes in France and Hurricane Rita in the United States. Excluding the impact of the strikes and Hurricane Rita, the refinery utilization rate would have been 91%, slightly lower than the rate in 2004 due to a larger program of major turnarounds.

Adjusted net operating income from the Downstream segment rose to 2,916 M€ in 2005 from 2,331 M€ in 2004, an increase of 25%. The stronger Downstream environment had a positive impact estimated at 0.6 B€. Self-help programs contributed approximately 0.1 B€, but this contribution was more than offset by an estimated 0.2 B€ negative impact from strikes in France and Hurricane Rita in the United States. The inventory valuation effect had a negative impact on adjusted net operating income of 1,032 M€ in 2005 and 349 M€ in 2004.

There were no special items in the Downstream segment in 2005 while in 2004 the exclusion of special items had a positive impact of 78 M€ on adjusted net operating income from the Downstream segment.

Downstream ROACE increased to 28% in 2005 from 25% in 2004, reflecting primarily the increase in adjusted net operating income.

In 2005, net operating income amounted to 3,948 M€ (for 2004, 2,602 M€) from operating income of 5,096 M€ (for 2004, 3,638 M€), with the difference resulting primarily from taxes on net operating income of 1,570 M€ (for 2004, 1,131 M€), offset by income from equity affiliates and other items of 422 M€ (for 2004, 95 M€).

Total expenditures by the Downstream segment were 1,779 M€ in 2005 compared to 1,675 M€ in 2004. Downstream investments in 2005 included 0.2 B€ for the construction of the distillate hydrocracker at the Normandy refinery, which began operations in 2006, as well as the acquisition of marketing activities in 14 African countries.

Chemicals⁽¹⁾


(M€)	2006		2005		2004
Non-Group sales	19,113		16,765		14,886
Operating income	996		1,119		893
Equity in income (loss) of affiliates and other items	(298	)	(348	)	(170	)
Tax on net operating income	(191	)	(170	)	(73	)
Net operating income	507		601		650
Adjustments affecting net operating income	(377	)	(366	)	(286	)
Adjusted net operating income^(a)	884		967		936
Total expenditures	995		1,115		949
Total divestments	128		59		122
ROACE	13%		15%		15%

(a)

Adjusted for special items and the inventory valuation effect.

2006 vs. 2005

Chemicals segment sales (excluding sales to other segments) increased by 14% to 19,113 M€ in 2006 from 16,765 M€ in 2005.

Adjusted net operating income for the Chemicals segment decreased by 9% to 884 M€ from 967 M€ in 2005, due principally to the impact of deferred tax credits related to Arkema activities, which amounted to 18 M€ in 2006 compared to 151 M€ in 2005, slightly offset by the positive impact of growth and productivity programs.

The adjustment for the inventory valuation effect had a positive impact on adjusted net operating income for the Chemicals segment of 28 M€ in 2006, compared to a negative impact of 50 M€ in 2005. In 2006, the exclusion of special items (comprised mainly of restructuring charges and asset impairments) had a positive impact of 349 M€ on adjusted net operating income. In 2005, the exclusion of special items (comprised mainly of restructuring charges, impairments and provisions for environmental liabilities in the Chemicals segment) had a positive impact of 416 M€ on adjusted net operating income. For further information on the impairment charges, including facts and circumstances giving rise to certain of them, see paragraph D of Note 4 to the Consolidated Financial Statements.

ROACE for the Chemicals segment was 13% in 2006 compared to 15% in 2005 (12% in 2005 excluding the deferred tax credits related to Arkema).

In 2006, net operating income amounted to 507 M€ (for 2005, 601 M€) from operating income of 996 M€ (for 2005, 1,119 M€), with the difference resulting primarily from losses from equity affiliates and other items of 298 M€ (for 2005, a loss of 348 M€), as well as from taxes on net operating income of 191 M€ (for 2005, 170 M€).

Total expenditures by the Chemicals segment decreased to 995 M€ in 2006 compared to 1,115 M€ in 2005. In 2006, 49% of these expenditures were for Base Chemicals, 42% for Specialties and 8% for Arkema activities which were spun off in May 2006.

2005 vs. 2004

Chemicals segment sales (excluding sales to other segments) increased by 13% to 16,765 M€ in 2005 from 14,886 M€ in 2004, primarily in response to an overall improved market environment for Chemicals.

Adjusted net operating income from the Chemicals segment was 967 M€ in 2005 compared to 936 M€ in 2004, reflecting improvement in the operating income from the Base Chemicals and Specialities activities.

(1)

Pursuant to IFRS 5, income statement data and ROACE have been recalculated to exclude Arkema.

Market conditions for base chemicals were volatile during 2005, with a very favorable first quarter in 2005 followed by margin weakness resulting from erratic customer demand linked to volatile raw material prices. Specialities performed well despite higher raw material costs.

The adjustment for the inventory valuation effect had a negative impact on adjusted net operating income for the Chemicals segment of 50 M€ in 2005 and 157 M€ in 2004. In 2005, the exclusion of special items (comprised mainly of restructuring charges, impairments and provisions for environmental liabilities in the Chemicals segment) had a positive impact of 416 M€ on adjusted net operating income. In 2004, the exclusion of special items had a positive impact of 443 M€ on adjusted net operating income. For further information on the

impairment charges, including facts and circumstances giving rise to certain of them, see paragraph D of Note 4 to the Consolidated Financial Statements.

Chemicals ROACE was 15% in 2005 compared to 15% in 2004.

In 2005, net operating income amounted to 601 M€ (for 2004, 650 M€) from operating income of 1,119 M€ (for 2004, 893 M€), with the difference resulting primarily from losses from equity affiliates and other items of 348 M€ (for 2004, a loss of 170 M€), as well as from taxes on net operating income of 170 M€ (for 2004, 73 M€).

Total expenditures by the Chemicals segment increased to 1,115 M€ in 2005 compared to 949 M€ in 2004. Capital expenditures in both years were made mainly in Europe, the United States and Asia.

Liquidity And Capital Resources

TOTAL’s cash requirements for working capital, share buybacks, capital expenditures and acquisitions over the past three years were financed primarily by a combination of funds generated from operations, borrowings and divestments of non-core assets. The Group continually monitors the balance between cash flow from operating activities and net expenditures. In the Company’s opinion, its working capital is sufficient for its present requirements.

The largest part (approximately 90%) of TOTAL’s capital expenditures are made up of additions to intangible assets and property, plant and equipment, with the remainder attributable to acquisitions of subsidiaries and equity-method affiliates. In the Upstream segment, as described in more detail under “Supplemental Oil and Gas Information — Costs incurred”, capital expenditures are principally development costs (approximately 75% mainly for construction of new production facilities), exploration expenditures (successful or unsuccessful, approximately 11%) and acquisitions of proved and unproved properties (approximately 3%). In the Downstream segment, about 45% of capital expenditures are related to refining activities (essentially 51% for upgrading units and 49% for new construction), the balance being used in marketing/retail activities and for information systems. In the Chemicals segment, capital expenditures relate to all activities, and are split between upgrading units (approximately 80%) and new construction (approximately 20%).

For detailed information on expenditures by business segment, please refer to the discussion of Company Results for each segment above.

Total expenditures were 11,852 M€ in 2006, up 6% from 11,195 M€ in 2005 after increasing 26% from 8,904 M€

in 2004. During 2006, 76% of the expenditures were made by the Upstream segment, 15% by the Downstream segment, 8% by the Chemicals segment and 1% by Corporate. During 2005, 72% of the expenditures were made by the Upstream segment, 16% by the Downstream segment, 10% by the Chemicals segment and 2% by Corporate. During 2004, 71% of the expenditures were made by the Upstream segment, 18% by the Downstream segment, 10% by the Chemicals segment and 1% by Corporate. The main source of funding for these expenditures has been cash from operating activities.

Cash flow from operating activities was 16,061 M€ in 2006 compared to 14,669 M€ in 2005 and 14,662 M€ in 2004. TOTAL’s non-current financial debt was 14,174 M€ at year-end 2006 compared to 13,793 M€ at year-end 2005 and 11,289 M€ at year-end 2004. For further information on the Company’s level of borrowing and the type of financial instruments, including maturity profile of debt and currency and interest rate structure, see Note 20 to the Consolidated Financial Statements. For further information on the Company’s treasury policies, including the use of instruments for hedging purposes and the currencies in which cash and cash equivalents are held, see “Item 11. Quantitative and Qualitative Disclosures about Market Risk”.

Total divestments, based on selling price and net of cash sold, were 2,278 M€ in 2006 compared to 1,088 M€ in 2005 and 1,192 M€ in 2004. In 2006, the Group sold certain Upstream assets in the U.S. and in France, was reimbursed for carried investments on Akpo in Nigeria and sold certain non-strategic financial interests. In 2005, the Group sold an interest of 1.85% in Kashagan to KazMunayGas and its interest in the UK

power generation company Humber Power. In 2004, TOTAL sold certain financial assets and non-strategic operating assets in the Upstream, Downstream and Chemicals segments and also transferred certain assets to Gaz de France in an asset swap.

Shareholders’ equity remained stable at 41,148 M€ at December 31, 2006 from 41,483 M€ at December 31, 2005 after increasing from 32,418 M€ at December 31, 2004. Changes to shareholders’ equity in 2006 were due primarily to the addition of net income, offset by the payment of the annual dividend, cancellation of treasury shares, the spin-off of Arkema and translation adjustments. During 2006, TOTAL repurchased 75.9⁽¹⁾⁽²⁾ million of its own shares for 3,975 M€. Changes to shareholders’ equity in 2005 were due primarily to the addition of net income, offset by the cancellation of treasury shares, the payment of the annual dividend and translation adjustments. During 2005, TOTAL repurchased 73.2⁽²⁾ million of its own shares for 3.5 B€. During 2004, TOTAL repurchased 90.2⁽²⁾ million of its own shares for approximately 3.6 B€.

As of December 31, 2006, TOTAL’s net-debt-to-equity ratio, which is the sum of its current borrowings, net

current financial instruments and non-current financial debt net of its hedging instruments of non-current financial debt, cash and cash equivalents divided by the sum of shareholders’ equity, redeemable preferred shares issued by consolidated subsidiaries and minority interest after expected dividends, was 34% compared to 32% and 31% at year-end 2005 and year-end 2004, respectively. Over the 2004-2006 period, TOTAL used its net cash flow (cash flow from operating activities less total expenditures plus total divestments) to maintain this ratio in its target range of around 25 to 30%, primarily by managing net debt (financial short-term debt plus non-current debt less cash and cash equivalents), while higher net income increased shareholders’ equity and repurchases and cancellations of shares decreased shareholders’ equity. As of December 31, 2006, TOTAL S.A. had $7,701 million of long-term confirmed lines of credit, of which $7,649 million were unused.

In 2007, the Company expects to use net cash flow after dividends to maintain its net debt-to-equity ratio in the targeted range of around 25 to 30% and to continue to repurchase shares of the Company depending on the market environment and the level of divestments.

Off-balance Sheet Arrangements

Neither TOTAL S.A. nor any other members of the Group has any off-balance sheet arrangements that currently have or are reasonably likely to have in the future a material effect on the Group’s financial condition, changes in financial condition, revenues or expenses, results of operation, liquidity, capital expenditure or capital resources. See Note 23 to the Consolidated Financial Statements for information on the Company’s commitments and contingencies.

(1)

Excludes 2.3 million shares reserved for restricted share grants pursuant to the decision of the Board on July 18, 2006.

(2)

Amounts recalculated to reflect the four-for-one stock split on May 18, 2006.

Contractual Obligations


Payment due by period (M€)	Less than 1 year	1-3 years	3-5 years	More than 5 years	Total

Non-current debt obligations^(a)	—	4,501	6,047	2,769	13,317
Current debt obligations^(b)	2,140	—	—	—	2,140
Capital (finance) lease obligations^(c)	29	96	89	186	400
Asset retirement obligations^(d)	221	226	350	3,096	3,893
Operating lease obligations^(c)	381	685	399	422	1,887
Purchase obligations^(e)	3,551	4,886	4,810	24,080	37,327
Total	6,322	10,394	11,695	30,553	58,964

(a)

Non-current debt obligations are included in the items “Non-current financial debt” and “Hedging instruments of non-current financial debt” of the balance sheet. It includes the non-current portion of issue swaps and swaps hedging debenture loans, and excludes non-current capital lease obligations of 371 M€.

(b)

The current portion of non-current debt is included in the items “Current borrowings” , “Other current financial liabilities” and “Current financial assets” of the balance sheet. It includes the current portion of issue swaps and swaps hedging debenture loans and excludes the current portion of capital lease obligations of 29 M€.

(c)

Capital (finance) lease obligations and operating lease obligations: the Group leases real estate, service stations, ships, and other equipment through non-cancelable capital and operating leases. These amounts represent the future minimum lease payments on non-cancelable leases to which the Group is committed as of December 31, 2006, less the financial expenses due on capital (finance) lease obligations for 87 M€.

(d)

The discounted present value of upstream asset retirement obligations, primarily asset removal costs at the completion date.

(e)

Purchase obligations are obligations under contractual agreements to purchase goods or services, including capital projects, that are enforceable and legally binding on the Company, and that specify all significant terms, including the amount and the timing of the payments. These obligations include mainly: hydrocarbon unconditional purchase contracts (except where an active, highly-liquid market exists and which are expected to be re-sold shortly after purchase), booking of transport capacities in pipelines, unconditional exploration works and development works in Upstream, and contracts for capital investment projects in Downstream. This disclosure does not include contractual exploration obligations with host states where a monetary value is not attributed and purchases of booking capacities in pipelines where the Group has a participation superior to the capacity used.

The Group has other obligations in connection with pension plans which are described in Note 18 to the Consolidated Financial Statements. As these obligations are not contractually fixed as to timing and amount, they have not been included in this disclosure. Other non-current liabilities, detailed in Note 19 to the Consolidated Financial Statements, are liabilities related to risks that are probable and amounts that can be reasonably estimated. However, no contractual agreements exist related to the settlement of such liabilities, and the timing of the settlement is not known.

Research and Development

The Group strategy for research and development is focused on its three business segments, principally in the following areas:

•

Exploration & Production technology to allow access, at acceptable costs, to new energy resources (high-pressure/high-temperature, deep offshore, heavy crude oils, polyphasic transportation, acidic gas), as well as environment-friendly technologies such as reduction of greenhouse gas emissions, capture and sequestration of CO₂ produced by the Group’s units, containment of acidic gas emissions and efficient use of water in the upstream industrial process.

•

Refining technology to allow the identification, anticipation and the reduction of constraints linked to the operation of facilities, the evolution of

specifications and the control of environmental emissions, including by exploiting biofuels and, more generally, bioenergy, and marketing technology allowing the creation of innovative products representing sales opportunities.

•

Chemical processes to increase competitiveness, quality, safety and respect of the environment, in particular on the following themes: new catalyst and polymerization technologies, new products (bio-polymers and bio-degradable polymers, elastomers, anti-vibration systems, new coatings) as well as nano-technologies.

Research and development costs amounted to 569 M€ in 2006 (or 0.4% of sales) compared to 676 M€ in 2005 (or 0.5% of sales) and 635 M€ in 2004. The number of employees dedicated to research and development activities in 2006 was 4,091 compared to 5,312 in 2005 and 5,257 in 2004.

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

Directors and Senior Management

Members of the Board of Directors

The following individuals were members of the Board of Directors of TOTAL S.A. in 2006:

(Information as of December 31, 2006)

Thierry Desmarest

61 years old.

A graduate of the École Polytechnique and a Mining Engineer, Mr. Desmarest served as Director of Mines and Geology in New Caledonia, then as technical advisor on the staffs of the Minister of Industry and the Minister of Economy. He joined TOTAL in 1981, where he held various management positions, then served as President of Exploration and Production until 1995. He served as Chairman and Chief Executive Officer of TOTAL from May 1995 until February 2007, and continues to serve as Chairman of the Board of TOTAL.

Director of TOTAL S.A. since 1995 and until 2007.

Holds 477,200 shares.

Principal other directorships

•

Chairman and Chief Executive Officer of Elf Aquitaine.

•

Director of Sanofi-Aventis.*

•

Member of the Supervisory Board of AREVA.*

•

Member of the Supervisory Board and then Director of Air Liquide.*

Daniel Boeuf

58 years old.

A graduate of the Ecole Supérieure des Sciences Economiques et Commerciales (ESSEC), Mr. Boeuf joined the Group in October 1973 and served in several sales positions before holding various operational positions in Refining & Marketing entities. He is currently responsible for training and skills management in specialties within the Refining & Marketing division. An elected member of the Supervisory Board of the TOTAL ACTIONNARIAT FRANCE employee investment fund since 1999, he served as the Chairman of its Supervisory Board from 2003 to 2006.

Director of TOTAL S.A. since 2004 and until 2007.

Holds 2,400 TOTAL shares and 3,112 shares of the TOTAL ACTIONNARIAT FRANCE employee investment fund.

*	*Publicly listed company.*

Daniel Bouton⁽¹⁾

56 years old.

Inspector General of Finance, Mr. Bouton has held various positions within the French Ministry of Economy. He served as Budget Director at the Ministry of Finance from 1988 to 1990. He joined Société Générale in 1991, where he was appointed Chief Executive Officer in 1993, then Chairman and Chief Executive Officer in November 1997.

Director of TOTAL S.A. since 1997 and until 2009.

Holds 3,200 shares.

Principal other directorships

•

Chairman and Chief Executive Officer of Société Générale.*

•

Director of Veolia Environnement.*

Bertrand Collomb

64 years old.

A graduate of the École Polytechnique and a Mining Engineer, Mr. Collomb held a number of positions within the Ministry of Industry and other staff positions from 1966 to 1975. He joined the Lafarge group in 1975, where he served in various management positions. He served as Chairman and Chief Executive Officer of Lafarge from 1989 to 2003, then as Chairman of the

Lafarge Board of Directors. He is also President of the French association of private-sector companies (AFEP).

Director of TOTAL S.A. since 2000 and until 2009.

Holds 4,712 shares.

Principal other directorships

•

Chairman of the Board of Directors of Lafarge.*

Paul Desmarais Jr.⁽²⁾

52 years old.

A graduate of McGill University in Montreal and INSEAD in Fontainebleau, Mr. Desmarais was elected Vice Chairman (1984) then Chairman of the Board (1990) of Corporation Financière Power, a company he helped to found. Since 1996, he has served as Chairman of the Board and Co-Chief Executive Officer of Power Corporation of Canada.

Director of TOTAL S.A. since 2002 and until 2008.

Holds 2,000 ADRs (corresponding to 2,000 shares).

Principal other directorships

•

Chairman of the Board and Co-Chief Executive Officer of Power Corporation of Canada.*

•

Chairman of the Executive Committee and Member of the Board of Corporation Financière Power (Canada).*

•

Vice-Chairman and Deputy Managing Director of Pargesa Holding S.A. (Switzerland).*

•

Vice-Chairman of the Board of Directors and member of the Strategic Committee of Imerys (France).*

•

Member of the Board of Directors and Executive Committee of Groupe Bruxelles Lambert S.A. (Belgium).*

•

Director of Suez (France).*

•

Director of Power Corporation International.

*	*Publicly listed company.*

(1)

Mr. Bouton is Chairman and Chief Executive Officer of Société Générale, which, to the Company’s knowledge, owns less than 0.1% of the Company’s shares and less than 0.1% of the voting rights. Mr. Bouton disclaims beneficial ownership of such shares.

(2)

Mr. Desmarais Jr. is a Director of Groupe Bruxelles Lambert (Belgium), which acting in concert with Compagnie Nationale à Portefeuille and other entities, to the Company’s knowledge, owns 5.3% of the Company’s shares and 5.4% of the voting rights. Mr. Desmarais Jr. disclaims beneficial ownership of such shares.

Jacques Friedmann

74 years old.

Director of TOTAL S.A. since 2000 and until May 12, 2006.

Bertrand Jacquillat

62 years old.

A graduate of École des Hautes Études Commerciales (HEC), Institut d’études politiques de Paris and Harvard Business School, Mr. Jacquillat holds both a PhD and an agrégé in management. He has been a university professor (France and the United States) since 1969, and has been on the faculty of the Institut d’Études politiques de Paris since 1999.

Director of TOTAL S.A. since 1996 and until 2008.

Holds 3,600 shares.

Principal other directorships

•

Chairman and Chief Executive Officer of Associés en Finance.

•

Member of the Supervisory Board of Klepierre.*

•

Member of the Supervisory Board of Presses Universitaires de France (PUF).

Antoine Jeancourt-Galignani

69 years old.

Inspector of Finance, Mr. Jeancourt-Galignani held various positions within the Ministry of Finance before serving as Deputy Managing Director of Crédit Agricole from 1973 to 1979. He became chief executive officer of Indosuez bank in 1979 before serving as its Chairman from 1988 to 1994. He then served as Chairman of Assurances Générale de France (AGF) from 1994 to 2001, before serving as Chairman of Gecina from 2001 to 2005, where he currently serves as a director.

Director of TOTAL S.A. since 1994 and until 2009.

Holds 4,440 shares.

Principal other directorships

•

Chairman of the Supervisory Board of Euro Disney SCA.*

•

Director of Gecina.*

•

Director of Assurances Générale de France.*

•

Director of Kaufman & Broad S.A.*

•

Director of Société Générale.*

Anne Lauvergeon⁽¹⁾

47 years old.

Chief Mining Engineer and a graduate of the École Normale Supérieure with a doctorate in physical sciences, Mrs. Lauvergeon held various positions with Usinor, the French Atomic Energy Commission (CEA) and then with the Paris region subsoil assets administration (1985-1988). Deputy Chief of Staff in the Office of the President of the Republic from 1990 to 1995, she then joined Lazard Frères et Cie from 1995 to 1997 as Managing Partner. She joined Alcatel before becoming Chairman of Cogema in June 1999. Since July 2001, she has been Chairman of the Management Board of AREVA.

Director of TOTAL S.A. since 2000 and until 2009.

Holds 2,000 shares.

Principal other directorships

•

Chairman of the Managment Board of AREVA.*

•

Director of Suez.*

•

Director of VODAFONE Group Plc.*

•

Vice-President and Member of the Supervisory Board of Safran.*

*	*Publicly listed company.*

(1)

Ms. Lauvergeon is Chairman of the Managing Board of Areva, which, to the Company’s knowledge, owns 0.3% of the Company’s shares and 0.6% of the voting rights. Ms. Lauvergeon disclaims beneficial ownership of such shares.

Lord Peter Levene of Portsoken

65 years old.

Lord Levene served in various positions within the Ministry of Defense, the office of the Secretary of State for the Environment, and the Ministry of Trade in the UK from 1984 to 1995. He then served as senior adviser at Morgan Stanley from 1996 to 1998 before becoming the Chairman of Bankers Trust International from 1998 to 2002. He was Lord Mayor of London from 1998 to 1999. He is currently Chairman of Lloyd’s.

Director of TOTAL S.A. since 2005 and until 2008.

Holds 2,000 shares.

Principal other directorships

•

Chairman of Lloyd’s.

•

Chairman of International Financial Services.

•

Chairman of General Dynamics UK Ltd.

•

Director of Haymarket Group Ltd.

•

Director of China Construction Bank.*

Maurice Lippens

63 years old.

Mr. Lippens holds a law degree from the Université Libre de Bruxelles and is a graduate of Harvard Business School (MBA). He has served as a Director of a venture capital company (Scienta SA), then as head of his own company in Brussels. He was appointed as Managing Director (1983), then as Chairman and Managing Director (1988) of the AG Group. Chairman of Fortis since 1990, he is the author of a corporate governance code for Belgian publicly traded companies, which was adopted in 2005.

Director of TOTAL S.A. since 2003 and until 2008.

Holds 3,200 shares.

Principal other directorships

•

Chairman of Fortis S.A./N.V.*

•

Chairman of Fortis N.V.*

•

Chairman of Compagnie Het Zoute.

•

Director of Belgacom.*

•

Director of Groupe Bruxelles Lambert.*

Christophe de Margerie

56 years old.

Christophe de Margerie joined the Group after graduating from the Ecole Supérieure de Commerce de Paris in 1974. He served in several positions in the Group’s Financial Department and Exploration-Production division. He became president of TOTAL Moyen-Orient in 1995 before joining the Group’s executive committee as the President of the exploration and production division in May 1999. He then became Senior Executive Vice-President of exploration and production of the new TotalFinaElf group in 2000. In January 2002 he became President of the Exploration & Production division of TOTAL. He has served as a member of the Executive Committee since 1999. He was appointed a member of the Board of Directors by the shareholders’ meeting held on May 12, 2006 and became Chief Executive Officer of TOTAL as from February 14, 2007.

Director of TOTAL S.A. since May 12, 2006 and until 2009.

Holds 72,000 shares.

*	*Publicly listed company.*

Michel Pébereau⁽¹⁾

64 years old.

Honorary Inspector General of Finance, Mr. Pébereau held various positions in the Ministry of Economy and Finance, before serving as Chief Executive Officer, then as Chairman and CEO of Crédit Commercial de France (CCF) from 1982 to 1993. He was Chairman and Chief Executive Officer of BNP then BNP Paribas from 1993 to 2003, and is currently Chairman of the Board of BNP Paribas.

Director of TOTAL S.A. since 2000 and until 2009.

Holds 2,356 shares.

Principal other directorships

•

Chairman of BNP Paribas.*

•

Director of Lafarge.*

•

Director of Saint Gobain.*

•

Director of Pargesa Holding SA (Switzerland).*

•

Member of the Supervisory Board of Axa.*

•

Chairman of the European Banking Federation.

Thierry de Rudder⁽²⁾

57 years old.

A graduate of the Université de Genève in mathematics, the Université Libre de Bruxelles and Wharton (MBA), Mr. De Rudder served in various positions at Citibank from 1975 to 1986 before joining Groupe Bruxelles Lambert, where he was appointed Acting Managing Director.

Director of TOTAL S.A. since 1999 and until 2007.

Holds 3,956 shares.

Principal other directorships

•

Acting Managing Director of Groupe Bruxelles Lambert.*

•

Director of Compagnie Nationale à Portefeuille.*

•

Director of Suez.*

•

Director of Imerys.*

Jürgen Sarrazin

70 years old.

Director of TOTAL S.A. since 2000 and until May 12, 2006.

*	*Publicly listed company.*

(1)

Mr. Pébereau is Chairman of BNP Paribas, which, to the Company’s knowledge, owns 0.3% of the Company’s shares and 0.4% of the voting rights. Mr. Pébereau is also a Director of Pargesa Holding SA (Switzerland), part of the Groupe Bruxelles Lambert (Belgium). Groupe Bruxelles Lambert (Belgium) acting in concert with Compagnie Nationale à Portefeuille and other entities, to the Company’s knowledge, owns 5.3% of the Company’s shares and 5.4% of the voting rights. Mr. Pébereau disclaims beneficial ownership of such shares.

(2)

Mr. de Rudder is Managing Director of Groupe Bruxelles Lambert (Belgium), which acting in concert with Compagnie Nationale à Portefeuille and other entities, to the Company’s knowledge, owns 5.3% of the Company’s shares and 5.4% of the voting rights. Mr. de Rudder disclaims beneficial ownership of such shares.

Serge Tchuruk

69 years old.

A graduate of the École Polytechnique and an Ingénieur de l’armement, Mr. Tchuruk held various management positions with Mobil Corporation, then with Rhône-Poulenc, where he was named Chief Executive Officer in 1983. He served as Chairman and CEO of CDF-Chimie/Orkem from 1986 to 1990, then as Chairman and CEO of TOTAL from 1990 to 1995. In 1995, he became Chairman and Chief Executive Officer of Alcatel. In 2006, he became Chairman of the Board of Alcatel-Lucent.

Director of TOTAL S.A. since 1989 and until 2007.

Holds 61,060 shares.

Principal other directorships

•

Chairman of the Board of Alcatel-Lucent.*

•

Director of Thales.*

•

Member of the Board of Directors of the École Polytechnique.

Pierre Vaillaud

71 years old.

A graduate of the École Polytechnique, a Mining Engineer and a graduate of the École Nationale Supérieure du Pétrole et des Moteurs, Mr. Vaillaud worked as an Engineer with Technip and Atochem before joining TOTAL. He served as Chief Executive Officer of TOTAL from 1989 to 1992, before becoming Chairman and Chief Executive Officer of Technip from 1992 to 1999, and of Elf Aquitaine from 1999 to 2000.

Director of TOTAL S.A. since 2000 and until 2009.

Holds 2,000 shares.

Principal other directorships

•

Director of Technip.*

•

Member of the Supervisory Board of Oddo et Cie.

Directors are elected for a three-year term of office, pursuant to article 11 of the Company’s bylaws.

The current members of the Board of Directors of the Company have informed the Company that they have not been convicted, have not been associated with a bankruptcy, receivership or liquidation, and have not been incriminated or publicly sanctioned or disqualified, as stipulated in item 14.1 of Annex I of (EC) Regulation 809/2004 of April 29, 2004.

Management

May 14, 2004 the Board of Directors resolved to continue to entrust the general management of the Company to the Chairman of the Board and confirmed that Thierry Desmarest would continue to serve as its Chairman and as Chief Executive Officer of the Company. At its meeting on February 13, 2007, the Board resolved to change this method of general management and to have separate individuals act as Chairman of the Board and Chief Executive Officer of the Company.

The Executive Committee (COMEX) is the primary decision-making body of the Group. It implements the strategy formulated by the Board of Directors and authorizes related investments. The Management Committee (CODIR) of the Group facilitates coordination among the divisions and monitors the operating results and activity reports of these divisions.

The Executive Committee

The following indivuals were serving as members of TOTAL’s Executive Committee as of December 31, 2006:

•

Thierry Desmarest, Chairman of the COMEX (Chairmain and Chief Executive Officer);

•

François Cornélis, Vice-Chairmain of the COMEX (President of the Chemicals division);

•

Michel Bénézit (President of the Refining-Marketing division);

•

Robert Castaigne (Chief Financial Officer);

•

Yves-Louis Darricarrère (President of the Gas & Power division);

•

Christophe de Margerie (President of the Exploration & Production division); and

•

Bruno Weymuller (President of the Strategy & Risk assessment department).

*	*Publicly listed company.*

The Management Committee

In addition to the members of the COMEX, the following 23 individuals from various non-operating departments and operating divisions were serving as members of TOTAL’s Management Committee as of December 31, 2006:

Holding

Jean-Pierre Cordier, Senior Vice-President, Executive Career Management.

Yves-Marie Dalibard, Vice-President, Corporate Communications.

Jean-Michel Gires, Senior Vice-President, Sustainable Development and the Environment.

Jean-Jacques Guilbaud, Senior Vice-President, Human Resources and Corporate Communications.

Peter Herbel, General Counsel.

Ian Howat, Vice-President, Corporate Strategy.

Jean-Marc Jaubert, Senior Vice-President, Industrial Safety.

Patrick de La Chevardière, Deputy Chief Financial Officer.

Jean-François Minster, Senior Vice-President, Scientific Development.

Upstream

Philippe Boisseau, Senior Vice-President, Middle East, Exploration & Production.

Jean-Marie Masset, Senior Vice-President, Geosciences, Exploration & Production.

Charles Mattenet, Senior Vice-President, Asia and the Far East, Exploration & Production.

Patrick Pouyanné, Senior Vice-President, Strategy, Business Development and R&D, Exploration & Production.

Jean Privey, Senior Vice-President, Africa, Exploration & Production.

Downstream

Alain Champeaux, Senior Vice-President, Overseas, Refining & Marketing.

Alain Grémillet, General Secretrary, Refining & Marketing.

François Groh, President, Trading & Shipping.

Eric de Menten, Senior Vice-President, Marketing Europe, Refining & Marketing.

Jean-Jacques Mosconi, Senior Vice-President, Strategy, Business Development and R&D, Refining & Marketing.

André Tricoire, Senior Vice-President, Refining, Refining & Marketing.

Chemicals

Pierre-Christian Clout, Senior Vice-President, Chairman of Hutchinson.

Françoise Leroy, General Secretary.

Hugues Woestelandt, Senior Vice-President, Specialties & Fertilizers.

In addition, Charles Paris de Bollardière serves as the Group’s Treasurer.

Recent Developments

On February 13, 2007, Christophe de Margerie was appointed Chief Executive Officer of TOTAL S.A., with Thierry Desmarest continuing to serve as non-executive Chairman of the Board of the Company. From February 14, 2007, Christophe de Margerie became the President of TOTAL’s Executive Committee and of TOTAL’s Management Committee. Yves-Louis Darricarrère replaced Christophe de Margerie as President of the Exploration & Production division of the Group and Philippe Boisseau was appointed President of the Gas & Power division. Jean-Jacques Guilbaud, President of the Human Resources & Communications department of the Group was appointed as a member of the Executive Committee on February 19, 2007.

*	*Publicly listed company.*

Compensation

Board Compensation

The amount paid to the members of the Board of Directors as directors’ fees was 0.82 M€ in 2006 in accordance with the decision of the shareholders’ meeting held on May 14, 2004. There were 15 directors as of December 31, 2006 compared with 16 as of December 31, 2005.

Compensation was paid to the members of the Board of Directors in 2006 based on the following principles:

•

A fixed amount of €15,000 was paid to each director (paid prorata temporis in case of a change during the period).

•

Each director was paid €5,000 for each meeting of the Board of Directors, of the Audit Committee or of the Nominating & Compensation Committee attended. This amount was increased to €7,000 for those directors who reside outside of France.

Total compensation (including in-kind benefits) paid to each director in the year indicated


(€)	2006	2005	2004
Thierry Desmarest	3,227,123	2,963,452	2,787,239
Daniel Boeuf^(a)	160,846	150,529	128,260
Daniel Bouton	50,000	45,000	37,500
Bertrand Collomb	55,000	30,000	42,000
Paul Desmarais Jr.	43,000	43,000	37,500
Jacques Friedmann^(b)	35,383	80,000	82,500
Bertrand Jacquillat	80,000	80,000	78,000
Antoine Jeancourt-Galignani	65,000	45,000	46,500
Anne Lauvergeon	40,000	40,000	42,000
Peter Levene of Portsoken	50,000	23,410	—
Maurice Lippens	50,000	57,000	37,500
Christophe de Margerie^(c)	1,426,443	—	—
Michel Pébereau	65,000	55,000	51,000
Thierry de Rudder	106,000	106,000	82,500
Jürgen Sarrazin^(b)	33,383	50,000	46,500
Serge Tchuruk	50,000	50,000	46,500
Pierre Vaillaud^(d)	186,340	178,906	177,933

(a)

Including the salary received by Mr. Boeuf as an employee of Total France, a subsidiary of TOTAL S.A., which amounted to €100,753 in 2004, €105,529 in 2005 and €110,846 in 2006.

(b)

Term of office expired on May 12, 2006.

(c)

Including the salary paid by TOTAL S.A. and in-kind benefits valued at €5,508. Mr. Christophe de Margerie does not receive any directors’ fees for his service on the Company’s Board of Directors.

(d)

Including pension payments related to previous employment by the Group, which amounted to €131,433 in 2004, €133,906 in 2005 and €136,400 in 2006.

Over the past three years, the directors currently in office have not received any compensation or in-kind benefits from companies controlled by TOTAL S.A., except for Mr. Daniel Boeuf, who is an employee of Total France. The compensation indicated in the table above (except for that of the Chairman and Messrs. Boeuf, de Margerie and Vaillaud) consists solely of directors’ fees (gross amount) paid during the relevant period. None of the directors of TOTAL S.A. have service contracts which provide for benefits upon termination of employment.

Executive Officer Compensation

In 2006, the aggregate amount paid directly or indirectly by the French and foreign affiliates of the Company as compensation to the executive officers of TOTAL (31 individuals, members of the Management Committee and the Treasurer) as a group was 19.7 M€, including 9 M€ paid to the seven members of the Executive Committee. Variable compensation accounted for 44.7% of the aggregate amount paid to executive officers in 2006.

Executive officers who are directors of affiliates of the Company are not entitled to retain any directors’ fees.

Compensation of the Chairman and Chief Executive Officer

The total gross compensation paid to Mr. Thierry Desmarest for fiscal 2006 amounted to €3,199,844. This compensation, set by the Board of Directors, is composed of a fixed base salary of €1,523,735 for 2006 and a variable portion, to be paid in 2007, which amounted to €1,676,109. The variable portion is calculated by taking into account the Group’s return on equity during the relevant fiscal year, the Group’s earnings compared to those of other major international oil companies and the Group’s future prospects based on action taken in the year in question.

Mr. Thierry Desmarest’s total gross compensation for fiscal 2005 amounted to €3,154,623, composed of a fixed base salary of €1,451,235 and a variable portion of €1,703,388 paid in 2006.

Mr. Desmarest does not receive any in-kind benefits.

Pensions and other commitments

The Group does not have a specific pension plan for the Chairman and the Chief Executive Officer.

The Chairman and the Chief Executive Officer are entitled to a retirement benefit calculated pursuant to the same formula used for all employees of TOTAL S.A. The method for calculating this benefit is determined by the National Collective Bargaining Agreement for the Petroleum Industry and is based on the annual gross compensation (including fixed and variable portions) paid to the Chairman or the Chief Executive Officer, as the case may be.

The Chairman and the Chief Executive Officer are also eligible for a complementary pension plan open to all employees of the Group whose annual compensation is greater than the annual social security threshold multiplied by eight. There are no French legal or collective bargaining provisions that apply to remuneration above this social security ceiling.

This complimentary pension plan is financed and managed by TOTAL S.A. to award a pension that is based on the period of employment (up to a limit of 20 years) and the portion of annual gross compensation (including fixed and variable portions) that exceeds the annual social security threshold multiplied by eight. This

pension is indexed to the French Association for Complementary Pensions Schemes (ARRCO) index.

As of December 31, 2006, the Group’s pension obligations related to the Chairman are the equivalent of an annual pension of 15.46% of the Chairman’s 2006 compensation.

For Mr. de Margerie, the Group’s pension obligations are, as of December 31, 2006, the equivalent of an annual pension of 26.10% of his 2006 compensation.

The Company also funds a life insurance policy which guarantees a payment, upon death, equal to two years’ compensation (both fixed and variable), increased to three years upon accidental death, as well as, in case of disability, a payment proportional to the degree of disability.

If the Chairman or the Chief Executive Officer’s employment is terminated or his term of office is not renewed, he is eligible for severance benefits calculated according to terms of the National Collective Bargaining Agreement for the Petroleum Industry that applies to employees of TOTAL S.A. The maximum severance benefit, based upon 30 years of employment with the Group, is equal to two times an individual’s annual pay, based upon the gross compensation (both fixed and variable) paid in the previous 12-month period.

These severance benefits may be increased by an amount equal to an additional year’s gross pay (calculated as specified above) if the Chairman or the Chief Executive Officer enters into a non-compete agreement or, in the case of a change in control of the ownership of the Company, if termination occurs within the two-year period following the change in control.

These provisions for severance benefits are not applicable if, at the time of severance or non-renewal, the Chairman or the Chief Executive Officer is eligible to receive full retirement benefits. The benefits mentioned above are considered to cover any amounts due to the Chairman or the Chief Executive Officer, as the case may be, for all functions he may have performed for the Group. If the Group terminates employment or does not renew a term of office for reason (faute grave or faute lourde), these provisions for benefits do not apply.

In addition to the pension commitments described above, the Company has the following commitments to Messrs. Tchuruk and Vaillaud:

•

The Company has funded a complementary pension for Mr. Tchuruk related to his previous employment by the Group. After retirement, the amount paid per year to Mr. Tchuruk under this complementary pension would amount to approximately €71,150,

based upon calculations as of December 31, 2006. This pension is indexed to the ARRCO index.

•

The Company has funded a complementary pension for Mr. Vaillaud related to his previous

employment by the Group. Mr. Vaillaud receives an annual complementary pension of approximately €137,450, based upon calculations as of December 31, 2006. This pension is indexed to the ARRCO index.

Corporate Governance

TOTAL actively examines corporate governance matters. In particular, the Group maintains a policy of transparency regarding the compensation of and the allocation of stock options and restricted share grants to its corporate officers.

Directors are appointed by the shareholders for a three-year term. In case of the resignation or death of a director, the Board may temporarily appoint a replacement director. This appointment must be ratified by the next shareholders’ meeting. The terms of office of the members of the Board are staggered to more evenly space the renewal of appointments.

In 1995, the Group established two special committees, the Nominating & Compensation Committee and the Audit Committee.

In 2003, the Board of Directors amended the corporate governance policies initially adopted in 1995 and in 2001 to take into account recent developments in this area, including the AFEP-MEDEF report published in France in September 2002.

In 2004, the Board of Directors adopted a code of ethics that, in the overall context of the Group’s Code of Conduct, applies to its Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and the financial and accounting officers for its principal activities. The Board has made the Audit Committee responsible for ensuring compliance with this Code.

At its meeting on February 18, 2004, the Board had designated Jacques Friedman, Chairman of the Audit Committee and an independent director, as Audit Committee financial expert. Mr. Friedman served in this capacity until the end of his term of office as a director, on May 12, 2006. Mr. Antoine Jeancourt-Galignani, an independent director, has been designated to succeed Mr. Friedman as Chairman of the Audit Committee and Audit Committee financial expert.

At its meeting on July 19, 2005, the Board of Directors amended the Audit Committee’s charter to clarify its role in supervising the independent auditors and the criteria for the independence of its members. The Board also approved the Audit Committee’s procedures for complaints or concerns regarding accounting, internal accounting controls or auditing matters.

TOTAL’s corporate governance practices conform with those generally followed by companies listed in France.

The shareholders’ meeting held on May 14, 2004 appointed a director, Mr. Daniel Boeuf, representing employee shareholders.

Board of Directors

The Board of Directors’ charter specifies the obligations of each director and sets forth the roles and working procedures of the Board.

Each director undertakes to maintain the independence of his analysis, judgment, decision and action as well as not to be unduly influenced. When a director participates in and votes at Board meetings, he is required to represent the interest of the shareholders and the Company as a whole. Directors must actively participate in the affairs of the Board, specifically on the basis of information communicated to him by the Company. Each director must inform the Board of conflicts of interest that may arise, including the nature and terms of any proposed transactions that could give rise to such situations. If a director is opposed to a project brought before the Board, he is required to clearly express his opposition. He is required to own at least 1,000 Company shares in registered form (with the exception of the director representing employee shareholders, for whom the requirements are more flexible) and comply strictly with provisions regarding the use of material non-public information. The requirement to hold a minimum of 1,000 shares while in office is accepted by each Director as a restriction on his ability to freely dispose of these shares.

In addition to stipulating that any shares and ADRs of TOTAL S.A. and its publicly traded subsidiaries held by directors are to be held in registered form, the Directors’ Charter prohibits buying on margin or short selling those same securities. It also prohibits trading shares of TOTAL S.A. on, and during the 15 calendar days preceding, the dates of the Company’s periodic earnings announcements.

The Board’s role is to determine the strategic vision for the Group and supervise the implementation of this vision.

With the exception of the powers and authority expressly reserved for shareholders and within the limits of the Company’s legal purpose, the Board may address any issue related to the operation of the Company and take any decision concerning the matters falling within its purview.

Within this framework, the Board’s duties and responsibilities include, but are not limited to, the following:

•

Appointing the officers responsible for managing the Company and supervising their actions;

•

Defining the Company’s strategic orientations and, more generally, those of the Group;

•

Considering major transactions to be pursued by the Group;

•

Receiving information on significant events related to the Company’s affairs;

•

Monitoring the quality of information supplied to shareholders and the financial markets through the financial statements that it approves and the annual report, or when major transactions are conducted;

•

Convening and setting the agenda for shareholders’ meetings;

•

Preparing, for each year, a list of the directors it deems to be independent under generally recognized corporate governance criteria; and

•

Conducting audits and investigations as it may deem appropriate.

The Board, with the assistance of its specialized committees where appropriate, ensures the following:

•

That authority within the Company has been properly delegated before it is exercised, and that the various entities of the Company respect the authority, duties and responsibilities they have been given;

•

That no individual is authorized to both contract and reimburse obligations of the Company without proper supervision and control;

•

That the internal audit function functions properly and that the independent auditors are able to conduct their audits under appropriate circumstances; and

•

That the committees it has created duly perform their responsibilities.

The Board meets at least four times a year and additionally as circumstances may require.

Directors may participate in meetings either by being present, by being represented by another director or via video conference (in compliance with the technical requirements set by applicable regulations).

The Board may establish specialized committees, whether permanent or ad hoc, as required by applicable legislation or as it may deem appropriate. The Board allocates directors’ fees to and may allocate additional directors’ fees to directors who participate on specialized committees, within the total amount established by the shareholders.

The Board regularly (at least every three years) conducts an evaluation of its own practices. Each year it also discusses its performance.

The Board, in general, is convened by written notice at least eight days in advance of a meeting. The documents provided to inform the Board’s decisions are, when possible, included with the convening notice or otherwise provided as soon as possible thereafter. At each meeting, the minutes of the preceding meeting are submitted for the approval of the Board.

The Board held seven meetings in 2006, with an average attendance of 86.2%.

Audit Committee

The Audit Committee’s role is to assist the Board of Directors in ensuring effective internal financial control and oversight and appropriate disclosure to shareholders and the financial markets. The Audit Committee’s duties include:

•

Recommending the appointment of independent auditors, their compensation and ensuring their independence;

•

Establishing the rules for the use of independent auditors for non-audit services;

•

Examining the accounting policies used to prepare the financial statements, examining the parent company annual financial statements and the consolidated annual, semi-annual, and quarterly financial statements prior to their examination by the Board, after regularly monitoring the financial situation, cash flow statement and obligations of the Company;

•

Reviewing the implementation of internal control procedures and the evaluation of their effectiveness with the assistance of the internal audit department;

•

Reviewing the creation and activities of the disclosure committee, including reviewing the conclusions of this committee;

•

Approving the scope of the annual audit work of internal and external auditors;

•

Keeping regularly informed of completed audits, examining internal audit reports and other reports (independent auditors, annual report, etc.),

•

Examining the appropriateness of risk oversight procedures;

•

Examining the choice of appropriate accounting principles and methods;

•

Examining the Group’s policy for the use of derivative instruments;

•

Giving, if requested by the Broard, its opinion regarding major transactions contemplated by the Group;

•

Annually reviewing significant litigation;

•

Implementing and monitoring compliance with the Financial Code of Ethics;

•

Proposing to the Board, for implementation, a procedure for complaints or concerns of employees, shareholders and others, related to accounting, internal accounting controls or auditing matters; and

•

Examining the procedure for booking the Group’s proved reserves.

The committee is made up of at least three directors designated by the Board of Directors. Members must be independent directors.

In selecting the members of the committee, the Board pays particular attention to their financial and accounting qualifications. Members of the committee may not be executive officers of the Company or one of its subsidiaries, nor own more than 10% of the Company’s shares, whether directly or indirectly, individually or acting together with another party.

Members of the Audit Committee may not receive from the Company and its subsidiaries, whether directly or indirectly, any compensation other than:

(i)	directors’ fees paid for their services as directors or as members of the Audit Committee or, if applicable, another committee of the Board; and

(ii)	compensation and pension benefits related to prior employment by the Company which are not dependant upon future work or activities.

The committee appoints its own Chairman. The Chief Financial Officer serves as the committee secretary. The committee meets at least four times a year to examine the consolidated annual and quarterly financial statements.

The Audit Committee may meet with the Chairman or the Chief Executive Officer, perform inspections and consult with managers of operating or non-operating departments, as may be useful in performing its duties. The committee meets with the independent auditors and examines their work, and may do so without management being present. If it deems it necessary for the accomplishment of its mission, the committee may request from the Board the means and resources to make use of outside assistance.

The committee submits written reports to the Board of Directors regarding its work.

In 2006, the members of the committee were Mr. Jacques Friedmann, who served as chairmain, until May 12, 2006, when he was succeeded by Mr. Antoine Jeancourt-Galignani, and Messrs, Bertrand Jacquillat and Thierry de Rudder, each of whom is an independent director.

The committee is chaired by Mr. Antoine Jeancourt-Galignani, who was appointed audit committee financial expert by the Board at its meeting on September 5, 2006.

As of December 31, 2006, the members of the committee had served as directors of TOTAL S.A. for twelve, ten and seven years, respectively.

The Audit Committee met six times in 2006, with an effective attendance rate of 100%.

Each quarter, the committee reviewed the financial condition of the Group and a presentation made by the head of the internal audit regarding internal audit activity.

Nominating & Compensation Committee

The principal objectives of this committee are to:

•

Recommend to the Board of Directors the persons that are qualified to be appointed as directors or corporate officers and to prepare the corporate governance rules and regulations that are applicable to the Company; and

•

Review and examine the executive compensation policies implemented in the Group and the compensation of members of the Executive Committee, recommend the compensation of the Chief Executive Officer, and prepare any report that the Company must submit on these subjects.

It performs the following specific tasks:

1. With respect to nominations:

a)	Assists the Board in the selection of directors, corporate officers, and directors as Committee members;

b)	Recommends annually to the Board the list of directors who may be considered as “independent directors” of the Company; and

c)	Proposes methods for the Board to evaluate its performance.

2. With respect to compensation:

a)	Makes recommendations and proposals to the Board regarding:

(i)

compensation, pension and insurance plans, in-kind benefits, and other compensation, including severance benefits, for the Chairmain or the Chief Executive Officer of TOTAL S.A., and

(ii)

awards of stock options and restricted share grants, including specific awards to the Chairman or the Chief Executive Officer;

b)	Reviews the compensation of members of the Executive Committee, including stock option plans, restricted share grants and equity-based plans as well as pension and insurance plans and in-kind benefits.

The committee is made up of at least three directors designated by the Board of Directors.

A majority of the members must be independent directors. Members of the Nominating & Compensation Committee may not receive from the Company and its subsidiaries any compensation other than:

(i)	directors’ fees paid for their services as directors or as members of the Nominating & Compensation Committee; and

(ii)	compensation and pension benefits related to prior employment by the Company which are not dependant upon future work or activities.

The committee appoints its Chairman as well as a secretary, who is a senior executive of the Company.

The committee meets at least twice a year. The committee invites the President or the Chief Executive Officer of the Company to present recommendations.

The President or the Chief Executive Officer may not be present during deliberations regarding his own compensation. While maintaining the appropriate level of confidentiality for its discussions, the committee may request that the Chief Executive Officer provide it with the assistance of any senior executive of the Company whose skills and qualifications could facilitate the handling of an agenda item.

If it deems it necessary to accomplish its duties, the committee may request from the Board the resources to engage external consultants. The committee reports on its activities to the Board of Directors.

The committee met on January 30, July 12 and November 28 in 2006, with an average effective attendance of 88.9%. Messrs. Bertrand Collomb, Michel Pébereau and Serge Tchuruk, each an independent director, are the members of the committee and Mr. Michel Pébereau serves as its Chairman.

The committee proposed to the Board of directors the list of directors to be recommended for appointment by the shareholders’ meeting.

In addition to its proposals for the compensation of the Chief Executive Officer and regarding stock options and restricted share grants, the committee also proposed to modify the rules for awarding directors’ fees. This proposal was adopted by the Board, subject to the approval of the total amount to be distributed to directors by the shareholders’ meeting to be held on May 11, 2007.

The committee also proposed a policy for determining the compensation and other advantages awarded to the Chairman and to the Chief Executive Officer.

The committee directed a self-evaluation of the Board and selected the external consultancy retained to assist with this evaluation. The self-evaluation was conducted in the fall of 2006 and confirmed that the Board of Directors had made appropriate choices in organizing its operations. A discussion of the results of this self-evaluation was on the agenda of the Board meeting held on February 13, 2007.

The committee also conducted a financial review of the compensation of the Company’s management bodies and of the Company’s pension and insurance plans, in preparation for the disclosure of this information in the Company’s annual report for 2006.

Director Independence

The committee proposed to the Board a list of independent directors based on generally recognized corporate governance principles. The Nominating & Compensation committee proposed that the Board consider a director to be independent when that director has “no relationship, of any nature, with the company, group or its management which could compromise the independent exercise of his judgement”, pursuant to the AFEP-MEDEF (French corporate associations) report of 2002.

At its meeting on February 13, 2007, the Board, acting on a proposal from the committee, determined that, as of December 31, 2006, the following directors were independent: Messrs. Bouton, Collomb, Desmarais, Jacquillat, Jeancourt-Galignani, Levene, Lippens, Pébereau, de Rudder, Tchuruk and Vaillaud.

These directors meet the independence criteria contained in the AFEP-MEDEF report of 2002, with the exception of Mr. Tchuruk, who has been a director of the Company for a period exceeding the 12 years recommended by the report. The Board, taking into account the nature of the Company’s industry, with the associated long-term investments and activities, considered that service as a director over a long period corresponds to certain experience and authority that strengthens the independence of a director. Upon this basis, the Board concluded that Mr. Tchuruk was an independent director.

In evaluating the independence criteria under the report related to material client, supply, banking or investment banking relationships between a director and the Company, the Board considered that the business dealings between Group companies and the banking institutions where Messrs. Bouton and Pébereau are members of the administrative or management bodies, which amount to less than 0.1% of their net banking income, are not material. The Board concluded the Messrs. Bouton and Pébereau were independent directors.

Under this evaluation, 73.3% of the members of the Board of Directors are considered to be independent.

The Board also noted that there were no potential conflicts of interest between the Company and its directors.

Policy for determining the compensation and other benefits of the Chairman and of the Chief Executive Officer

Based on a proposal by the committee, the Board adopted the following policy for determining the compensation and other advantages of the Chairman and of the Chief Executive Officer:

•

Compensation for the Chairman and the Chief Executive Officer is set by the Board of Directors after considering proposals from the Compensation Committee. Such compensation shall be reasonable and fair, in a context that values both teamwork and motivation within the Company.

Compensation for the Chairman and the Chief Executive Officer is related to market practice, work performed, results obtained and responsibilities held.

•

Compensation for the Chairman and the Chief Executive Officer includes both a fixed portion and a variable portion, each of which are reviewed annually.

•

The amount of variable compensation may not exceed a stated percentage of fixed compensation.

Variable compensation is determined based on pre-defined quantitative and qualitative criteria. Quantitative criteria are limited in number, objective, measurable and adapted to the Group’s strategy.

Variable compensation is designed to reward short-term performance and progress towards medium-term objectives. The qualitative criteria for variable compensation are designed to allow exceptional circumstances to be taken into account, when appropriate.

•

Stock options are designed to align the long-term interests of the Chairman and the Chief Executive Officer with those of the shareholders.

Awards of stock options are considered in light of the amount of the total compensation paid to the Chairman and the Chief Executive Officer.

The exercise price for stock options awarded is not discounted compared to the market price for the underlying share.

Stock options are awarded at regular intervals to prevent opportunistic behavior.

The Chairman and Chief Executive Officer are required to hold a number of shares of the Company equal in value to two years of the fixed portion of their annual compensation.

•

The Chairman and Chief Executive Officer do not receive restricted share grants.

Recent Corporate Governance Developments

At its meeting on February 13, 2007, the Board of Directors, acting on a proposal by the Nominating & Compensation Committee, enacted certain changes related to the Group’s corporate governance, effective as of February 2007. The Board amended the Directors Charter, subsequently renamed the Rules of Procedure of the Board of Directors, mainly to take into account the fact that separate individuals would serve as Chairman and as Chief Executive Officer and to create a separate Nominating & Governance Committee and Compensation Committee to divide the duties of the former Nominating & Compensation Committee. The Board also adopted charters for these committees.

Also on February 13, 2007, the Board of Directors appointed Mr. Christophe de Margerie as Chief Executive Officer of the Company. Mr. Thierry Desmarest remains Chairman of the Board of Directors.

Employees, Share Ownership, Stock Options and Restricted Share Grants

Employees

The tables below set forth the number of employees, by divisions and geographic location, of the Group (fully consolidated subsidiaries) as of the end of the periods indicated.


	Upstream	Downstream	Chemicals	Corporate	Total
2006^(a)	14,862	34,467	44,504	1,237	95,070
2005	14,849	34,611	62,214	1,203	112,877
2004	14,597	34,045	61,570	1,189	111,401
		France	Rest of Europe	Rest of world	Total
2006^(a)		37,831	26,532	30,707	95,070
2005		48,751	30,140	33,986	112,877
2004		49,174	29,711	32,516	111,401

(a)

At December 31, 2006, these figures exclude the employees of Arkema, pursuant to the spin-off of these activities in May 2006.

TOTAL believes that the relationship between its management and labor unions is, in general, satisfactory.

Arrangements for involving employees in the capital of the Company

Pursuant to agreements signed on March 15, 2002, as amended, the Group created a “Total Group Savings Plan” (PEGT), a “Partnership for Voluntary Wage Savings Plan” (PPESV, later becoming PERCO) and a “Complementary Company Savings Plan” (PEC) for employees of the Group’s French companies. These plans allow investments in a number of mutual funds including one that invests in Company shares (“Total Actionnariat France”). A “Shareholder Group Savings Plan” (PEG-A) has also been in place since November 19, 1999 to facilitate capital increases reserved for employees of the Group’s French and foreign subsidiaries covered by these plans.

Savings Plans

The various Company Savings plans (PEGT, PEC) and the Group Savings plan (“Plan d’Épargne Groupe Actionnariat” (PEG-A) linked to the capital increase operations reserved for employees, give the employees of French Group Companies belonging to these savings plans access to several collective investment plans (Fonds communs de placement), including a Fund invested in shares of the Company (“Total Actionnariat France”).

For the employees of foreign companies, the capital increases reserved for employees were conducted under PEG-A through the “Total Actionnariat International” Fund and the Caisse Autonome of the Group in Belgium. In addition, U.S. employees participate in these operations through ADRs and Italian employees may participate by directly subscribing to new shares.

Employee shareholding

The total number of TOTAL shares held by employees as of December 31, 2006 is as follows:


Total Actionnariat France		68,675,754
Total Actionnariat International		15,542,253
Privatisation No. 1		1,683,255
Shares held by U.S. employees		1,905,522
Group Caisse Autonome (Belgium)		491,784
TOTAL shares from the exercise of the Company’s stock options and held as registered shares within a Company Savings Plan (PEE)		2,530,385
Total shares held by employee shareholder funds		90,828,953

As of December 31, 2006, the employees of the Group held, on the basis of the definition of employee shareholding contained in Article L. 225-102 of the French Commercial Code, 90,828,953 TOTAL shares, representing 3.74% of the Company’s share capital on that date.

Capital increase reserved for employees

The shareholders’ meeting held on May 17, 2005 delegated the Board of Directors the authority to undertake, in one or several steps, and within a maximum of 26 months, a capital increase reserved for the employees participating in a savings plan. Pursuant to this delegation of authority, the number of shares to be issued cannot exceed 1.5% of the capital stock on the day of the meeting of the Board that decided on the issue. The capital stock issued will be counted against the overall ceiling for the capital increase that could be authorized under the same delegation of authority granted by the shareholders’ meeting held on May 17, 2005 to the Board when capital is increased through ordinary share issues or through any marketable security linked to the capital that maintains preferential subscription rights (4 B€ of par value). This delegation of authority cancelled and replaced, for the unused part, the one granted by the shareholders’ meeting of May 14, 2004.

Pursuant to this delegation of authority, the Board of Directors decided on November 3, 2005 to proceed with a capital increase of a maximum of three million Company shares with a par value of €10 per share, representing 12 million shares with a par value of €2.50 per share reserved for TOTAL employees, bearing dividends as of January 1, 2005, at a price of €166.60 per share with a par value of €10 or €41.65 per share with a par value of €2.50. The offering was

opened to the employees of TOTAL S.A. and to the employees of its French and foreign subsidiaries in which TOTAL S.A. holds directly or indirectly 50% at least of the capital, who are participants in the TOTAL Group Savings Plan (PEG-A) and for which local regulatory approval was obtained. The offering was also opened to former employees of TOTAL S.A. and its French subsidiaries who took their retirement. Subscription was opened from February 6 through February 24, 2006, and resulted in the issuance of 2,785,330 new shares with a par value of €10 per share, or 11,141,320 new shares with a par value of €2.50 per share, in 2006.

Shares held by Directors and Executive Officers

On December 31, 2006, based upon information from the members of the Board and the share registrar, the members of the Board and the Executive Officers of the Group (Management Committee and Treasurer) held a total of less than 0.5% of the Company’s shares:

Members of the Board of Directors (including the Chairman): 680,773 shares.

Executive Officers (including the Chairman): 1,616,337 shares.

Chairman of the Board of Directors: 477,200 shares.

Share transactions

The following table presents transactions, of which the Company has been informed, in the Company’s shares or related financial instruments carried out in 2006 by the relevant individuals⁽¹⁾ under paragraphs a) through c) of Article L.621-18-2 of the French Monetary and Financial Code.


		Purchases^(a)	Subscriptions^(a)	Sales^(a)		Swaps^(a)
Thierry Desmarest	TOTAL shares	276,000.00	116,000.00	208,000.00	^(c)
	Shares in savings plans (FCPE), and other related financial instruments^(b)
Christophe de Margerie	TOTAL shares	36,000.00
	Shares in savings plans (FCPE), and other related financial instruments^(b)	1,071.06	7,704.63
Daniel Boeuf	TOTAL shares
	Shares in savings plans (FCPE), and other related financial instruments^(b)		312.12
Pierre Vaillaud	TOTAL shares	2,000.00		2,000.00
	Shares in savings plans (FCPE) and other related financial instruments^(b)
François Cornélis	TOTAL shares	225,748.00		215,748.00
	Shares in savings plans (FCPE), and other related financial instruments^(b)	207.08	4,184.00
Michel Bénézit	TOTAL shares	70,000.00	5,350.00	42,500.00
	Shares in savings plans (FCPE), and other related financial instruments^(b)	6.42	3,018.82	3,105.26
Robert Castaigne	TOTAL shares		45,232.00	20,000.00
	Shares in savings plans (FCPE), and other related financial instruments^(b)	2.25	6,800.00	7,015.81
Yves-Louis Darricarrère	TOTAL shares		10,880.00
	Shares in savings plans (FCPE), and other related financial instruments^(b)	0.43	3,721.49
Bruno Weymuller	TOTAL shares
	Shares in savings plans (FCPE), and other related financial instruments^(b)	242.78	3,961.58	5,201.99

(a)

To reflect the four-for-one stock split approved by the shareholders’ meeting on May 12, 2006, the number of TOTAL shares and interests in FCPEs for transactions carried out prior to May 18, 2006, either directly or through a FCPE, has been multiplied by four.

(b)

FCPE primarily investing in Company shares.

(c)

In addition, on January 2, 2007 Mr. Desmarest sold 80,000 shares.

Stock options and restricted share grants

Award policy

Stock options and restricted share grants concern only shares of TOTAL S.A. No options for or restricted grants of shares of any of the Group’s listed subsidiaries are awarded.

Alll plans are approved by the Board of Directors, based on recommendations by the Compensation Committee. For each plan, the committee establishes a list of the beneficiaries and the number of options or restricted shares granted to each beneficiary. The Board of Directors then gives final approval for this list.

(1)

Including related persons as defined under Article R.621-43-1 of the French Monetary and Financial Code.

Stock options have a term of eight years, with an exercise price set at the average of the opening share prices during the 20 trading days prior to the grant date, without any discount being applied. For the option plans established after 2002, options may only be exercised after an initial two-year period and the shares issued upon exercise may not be transferred prior to the termination of an additional two-year holding period.

Restricted share grants become final after a two-year vesting period, subject to certain pre-defined conditions, set by the Board acting upon recommendations from the Compensation Committee, related to the return on equity of the Group in the fiscal year preceding the year of final attribution. At the end of this vesting period, and subject to these performance conditions, the restricted share grants become final. However, these shares may

not be transferred prior to the end of an additional two-year holding period.

The grant of these options or restricted shares is used to complement, based upon individual performance assessments at the time of each plan, the Group-wide policy of developing employee shareholding (including saving plans, and capital increases reserved for employees every two years) and allows employees to be more closely associated with the financial and share price performance of TOTAL.

In addition, performance indicators used under profit-sharing agreements allow the Group, when permitted by local legislation, to benefit from the performance of the Group as a whole.

TOTAL stock options

The following table gives a breakdown of stock options awarded by category of beneficiaries (executive officers, senior managers and other employees) for the plans in effect during 2006.


		Number of beneficiaries	Number of options awarded^(g)	Percentage		Average number of options per beneficiary^(g)
1998 Plan^(a)
Stock purchase options	Executive Officers^(f)	16	157,500	16.5	%	9,844
(Decision of the Board on March 17, 1998; exercise price: €93.76 (615 French francs); discount: 4.94%)	Senior managers Other employees	162 824	347,600 449,900	36.4 47.1	% %	2,146 546
	Total	1,002	955,000	100.0	%	953

1999 Plan^(a)
Stock purchase options	Executive Officers^(f)	19	279,000	18.6	%	14,684
(Decision of the Board on June 15, 1999; exercise price: €113.00; discount: 4.74%; exercise price after May 24, 2006: €27.86^(g))	Senior managers Other employees	215 1,351	517,000 703,767	34.5 46.9	% %	2,405 521
	Total	1,585	1,499,767	100	%	946

2000 Plan^(b)(e)
Stock purchase options	Executive Officers^(f)	24	246,200	10.2	%	10,258
(Decision of the Board on July 11, 2000; exercise price: €162.70; discount: 0.0%; exercise price after May 24, 2006: €40.11^(g))	Senior managers Other employees	298 2,740	660,700 1,518,745	27.2 62.6	% %	2,217 554
	Total	3,062	2,425,645	100	%	792

2001 Plan^(c)(e)
Stock purchase options	Executive Officers^(f)	21	295,350	11.0	%	14,064
(Decision of the Board on July 10, 2001; exercise price: €168.20; discount: 0.0%; exercise price after May 24, 2006: €41.47^(g))	Senior managers Other employees	281 3,318	648,950 1,749,075	24.1 64.9	% %	2,309 527
	Total	3,620	2,693,375	100	%	744


		Number of beneficiaries	Number of options awarded^(g)	Percentage		Average number of options per beneficiary^(g)

2002 Plan^(d)(e)
Stock purchase options	Executive Officers^(f)	28	333,600	11.6	%	11,914
(Decision of the Board on July 9, 2002; exercise price: €158.30; discount: 0.0%; exercise price after May 24, 2006: €39.03^(g))	Senior managers Other employees	299 3,537	732,500 1,804,750	25.5 62.9	% %	2,450 510
	Total	3,864	2,870,850	100	%	743

2003 Plan^(d)(e)
Stock subscription options	Executive Officers^(f)	28	356,500	12.2	%	12,732
(Decision of the Board on July 16, 2003; exercise price: €133.20; discount: 0.0%; exercise price after May 24, 2006: €32.84^(g))	Senior managers Other employees	319 3,603	749,206 1,829,600	25.5 62.3	% %	2,349 508
	Total	3,950	2,935,306	100	%	743

2004 Plan^(d)
Stock subscription options	Executive Officers^(f)	30	423,500	12.6	%	14,117
(Decision of the Board on July 20, 2004; exercise price: €159.40; discount: 0.0%; exercise price after May 24, 2006: €39.30^(g))	Senior managers Other employees	319 3,997	902,400 2,039,730	26.8 60.6	% %	2,829 510
	Total	4,346	3,365,630	100	%	774

2005 Plan^(d)
Stock subscription options	Executive Officers^(f)	30	370,040	24.3	%	12,335
(Decision of the Board on July 19, 2005; exercise price: €198.90; discount: 0.0%; exercise price after May 24, 2006: €49.04^(g))	Senior managers Other employees	330 2,361	574,140 581,940	37.6 38.1	% %	1,740 246
	Total	2,721	1,526,120	100	%	561

2006 Plan^(d)
Stock subscription options	Executive Officers^(f)	28	1,447,000	25.3	%	51,679
(Decision of the Board on July 19, 2006; exercise price: €50.60; discount 0.0%)	Senior managers Other employees	304 2,253	2,120,640 2,159,600	37.0 37.7	% %	6,976 959
	Total	2,585	5,727,240	100	%	2,216

^(a)

Options are exercisable after a five-year vesting period from the individual award date of individual grant and expire eight years after this date.

^(b)

Options are exercisable after a four-year vesting period from the individual award date and expire eight years after this date. The underlying shares may not be transferred during the five-year period from the individual award date.

^(c)

Options are exercisable after January 1, 2005 and expire eight years after the individual award date. The underlying shares may not be transferred during the four-year period from the individual award date.

^(d)

Options are exercisable after a two-year vesting period from the individual award date and expire eight years after this date. The underlying shares may not be transferred during the four-year period from the individual award date.

^(e)

Certains employees of the Elf Aquitaine group in 1998 also benefited in 2000, 2001, 2002 and 2003 from the vesting of Elf Aquitaine options awarded in 1998 subject to performance conditions related to the Elf Aquitaine group from 1998 to 2002. These Elf Aquitaine plans expired on March 31, 2005.

^(f)

Members of the Executive Committee and the Treasurer as of the date of the Board meeting awarding the options.

^(g)

To reflect the spin-off of Arkema, pursuant to Articles 174-9, 174-12 and 174-13 of Decree number 67-236 of March 23, 1967 effective at that time and as of the date of the shareholders’ meeting of May 12, 2006, at its meeting on March 14, 2006 the Board of Directors resolved to adjust the rights of holders of TOTAL stock options. For each plan and each holder, the exercise prices for TOTAL stock options were multiplied by 0.986147 and the number of unexercised stock options was multiplied by 1.014048 (and then rounded up), effective as of May 24, 2006. Additionally, to reflect the four-for-one stock split approved by the shareholders’ meeting on May 12, 2006, the exercise price for stock options was divided by four and the number of unexercised stock options was multiplied by four. The presentation in this table of the number of options initially awarded has not been adjusted to reflect the four-for-one stock split.

TOTAL STOCK OPTIONS AS OF DECEMBER 31, 2006


	1998 Plan		1999 Plan		2000 Plan		2001 Plan		2002 Plan		2003 Plan		2004 Plan		2005 Plan		2006 Plan		Total
Type of options	Purchase options		Purchase options		Purchase options		Purchase options		Purchase options		Subscription options		Subscription options		Subscription options		Subscription options

Date of the shareholders’ meeting	May 21, 1997		May 21, 1997		May 21, 1997		May 17, 2001		May 17, 2001		May 17, 2001		May 14, 2004		May 14, 2004		May 14, 2004
Date of the Board meeting	March 17, 1998		June 15, 1999		July 11, 2000		July 10, 2001		July 9, 2002		July 16, 2003		July 20, 2004		July 19, 2005		July 18, 2006
Options awarded by the Board (before taking into account the four-for-one stock split^(a)), of which:	955,000		1,499,767		2,425,645		2,693,375		2,870,850		2,935,306		3,365,630		1,526,120		5,727,240
• Executive directors^(b)	30,000		40,000		50,000		75,000		60,000		60,000		60,000		60,180		400,720
• Ten highest awards to employees^(c)	111,000		172,000		138,000		166,000		176,500		175,000		204,000		184,000		633,000
Options awarded by the Board (after taking into account the four-for-one stock split^(a)), of which:	3,820,000		5,999,068		9,702,580		10,773,500		11,483,400		11,741,224		13,462,520		6,104,480		5,727,240		78,814,012
• Executive directors^(b)	120,000		160,000		200,000		300,000		240,000		240,000		240,000		240,720		400,720		2,141,440
• Ten highest awards to employees^(c)	444,000		688,000		552,000		664,000		706,000		700,000		816,000		736,000		633,000		5,939,000
Date as of which options may be exercised	March 18, 2003		June 16, 2004	^(d)	July 12, 2004	^(e)	January 1, 2005		July 10, 2004		July 17, 2005		July 21, 2006		July 20, 2007		July 19, 2008

Expiration date	March 17, 2006		June 15, 2007		July 11, 2008		July 10, 2009		July 9, 2010		July 16, 2011		July 20, 2012		July 19, 2013		July 18, 2014

Initial exercise price (€)	93.76		113.00		162.70		168.20		158.30		133.20		159.40		198.90		—

Exercise price until May 23, 2006 (€)^(f)	23.44		28.25		40.68		42.05		39.58		33.30		39.85		49.73		—
Exercise price from May 24, 2006 (€)^(f)	—		27.86		40.11		41.47		39.03		32.84		39.30		49.04		50.60
Number of options:^(a)
• Outstanding as of January 1, 2006	589,652		2,052,432		6,509,944		8,735,900		11,283,480		11,196,796		13,411,320		6,094,080				59,873,604
• Awarded in 2006	—		—		—		—		—		—		—		134,400		5,727,240		5,861,640
• Cancelled in 2006	(72,692	)	—		(7,272	)^(h)	(15,971	)	(26,694	)	(22,200	)	(57,263	)	(43,003	)	(1,080	)	(246,175	)
• Adjustments related to the Arkema spin-off^(g)	—		25,772		84,308		113,704		165,672		163,180		196,448		90,280		—		839,364
• Exercised in 2006	(516,960	)	(707,780	)	(1,658,475	)	(1,972,348	)	(2,141,742	)	(729,186	)	(120,133	)	—		—		(7,846,624	)
• Outstanding as of December 31, 2006	—		1,370,424		4,928,505		6,861,285		9,280,716		10,608,590		13,430,372		6,275,757		5,726,160		58,481,809

(a)

The number of options awarded, outstanding, cancelled and exercised up to May 23, 2006 has been multiplied by four to take into account the four-for-one stock split approved by TOTAL’s shareholders’ meeting on May 12, 2006.

(b)

Options awarded to employees of the Group serving on the Board at the time of award. For the 2006 plan, options awarded to Messrs. Thierry Desmarest, Chairman and Chief Executive Officer of TOTAL S.A., Daniel Boeuf, the director representing employee shareholders, and Christophe de Margerie, director of TOTAL S.A. and President of the Exploration & Production division.

(c)

Employees of TOTAL S.A. and any company in the Group who were not executive directors of TOTAL S.A. at the time of award.

(d)

January 1, 2003 for employees under contract with a subsidiary incorporated outside of France.

(e)

January 1, 2004 for employees under contract with a subsidiary incorporated outside of France.

(f)

To take into account the four-for-one stock split, the exercise price of stock options has been divided by four. In addition, to take into account the Arkema spin-off, the exercise price of stock options was multiplied by an adjustment ratio of 0.986147, effective as of May 24, 2006.

(g)

Adjustments approved by the Board on March 14, 2006 pursuant to Articles 174-9, 174-12 and 174-13 of Decree No. 67-236 dated March 23, 1967 in effect at the time of the Board meeting as well as at the time of the shareholders’ meeting of TOTAL S.A. on May 12, 2006, related to the spin-off of Arkema. The adjustments were made on May 22, 2006 and became effective on May 24, 2006.

(h)

Including the confirmation in 2006 by the Company of the award of 500 stock options (for underlying shares,par value €10 per share) that had been cancelled erroneously in 2001.

TOTAL STOCK OPTIONS AWARDED TO EXECUTIVE OFFICERS (MANAGEMENT COMMITTEE AND TREASURER AS OF DECEMBER 31, 2006)


	1998 Plan		1999 Plan		2000 Plan		2001 Plan		2002 Plan		2003 Plan		2004 Plan	2005 Plan	2006 Plan	Total
Type of option	Purchase options		Purchase options		Purchase options		Purchase options		Purchase options		Subscription options		Subscription options	Subscription options	Subscription options
Expiration date	March 17, 2006		June15, 2007		July 11, 2008		July 10, 2009		July 9, 2010		July 16, 2011		July 20, 2012	July 19, 2013	July 18, 2014
Initial exercise price (€)	93.76		113.00		162.70		168.20		158.30		133.20		159.40	198.90	—
Exercise price until May 23, 2006 (€)^(a)	23.44		28.25		40.68		42.05		39.58		33.30		39.85	49.73	—
Exercise price from May 24, 2006 (€)^(a)	—		27.86		40.11		41.47		39.03		32.84		39.30	49.04	50.60
Options awarded by the Board (before taking into account the four-for-one stock split)^(b)	106,700		183,000		215,000		269,550		280,300		307,276		369,000	326,360	1,438,920
Options awarded by the Board (after taking into account the four-for-one stock split)^(b)	426,800		732,000		860,000		1,078,200		1,121,200		1,229,104		1,476,000	1,305,440	1,438,920	9,667,664
Options outstanding as of January 1, 2006^(b)	67,448		247,076		540,000		1,056,200		1,121,200		1,102,592		1,476,000	1,305,440	—	6,915,956
Options exercised up to May 23, 2006^(b)	(67,448	)	(59,000	)	(112,800	)	(327,200	)	—		(23,680	)	—	—	—	(590,128	)
Adjustment related to the Arkema spin-off^(c)	—		2,664		6,048		10,300		15,820		15,228		20,796	18,400	—	89,256
Options awarded after May 24, 2006			—		—		—		—		—		—	—	1,438,920	1,438,920
Options exercised after May 24, 2006	—		(8,918	)	(17,852	)	(100,272	)	(164,284	)	(205,216	)	—	—	—	(496,542	)
Options outstanding as of December 31, 2006	—		181,822		415,396		639,028		972,736		888,924		1,496,796	1,323,840	1,438,920	7,357,462

(a)

(b)

The number of options awarded, outstanding or exercised up to May 23, 2006 has been multiplied by four to take into account the four-for-one stock split approved by TOTAL’s shareholders’ meeting on May 12, 2006.

(c)

In 2006, Mr. Christophe de Margerie, a director of TOTAL S.A. and member of the Executive Committee, was awarded 160,000 options under the 2006 Plan and exercised 9,000 options, awarded under the 1998 Plan, for 9,000 underlying shares, par value €10 per share (after the stock split, 36,000 shares, par value €2.50 per share). Pursuant to the adjustments related to the Arkema spin-off, Mr. Christophe de Margerie was attributed an additional 9,876 options based on his options outstanding as of May 23, 2006. These options from the adjustment give rights, upon exercise, to a total of 9,876 shares, par value €2.50 per share.

In 2006, Mr. Daniel Boeuf, the director of TOTAL S.A. representing employee shareholders, was awarded 720 options under the 2006 Plan and did not exercise any options. Pursant to the adjustments related to the Arkema spin-off, Daniel Boeuf was attributed an additional 12 options related to the options he had been awarded under the 2005 Plan. These options from the adjustment give rights, upon exercise, to a total of 12 shares, par value €2.50 per share.

Certain Executive Officers of TOTAL as of December 31, 2006 who were previously with the Elf Aquitaine group hold Elf Aquitaine options that, upon exercise, benefit from exchange rights for TOTAL shares based upon the exchange ratio used in the public tender offer of TOTAL for Elf Aquitaine in 1999.

TOTAL STOCK OPTIONS AWARDED TO MR. THIERRY DESMAREST,

CHAIRMAN OF THE BOARD OF TOTAL S.A.


	1998 Plan	1999 Plan		2000 Plan		2001 Plan		2002 Plan	2003 Plan		2004 Plan	2005 Plan	2006 Plan	Total
Type of option	Purchase options	Purchase options		Purchase options		Purchase options		Purchase options	Subscription options		Subscription options	Subscription options	Subscription options
Expiration date	March 17, 2006	June15, 2007		July 11, 2008		July 10, 2009		July 9, 2010	July 16, 2011		July 20, 2012	July 19, 2013	July 18, 2014
Initial exercise price (€)	93.76	113.00		162.70		168.20		158.30	133.20		159.40	198.90	—
Exercise price until May 23, 2006 (€)^(a)	23.44	28.25		40.68		42.05		39.58	33.30		39.85	49.73	—
Exercise price from May 24, 2006 (€)^(a)	—	27.86		40.11		41.47		39.03	32.84		39.30	49.04	50.60
Options awarded by the Board (before taking into account the four-for-one stock split)^(b)	30,000	40,000		50,000		75,000		60,000	60,000		60,000	60,000	240,000
Options awarded by the Board (after taking into account the four-for-one stock split)^(b)	120,000	160,000		200,000		300,000		240,000	240,000		240,000	240,000	240,000	1,980,000
Options outstanding as of January 1, 2006^(b)	—	24,000		52,000		300,000		240,000	176,000		240,000	240,000	—	1,272,000
Options exercised up to May 23, 2006^(b)	—	(24,000	)	(52,000	)	(120,000	)	—	—		—	—	—	(196,000	)
Adjustment related to the Arkema spin-off^(c)	—	—		—		2,532		3,372	2,476		3,372	3,372	—	15,124
Options awarded after May 24, 2006	—	—		—		—		—	—		—	—	240,000	240,000
Options exercised after May 24, 2006	—	—		—		(80,000	)	—	(116,000	)	—	—	—	(196,000	)
Options outstanding as of December 31, 2006	—	—		—		102,532		243,372	62,476		243,372	243,372	240,000	1,135,124

(a)

(b)

(c)

STOCK OPTIONS EXERCISED BY THE TEN EMPLOYEES (OTHER THAN EXECUTIVE DIRECTORS) EXERCISING THE LARGEST NUMBER OF OPTIONS


	Total number of options exercised^(a)	Exercise price up to May 23, 2006^(b) (€)	Exercise price from May 24, 2006^(b) (€)	Date of the Board meeting awarding the options	Expiration date
Options exercised in 2006 by the ten employees of TOTAL S.A., or any company in the Group, exercising the largest number of options	3,200	23.44	—	March 17, 1998	March 17, 2006
	31,256	28.25	27.86	June 15, 1999	June 15, 2007
	55,888	40.68	40.11	July 11, 2000	July 11, 2008
	256,544	42.05	41.47	July 10, 2001	July 10, 2009
	183,638	39.58	39.03	July 9, 2002	July 9, 2010
	108,690	33.30	32.84	July 16, 2003	July 16, 2011
	22,312	39.85	39.30	July 20, 2004	July 20, 2012
	661,528	38.70^(c)

(a)

The number of options exercised up to May 23, 2006 has been multiplied by four to take into account the four-for-one stock split approved by TOTAL’s shareholders’ meeting on May 12, 2006.

(b)

(c)

Weighted-average price.

TOTAL restricted share grants

The following table gives a breakdown of restricted share grants by category of grantee (executive officers, senior managers and other employees).


		Number of grantees	Number of restricted shares granted^(a)	Percentage		Average number of restricted shares per grantee^(b)
2005 Plan^(b)	Executive officers^(d)	29	13,692	2.4	%	472
(Decision of the Board on July 19, 2005)	Senior managers	330	74,512	13.1	%	226
	Other employees	6,956	481,926	84.5	%	69
	Total	7,315	570,130	100	%	78
2006 Plan^(c)	Executive officers^(d)	26	49,200	2.2	%	1,892
(Decision of the Board on July 18, 2006)	Senior managers	304	273,832	12.0	%	901
	Other employees^(e)	7,509	1,952,332	85.8	%	260
	Total	7,839	2,275,364	100	%	290

(a)

The number of restricted shares granted shown in this table has not been recalculated to take into account the four-for-one stock split approved by the shareholders’ meeting on May 12, 2006.

(b)

Grant approved by the Board on July 19, 2005 pursuant to the authority given by the shareholders’ meeting on May 17, 2005. Grants of these restricted shares, which the Company purchased on the market in 2005, will become final, subject to performance conditions, on July 20, 2007, after a two-year vesting period. Under these performance conditions, the final number of restricted shares granted will be calculated according to the return on average capital employed, based on the accounts published by the Group for the financial year, in this case 2006, preceding the year of final grant. The restricted shares finally granted are then subject to a two-year holding period, in this case ending on July 20, 2009. To provide for the eventual final grant of these restricted shares, the Company purchased 574,000 previously issued shares, par value €10 per share, on the market at an average price of €206.49 per share, par value €10 per share, the equivalent of an average price of €51.62 per share, par value €2.50 per share.

(c)

Grant approved by the Board on July 18, 2006 pursuant to the authority given by the shareholders’ meeting on May 17, 2005. Grants of these restricted shares, which the Company purchased on the market in 2006, will become final, subject to performance conditions, on July 19, 2008, after a two-year vesting period. Under these performance conditions, the final number of restricted shares granted will be calculated according to the return on average capital employed, based on the accounts published by the Group for the financial year, in this case 2007, preceding the year of final grant. The restricted shares finally granted are then subject to a two-year holding period, in this case ending on July 19, 2010. To provide for the eventual final grant of these restricted shares, the Company purchased 2,295,684 shares on the market at an average price of €51.91 per share.

(d)

Members of the Executive Committee and the Treasurer as of the date of the Board meeting granting the restricted shares. The Chairman of the Board is not granted restricted shares. Mr. Christophe de Margerie, a director of TOTAL S.A., was not granted restricted shares under the 2006 Plan.

(e)

Mr. Daniel Boeuf, the director of TOTAL S.A. representing employee shareholders, was granted 416 restricted shares under the 2006 Plan.

RESTRICTED SHARE PLANS AS OF DECEMBER 31, 2006


	2005 Plan^(a)		2006 Plan
Date of the shareholders’ meeting	May 17, 2005		May 17, 2005
Date of the Board meeting	July 19, 2005		July 18, 2006
Closing share price on the date of the Board meeting (€)^(b)	52.13		50.40
Average repurchase price per share paid by the Company (€)^(b)	51.62		51.91
Total number of restricted shares granted, of which	2,280,520		2,275,364
- Executive directors^(c)	416		416
- Ten employees with largest grants^(d)	20,000		20,000
Start of the vesting period	July 19, 2005		July18, 2006
Date of final grant, subject to specified conditions (end of the vesting period)	July 20, 2007		July 19, 2008
Transfer possible from (end of the holding period)	July 20, 2009		July 19, 2010
Number of restricted shares:
- Outstanding as of January 1, 2006	2,274,528		—
- Granted in 2006	—		2,275,364
- Cancelled in 2006	(7,432	)	(3,068	)
- Outstanding as of December 31, 2006	2,267,096		2,272,296
Number of restricted shares finally granted in 2006	—		—

(a)

The number of restricted shares granted has been multiplied by four to take into account the four-for-one stock split approved by TOTAL’s shareholders’ meeting on May 12, 2006.

(b)

The closing price for TOTAL shares on July 19, 2005 (€208.50) has been divided by four in order to take into account the four-for-one stock split. The average repurchase price per share in 2005 (€206.49) has also been divided by four.

(c)

Restricted shares granted to executive directors as of the date of grant. The Chairman of the Board is not granted restricted shares. Mr. Daniel Boeuf, the director of TOTAL S.A. representing employee shareholders, was granted 416 restricted shares under the 2006 Plan. Mr. Christophe de Margerie, a director of TOTAL S.A. and President of the Exploration & Production division, was not granted restricted shares under the 2006 Plan.

(d)

Employees of TOTAL S.A., or of any Group company, who were not executive directors of TOTAL S.A. as of the date of grant.

ELF AQUITAINE STOCK OPTIONS OF EXECUTIVE OFFICERS (MEMBERS OF THE MANAGEMENT COMMITTEE AND THE TREASURER AS OF DECEMBER 31, 2006)

This exchange ratio was adjusted on May 22, 2006 as described in note (c) to the table below as well as in Note 24 to the Consolidated Financial Statements.


Elf Aquitaine stock subscription plan	1999 Plan No.1
Exercise price, per Elf Aquitaine share, until May 23, 2006 (€)^(a)	115.60
Exercise price, per Elf Aquitaine share, from May 24, 2006 (€)^(a)	114.76
Expiration date	March 30, 2009
Options awarded	16,130
Options outstanding as of January 1, 2006	4,287
Options exercised in 2006	(1,356	)
Adjustments for S.D.A. spin-off^(b)	28
Options outstanding as of 2006	2,959
Corresponding number of TOTAL shares, as of December 31, 2006, pursuant to the exchange guarantee^(c)	17,754

(a)

The exercise price for Elf Aquitaine options was adjusted to take into account the spin-off of S.D.A (Société de Développement Arkema) by Elf Aquitaine. This adjustment consisted of multiplying the exercise price by 0.992769, effective as of May 24, 2006.

(b)

Adjustments approved by the Board of Elf Aquitaine on March 10, 2006 pursuant to Articles 174-9, 174-12 and 174-13 of Decree No-67-236 dated March 23, 1967 in effect at the time of this meeting as well as at the time of the shareholders’ meeting of Elf Aquitaine on May 10, 2006, related to the spin-off of S.D.A. The adjustments were made on May 22, 2006 and became effective on May 24, 2006.

(c)

To take into account the spin-off of S.D.A. by Elf Aquitaine, the spin-off of Arkema by TOTAL S.A. and the four-to-one TOTAL stock split, on March 14, 2006 the Board of TOTAL S.A. approved an adjustment to the exchange ratio used under the exchange guarantee mentioned above. This exchange ratio was adjusted to become six TOTAL shares per each Elf Aquitaine share upon approval of the S.D.A. spin-off by the shareholders’ meeting of Elf Aquitaine on May 10, 2006 and of the Arkema spin-off as well as the four-for-one TOTAL stock split by the shareholders’ meeting of TOTAL S.A. on May 12, 2006.

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

Major Shareholders

As of December 31, 2006, to the Company’s knowledge, Total Actionnariat France, an employee investment fund, held shares representing 2.8% of the Company’s shares and 5.5% of the voting rights in the Company. In addition, Frère-Bourgeois S.A. (mainly through Compagnie Nationale à Portefeuille) and the Desmarais family indirectly control Groupe Bruxelles Lambert. These parties have declared that, acting in concert, they hold 5.3% of the Company’s shares and 5.4% of the voting rights. Neither TOTAL Actionnariat France, Compagnie Nationale à Portefeuille nor Groupe Bruxelles Lambert has voting rights different from other shareholders of the Company having held their shares in registered form for over two years.

As of March 31, 2007, there were 180,713,411 ADSs outstanding in the United States, representing 7.55% of the total outstanding shares.

The Company is not directly or indirectly owned or controlled by another corporation, by any foreign government or by any other natural or legal person. The Company does not know of any arrangements that may,

at a subsequent date, result in a change of control of TOTAL. The so-called “golden share” of the French State, which previously allowed the State to restrict the transfer of control of Elf Aquitaine, was abrogated on October 3, 2002 and has no further effect.

Related Party Transactions

The Group’s main transactions with related parties (principally all the investments carried under the equity method) and the balances receivable from and payable to them are shown in Note 28 to the Consolidated Financial Statements included elsewhere herein.

In the ordinary course of its business, TOTAL enters into transactions with various organizations with which certain of its directors or executive officers may be associated, but no such transactions of a material or unusual nature have been entered into during the period commencing on January 1, 2005 and ending on March 31, 2007.

ITEM 8. FINANCIAL INFORMATION

Consolidated Statements and other supplemental information

See pages F-1 through F-83 and S-1 through S-11 for TOTAL’s Consolidated Financial Statements and other supplemental information.

Legal or arbitration proceedings

While it is not feasible to predict the outcome of the pending claims, proceedings, and investigations described below with certainty, management is of the opinion that their ultimate disposition should not have a material adverse effect on the Company’s financial position, cash flows, or results of operations.

Grande Paroisse

An explosion occurred at the Grande Paroisse industrial site in the city of Toulouse (France) on September 21, 2001. Grande Paroisse, a former subsidiary of Atofina which became a subsidiary of Elf Aquitaine Fertilisants on December 31, 2004 pursuant to the reorganization of the Chemicals segment, was principally engaged in the production and sale of agricultural fertilizers. The explosion, which involved a stockpile of ammonium nitrate pellets, destroyed a portion of the site and caused the death of 30 people and injured many others. In addition, certain property in an area of Toulouse was damaged.

This plant has been closed and the site is being restored. Individual assistance packages have been provided for employees.

On December 14, 2006, Grande Paroisse signed, under the supervision of the city of Toulouse, the deed whereby it donated the former site of the AZF plant to the greater agglomeration of Toulouse (CAGT) and the Caisse des Dépôts et Consignations and its subsidiary ICADE. Under this deed, TOTAL S.A. guaranteed the site restoration obligations of Grande Paroisse and granted a 10 M€ endowment to the InNaBioSanté research foundation in the framework of the city of Toulouse’s project to create a cancer research center at the site.

Regarding the cause of the explosion, the hypothesis that the explosion was caused by Grande Paroisse through the accidental mixing of hundreds of kilos of a chlorine compound at a storage site for amonium nitrate was discredited over the course of the investigation. As a result, proceedings against ten of the eleven Grande Paroisse employees charged during the criminal investigation conducted by the Toulouse Regional Court (Tribunal de Grande Instance) were dismissed and this dismissal was upheld by the Appeals Court of Toulouse.

Nevertheless, the final experts’ report filed on May 11, 2006 continues to focus on the hypothesis of a chemical accident, although this hypothesis was not confirmed by an attempt to reconstruct the accident at the site. The hypothesis no longer is based on the mixing of 500 kilograms of a chlorine compound at a storage site for ammonium nitrate, but instead the pouring of 500 kilograms of ammonium nitrate in a container whose floor was supposedly covered with sweepings of a chlorine compound. Grande Paroisse was investigated based on this new hypothesis in 2006. Grande Paroisse is contesting this explanation, which it believes to be based on elements that are not factually accurate.

On September 21, 2006, the investigating judge closed his investigation. Grande Paroisse and the former manager of the site have requested that additional information be obtained relating to the expert’s investigations. These requests are currently being reviewed by the Chambre d’Instruction of the Court of Appeals of Toulouse. A decision on this appeal is expected in the first half 2007.

Pursuant to applicable French law, Grande Paroisse is presumed to bear sole responsibility for the explosion as long as the cause of the explosion remains unknown. While awaiting the conclusion of the investigation, Grande Paroisse has set up a compensation system for victims. At this stage, the estimate for the compensation of all claims and related expenses has been increased to 2.15 B€ (compared to 2.05 B€ in 2005). This figure exceeds by 1.35 B€ Grande Paroisse’s insurance coverage for legal liability (capped at 0.8 B€). The provision for potential liability and complementary claims was increased by 100 M€ in 2006, and as a result the total unused provision stands at 176 M€ as of December 31, 2006, compared to a provision of 133 M€ as of December 31, 2005.

Antitrust investigations

Following investigations into certain commercial practices in the chemicals industry in the United States, certain chemical subsidiaries of the Arkema group are involved in several civil liability lawsuits in the United States and Canada for violations of antitrust laws. TOTAL S.A. has been named in certain of these suits as the parent company.

In Europe, the European Commission commenced investigations in 2000, 2003 and 2004 into alleged anti-competitive practices involving certain products sold by Arkema⁽¹⁾. In January 2005, following one of these investigations, the European Commission fined Arkema 13.5 M€ and jointly fined Arkema and Elf Aquitaine 45 M€. Arkema and Elf Aquitaine have appealed these decisions to the Court of First Instance of the European Union.

The Commission notified Arkema, TOTAL S.A. and Elf Aquitaine of complaints concerning two other product lines in January and August 2005, respectively. Arkema has cooperated with the authorities in these procedures and investigations. As a result of these proceedings, in May 2006 the European Commission fined Arkema 78.7 and 219.1 M€, respectively. Elf Aquitaine was held jointly and severally liable for, respectively, 65.1 M€ and 181.35 M€ of these fines while TOTAL S.A. was held jointly and severally liable, respectively, for 42 M€ and 140.4 M€. TOTAL S.A., Elf Aquitaine and Arkema have appealed these decisions to the Court of First Instance of the European Union.

(1)

Arkema is used in this section to designatee those companies of the Arkema group whose ultimate parent company is Arkema S.A. Arkema became an independent company after being spun-off from TOTAL S.A. in May 2006.

No facts have been alleged that would implicate TOTAL S.A. or Elf Aquitaine in the practices questioned in these proceedings and the fines are based solely on their status as parent companies.

Arkema began implementing compliance procedures in 2001 that are designed to prevent its employees from violating antitrust provisions. However, it is not possible to exclude the possibility that the relevant authorities could commence additional proceedings involving Arkema and TOTAL S.A. and Elf Aquitaine.

2)	As part of the agreement relating to the spin-off of Arkema, TOTAL S.A. or certain other Group companies agreed to grant Arkema guarantees for certain risks related to antitrust proceedings arising from events prior to the spin-off.

These guarantees cover, for a period of ten years, 90% of the amounts paid by Arkema companies related to (i) fines imposed by European authorities or European member-states for competition law violations, (ii) fines imposed by American courts or antitrust authorities for federal antitrust violations or violations of the competition laws of U.S. states, (iii) damages awarded in civil proceedings related to the government proceedings mentioned above, and (iv) certain costs related to these proceedings.

The guarantee covering anticompetition violations in Europe applies to amounts that exceed a 176.5 M€ threshold.

If one or more individuals or legal entities, acting alone or together, directly or indirectly holds more than one-third of the voting rights of Arkema, or if the Arkema group transfers more than 50% of its assets (as calculated under the enterprise valuation method, as of the date of the transfer) to a third party or parties acting together, irrespective of the type or number of transfers, these guarantees will become void.

On the other hand, the agreements provide that Arkema will indemnify TOTAL S.A. or any Group companies for 10% of any amount that TOTAL S.A. or any Group companies are required to pay under any of the proceedings covered by these guarantees.

3)	The Group has recorded provisions amounting to 138 M€ in its consolidated accounts as of December 31, 2006 to cover the risks mentioned above.

4)	Moreover, as a result of investigations initiated by the European Commission in October 2002 concerning certain Refining & Marketing

subsidiaries of the Group, Total Nederland N.V. received a statement of objections in October 2004. A statement of objections regarding these practices has also been addressed to TOTAL S.A. These proceedings resulting in Total Nederland N.V. being fined 20.25 M€ and in TOTAL S.A. being held jointly responsible for 13.5 M€ of this amount, although no facts implicating TOTAL S.A. in the practices under investigation were alleged.

TOTAL S.A. and Total Nederland N.V. have appealed this decision to the Court of First Instance of the European Union.

Given the discretionary powers granted to the European Commission for determining fines, it is not currently possible to determine with certainty the outcome of these investigations and proceedings. TOTAL S.A. and Elf Aquitaine are contesting their liability and the method of determining these fines. Although it is not possible to predict the outcome of these proceedings, the Group believes that they will not have a material adverse effect on its financial condition or results.

Sinking of the Erika

Following the sinking in December 1999 of the Erika, a tanker that was transporting products belonging to one of the Group companies, the clean-up of parts of the coastline, pumping out the remaining cargo from the wreck and processing of more than 200,000 tons of waste was completed from 2000 to 2003, pursuant to the Company’s undertakings.

As part of a criminal investigation, on February 1, 2006 the investigating judge brought charges in the Tribunal correctionnel de Paris against 15 parties, including four entities.

TOTAL S.A. and two of its subsidiaries responsible for shipping have been charged with marine pollution and as accessories to the endangerment of human life. A manager in the shipping department was charged with the same offenses, as well as with the failure to take action to limit the damage from an accident. The case is being heard by the Tribunal de grande instance in Paris. Proceedings began on February 12, 2007 and are scheduled to continue until June 13, 2007.

TOTAL believes that the violations with which the Group and its employee were charged are without substance as a matter of fact and as a matter of law.

Buncefield

On December 11, 2005, several explosions followed by a major fire occurred at Buncefield, north of London, in an oil storage depot. This depot is operated by HOSL, a company in which the British subsidiary of TOTAL holds 60% and another oil group holds 40%.

The explosion injured 40 people, most of whom suffered slight injuries, and caused property damage to the depot and the buildings and homes located nearby. The HSE Investigation Board has indicated that the explosion was caused by the overflow of a tank at the depot. The final HSE report detailing the circumstances and the exact cause of the explosion is expected to be released before the end of 2007. At this stage, responsibility for the explosion and the allocation of liabilities have not yet been determined.

The Group is insured for damage to these facilities, operating losses and claims from third parties under its civil liability and believes that, based on the current information available, this accident should not have a significant impact on its financial position, cash flows or results.

Myanmar

Under the Belgian “universal jurisdiction” laws of June 16, 1993 and February 10, 1999, a complaint was filed in Belgium on April 25, 2002 against the Company, its Chairman and the former president of its subsidiary in Myanmar. These laws were repealed by the Belgian law of August 5, 2003 on “serious violations of international human rights”, which also provided a procedure for terminating certain proceedings that were underway. In this framework, the Belgian Cour de cassation terminated the proceedings against TOTAL in a decision dated June 29, 2005. The plaintiffs’ appeal against this decision was rejected by the Cour de cassation on March 28, 2007.

TOTAL has always maintained that the accusations made against the Company and its management arising out of the activities of its subsidiary in Myanmar are without substance as a matter of fact and as a matter of law.

South Africa

In a threatened class action proceeding in the United States, TOTAL is being accused, together with approximately 100 other multinational companies, by certain South African citizens who allege that their human rights were violated during the era of apartheid by the army, the police or militias, and who consider that these companies were accomplices in the actions by the South African authorities at the time.

The claims against the companies named in the class action, which has not yet been officially brought against TOTAL, were dismissed by a federal judge in New York. The plaintiffs have appealed this dismissal.

Iran

In 2003, the SEC issued a non-public formal order directing a private investigation in the matter of certain oil companies (including, among others, TOTAL) in connection with the pursuit of business in Iran. More recently, a judicial inquiry related to TOTAL was initiated in France. In 2007, Christophe de Margerie, as the former President of the Middle East department of the Upstream segment, was placed under formal investigation in relation to this inquiry. The inquiry concerns an agreement concluded by the Group that relates to the South Pars gas field and allegations that certain payments made pursuant to this agreement were paid to Iranian officials in connection with contracts entered into between the Group and the National Iranian Oil Company (NIOC). The Company believes that the negotiation and execution of the agreement did not violate any applicable laws or applicable international conventions. The Company cannot, however, exclude the possibility that additional procedures may be initiated with respect to this matter.

Oil-for-Food Program

Several countries have commenced investigations concerning possible violations related to the United Nations (UN) Oil-for-Food program in Iraq.

Pursuant to a French judicial investigation, certain current or former Group employees were placed under formal investigation for possible charges as accessories to the misappropriation of corporate assets and as accessories to the corruption of foreign public agents. The President of the Group’s Exploration & Production division, who is now the Company’s Chief Executive Officer, was also placed under formal investigation in October 2006.

The Company believes that its activities related to the Oil-for-Food program have been in compliance with this program, as organized by the UN.

CEPSA

TOTAL has been a shareholder in the Spanish oil and gas company CEPSA since 1990. The other main shareholders of CEPSA are Santander Central Hispano S.A. (SCH), Unión Fenosa and International Petroleum Investment Company.

In March 2006, the Netherlands Arbitration Institute at The Hague settled a dispute between TOTAL and SCH. In August 2006, TOTAL and SCH signed an agreement in order to implement this arbitration award, thus enabling TOTAL to directly hold the 7.51% of CEPSA’s stock that it used to indirectly hold through the holding entity Somaen Dos, while shareholders’ agreements between TOTAL and SCH in respect of CEPSA were terminated.

Furthermore, following the authorization of the European Commission in October 2006, SCH sold to TOTAL 4.35% of CEPSA’s shares at a price of €4.54 per share, representing an aggregate amount of approximately 53 M€, also to implement the aforementioned arbitration award.

Dividend policy

The Company has paid dividends on its share capital in each year since 1946. Future dividends will depend on the Company’s earnings, financial condition and other factors. The payment and amount of dividends are subject to the recommendation of the Board of Directors and resolution by the Company’s shareholders’ at the annual shareholders’ meeting.

For the 2006 fiscal year, the Board of Directors has proposed a dividend of €1.87 per share. This proposed dividend will be voted on by the shareholders’ meeting

to be held on May 11, 2007. An interim dividend of €0.87 per share was paid on November 17, 2006. If approved, the balance of €1.00 per share will be paid on May 18, 2007.

Dividends paid to holders of ADRs will be subject to a charge by the Depositary for any expenses incurred by the Depositary in the conversion of euro to dollars. See “Taxation” under “Item 10. Additional Information” for a summary of certain U.S. federal and French tax consequences to holders of shares and ADRs.

Significant changes

For a description of significant changes that have occurred since the date of the Company’s Consolidated Financial Statements, see “Item 4. Information on the Company” and “Item 5. Operating and Financial Review and Prospects”, which include descriptions of certain recent 2007 activities.

ITEM 9. THE OFFER AND LISTING

Markets

The principal trading market for the shares is the Eurolist by Euronext exchange in Paris. The shares are also listed on Euronext Brussels and the London Stock Exchange, and are quoted on SEAQ International.

Offer and listing details

Trading on Euronext Paris

Official trading of listed securities on Euronext Paris, including the shares, is transacted through French investment service providers that are members of Euronext Paris and takes place continuously on each business day in Paris from 9:00 a.m. to 5:30 p.m. (Paris time), with a fixing of the closing price at 5:35 p.m. Euronext Paris may suspend or resume trading in a security listed on Eurolist if the quoted price of the security exceeds certain price limits defined by the regulations of Euronext Paris.

From April 1, 2006, all the markets of Euronext Paris settle and transfer ownership three trading days after a transaction (T+3). Highly liquid shares, including those of the Company, are eligible for deferred settlement (Service à Réglement Différé — SRD). Payment and delivery for shares under the SRD occurs on the last trading day of each month. Use of the SRD service requires payment of a commission. Under this system, the determination date for settlement on the following month occurs on the fifth trading day prior to the last trading day (inclusive) of each month.

In France, the shares are included in the principal index published by Euronext Paris (the “CAC 40 Index”). The CAC 40 Index is derived daily by comparing the total

market capitalization of 40 stocks included in the Eurolist by Euronext exchange in Paris to the total market capitalization of the same stocks on December 31, 1987. Adjustments are made to allow for expansion of the sample due to new issues. The CAC 40 Index indicates trends in the French stock market as a whole and is one of the most widely followed stock price indices in France. In the UK, the shares are listed in both the FTSE Eurotop 100 and FTSEurofirst 300 index. As a result of the creation of Euronext, the shares are included in Euronext 100, the index representing Euronext’s blue chip companies based on market capitalization. The shares are also included in the Dow Jones Stoxx 50 and Dow Jones Euro Stoxx 50, blue chip indices comprised of the 50 most highly capitalized and most actively traded equities throughout Europe and within the European Monetary Union, respectively. Since June 2000, the shares have been included in the Dow Jones Global Titans Index which consists of 50 global companies selected based on market capitalization, book value, assets, revenue and earnings.

Pursuant to the vote of the May 12, 2006 shareholders’ meeting approving to TOTAL’s four-for-one stock split, each shareholder received on May 18, 2006 four new TOTAL shares, par value of €2.50 per share, in return for each old share with a par value of €10. The table below sets forth, for the periods indicated, the reported high and low quoted prices in euros for the currently outstanding shares on Euronext Paris. Data prior to May 18, 2006 reported in this table has been adjusted to reflect this stock split by dividing stock prices by four. The May 12, 2006 shareholders’ meeting also approved the spin-off of Arkema and the allocation as of May 18, 2006 of one Arkema share allocation right for each TOTAL share with a par value of €10, ten allocation

rights entitling the holder to one Arkema share. Data prior to May 18, 2006 reported in the third and fourth columns of this table are adjusted in order to consider Arkema’s share allocation right partition.


Price per share (€)	High	Low	High adjusted	Low adjusted
2002	44.85	30.30	44.27	29.91
2003	36.98	27.63	36.50	27.27
2004	42.95	34.85	42.40	34.40
2005	57.28	39.50	56.54	38.99
First Quarter	46.03	39.50	45.43	38.99
Second Quarter	49.15	42.85	48.52	42.30
Third Quarter	57.28	48.03	56.54	47.41
Fourth Quarter	57.05	49.75	56.32	49.11

2006	58.15	46.52	57.40	46.52
First Quarter	58.15	51.43	57.40	50.76
Second Quarter	57.43	46.52	56.69	46.52
Third Quarter	54.50	49.45	—	—
Fourth Quarter	56.95	50.10	—	—
October	54.80	50.10	—	—
November	56.95	52.30	—	—
December	56.00	52.20	—	—

2007 (through April 5)	55.45	48.33	—	—
First Quarter	55.45	48.33	—	—
January	55.45	50.80	—	—
February	53.95	51.02	—	—
March	52.99	48.33	—	—
Second Quarter	52.99	52.05	—	—
April	52.99	52.05	—	—

Trading on the New York Stock Exchange

ADRs have been listed on the New York Stock Exchange since October 25, 1991. The Bank of New York serves as depositary with respect to the ADRs traded on the New York Stock Exchange. The table below sets forth, for the periods indicated, the reported high and low prices quoted in dollars for the currently outstanding ADRs on the New York Stock Exchange. After the four-for-one stock split, which was approved by the shareholders’ meeting on May 12, 2006 and

effective on May 18, 2006, and after the split of the ADRs by two on May 23, 2006, one ADR now corresponds to one TOTAL share. Data prior to May 23, 2006 reported in this table has been adjusted to take into account this stock split by dividing ADR prices by two. The May 12, 2006 shareholders’ meeting also approved the spin-off of Arkema and the allocation as from May 18, 2006 of one Arkema share allocation right for each TOTAL share with a par value of €10, 10 allocation rights entitling the holder to one Arkema share. Data prior to May 23, 2006 reported in the third and fourth columns of this table has been adjusted to reflect Arkema’s share allocation right partition.


Price Per ADR ($)	High	Low	High adjusted	Low adjusted
2002	41.62	30.15	40.95	29.66

2003	46.73	30.48	45.98	29.98

2004	55.28	43.88	54.39	43.17

2005	68.97	51.87	67.86	51.03
First Quarter	61.38	51.87	60.38	51.03
Second Quarter	59.99	54.21	59.03	53.33
Third Quarter	68.97	58.61	67.86	57.66
Fourth Quarter	67.58	59.76	66.49	58.79

2006	73.46	58.06	73.46	58.06
First Quarter	69.76	61.52	68.63	60.53
Second Quarter	72.27	58.06	71.10	58.06
Third Quarter	69.73	62.23	—	—
Fourth Quarter	73.46	63.71	—	—
October	69.05	63.71	—	—
November	72.13	66.84	—	—
December	73.46	69.48	—	—

2007 (through April 9)	72.65	63.89	—	—
First Quarter	72.65	63.89	—	—
January	72.65	66.13	—	—
February	70.97	66.99	—	—
March	70.44	63.89	—	—
Second Quarter	71.00	69.57	—	—
April	71.00	69.57	—	—

ITEM 10. ADDITIONAL INFORMATION

Memorandum and Articles of Association

Register Information

TOTAL S.A. is registered with the Nanterre Trade Register under the registration number 542 051 180.

Objects and Purposes

The Company’s purpose can be found in Article 3 of its statuts. Generally, the Company may engage in all activities relating to (i) the exploration and extraction of mining deposits and the performance of industrial refining, processing, and trading of these materials, as well as their derivatives and by-products; (ii) the production and distribution of all forms of energy; (iii) the chemicals, rubber and health industries; (iv) the transportation and shipping of hydrocarbons and other products or materials relating to the Company’s business purpose; and (v) all financial, commercial, and industrial operations and operations relating to any fixed or unfixed assets and real estate, acquisitions of interests or holdings in any business or company that may relate to any of the above-mentioned purposes or to any similar or related purposes, of such nature as to promote the Company’s extension or its development.

Director Issues

Compensation

Directors receive attendance fees, the maximum aggregate amount of which, determined by the shareholders acting at a shareholders’ meeting, remains in effect until a new decision is made. The Board of Directors may apportion this amount among its members in whatever way it considers appropriate. The Board may also grant its Chairman compensation in addition to attendance fees.

Retirement

The number of directors of TOTAL who are acting in their own capacity or as permanent representatives of a legal entity and are over 70 years old may not exceed one-third of the number of directors in office at the end of the fiscal year. If such number is exceeded, the oldest Board member is automatically deemed to have resigned. Directors who are the permanent representative of a legal person may not continue in office beyond their seventieth birthday.

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Shareholdings

Each director must own at least 1,000 shares of TOTAL during his or her term of office.

Election

Directors are elected for a term of three years. In 2003, TOTAL amended its Articles of Incorporation to provide for the election of one director to represent employee shareholders. This director was appointed at the shareholders’ meeting held on May 14, 2004.

Description of Shares

The following is a summary of the material rights of holders of fully paid shares and is based on the statuts of the Company and French Company Law as codified in Volume II of the French Commercial Code (referred to herein as the “French Company Law”). For more complete information, please read the statuts of TOTAL, a copy of which has been filed as an exhibit to this Annual Report.

Dividend rights

The Company may make dividend distributions to its shareholders from net income in each fiscal year, after deduction of the overhead and other social charges, as well as of any amortization of the business assets and of any provisions for commercial and industrial contingencies, as reduced by any loss carried forward from prior years, and less any contributions to reserves or amounts that the shareholders decide to carry forward. These distributions are also subject to the requirements of French Company Law and the Company’s statuts.

Under French Company Law, the Company must allocate 5% of its net profits in each fiscal year to a legal reserve fund until the amount in that fund is equal to 10% of the nominal amount of its share capital.

The Company’s statuts provide that its shareholders may decide to allocate all or a part of any distributable profits among special or general reserves, to carry them forward to the next fiscal year as retained earnings, or to allocate them to the shareholders as dividends. The statuts provide that the remainder of any distributable profits shall be distributed among the shareholders in the form of dividends, either in cash or in shares.

Under French Company Law, the Company must distribute dividends to its shareholders pro rata according to their shareholdings. Dividends are payable to holders of outstanding shares on the date fixed by the shareholders’ meeting approving the distribution of dividends or, in the case of interim dividends, on the date fixed by the Company’s Board of Directors at the

meeting that approves the distribution of interim dividends. Under French Company Law, dividends not claimed within five years of the date of payment revert to the French State.

Voting rights

Each shareholder of the Company is entitled to the number of votes he or she possesses or for which he or she holds proxies. According to French Company Law, voting rights may not be exercised in respect of fractional shares.

Each registered share that is fully paid and registered in the name of the same shareholder for a continuous period of at least two years is granted a double voting right after such two-year period. Upon capital increase by capitalization of reserves, profits or premiums on shares, a double voting right is granted to each registered share allocated to a shareholder relating to previously existing shares that already carry double voting rights. The double voting right is automatically canceled when the share is converted into a bearer share or when the share is transferred, unless the transfer is due to inheritance, division of community property between spouses, or a donation during the lifetime of the shareholder to the benefit of a spouse or relatives eligible to inherit.

In certain circumstances, French Company Law limits a shareholder’s right to vote:

•

Shares held by the Company or entities controlled by the Company, which cannot be voted;

•

Shares held by shareholders making a contribution in-kind to the Company, which cannot be voted with respect to resolutions relating to such in-kind contributions; and

•

Shares held by interested parties, which cannot be voted with respect to resolutions relating to such shareholders.

Under the Company’s statuts, the voting rights exercisable by a shareholder, directly, indirectly or by proxy, at any shareholders’ meeting are limited to 10% of the total number of voting rights attached to the shares on the date of such shareholders’ meeting. This 10% limitation may be increased by taking into account double voting rights held directly or indirectly by the shareholder or by proxy, provided that the voting rights exercisable by a shareholder at any shareholders’ meeting may never exceed 20% of the total number of voting rights attached to the shares.

These limitations on voting lapse automatically if any individual or entity acting alone or in concert with an individual or entity holds at least two-thirds of the total number of shares as a result of a tender offer for 100% of the shares.

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Liquidation rights

In the event the Company is liquidated, its assets remaining after payment of its debts, liquidation expenses and all of its other remaining obligations will first be distributed to repay the nominal value of the shares. After these payments have been made, any surplus will be distributed pro rata among the holders of shares based on the nominal value of their shareholdings.

Future capital calls

Shareholders are not liable to the Company for further capital calls other than the nominal value of their shares.

Preferential subscription rights

Holders of shares have preferential rights to subscribe on a pro rata basis for additional shares issued for cash. Shareholders may waive their preferential rights, either individually or, under certain circumstances, as a group at an extraordinary shareholders’ meeting. During the subscription period relating to a particular offering of shares, shareholders may transfer their preferential subscription rights that they have not previously waived.

Changes in share capital

Under French Company Law, the Company may increase its share capital only with the approval of its shareholders at an extraordinary shareholders’ meeting (or with a delegation of authority from its shareholders). There are two methods to increase share capital: (i) by issuing additional shares, including the creation of a new class of securities and (ii) by increasing the nominal value of existing shares. The Company may issue additional shares for cash or for assets contributed in kind, upon the conversion of debt securities, or other securities giving access to its share capital, that it may have issued, by capitalization of its reserves, profits or issuance premiums or, subject to certain conditions, in satisfaction of its indebtedness.

Under French Company Law, TOTAL may decrease its share capital only with the approval of its shareholders at an extraordinary shareholders’ meeting (or with a delegation of authority from its shareholders). There are two methods to reduce share capital: (i) by reducing the number of shares outstanding and (ii) by decreasing the nominal value of existing shares. The conditions under which the share capital may be reduced will vary depending upon whether the reduction is attributable to losses. The Company may reduce the number of outstanding shares either by an exchange of shares or by the repurchase and cancellation of its shares. Any decrease must meet the requirements of French Company Law, which states that all the holders of

shares in each class of shares must be treated equally, unless the affected shareholders otherwise agree.

Form of shares

The Company has only one class of shares, par value €2.50 per share. Shares may be held in either bearer or registered form. Shares traded on the Eurolist of Euronext Paris S.A. are cleared and settled through Euroclear France. The Company may use any lawful means to identify holders of shares, including a procedure known as titres au porteur identifiable according to which Euroclear France will, upon the Company’s request, disclose to the Company the name, nationality, address and number of shares held by each shareholder in bearer form. The information may only be requested by the Company and may not be communicated to third parties.

Holding of shares

Under French Company Law concerning the “dematerialization” of securities, the ownership rights of shareholders are represented by book entries instead of share certificates (other than certificates representing French securities which are outstanding exclusively outside the territory of France and are not held by French residents). Registered shares are entered into an account maintained by the Company or by a representative that it has nominated, while shares in bearer form must be held in an account maintained by an accredited financial intermediary on the shareholder’s behalf.

For all shares in registered form, the Company maintains a share account with Euroclear France which is administered by BNP Paribas Securities Services. In addition, the Company maintains accounts in the name of each registered shareholder either directly or, at a shareholder’s request, through a shareholder’s accredited intermediary, in separate accounts maintained by BNP Paribas Securities Services on behalf of the Company. Each shareholder’s account shows the name and number of shares held and, in the case of shares registered through an accredited financial intermediary, the fact that they are so held. BNP Paribas Securities Services, as a matter of course, issues confirmations to each registered shareholder as to shares registered in a shareholder’s account, but these confirmations do not constitute documents of title.

Shares held in bearer form are held and registered on the shareholder’s behalf in an account maintained by an accredited financial intermediary and are credited to an account at Euroclear France maintained by the intermediary. Each accredited financial intermediary maintains a record of shares held through it and will

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issue certificates of inscription for the shares that it holds. Transfers of shares held in bearer form only may be made through accredited financial intermediaries and Euroclear France.

Cancellation of treasury shares

The Board of Directors of the Company may cancel treasury shares owned by the Company in accordance with French Company Law up to a maximum of 10% of the share capital within any period of 24 months.

Description of TOTAL Share Certificates

The TOTAL share certificates are issued by Euroclear France. French law allows Euroclear France to create certificates representing French securities provided that these certificates are intended to be outstanding exclusively outside the territory of France and cannot be held by residents of France. Furthermore, TOTAL share certificates may not be held by a foreign resident in France, either personally or in the form of a bank deposit, but the coupons and rights may be exercised in France.

Certificates for TOTAL shares are either in bearer form or registered in a securities trading account. Under Euroclear France regulations applicable to bearer stock certificates, TOTAL share certificates cannot be categorized as secondary securities, such as ADSs, issued by a foreign company to represent TOTAL shares.

TOTAL share certificates have the characteristics of a bearer security, meaning:

•

negotiable outside France;

•

transmission by delivery; and

•

fungibility of the TOTAL share certificate, which may be converted freely from bearer form to registration in an account.

All rights attached to TOTAL shares must be exercised directly by the bearer of the TOTAL share certificates.

Description of TOTAL ADRs

The following is a general description of the depositary arrangement, including a summary of all material provisions of the deposit agreement pursuant to which ADSs are issued. The deposit agreement is among the Company, The Bank of New York, as depositary, and the holders from time to time of ADRs. For more complete information, please read the deposit agreement and the Form of ADR itself, copies of which are attached as Exhibit 1 to the registration statement on Form F-6 (Reg. No. 333-107311) filed with the Securities and Exchange Commission on July 24, 2003. Additional copies of the deposit agreement are available for inspection at the Corporate Trust Office of the depositary in New York, which is presently located at

101 Barclay Street, New York, New York 10286. The depositary’s principal executive office is located at One Wall Street, New York, New York 10286.

ADRs

ADRs evidencing the ADSs are issuable by the depositary pursuant to the deposit agreement. An ADR may evidence any number of ADSs. Each ADS represents one share deposited under the deposit agreement.

Deposit and withdrawal of shares

All references to the deposit, surrender, delivery, transfer and withdrawal of the shares when referring to shares not in certificated form, refer to book-entry transfers and do not contemplate the physical transfer of certificates representing the shares.

Upon receipt of notice, as provided in the deposit agreement, of a deposit with the custodian in Paris, and subject to the terms of the deposit agreement, the depositary will execute and deliver through its Corporate Trust Office to the holders of such ADSs, ADRs registered in the names of those holders for the number of ADSs requested by each holder. This execution and delivery will occur only upon payment to the depositary of a fee for the execution and delivery of the ADRs and of all taxes, governmental charges and fees.

Upon surrender of ADRs at the Corporate Trust Office of the depositary and payment of the fee of the depositary, and of all taxes and governmental charges, and subject to the provisions of the deposit agreement and the statuts of the Company, ADR holders are entitled to the transfer of deposited securities to an account in the name of such holder as shall be designated by such holder maintained by the Company in the case of shares in registered form, or by an accredited financial institution, as in the case of shares in bearer form. The depositary will not accept for surrender an ADR representing fewer than two ADSs or integral multiples thereof.

The forwarding of documents of title for delivery at the Corporate Trust Office of the depositary in New York City will be at the request, risk and expense of the ADR holder.

Pre-release of ADRs

In certain circumstances, subject to the provisions of the deposit agreement, The Bank of New York may issue ADRs before deposit of the underlying shares. This issuance is a “pre-release”. The Bank of New York may also deliver shares prior to receipt and cancellation of ADRs (even if they are cancelled before the pre-release

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transaction has been closed out). A pre-release is closed out as soon as the underlying shares are delivered to The Bank of New York. The Bank of New York may receive ADRs instead of shares to close out a pre-release. The Bank of New York may pre-release ADRs only under the following conditions:

•

before or at the time of the pre-release, the person to whom the pre-release is being made must represent to The Bank of New York in writing that it or its customer owns the shares or ADRs to be deposited;

•

the pre-release must be fully collateralized with cash or other collateral that The Bank of New York considers appropriate; and

•

The Bank of New York must be able to close out the pre-release on not more than five business days’ notice.

In addition, The Bank of New York will limit the number of ADRs that may be outstanding at any time as a result of pre-release. The Bank of New York, however, may disregard the limit from time to time, if it thinks it is appropriate to do so.

Dividends, other distributions and rights

Whenever the depositary receives any cash dividend or cash distribution from the Company, the depositary will, to the extent that in its judgment it can convert euros or any other foreign currency on a reasonable basis into dollars and transfer the resulting dollars to the United States:

•

convert all cash dividends and other cash distributions that it receives on the underlying deposited securities into dollars; and

•

distribute the amount received net of any expense, taxes, governmental charges incurred by the depositary in connection with the conversion, to the holders of the ADRs in proportion to the number of the ADSs representing shares held by each holder.

The amount distributed will be reduced by any amounts required to be withheld by the Company or the French paying agent on account of taxes. The depositary may convert euros into dollars by sale or in any other manner that it may determine. If the depositary determines in its judgment that any foreign currency received cannot be converted on a reasonable basis and transferred to the United States, the depositary may, after consultation with the Company, distribute the foreign currency received by it or, at its discretion, hold the foreign currency, uninvested and without liability for interest, for the respective accounts of the holders of the ADRs entitled to receive the amounts. The depositary will distribute only whole U.S. dollars and cents and will

round fractional cents to the nearest whole cent. If the exchange rates fluctuate during a time when the depositary cannot convert the foreign currency, the holder may lose some or all of the value.

The depositary will use reasonable efforts to follow the procedures established by the French Treasury for eligible U.S. Holders of ADRs to recover the excess 10% French withholding tax initially withheld and deducted in respect of dividends distributed to them and any fiscal or tax credit payment to be made to them by the French Treasury. To effect this recovery, the depositary will provide U.S. Holders of depositary receipts registered on the books of the depositary with the appropriate French tax forms and instructions, which will be provided by the Company to the depositary. Upon receipt by the depositary of properly completed and executed forms, the depositary will promptly cause them to be filed with the appropriate French tax authorities. Upon receipt of any resulting remittance, the depositary will distribute to the holders of the Company ADRs entitled to remittance, as soon as practicable, the remittance converted into dollars, net of expenses incurred by the depositary in connection with conversion.

If any distribution by the Company consists of a dividend in, or free distribution of, shares, the depositary may, upon prior consultation with and approval of the Company, and will, if the Company so requests, issue an amount of ADRs evidencing ADSs representing the amount of shares received as a dividend or free distribution. The depositary will distribute to the holders of outstanding ADRs, in proportion to their holding and subject to the provisions of the deposit agreement, including the withholding of taxes and governmental charges and the payment of fees, additional ADRs evidencing an aggregate number of ADSs representing the number of shares received as a dividend or free distribution.

In lieu of distributing fractional ADSs, the depositary will sell the amount of the shares represented by the aggregate amount of shares representing fractional ADSs and distribute the net proceeds in accordance with the provisions of the deposit agreement.

If additional ADSs are not so distributed, each ADS will represent the additional shares distributed. The Company and the depositary will not offer the shares to holders of ADRs unless a registration statement is in effect with respect to the securities represented by those rights under the Securities Act of 1933, as amended (the “Securities Act”) or the offer and sale of such shares to the holders are exempt from registration under the provisions of the Securities Act.

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Record dates

Whenever:

•

any cash dividend or other cash distribution becomes payable or any distribution other than cash is made;

•

rights are issued with respect to the underlying deposited securities;

•

for any reason the depositary causes, at the Company’s election, a change in the number of shares represented by each ADS; or

•

the depositary receives notice of any shareholders’ meeting’

the depositary will fix a record date, after consultation with the Company if the date is to be different from any payment date established by the Company in respect of the shares, for the determination of the holders of ADSs who are entitled to receive the dividend, distribution or rights. The depositary will, further, give instructions for the exercise of voting rights at any such meeting or for fixing the date on or after which each ADS will represent a changed number of shares, subject to the provisions of the deposit agreement.

Voting of the deposited securities

As soon as practicable after receipt by the depositary of a notice of any shareholders’ meeting, the depositary will mail a notice to the holders of the ADRs registered on the books of the depositary which will contain:

•

a summary in English of the notice of such meeting;

•

a statement that the holders of ADRs at the close of business on a specified record date will be entitled, subject to any applicable provisions of French Company Law, the Company’s statuts and the shares, to instruct the depositary to exercise the voting rights, if any, pertaining to the shares represented by their ADSs;

•

summaries in English of any materials or other documents provided by the Company for the purpose of enabling holders of the ADRs to exercise voting rights; and

•

a statement as to the manner in which instructions for exercising voting rights may be given to the depositary, including a statement as to the manner in which the shares with respect to which the depositary does not receive properly completed voting instructions or receives a blank proxy will be voted, and stating the date established by the depositary for the receipt of those instructions.

The depositary intends so far as practicable to vote or cause to be voted the amount of the shares evidenced by the ADSs in accordance with the nondiscretionary instructions of the holders of ADSs. The depositary has agreed not to vote any of the shares so evidenced unless (i) it has received instructions from the record holders of ADRs or (ii) in accordance with the last statement of the paragraph above, if it does not receive properly completed voting instructions or it receives a blank proxy. Ownership of two ADRs or integral multiples of ADRs is required to exercise such voting rights subject to appropriate adjustment.

In accordance with French Company Law and the statuts of the Company, shares that have been fully paid and registered in the name of the same holder for a continuous period of at least two years will be entitled to double voting rights. Similarly, holders of ADSs that have been held in the same name for a continuous period of two years or more and representing shares held in registered form for two years or more are entitled to double voting rights. No other ADSs will be entitled to double voting rights. Therefore, in order to be eligible for double voting rights, each holder of the ADSs must (i) request that the depositary hold shares in registered form and (ii) hold the ADRs in registered form (i.e., registered in the name of such holder in the books of the depositary).

Liability of ADR holders for taxes

The holders of ADRs will be responsible for any tax or other governmental charge that becomes payable with respect to any ADRs or any underlying deposited securities evidenced by any of the ADRs.

Amendment and termination of the deposit agreement

The ADRs and the deposit agreement may at any time be amended by written agreement between the Company and the depositary. Any amendment which:

•

imposes or increases any fees or charges, other than taxes and other governmental charges, registration fees, cable, telex, or facsimile transmission costs, deliver costs or other such expenses; or

•

which otherwise prejudices any substantial existing rights of holders of the ADRs,

will not take effect as to outstanding ADRs until the expiration of 90 days after written notice of the amendment has been mailed to the holders of outstanding ADRs registered on the books of the depositary.

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Every holder of ADRs at the time such amendment becomes effective will be deemed, if such notice shall have been mailed to the holder, by continuing to hold such ADRs, to consent to the amendment and to be bound by the deposit agreement or ADRs as amended. In no event may any amendment impair the right of any holder of ADRs to surrender his or her ADRs and receive the shares of the Company and any property represented by the ADR, except in accordance with applicable law. In the event that the depositary resigns, is removed or is otherwise substituted and the Company enters into a new deposit agreement, holders of ADRs will be notified by the successor depositary.

Whenever so directed by the Company, the depositary has agreed to terminate the deposit agreement by mailing notice of such termination to the holders of all then outstanding ADRs registered on the books of the depositary at least 30 days prior to the date fixed in the notice for the termination. The depositary may likewise terminate the deposit agreement by mailing notice of the termination to the Company and the holders of outstanding ADRs registered on the books of the depositary, if at any time 60 days after the depositary shall have delivered to the Company a written notice of its resignation, a successor depositary shall not have been appointed and accepted its appointment as provided in the deposit agreement.

The depositary will mail notice of the termination to the registered holders of ADRs then outstanding at least 30 days prior to the date fixed in the notice for the termination. On and after the date of termination, each holder shall, upon:

•

surrender of the holder’s ADRs at the Corporate Trust Office;

•

payment of the fees of the depositary for the surrender of the ADRs provided in the deposit agreement; and

•

payment of any applicable taxes and governmental charges;

be entitled to delivery, to the holder or upon his or her order, of the amount of deposited TOTAL securities represented by the ADRs.

If any of the ADRs remain outstanding after the date of termination, the depositary will discontinue the registration of transfers of the ADRs, will suspend the distribution of dividends to the holders of the ADRs, and will not give any further notices or perform any further acts under the deposit agreement. The depositary will, however:

•

continue to collect dividends and other distributions pertaining to the underlying deposited securities;

•

sell rights as provided in the deposit agreement; and

•

continue to deliver the underlying deposited securities, together with any dividends or other distributions received, and the net proceeds of the sale of any rights or other property, in exchange for surrendered ADRs after deducting, in each case, fees and expenses of the depositary for the surrender of the ADRs, expenses for the account of the holders of the ADRs in accordance with the provisions of the deposit agreement, and taxes and governmental charges.

At any time after the expiration of one year from the date of termination, the depositary may sell:

•

the underlying deposited securities and any other property represented by the ADSs; and

•

hold the net proceeds, together with any other cash then held, unsegregated and without liability for interest, for the pro rata benefit of the holders of the ADRs that have not been surrendered, in which case, the holders will become general creditors of the depositary with respect to such proceeds.

Charges of depositary

The depositary will charge the party to whom the ADRs are issued and the party surrendering the ADRs for delivery of shares or other underlying securities, a fee not in excess of $5 per 100 ADSs for the issuance or surrender, respectively, of ADRs. The depositary will also charge holders of the ADRs a fee for, and will deduct the fee from, the distribution of proceeds from the sale of rights pursuant to the deposit agreement. This fee will be in an amount equal to the fee that would have been charged as a result of the deposit by holders of shares received in exercise of rights distributed to them had such rights not been sold by the depositary and the net proceeds distributed.

In addition, the following charges will be incurred by any party depositing or withdrawing shares, surrendering the ADRs or to whom the ADRs are issued, whenever applicable:

•

taxes and other governmental charges;

•

any applicable registration fees for the registration of transfers of shares generally on the share register of the Company and applicable to transfers of shares to the name of the depositary or the custodian on the making of deposits or withdrawals under the deposit agreement;

•

any cable, telex and facsimile charges provided in the deposit agreement;

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•

and expenses incurred by the depositary in the conversion of foreign currency pursuant to the deposit agreement.

The charges and expenses of the custodian are for the sole account of the depositary.

Transfer of ADRs

The ADRs are transferable on the books of the depositary, provided that the depositary may close the transfer books, after consultation with or at the request of the Company, at any time or from time to time, when deemed expedient by the depositary in connection with the performance of its duties. Holders of the ADRs will have the right to inspect the transfer books, subject to certain conditions provided in the deposit agreement.

As a condition precedent to the execution and delivery, registration of transfer, split-up, combination or surrender of any of the ADRs, the delivery of any distribution thereon or the withdrawal of the underlying deposited securities, the depositary or the custodian may require payment of a sum sufficient to reimburse it for any share transfer, registration or conversion fee and payments of any applicable fees provided in the deposit agreement.

The depositary may refuse to effect any transfer of any of the ADRs or any withdrawal of the underlying deposited securities until all tax or other governmental charges payable with respect to the ADRs or deposited securities are paid. The depositary may also withhold any dividends or other distributions or, after attempting by reasonable means to notify the holder of any of the ADRs, may sell for the account of the holder any part or all of the underlying deposited securities evidenced by the ADRs, and may apply such dividends or other distributions or the proceeds of any sale to the payment of a tax or other governmental charge, with the holder of the ADRs remaining liable for any deficiency.

The delivery, transfer and registration of transfer of the ADRs generally may be suspended during any period when the transfer books of the depositary are closed, or if any such action is deemed necessary or advisable by the depositary or the Company at any time or from time to time, subject to the provisions of the deposit agreement.

The surrender of outstanding ADRs and the withdrawal of the underlying deposited securities may not be suspended subject only to:

•

temporary delays caused by closing the transfer books of the depositary or the Company for the

deposit of shares of the Company in connection with voting at a shareholders’ meeting or the payment of dividends;

•

the payment of fees, taxes and similar charges; and

•

compliance with any U.S. or foreign laws or governmental regulations relating to the ADRs or to the withdrawal of the underlying deposited securities.

Notices and reports

The Company will furnish to the depositary for distribution to the holders of ADRs:

•

summaries of notices of shareholders’ meetings; and

•

other reports and summaries that are generally distributed by the Company to its shareholders.

The depositary will arrange for the mailing of copies of such reports and summaries in English to all record holders of the ADSs.

Compliance with U.S. securities laws

Notwithstanding anything in the deposit agreement to the contrary, the Company and the depositary each agrees that it will not exercise any rights it has under the deposit agreement to permit the withdrawal or delivery of the underlying deposited securities in a manner which would violate U.S. securities laws.

Governing law

The deposit agreement is governed by the laws of the State of New York.

Other Issues

Shareholders’ meetings

French companies may hold either ordinary or extraordinary shareholders’ meetings. Ordinary shareholders’ meetings are required for matters that are not specifically reserved by law to extraordinary shareholders’ meetings: the election of the members of the Board of Directors, the appointment of statutory auditors, the approval of a management report prepared by the Board of Directors, the approval of the annual financial statements, the declaration of dividends and the issuance of bonds. Extraordinary shareholders’ meetings are required for approval of amendments to a company’s statuts, modification of shareholders’ rights,

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mergers, increases or decreases in share capital, including a waiver of preferential subscription rights, the creation of a new class of shares, the authorization of the issuance of investment certificates or securities convertible, exchangeable or redeemable into shares and for the sale or transfer of substantially all of a company’s assets.

The Company’s Board of Directors is required to convene an annual shareholders’ meeting for approval of the annual financial statements. This meeting must be held within six months of the end of the fiscal year. However, the president of the Tribunal de Commerce of Nanterre, the local French commercial court, may order an extension of this six-month period. The Company may convene other ordinary and extraordinary meetings at any time during the year. Meetings of shareholders may be convened by the Board of Directors or, if it fails to call a meeting, by the Company’s statutory auditors or by a court-appointed agent. A shareholder or shareholders holding at least 5% of the share capital, the employee committee or another interested party under certain exceptional circumstances, may request that the court appoint an agent. The notice of meeting must state the agenda for the meeting.

French Company Law requires that a preliminary notice of a listed company’s shareholders’ meeting be published in the Bulletin des annonces légales obligatoires (“BALO”) at least 30 days prior to the meeting. The preliminary notice must first be sent to the Autorité des marchés financiers with an indication of the date it is to be published in the BALO. The preliminary notice must include the agenda of the meeting and the proposed resolutions that will be submitted to a shareholders’ vote. Within 10 days of publication, one or more shareholders holding a certain percentage of the Company’s share capital determined on the basis of a formula related to capitalization may propose additional resolutions.

Notice of a shareholders’ meeting is sent by mail at least 15 days before the meeting to all holders of registered shares who have held their shares for more than one month. However, in the case where the original meeting was adjourned because a quorum was not met, this time period is reduced to six days.

Attendance and the exercise of voting rights at both ordinary and extraordinary shareholders’ meetings are subject to certain conditions. Under the Company’s statuts, in order to participate in any shareholders’ meeting, the owners of bearer shares or shares that are entered in an account not maintained by the Company must, at least one day before the date of the meeting, file a certificate (certificat d’immobilisation des titres au porteur) prepared by the broker who keeps their accounts, recording the non-transferability of the

securities until the meeting date at the places indicated in the meeting notice. The owners of registered shares entered in an account maintained by the Company must be entered into the Company’s registers at least one day before the day scheduled for the meeting.

Subject to the above restrictions, all of the Company’s shareholders have the right to participate in the Company’s shareholders’ meetings, either in person or by proxy. No shareholder may delegate voting authority to another person except the shareholder’s spouse or another shareholder or, if the shareholder is not a resident of France, by a registered intermediary in conformity with applicable regulations. Shareholders may vote, either in person, by proxy or by mail, and each is entitled to as many votes as he or she possesses or as many shares as he or she holds proxies for. If the shareholder is a legal entity, it may be represented by a legal representative. A shareholder may grant a proxy to the Company by returning a blank proxy form. In this last case, the chairman of the shareholders’ meeting may vote the shares in favor of all resolutions proposed or agreed to by the Board of Directors and against all others. The Company will send proxy forms to shareholders upon request. In order to be counted, proxies must be received at least one day prior to the shareholders’ meeting at the Company’s registered office or at another address indicated in the notice convening the meeting. Under French Company Law, shares held by entities controlled directly or indirectly by the Company are not entitled to voting rights. There is no requirement that a shareholder have a minimum number of shares in order to be able to attend or be represented at shareholders’ meetings.

Under French Company Law, a quorum requires the presence, in person or by proxy, including those voting by mail, of shareholders having at least 20% of the shares entitled to vote in the case of an ordinary shareholders’ meeting or at an extraordinary meeting where shareholders are voting on a capital increase by capitalization of reserves, profits or share premium, or 25% of the shares entitled to vote in the case of any other extraordinary shareholders’ meeting. If a quorum is not present at any meeting, the meeting is adjourned. There is no quorum requirement when an ordinary shareholders’ meeting is reconvened, but the reconvened meeting may consider only questions which were on the agenda of the adjourned meeting. When an extraordinary shareholders’ meeting is reconvened, the quorum required is 20% of the shares entitled to vote, except where the reconvened meeting is considering capital increases through capitalization of reserves, profits or share premium. For these matters, no quorum is required at the reconvened meeting. If a quorum is not present at a reconvened meeting requiring a quorum, then the meeting may be adjourned for a maximum of two months.

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At an ordinary shareholders’ meeting, approval of any resolution requires the affirmative vote of a simple majority of the votes of the shareholders present or represented by proxy. The approval of any resolution at an extraordinary shareholders’ meeting requires the affirmative vote of a two-thirds majority of the votes cast, except that any resolution to approve a capital increase by capitalization of reserves profits, or share premium only requires the affirmative vote of a simple majority of the votes cast. Notwithstanding these rules, an unanimous vote is required to increase shareholders’ liabilities. Abstention from voting by those present or represented by proxy is counted as a vote against any resolution submitted to a vote.

As set forth in the Company’s statuts, shareholders’ meetings are held at the Company’s registered office or at any other location specified in the written notice.

Ownership of shares by non-French persons

There is no limitation on the right of non-resident or foreign shareholders to vote securities of the Company, either under French Company Law or under the statuts of the Company.

Requirement for holdings exceeding certain percentages

French Company Law provides that any individual or entity, acting alone or in concert with others, that holds, directly or indirectly, more than 5%, 10%, 15%, 20%, 25%, 33¹/3%, 50%, 66²/3%, 90% or 95% of the outstanding shares or the voting rights attached to the shares, or that increases or decreases its shareholding or voting rights by any of the above percentages must notify the Company by registered letter, with return receipt, within 5 business days of crossing that threshold, of the number of shares and voting rights it holds. An individual or entity must also notify the AMF, the self-regulatory organization that has general regulatory authority over the French stock exchanges and whose members include representatives of French stockbrokers, by registered letter, with return receipt, within five trading days of crossing that threshold. Any shareholder who fails to comply with these requirements will have its voting rights in excess of such thresholds suspended for a period of two years from the date such shareholder complies with the notification requirements and may have all or part of its voting rights suspended for up to five years by the commercial court at the request of the Company’s Chairman, any of the Company’s shareholders or the Autorité des marchés financiers. In addition, every shareholder who, directly or indirectly, acting alone or in concert with others, acquires ownership or control of shares representing

10% or 20% of the Company’s share capital must notify the Company and the Autorité des marchés financiers of its intentions for the 12 months following such acquisition. Failure to comply with this notification of intentions will result in the suspension of the voting rights attached to the shares exceeding this 10% or 20% threshold held by the shareholder for a period of two years from the date on which the shareholder has cured such default and, upon a decision of the commercial court part or all the shares held by such shareholder may be suspended for up to five years.

In addition, the Company’s statuts provide that any person, whether a natural person or a legal entity, who comes to hold, directly or indirectly, 1% or more, or any multiple of 1%, of the Company’s share capital or voting rights or of securities that may include future voting rights or future access to share capital or voting rights, must notify the Company by registered letter with return receipt requested, within 15 calendar days of crossing such threshold. Failure to comply with these notification provisions will result in the suspension of the voting rights attached to the shares exceeding this 1% threshold held by the shareholder if requested at a shareholders’ meeting by one or more shareholders holding shares representing at least 3% of the share capital.

Any individual or legal entity whose direct or indirect holding of shares falls below each of the levels mentioned must also notify the Company in the manner and within the time limits set forth above.

Subject to certain limited exemptions, any person, or persons acting in concert, owning in excess of 33¹/3% of the share capital or voting rights of the Company must initiate a public tender offer for the balance of the share capital, voting rights and securities giving access to such share capital or voting rights.

Material Contracts

There have been no material contracts (not entered into in the ordinary course of business) entered into by members of the Group since March 31, 2005.

Exchange Controls

Under current French exchange control regulations, no limits exist on the amount of payments that TOTAL may remit to residents of the United States. Laws and regulations concerning foreign exchange controls do require, however, that an accredited intermediary must handle all payments or transfer of funds made by a French resident to a non-resident.

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Taxation

General

This section describes the material U.S. federal income tax and French tax consequences of owning and disposing of shares and ADSs of TOTAL to U.S. Holders that hold their shares or ADSs as capital assets for tax purposes. A U.S. Holder is a beneficial owner of shares or ADSs that is (i) a citizen or resident of the United States for U.S. federal income tax purposes, (ii) a domestic corporation or other domestic entity treated as a corporation for U.S. federal income tax purposes, (iii) an estate whose income is subject to U.S. federal income tax regardless of its source, or (iv) a trust if a U.S. court can exercise primary supervision over the trust’s administration and one or more U.S. persons are authorized to control all substantial decisions of the trust.

This section does not apply to members of special classes of holders subject to special rules, including:

•

dealers in securities,

•

traders in securities that elect to use a mark-to-market method of accounting for their securities holdings,

•

tax-exempt organizations,

•

life insurance companies,

•

persons liable for alternative minimum tax,

•

persons that actually or constructively own 5% or more of the share capital or voting rights in TOTAL,

•

persons that hold the shares or ADSs as part of a straddle or a hedging or conversion transaction, or

•

U.S. Holders whose functional currency is not the U.S. dollar.

In addition, the discussion of the material French tax consequences is limited to U.S. Holders that (i) are residents of the United States for purposes of the Treaty (as defined below), (ii) do not maintain a permanent establishment or fixed base in France to which the shares or ADSs are attributable and through which the respective U.S. Holders carry on, or have carried on, a business (or, if the holder is an individual, performs or has performed independent personal services), and (iii) are otherwise eligible for the benefits of the Treaty in respect of income and gain from the shares or ADSs. In addition, this section is based in part upon the representations of the Depositary and the assumption that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms.

This section is based on the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations, published rulings and court

decisions, and with respect to the description of the material French tax consequences, the laws of the Republic of France and French tax regulations, all as currently in effect, as well as on the Convention Between the United States and the Republic of France for the Avoidance of Double Taxation (the “Treaty”). These laws are subject to change, possibly on a retroactive basis.

Holders are urged to consult their own tax advisor regarding the U.S. federal, state and local, and French and other tax consequences of owning and disposing shares or ADSs of TOTAL in their respective circumstances. In particular, a holder is encouraged to confirm whether the holder is a U.S. Holder eligible for the benefits of the Treaty with its advisor.

Taxation of Dividends

French taxes

Dividends paid to non-residents of France are subject to French withholding tax at a rate of 25% unless the rate is reduced pursuant to a tax treaty or similar agreement. Under the Treaty, a U.S. Holder generally is entitled to a reduced rate of French withholding tax of 15% with respect to dividends, provided the ownership of shares or ADSs is not effectively connected with a permanent establishment or a fixed base in France and certain other requirements are satisfied.

In France, companies may pay dividends only out of income remaining after tax has been paid. Until December 31, 2004, when dividends were received by shareholders resident in France, such persons were under certain circumstances entitled to a tax credit (Avoir fiscal) representing a portion of the underlying tax paid at the corporate level.

The French Finance Law of 2004, which reformed the taxation of dividends, repealed the benefit of the Avoir fiscal. Instead, for dividends received as from January 1, 2006, French resident shareholders who are individuals are taxed on only 60% of the amount of dividends. In addition, French resident shareholders who are individuals are entitled to a new tax credit (Crédit d’impôt) equal to 50% of the amount of dividends they received but with an overall annual cap of €230 or, as the case may be, €115 depending on the marital status of the individual holder.

Under French domestic law, shareholders who are not resident of France for tax purposes are not eligible to the benefit of the Crédit d’impôt. However, U.S. Holders who benefit from the Treaty may be entitled to the refund of the Crédit d’impôt (less applicable withholding tax). The procedure to obtain payment of this tax credit has not yet been released by the French tax authorities.

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With respect to dividends distributed as from January 1, 2005, the administrative guidelines issued on February 25, 2005 (4 J-1-05) (the “February 25, 2005 Administrative Guidelines”) set forth the conditions under which the reduced French withholding tax at the rate of 15% may be available. The immediate application of the reduced 15% rate is available to those U.S. Holders that may benefit from the so-called “simplified” procedure (within the meaning of the February 25, 2005 Administrative Guidelines).

Under the “simplified procedure,” U.S. Holders may claim the immediate application of withholding tax at the rate of 15% on the French dividends to be received by them, provided that:

(i)

they furnish to the financial institution managing their securities account a certificate of residence conforming with the model attached to the February 25, 2005 Administrative Guidelines. The immediate application of the 15% withholding tax will be available only if the certificate of residence is sent to the financial institution managing their securities account before the dividend payment date. Furthermore, each financial institution managing the U.S. Holders’ securities account must also send to the French paying agent the figure of the total amount of dividends to be received which are eligible to the reduced withholding tax rate before the dividend payment date;

(ii)

the U.S. financial institution managing the U.S. Holder’s securities account provides to the French paying agent a list of the eligible U.S. Holders and other pieces of information set forth in the February 25, 2005 Administrative Guidelines. Furthermore, the financial institution managing the U.S. Holders’ securities account should certify that each U.S. Holder is, to the best of its knowledge, a United States resident within the meaning of the Treaty. These documents must be sent as soon as possible, in all cases before the end of the third month computed as from the end of the month of the dividend payment date.

Where the U.S. Holder’s identity and tax residence are known by the French paying agent, the latter may release such U.S. Holder from furnishing to (i) the financial institution managing its securities account, or (ii) as the case may be, the Internal Revenue Service, the abovementioned certificate of residence, and apply the 15% withholding tax rate to dividends it pays to such U.S. Holder.

U.S. Pension Funds and Other Tax-Exempt Entities created and operating in accordance with the provisions of Sections 401 (a), 403 (b), 457 or 501 (c) (3) of the U.S.

Internal Revenue Code (IRC) are subject to the same general filing requirements except that, in addition, they have to supply a certificate issued by the U.S. Internal Revenue Service (“IRS”) or any other document stating that they have been created and are operating in accordance with the provisions of the abovementioned Code Sections. This certificate must be produced together with the first request of application of the reduced rate, once together with the first request of immediate application of the 15% withholding tax and at French Tax Authorities specific request.

In the same way, regulated companies such as RIC, REIT, REMIC will have to send to the financial institution managing their securities account a certificate from the IRS indicating that they are classified as Regulated Companies (RIC, REIT or REMIC) within the provisions of the relevant sections of the IRC. In principle, this certification must be produced each year and before the dividend payment.

For a U.S. Holder that is not entitled to the “simplified” procedure, the 25% French withholding tax will be levied at the time the dividends are paid. Such U.S. Holder may, however, be entitled to a refund of the withholding tax in excess of the 15% rate under the “standard,” as opposed to the “simplified,” procedure, provided that the U.S. Holder furnishes to the French paying agent an application for refund on form RF 1B EU-No 5053 (or any other relevant form to be issued by the French tax authorities), certified by the U.S. financial institution managing the U.S. Holder’s securities account, before December 31 of the second year following the date of payment of the withholding tax at the 25% rate to the French tax authorities. Any French withholding tax refund is generally expected to be paid within 12 months from the filing of form RF 1B EU-No 5053 (or any other relevant form to be issued by the French tax authorities). However, it will not be paid before January 15 of the year following the year in which the dividend was paid.

Copies of form RF 1B EU-No 5053 (or any other relevant form to be issued by the French tax authorities) as well as the form of the certificate of residence and the U.S. financial institution certification, together with instructions, are (or will be, as soon as practical) available from the U.S. Internal Revenue Service and the French Centre des Impôts des Non-Residents at 10 rue du Centre, 93463 Noisy le Grand, France.

These forms, together with instructions, will also be provided by the Depositary to all U.S. Holders of ADRs registered with the Depositary. The Depositary will use reasonable efforts to follow the procedures established by the French tax authorities for U.S. Holders to benefit from the immediate application of the 15% French

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withholding tax rate or, as the case may be, recover the excess 10% French withholding tax initially withheld and deducted in respect of dividends distributed to them by the Company, and obtain, in respect to dividend distributions made as from January 1, 2005 to U.S. Holders who are individuals, the refund of the Crédit d’impôt (less applicable withholding tax), in accordance with the procedures established by the French tax authorities. To effect such benefit, recovery and/or refund, the Depositary shall advise such U.S. Holder to return the relevant forms to it properly completed and executed. Upon receipt of the relevant forms properly completed and executed by such U.S. Holder, the Depositary shall cause them to be filed with the appropriate French tax authorities, and upon receipt of any resulting remittance, the Depositary shall distribute to the U.S. Holder entitled thereto, as soon as practicable, the proceeds thereof in U.S. Dollars.

The identity and address of the French paying agent is available from the Company.

U.S. taxation

For U.S. federal income tax purposes, the gross amount of dividend a U.S. Holder must include in gross income equals the amount paid by TOTAL plus any amount of the Crédit d’impôt described above (see “— French Taxes” above) transferred to the U.S. Holder with respect to this amount (including any French tax withheld with respect to the distribution made by TOTAL and the Crédit d’impôt) to the extent of the current and accumulated earnings and profits of TOTAL (as determined for U.S. federal income tax purposes). The dividend will be income from foreign sources. Dividends paid to a noncorporate U.S. Holder in taxable years beginning before January 1, 2011 that constitute qualified dividend income will be taxable to the holder at a maximum tax rate of 15% provided that the shares or ADSs are held for more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and the holder meets other holding period requirements. TOTAL believes that dividends paid by TOTAL with respect to its shares or ADSs will be qualified dividend income. The dividend will not be eligible for the dividends-received deduction allowed to a U.S. corporation under Section 243 of the Code. The dividend is taxable to the U.S. Holder when the holder, in the case of shares, or the Depositary, in the case of ADSs, receives the dividend, actually or constructively. To the extent that an amount received by a U.S. Holder exceeds the allocable share of the Company’s current and accumulated earnings and profits, it will be applied first to reduce such holder’s tax basis in shares or ADSs owned by such holder and then, to the extent it exceeds the holder’s tax basis, it will constitute capital gain.

The amount of any dividend distribution includible in the income of a U.S. Holder equals the U.S. dollar value of the euro payment made, determined at the spot dollar/euro exchange rate on the date the dividend distribution is includible in the U.S. Holder’s income, regardless of whether the payment is in fact converted into U.S. dollars. Any gain or loss resulting from currency exchange fluctuations during the period from the date the dividend payment is includible in the U.S. Holder’s income to the date the payment is converted into U.S. dollars will generally be treated as ordinary income or loss from sources within the United States and will not be eligible for the special tax rate applicable to qualified dividend income.

Subject to certain conditions and limitations, French taxes withheld in accordance with the Treaty will be eligible for credit against the U.S. Holder’s U.S. federal income tax liability. The limitation on foreign taxes eligible for credit is calculated separately with respect to specific classes of income. In addition, special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the maximum 15% tax rate. For this purpose, dividends distributed by the Company and the related Crédit d’impôt payments paid in taxable years beginning before January 1, 2007 generally will constitute “passive income”, or, in the case of certain U.S. Holders, “financial services income”, and dividends paid in taxable years beginning after December 31, 2006 will, depending on your circumstances, be “passive” or “general income”. Alternatively, a U.S. Holder may claim all foreign taxes paid as an itemized deduction in lieu of claiming a foreign tax credit.

Taxation of Disposition of Shares

In general, a U.S. Holder who is eligible for the benefits of the Treaty will not be subject to French tax on any capital gain from the sale or exchange of the ADSs or redemption of the underlying shares unless those ADSs or shares form part of a business property of a permanent establishment or fixed base that the U.S. Holder has in France. Special rules may apply to individuals who are residents of more than one country.

A 1.1% registration duty assessed on the higher of the purchase price and the market value of the shares (subject to a maximum of €4,000 per transfer) applies to certain transfers of shares in French companies. The duty does not apply to transfers of shares in TOTAL provided that the transfer is not evidenced by a written agreement, or that such written agreement is executed outside France.

For U.S. federal income tax purposes, a U.S. Holder generally will recognize capital gain or loss upon

112

the sale or disposition of shares or ADSs equal to the difference between the U.S. dollar value of the amount realized on the sale or disposition and the holder’s tax basis, determined in U.S. dollars, in the shares or ADSs. The gain or loss generally will be U.S. source gain or loss and will be long-term capital gain or loss if the U.S. Holder’s holding period of the shares or ADSs is more than one year at the time of the disposition. Long-term capital gain of a non-corporate U.S. Holder that is recognized on or after May 6, 2003 and before January 1, 2011 is taxed at a maximum rate of 15%. The deductibility of capital losses is subject to limitation.

French Estate and Gift Taxes

In general, a transfer of ADSs or shares by gift or by reason of the death of a U.S. Holder that would otherwise be subject to French gift or inheritance tax, respectively, will not be subject to such French tax by reason of the Convention between the United States of America and the French Republic for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with Respect to Taxes on Estates, Inheritances and Gifts, dated November 24, 1978, unless the donor or the transferor is domiciled in France at the time of making the gift, or at the time of his death, or if the ADSs or shares were used in, or held for use in, the conduct of a business through a permanent establishment or a fixed base in France.

French Wealth Tax

The French wealth tax does not apply to a U.S. Holder (i) that is not an individual, or (ii) in the case of individuals who are eligible for the benefits of the Treaty and who own, alone or with related persons, directly or indirectly, TOTAL shares which give right to less than 25 per cent of TOTAL’s earnings.

U.S. State and Local Taxes

In addition to U.S. federal income tax, U.S. Holders of shares or ADSs may be subject to U.S. state and local taxes with respect to their shares or ADSs. U.S. Holders should consult their own tax advisors.

Dividends and Paying Agents

After BNP Paribas Securities Services performs centralizing procedures, dividends are paid through the accounts of financial intermediaries participating in Euroclear France’s direct payment procedures. The Bank of New York acts as paying agent for dividends distributed to ADS holders.

Documents on Display

TOTAL files annual, periodic, and other reports and information with the Securities and Exchange Commission. You may read and copy any reports, statements or other information TOTAL files with the Securities and Exchange Commission at the Securities and Exchange Commission’s public reference rooms by calling the Securities and Exchange Commission for more information at 1-800-SEC-0330. All of TOTAL’s Securities and Exchange Commission filings made after December 31, 2001 are available to the public at the Securities and Exchange Commission web site at http://www.sec.gov and from certain commercial document retrieval services. You may also read and copy any document the Company files with the Securities and Exchange Commission at the offices of The New York Stock Exchange, 20 Broad Street, New York, New York 10005.

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Sensitivity to market environment

The financial performance of TOTAL is sensitive to a number of parameters, the most significant being oil and gas prices, generally expressed in dollars, and exchange rates, in particular that of the dollar versus the euro.

Overall, a rise in the price of crude oil has a positive effect on earnings as a result of an increase in revenues from oil and gas production. Conversely, a decline in crude oil prices reduces revenues. For the year 2007,

the Group estimates that an increase or decrease of $1.00 per barrel in the price of Brent crude would respectively improve or reduce annual operating income by approximately 0.38 B€⁽¹⁾. The impact of changes in crude oil prices on Downstream and Chemicals operations depends upon the speed at which the prices of finished products adjust to reflect these changes. The Group estimates that an increase or decrease in TRCV refining margins of $1.00 per ton would improve or reduce annual operating income by approximately 0.09 B€^(a).

(1)

Calculated with a base case exchange rate of $1.25 / €.

113

All of the Group’s activities are, to various degrees, sensitive to fluctuations in the dollar/euro exchange rate. For the year 2007, the Group estimates that a strengthening or weakening of the dollar against the euro by €0.10/$ would respectively improve or reduce annual operating income, expressed in euros, by approximately 2.2 B€.

The Group’s results, particularly in the Chemicals segment, also depend on the overall economic environment.


2007 Sensitivities	Scenario		Change	Estimated impact on operating income
Dollar/euro exchange rate	$1.25/	€	+€0.10/$	+2.2 B	€
Brent	$60/b		+$1/b	+0.38 B	€
European refining margins (TRCV)	$30/t		+$1/t	+0.09 B	€

Oil and gas market related risks

Due to the nature of its business, the Group has significant oil and gas trading activities as part of its day-to-day operations in order to attempt to optimize revenues from its oil and gas production and to obtain favorable pricing for supplies for its refineries.

companies, uses energy derivative instruments to adjust its exposure to price fluctuations of crude oil, refined products, natural gas and electricity. The Group also uses freight-rate derivatives contracts in its shipping activities to adjust its exposure to freight-rate fluctuations. To hedge against this risk, the Group uses various instruments such as futures, forwards, swaps and options on organized markets or over-the-counter markets.

The notional and fair values of derivatives as of December 31, 2006 were as follows:


ASSETS / (LIABILITIES) (M€)	Notional value - assets^(a)	Notional value - liabilities^(a)	Carrying amount		Fair Value
Commodities instruments on crude oil, petroleum products and freight rates
Petroleum products and crude oil swaps^(a)	8,258	9,459	(43	)	(43	)
Swap freight agreements	56	86	2		2
Forwards^(b)	5,145	5,830	(11	)	(11	)
Options^(c)	6,046	4,835	66		66
Futures^(d)	1,274	2,434	79		79
Options on futures^(c)	143	165	(4	)	(4	)
Total - Commodities instruments on crude oil, petroleum products and freight rates			89		89

Commodities instruments on gas and power
Swaps^(a)	890	716	(25	)	(25	)
Forwards	9,973	9,441	(73	)	(73	)
Options^(c)	18	58	2		2
Futures^(d)	92	46	31		31
Total - Commodities instruments on gas and power			(65	)	(65	)
Total			24		24
Total of fair value not recognized in the balance sheet					—

(a)

Swaps (including “Contracts for differences”): the “Notional value” columns correspond to receive-fixed and pay-fixed swaps.

(b)

Forwards: contracts resulting in physical delivery are accounted for as derivative commodity contracts and included in the amounts shown. The 2005 amounts for commodities instruments on gas and power have been reclassified accordingly.

(c)

Options: the “Notional value” columns correspond to the nominal value of options (calls or puts) purchased and sold, valued based on the strike price.

(d)

Futures: the “Notional value” columns correspond to the net purchasing/selling positions, valued based on the closing rate on the organized exchange market.

114

To measure market risk related to oil, gas and electricity price movements, the Group uses the “value at risk” method. Under this method, there is a 97.5% probability that unfavorable daily market variations for the Group’s trading activities of crude oil, refined products and freight rate derivatives would result in a loss of less than 11.4 M€ per day, defined as the “value at risk”, based on positions as of December 31, 2006.

As part of its gas and electricity trading activities, the Group also uses derivative instruments such as futures, forwards, swaps and options in both organized and over-the-counter markets. In general, the transactions are settled at maturity through physical delivery. Based on positions as of December 31, 2006, there is a 97.5% probability that unfavorable daily market variations would result in a loss of less than 6.0 M€ per day.

The Group has implemented strict policies and procedures to manage and monitor these market risks. These are based on an organization that separates supervisory functions from operational functions and on an integrated information system that enables real-time monitoring of trading activities.

producers and consumers and financial institutions. The Group has established counterparty limits and monitors amounts outstanding with each counterparty on an ongoing basis.

Financial markets related risks

As part of its financing and cash management activities, the Group uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Group may also use, on a less frequent basis, futures, caps, floors and options contracts. These operations and their accounting treatment are detailed in paragraph M of Note 1 and Notes 20 and 27 to the Consolidated Financial Statements.

Risks relative to cash management activities and to interest rate and foreign exchange financial instruments are managed in accordance with rules set by the Group’s senior management. Liquidity positions and the management of financial instruments are centralized by the treasury/financing department, where they are managed by a group specialized in foreign exchange and interest rate market transactions. The cash monitoring and management group monitors limits and positions on a daily basis and reports of results. This group also prepares marked-to-market valuations and, as necessary, performs sensitivity analysis.

115

The classification by strategy and the notional amount of derivative instruments as of December 31, 2006 was as follows:

Notional amount^(a)

ASSETS/(LIABILITIES) (M€)

Fair
Value

Total

2007

2008

2009

2010

2011

2012 and
after

Financial instruments hedging non-current financial debt

Issue swaps and swap hedging debenture
issues - non-current (liabilities)

(193

)

5,691

Issue swaps and swap hedging debenture
issues - non-current (assets)

486

5,317

Issue swaps and swap hedging debenture
issues - non-current

293

11,008

1,756

2,018

1,870

2,740

2,624

Non-current currency and interest rate swaps
hedging bank loans

Issue swaps and swap hedging debenture
issues - less than one year (liabilities)

475

Issue swaps and swap hedging debenture
issues - less than one year (assets)

341

1,341

Issue swaps and swap hedging debenture
issues - less than one year

341

1,816

Financial instruments hedging net investment

N/A

Financial instruments held for trading

3,496

Other interest rate swaps - assets

6,488

Other interest rate swaps - liabilities

)

9,580

Other swaps assets and liabilities

16,068

16,062

—

Currency swaps and forward exchange contracts - assets

5,003

Currency swaps and forward exchange contracts - liabilities

(67

)

6,065

Currency swaps and forward exchange contracts - assets and liabilities

)

11,068

10,513

287

201

—

(a)

These amounts set the levels of notional involvement and are not indicative of a contingent gain or loss.

Currency exposure

The Group seeks to minimize the currency exposure of each entity to its operating currency (primarily the euro, U.S. dollar, pound sterling, and Norwegian krone).

For currency exposure generated by commercial activity, the hedging of revenues and costs in foreign currencies is typically performed using currency operations on the spot market and in some cases on the forward market. The Group rarely hedges future cash flows, although it may use options to do so.

With respect to currency exposure linked to non-current assets booked in a currency other than the euro, the Group has a policy of reducing the related currency exposure by financing these assets in the same currency.

Net short-term currency exposure is periodically monitored against limits set by the Group’s senior management. This currency exposure is managed by the Group’s central treasury entities, which are responsible for debt issuances on the financial markets (the proceeds of which are then loaned to borrowing subsidiaries), cash centralization for Group companies and cash management on the monetary markets.

Short-term interest rate exposure and cash

Cash balances, which are primarily composed of euros and dollars, are managed according to the guidelines established by senior management (maintain maximum liquidity, optimize revenue from investments considering existing interest rate yield curves, and minimize the cost of borrowing) over a less than 12-month horizon and on the basis of a daily interest rate benchmark, primarily through short-term interest rate swaps and short-term currency swaps, without modifying the currency exposure.

Interest rate risk on non-current debt

The Group’s policy consists of incurring non-current debt primarily at a floating rate, or at a fixed rate depending on the levels of interest rates, in dollars or in euros according to general corporate needs. Long-term interest rate and currency swaps can hedge debenture loans at their issuance in order to create a variable rate synthetic debt. In order to partially modify the interest rate structure of the long-term debt, TOTAL can also enter into long-term interest rate swaps.

116

Sensitivity analysis on interest rate and foreign exchange risk

The tables below present the potential impact of an increase or decrease of 10% in the interest rate yield curves in each of the currencies on the fair value of the current financial instruments as of December 31, 2006 and 2005.


ASSETS/(LIABILITIES)	Carrying amount		Estimated fair value		Change in fair value with a 10% interest rate increase		Change in fair value with a 10% interest rate decrease
As of December 31, 2006 (M€)	Carrying amount		Estimated fair value
Debenture loans (non-current portion, before swaps)	(11,413	)	(11,413	)	26		(26	)

Issue swaps and swaps hedging debenture loans (liabilities)	(193	)	(193	)

Issue swaps and swaps hedging debenture loans (assets)	486		486
Total issue swaps and swaps hedging debenture loans – assets and liabilities	293		293		(26	)	26

Fixed-rate bank loans	(210	)	(207	)	6		(6	)

Current portion of non-current debt after swap (excluding capital lease obligations)	(2,140	)	(2,140	)	1		(1	)

Other interest rates swaps	12		12		(1	)	1

Currency swaps and forward exchange contracts	(8	)	(8	)	1		(1	)

Currency options	—		—		—		—
ASSETS/(LIABILITIES)	Carrying amount		Estimated fair value		Change in fair value with a 10% interest rate increase		Change in fair value with a 10% interest rate decrease
As of December 31, 2005 (M€)	Carrying amount		Estimated fair value
Debenture loans (non-current portion, before swaps)	(11,025	)	(11,025	)	126		(129	)

Issue swaps and swaps hedging debenture loans (liabilities)	(128	)	(128	)

Issue swaps and swaps hedging debenture loans (assets)	450		450

Total issue swaps and swaps hedging debenture loans – assets and liabilities	322		322		(115	)	117

Fixed-rate bank loans	(411	)	(406	)	7		(7	)

Current portion of non-current debt after swap (excluding capital lease obligations)	(920	)	(919	)	1		(1	)

Other interest rates swaps	3		3		(3	)	3

Currency swaps and forward exchange contracts	260		260		4		(4	)

Currency options	—		—		—		—

117

As a result of its policy for the management of currency exposure previously described, the Group believes that its short-term currency exposure is not material. The Group’s sensitivity to long-term currency exposure is primarily influenced by the net equity of the subsidiaries whose functional accounting currency is the dollar and, to a lesser extent, the pound sterling and the Norwegian

krone. This sensitivity is reflected by the historical evolution of the currency translation adjustment imputed in the statement of changes in shareholders’ equity which, in the course of the last three fiscal years, is essentially related to the evolution of the dollar and is set forth in the table below:


	Dollar/euro exchange rate	Currency translation adjustments (M€)
As of December 31, 2006	1.32	(1,383	)
As of December 31, 2005	1.18	1,421
As of December 31, 2004	1.36	(1,429	)

The non-current debt in dollars described in Note 20 to the Consolidated Financial Statements is generally raised by the treasury entities either in dollars or in euros, or in other currencies which are then systematically exchanged for dollars or euros according to the general corporate purposes, through issue swaps. The proceeds from these debt issuances are principally loaned to affiliates whose accounts are kept in dollars and any remaining balance is held in dollar-denominated investments. Thus, the net sensitivity of these positions to currency exposure is not material.

The Group’s short-term currency swaps, the nominal amounts of which appear in Note 27 to the Consolidated Financial Statements, are used to attempt to optimize the centralized cash management of the Group. Thus the sensitivity to currency fluctuations which may be induced is likewise considered negligible.

As a result of this policy, the impact of currency exchange on consolidated income, as illustrated in Note 7 to the Consolidated Financial Statements, has not been significant over the last three years despite the considerable fluctuation of the dollar (loss of 30 M€ in 2006, gain of 76 M€ in 2005, loss of 75 M€ in 2004).

Counterparty risk

The Group has established standards for market transactions according to which bank counterparties

must be approved in advance, based on an assessment of the counterparty’s financial soundness and its rating (Standard & Poors, Moody’s), which must be of high quality.

An overall authorized credit limit is set for each bank and is divided among the subsidiaries and the Group’s central treasury entities according to their needs.

Stock market risk

The Group holds interests in a number of publicly-traded companies (see Note 13 to the Consolidated Financial Statements). The market value of these holdings fluctuates due to various factors, including stock market trends, valuations of the sectors in which the companies operate, and the economic and financial condition of each individual company.

Liquidity risk

TOTAL S.A. has confirmed lines of credit granted by international banks, which are calculated to allow it to manage its short-term liquidity needs as required.

The following tables show the maturity of the financial assets and debt instruments of the Group as of December 31, 2006 and 2005 (see Note 20 to the Consolidated Financial Statements).


ASSETS/(LIABILITIES)
As of December 31, 2006 (M€)	Less than 1 year	Between 1 and 5 years	More than 5 years	Total
Financial debt after swaps	(2,025)	(10,733)	(2,955)	(15,713)
Cash and cash equivalents	2,493	—	—	2,493
Net amount	468	(10,733)	(2,955)	(13,220)
ASSETS/(LIABILITIES)
As of December 31, 2005 (M€)	Less than 1 year	Between 1 and 5 years	More than 5 years	Total
Financial debt after swaps	(3,619)	(9,057)	(4,259)	(16,935)
Cash and cash equivalents	4,318	—	—	4,318
Net amount	699	(9,057)	(4,259)	(12,617)

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ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable.

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

None.

ITEM 15. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

An evaluation was carried out under the supervision and with the participation of the Group’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness, as of the end of the period covered by this report, of the design and operation of the Group’s disclosure controls and procedures, which are defined as those controls and procedures designed to ensure that information required to be disclosed in reports filed under the U.S. Securities Exchange Act of 1934 is recorded, summarized and reported within specified time periods. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that the Company files under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

The Group’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Because of its inherent limitations, internal control over financial reporting may not prevent or

detect misstatements and even when determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of an internal control system may change over time.

The Group’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of internal control over financial reporting using the criteria set forth in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on the results of this evaluation, the Group’s management concluded that its internal control over financial reporting was effective as of December 31, 2006.

This assessment of internal control over financial reporting as of December 31, 2006 by the Group’s management was audited by KPMG Audit and Ernst & Young Audit, independent registered public accounting firms, as stated in their report beginning on page F-2 of this report.

Changes in Internal Control Over Financial Reporting

There were no changes in the Group’s internal control over financial reporting that occurred during the period covered by this report that have materially affected, or that were reasonably likely to materially affect, the Group’s internal control over financial reporting.

119

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

Mr. Antoine Jeancourt-Galignani is the Audit Committee financial expert. Mr. Jeancourt-Galignani is an independent member of the Board of Directors in accordance with the NYSE listing standards applicable to TOTAL, as are the other members of the Audit Committee.

ITEM 16B. CODE OF ETHICS

At its meeting on February 18, 2004, the Board of Directors adopted a code of ethics that applies to its Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and the financial and accounting officers for its principal activities. A copy of this code of ethics is included as an exhibit to this annual report.

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

During the fiscal years ended December 31, 2006 and 2005, fees for services provided by Ernst & Young Audit and KPMG S.A. were as follows:


	KPMG S.A. Year Ended December 31,		Ernst & Young Audit Year Ended December 31,
(M€)	2006	2005	2006	2005
Audit Fees	17.5	12.7	19.2	12.8
Audit-Related Fees^(a)	2.4	8.1	1.7	3.4
Tax Fees^(b)	1.1	1.0	1.3	1.4
All Other Fees^(c)	0.1	0.1	0.0	0.1
Total	21.1	21.9	22.2	17.7

(a)

Audit-related fees are generally fees billed for services that are closely related to the performance of the audit or review of financial statements. These include due diligence services related to business combinations, attestation services not required by statute or regulation, agreed upon or expanded auditing procedures related to accounting or billing records required to respond to or comply with financial, accounting or regulatory reporting matters, consultations concerning financial accounting and reporting standards, information system reviews, internal control reviews and assistance with internal control reporting requirements.

(b)

Tax fees are fees for services related to international and domestic tax compliance, including the preparation of tax returns and claims for refund, tax planning and tax advice, including assistance with tax audits and tax appeals, and tax services regarding statutory, regulatory or administrative developments and expatriate tax assistance and compliance.

(c)

All other fees are principally for risk management advisory services.

Audit Committee Pre-Approval Policy

The Audit Committee has adopted an Audit and Non-Audit Services Pre-Approval Policy that sets forth the procedures and the conditions pursuant to which services proposed to be performed by the statutory auditors may be pre-approved. This policy provides for both general pre-approval of certain types of services through the use of an annually established budget for these types of services and special pre-approval of services on a case by case basis. The Audit Committee has designated the Company’s internal audit department to monitor the performance of services provided by the statutory auditors and to assess

compliance with the pre-approval policies and procedures. The internal audit department reports the results of its monitoring to the Audit Committee on a periodic basis. Both the internal audit department and management are required to report any breach of this policy to the chairman of the Audit Committee. During 2006, no audit-related fees, tax fees or other non-audit fees were approved by the Audit Committee pursuant to the de minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

120

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

None.

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS


Period	Total Number Of Shares Purchased^(a)	Average Price Paid Per Share (€)^(a)	Total Number Of Shares Purchased, As Part Of Publicly Announced Plans Or Programs^(a)		Maximum Number Of Shares That May Yet Be Purchased Under The Plans Or Programs^(a)(d)
January 2006	7,600,000	55.37	7,600,000	^(b)	102,605,540
February 2006	3,860,000	53.48	3,860,000	^(b)	99,097,892
March 2006	10,540,000	53.36	10,540,000	^(b)	90,191,983
April 2006	2,000,000	55.12	2,000,000	^(b)	89,015,146
May 2006	7,000,000	50.67	7,000,000	^(b)(c)	82,074,439
June 2006	11,000,000	49.05	11,000,000	^(c)	71,166,117
July 2006	5,215,684	51.24	5,215,684	^(c)	109,011,392	^(e)
August 2006	8,310,000	52.95	8,310,000	^(c)	101,428,133
September 2006	8,770,000	50.91	8,770,000	^(c)	92,924,937
October 2006	4,700,000	52.30	4,700,000	^(c)	89,014,781
November 2006	5,725,000	54.65	5,725,000	^(c)	84,349,006
December 2006	3,500,000	53.57	3,500,000	^(c)	81,376,088
January 2007	—	—	—	^(c)	111,353,833	^(e)
February 2007	1,100,000	51.95	1,100,000	^(c)	110,604,421

(a)

Amounts recalculated to reflect the four-for-one stock split on May 18, 2006.

(b)

Since May 18, 2005: the shareholders’ meeting of May 17, 2005 authorized the Board of Directors to trade the company’s own shares on the market for a period of 18 months within the framework of the stock purchase program approved by the Autorité des marchés financiers (AMF) under visa no. 05-247 of April 11, 2005. The number of shares held or acquired may not exceed 10% of the authorized share capital. Under this authorization, 66,862,636 shares have been repurchased from May 18, 2005 to May 12, 2006.

(c)

Since May 15, 2006: the shareholders’ meeting of May 12, 2006 cancelled and replaced the previous resolution from the shareholders’ meeting of May 17, 2005, authorizing the Board of Directors to trade in the Company’s own shares on the market for a period of 18 months within the framework of the stock purchase program. The maximum number of shares that may be purchased by virtue of this authorization may not exceed 10% of the total number of shares constituting the share capital, this amount is periodically adjusted to take into account operations modifying the share capital after each shareholders’ meeting. Under no circumstances may the total number of shares the Company holds, either directly or indirectly through its subsidiaries, exceed 10% of the share capital. Under this authorization, 55,252,048 shares have been repurchased from May 15, 2006 to February 28, 2007, including 2,295,684 shares that were purchased to cover restricted share grants to Group employees.

(d)

Based on 10% of the Company’s share capital, and after deducting the shares held by the Company for cancellation and the shares held by the Company to cover the share purchase option plans for Company employees and restricted share grants for Company employees, as well as after deducting the shares held by the subsidiaries.

(e)

The increase in the maximum number of shares is mainly due to the cancellation by the Board of Directors on July 18, 2006 and January 10, 2007 of, respectively, 47,020,000 and 33,005,000 shares.

121

ITEM 17. FINANCIAL STATEMENTS

Not applicable.

ITEM 18. FINANCIAL STATEMENTS

The following financial statements, together with the report of Ernst & Young Audit and KPMG S.A. thereon, are held as part of this annual report.


		Page
Report of Independent Registered Public Accounting Firms		F-1
Report of Independent Registered Public Accounting Firms		F-2
Consolidated Statement of Income for the Years Ended December 31, 2006, 2005 and 2004		F-3
Consolidated Balance Sheet at December 31, 2006, 2005 and 2004		F-4
Consolidated Statement of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004		F-5
Consolidated Statement of Change in Shareholders’ Equity for the years ended December 31, 2006, 2005 and 2004		F-6
Notes to the Consolidated Financial Statements		F-7

Schedules for the years ended December 31, 2006, 2005 and 2004
Schedule II — Valuation and Qualifying Accounts		F-83

Supplemental Oil and Gas Information (Unaudited)		S-1

All other Schedules have been omitted since they are not required under the applicable instructions or the substance of the required information is shown in the financial statements.

122

ITEM 19. EXHIBITS

The following documents are filed as part of this annual report:



1.		Statuts of TOTAL S.A. (as amended through January 10, 2007)

8.		List of Subsidiaries (see Note 33 to the Consolidated Financial Statements included in this Annual Report)

11.		Code of Ethics (incorporated by reference to the Company’s Annual Report on Form 20-F for the year ended December 31, 2005).

12.1		Certification of Chief Executive Officer

12.2		Certification of Chief Financial Officer

13.1		Certification of Chief Executive Officer

13.2		Certification of Chief Financial Officer

15		Consent of ERNST & YOUNG AUDIT and of KPMG S.A.

123

SIGNATURE

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.


TOTAL S.A.

By:		/s/ CHRISTOPHE DE MARGERIE
		Name: Christophe de Margerie
		Title: Chief Executive Officer

Date: April 10, 2007

124

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

Year ended December 31, 2006

The Board of Directors and Shareholders

TOTAL S.A.

We have audited the accompanying consolidated balance sheets of TOTAL S.A. and subsidiaries (the “Company”) as of December 31, 2006, 2005 and 2004, and the related consolidated statements of income, cash flows and changes in shareholders’ equity for each of the three years in the period ended December 31, 2006. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule listed in the Index as Schedule II. These consolidated financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2006, 2005 and 2004, and the consolidated results of its operations and its consolidated cash flows for each of the three years in the period ended December 31, 2006, in conformity with International Financial Reporting Standards as adopted by the European Union. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

International Financial Reporting Standards as adopted by the European Union differ in certain respects from United States generally accepted accounting principles. Information relating to the nature and effect of such differences is presented in Note 34 to the Consolidated Financial Statements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria) and our report dated April 3, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

Paris-La Défense, France

April 3, 2007


KPMG Audit	ERNST & YOUNG AUDIT
A division of KPMG S.A.	/s/ Gabriel Galet	/S/ PHILIPPE DIU
/S/ RENÉ AMIRKHANIAN	Gabriel Galet	Philippe Diu
René Amirkhanian

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

Year ended December 31, 2006

The Board of Directors and Shareholders

TOTAL S.A.

We have audited management’s assessment, included in the accompanying management report on internal control over financial reporting disclosed in Item 15, that TOTAL S.A. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria).The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2006, 2005 and 2004, and the related consolidated statements of income, cash flows, and changes in shareholders’ equity for each of the three years in the period ended December 31, 2006, and our report dated April 3, 2007, expressed an unqualified opinion on those consolidated financial statements.

Paris-La Défense, France

April 3, 2007


KPMG Audit	ERNST & YOUNG AUDIT
A division of KPMG S.A.	/s/ GABRIEL GALET	/s/ PHILIPPE DIU
/s/ RENÉ AMIRKHANIAN	Gabriel Galet	Philippe Diu
René Amirkhanian

F-2

CONSOLIDATED STATEMENT OF INCOME

TOTAL


(M€)^(a)
For the year ended December 31,		2006		2005		2004
Sales	(Notes 4 & 5)	153,802		137,607		116,842
Excise taxes		(21,113	)	(20,550	)	(21,517	)
Revenues from sales		132,689		117,057		95,325

Purchases net of inventory variation	(Note 6)	(83,334	)	(70,291	)	(56,020	)
Other operating expenses	(Note 6)	(19,536	)	(17,159	)	(16,770	)
Exploration costs	(Note 6)	(634	)	(431	)	(414	)
Depreciation, depletion, and amortization of tangible assets and leasehold rights		(5,055	)	(5,007	)	(5,095	)
Operating income	(Note 4)	24,130		24,169		17,026
Other income	(Note 7)	789		174		3,138
Other expense	(Note 7)	(703	)	(455	)	(836	)

Financial interest on debt		(1,731	)	(1,214	)	(702	)
Financial income from marketable securities & cash equivalents		1,367		927		572
Cost of net debt		(364	)	(287	)	(130	)

Other financial income	(Note 8)	592		396		321
Other financial expense	(Note 8)	(277	)	(260	)	(227	)
Income taxes	(Note 9)	(13,720	)	(11,806	)	(8,603	)
Equity in income (loss) of affiliates	(Note 12)	1,693		1,173		1,158
Consolidated net income from continuing operations (Group without Arkema)		12,140		13,104		11,847
Consolidated net income from discontinued operations (Arkema)	(Note 32)	(5	)	(461	)	(698	)
Consolidated net income		12,135		12,643		11,149
Group share		11,768		12,273		10,868
Minority interests and dividends on subsidiaries’ redeemable preferred shares		367		370		281

Earnings per share (euros)^(b)		5.13		5.23		4.50
Diluted earnings per share (euros)^(b)		5.09		5.20		4.48

(a)

Except for per share amounts.

(b)

2005 and 2004 amounts are recalculated to reflect the four-for-one stock split that took place on May 18, 2006. The earnings per share from continuing and discontinued operations are disclosed in Note 32 to the Consolidated Financial Statements.

The accompanying Notes are an integral part of these Consolidated Financial Statements

F-3

CONSOLIDATED BALANCE SHEET

TOTAL


As of December 31, (M€)		2006		2005		2004
ASSETS
Non-current assets
Intangible assets, net	(Notes 5 & 10)	4,705		4,384		3,176
Property, plant and equipment, net	(Notes 5 & 11)	40,576		40,568		34,906
Equity affiliates: investments and loans	(Note 12)	13,331		12,652		10,680
Other investments	(Note 13)	1,250		1,516		1,198
Hedging instruments of non-current financial debt	(Notes 20 & 27)	486		477		1,516
Other non-current financial assets	(Note 14)	2,088		2,794		2,351
Total non-current assets		62,436		62,391		53,827
Current assets
Inventories, net	(Note 15)	11,746		12,690		9,264
Accounts receivable, net	(Note 16)	17,393		19,612		14,025
Prepaid expenses and other current assets	(Note 16)	7,247		6,799		5,314
Current financial assets	(Notes 20 & 27)	3,908		334		477
Cash and cash equivalents		2,493		4,318		3,860
Total current assets		42,787		43,753		32,940
Total assets		105,223		106,144		86,767
LIABILITIES & SHAREHOLDERS’ EQUITY
Shareholders’ equity
Common shares		6,064		6,151		6,350
Paid-in surplus and retained earnings		41,460		37,504		31,717
Cumulative translation adjustment		(1,383	)	1,421		(1,429	)
Treasury shares		(5,820	)	(4,431	)	(5,030	)
Total shareholders’ equity - Group share	(Note 17)	40,321		40,645		31,608
Minority interests and subsidiaries’ redeemable preferred shares		827		838		810
Total shareholders’ equity		41,148		41,483		32,418
Non-current liabilities
Deferred income taxes	(Note 9)	7,139		6,976		6,402
Employee benefits	(Note 18)	2,773		3,413		3,607
Other non-current liabilities	(Note 19)	6,467		7,051		6,274
Total non-current liabilities		16,379		17,440		16,283
Non-current financial debt	(Note 20)	14,174		13,793		11,289
Current liabilities
Accounts payable		15,080		16,406		11,672
Other creditors and accrued liabilities	(Note 21)	12,509		13,069		11,148
Current borrowings	(Note 20)	5,858		3,920		3,614
Other current financial liabilities	(Notes 20 & 27)	75		33		343
Total current liabilities		33,522		33,428		26,777
Total liabilities and shareholders’ equity		105,223		106,144		86,767

The accompanying Notes are an integral part of these Consolidated Financial Statements

F-4

CONSOLIDATED STATEMENT OF CASH FLOWS

TOTAL


(Note 26)
For the year ended December 31, (M€)	2006		2005		2004
CASH FLOW FROM OPERATING ACTIVITIES
Consolidated net income	12,135		12,643		11,149
Depreciation, depletion, and amortization	5,555		6,083		6,682
Non-current liabilities, valuation allowances, and deferred taxes	601		515		715
Impact of coverage of pension benefit plans	(179	)	(23	)	(181	)
(Gains) Losses on sales of assets	(789	)	(99	)	(3,139	)
Undistributed affiliates’ equity earnings	(952	)	(596	)	(583	)
(Increase) Decrease in operating assets and liabilities	(441	)	(4,002	)	(253	)
Other changes, net	131		148		272
Cash flow from operating activities	16,061		14,669		14,662
CASH FLOW USED IN INVESTING ACTIVITIES
Intangible assets and property, plant and equipment additions	(9,910	)	(8,848	)	(7,777	)
Acquisitions of subsidiaries, net of cash acquired	(127	)	(1,116	)	(131	)
Investments in equity affiliates and other securities	(402	)	(280	)	(209	)
Increase in non-current loans	(1,413	)	(951	)	(787	)
Total expenditures	(11,852	)	(11,195	)	(8,904	)
Proceeds from sale of intangible assets and property, plant and equipment	413		274		225
Proceeds from sale of subsidiaries, net of cash sold	18		11		1
Proceeds from sale of non-current investments	699		135		408
Repayment of non-current loans	1,148		668		558
Total divestments	2,278		1,088		1,192
Cash flow used in investing activities	(9,574	)	(10,107	)	(7,712	)
CASH FLOW USED IN FINANCING ACTIVITIES
Issuance (repayment) of shares:
- Parent company’s shareholders	511		17		371
- Treasury shares	(3,830	)	(3,189	)	(3,554	)
- Minority shareholders	17		83		162
- Subsidiaries’ redeemable preferred shares	—		(156	)	(241	)
Cash dividends paid to:
- Parent company’s shareholders	(3,999	)	(3,510	)	(4,293	)
- Minority shareholders	(326	)	(237	)	(207	)
Net issuance (repayment) of non-current debt	3,722		2,878		2,249
Increase (Decrease) in current borrowings	(6	)	(951	)	(2,195	)
Changes in current financial assets and liabilities	(3,496	)	—		—
Other changes, net	—		(1	)	(6	)
Cash flow used in financing activities	(7,407	)	(5,066	)	(7,714	)
Net increase/decrease in cash and cash equivalents	(920	)	(504	)	(764	)
Effect of exchange rates and changes in reporting entity	(905	)	962		(236	)
Cash and cash equivalents at the beginning of the period	4,318		3,860		4,860
Cash and cash equivalents at the end of the period	2,493		4,318		3,860

The accompanying Notes are an integral part of these Consolidated Financial Statements

F-5

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

TOTAL


	Common shares issued				Paid-in surplus and retained earnings		Cumulative translation adjustment		Treasury shares				Share holders’ equity		Subsidiaries’ redeemable preferred shares		Minority interest		Total equity
(M€)	Number		Amount		Paid-in surplus and retained earnings		Cumulative translation adjustment		Number		Amount		Share holders’ equity				Minority interest		Total equity
As of January 1, 2004	649,118,236		6,491		27,360		—		(37,112,105	)	(4,613	)	29,238		396		683		30,317
Net income 2004	—		—		10,868		—		—		—		10,868		6		275		11,149
Items recognized directly in equity	—		—		29		(1,429	)	—		—		(1,400	)	(14	)	(88	)	(1,502	)
Total excluding transactions with shareholders	—		—		10,897		(1,429	)	—		—		9,468		(8	)	187		9,647
- Cash dividend	—		—		(4,293	)	—		—		—		(4,293	)	—		(207	)	(4,500	)
- Issuance of common shares (Note 17)	5,770,804		58		478		—		—		—		536		—		—		536
- Purchase of treasury shares	—		—		—		—		(22,550,000	)	(3,554	)	(3,554	)	—		—		(3,554	)
- Sale of treasury shares	—		—		14		—		715,686		61		75						75
- Repayment of subsidiaries’ redeemable preferred shares													—		(241	)			(241	)
- Share-based payments (Note 24)					138								138						138
Transactions with shareholders	5,770,804		58		(3,663	)	—		(21,834,314	)	(3,493	)	(7,098	)	(241	)	(207	)	(7,546	)
Cancellation of purchased shares (Note 17)	(19,873,932	)	(199	)	(2,877	)	—		19,873,932		3,076		—		—		—		—
As of December 31, 2004	635,015,108		6,350		31,717		(1,429	)	(39,072,487	)	(5,030	)	31,608		147		663		32,418
Net income 2005	—		—		12,273		—		—		—		12,273		1		369		12,643
Items recognized directly in equity (Note 17)	—		—		418		2,850		—		—		3,268		8		43		3,319
Total excluding transactions with shareholders	—		—		12,691		2,850		—		—		15,541		9		412		15,962
- Cash dividend	—		—		(3,510	)	—		—		—		(3,510	)	—		(237	)	(3,747	)
- Issuance of common shares (Note 17)	1,176,756		12		88		—		—		—		100		—		—		100
- Purchase of treasury shares	—		—		—		—		(18,318,500	)	(3,485	)	(3,485	)	—		—		(3,485	)
- Sale of treasury shares	—		—		34		—		2,066,087		226		260		—		—		260
- Repayment of subsidiaries’ redeemable preferred shares	—		—		—		—		—		—		—		(156	)	—		(156	)
- Share-based payments (Note 24)	—		—		131		—		—		—		131		—		—		131
Transactions with shareholders	1,176,756		12		(3,257	)	—		(16,252,413	)	(3,259	)	(6,504	)	(156	)	(237	)	(6,897	)
Cancellation of purchased shares (Note 17)	(21,075,568	)	(211	)	(3,647	)	—		21,075,568		3,858		—		—		—		—
As of December 31, 2005	615,116,296		6,151		37,504		1,421		(34,249,332	)	(4,431	)	40,645		—		838		41,483
Net income 2006	—		—		11,768		—		—		—		11,768		—		367		12,135
Items recognized directly in equity (Note 17)	—		—		(37	)	(2,595	)	—		—		(2,632	)			(44	)	(2,676	)
Total excluding transactions with shareholders	—		—		11,731		(2,595	)	—		—		9,136		—		323		9,459
Four-for-one split of shares par value	1,845,348,888		—		—		—		(102,747,996	)	—		—		—		—		—
- Spin-off of Arkema	—		—		(2,061	)	(209	)	—		16		(2,254	)	—		(8	)	(2,262	)
- Cash dividend	—		—		(3,999	)	—		—		—		(3,999	)	—		(326	)	(4,325	)
- Issuance of common shares (Note 17)	12,322,769		30		469		—		—		—		499		—		—		499
- Purchase of treasury shares	—		—		—		—		(78,220,684	)	(4,095	)	(4,095	)	—		—		(4,095	)
- Sale of treasury shares	—		—		—		—		6,997,305		232		232		—		—		232
- Share-based payments (Note 24)	—		—		157		—						157		—		—		157
Transactions with shareholders	1,857,671,657		30		(5,434	)	(209	)	(173,971,375	)	(3,847	)	(9,460	)	—		(334	)	(9,794	)
Cancellation of purchased shares (Note 17)	(47,020,000	)	(117	)	(2,341	)	—		47,020,000		2,458		—		—		—		—
As of December 31, 2006	2,425,767,953		6,064		41,460		(1,383	)	(161,200,707	)	(5,820	)	40,321		—		827		41,148

The accompanying Notes are an integral part of these Consolidated Financial Statements

F-6

TOTAL

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

On February 13, 2007, the Board of Directors established and authorized the publication of the consolidated financial statements of TOTAL S.A. for the year ended December 31, 2006.

INTRODUCTION

The consolidated financial statements of TOTAL S.A. and its subsidiaries (the Group) have been prepared on the basis of IFRS (International Financial Reporting Standards) as adopted by the European Union, as of December 31, 2006. As of December 31, 2006, December 31, 2005 and December 31, 2004, TOTAL’s consolidated financial statements would not have been different if presented under “IFRS as published by the IASB” or under “IFRS as adopted by the EU”.

The preparation of financial statements in accordance with IFRS requires management to make estimates and apply assumptions that affect the reported amounts of assets, liabilities and contingent liabilities at the date of preparation of the financial statements and reported income and expenses for the period. Management reviews these estimates and assumptions on an ongoing basis, by reference to past experience and various other factors considered as reasonable which form the basis for assessing the book value of assets and liabilities. Actual results may differ significantly from these estimates, if different assumptions or circumstances apply.

Lastly, where a specific transaction is not dealt with in any standards or interpretation, management applies its judgment to define and apply accounting policies that will lead to relevant and reliable information, so that the financial statements:

•

give a true and fair view of the Group’s financial position, financial performance and cash flow;

•

reflect the substance of transactions;

•

are neutral;

•

are prepared on a prudent basis; and

•

are complete in all material aspects.

1. ACCOUNTING POLICIES

The consolidated financial statements have been prepared on a historical cost basis, except for certain financial assets and liabilities that have been measured at fair value.

The accounting policies used by the Group are described below.

A. PRINCIPLES OF CONSOLIDATION

The subsidiaries that are directly controlled by the parent company or indirectly controlled by other consolidated subsidiaries are fully consolidated.

Investments in jointly controlled entities are proportionately consolidated.

Investments in associates, in which the Group has significant influence, are accounted for by the equity method. Significant influence is presumed when the Group holds, directly or indirectly (e.g. through subsidiaries), 20% or more of the voting rights.

Companies in which ownership interest is less than 20%, but over which the Company has the ability to exercise significant influence, are also accounted for by the equity method.

All significant intercompany balances, transactions and income have been eliminated.

B. BUSINESS COMBINATIONS

Business combinations are accounted for using the purchase method. This method implies the recognition of the assets, liabilities and contingent liabilities of the companies acquired by the Group at their fair value.

The difference between the acquisition cost of the shares and the total valuation, at fair value, of the acquired share of the assets, liabilities and contingent liabilities identified on the acquisition date is recorded as goodwill.

If the cost of an acquisition is less than the fair value of the net assets of the subsidiary acquired, an additional analysis is performed on the identification and valuation of the identifiable elements of the assets and liabilities. Any residual negative goodwill is recorded as net operating income.

The analysis of goodwill is finalized within one year from the acquisition date.

F-7

C. FOREIGN CURRENCY TRANSLATION

The financial statements of subsidiaries are prepared in the currency that most clearly reflects their business environment. This is referred to as their functional currency.

(i)

Monetary transactions

Transactions denominated in foreign currencies are translated at the exchange rate prevailing at the transaction date. At each balance sheet date, monetary assets and liabilities are translated at the closing rate and the resulting exchange differences are recognized in “Other income” or “Other expenses”.

(ii)

Translation of financial statements denominated in foreign currencies

Assets and liabilities of foreign entities are translated into euros on the basis of the exchange rates at the end of the period. The income and cash flow statements are translated using the average exchange rates of the period. Foreign exchange differences resulting from such translations are either recorded in Shareholders’ equity under “Cumulative translation adjustments” (for the Group share) or under “Minority interests” as deemed appropriate.

D. SALES AND REVENUES FROM SALES

Revenues from sales are recognized when the significant risks and rewards of ownership have been passed to the buyer and the amount can be reasonably measured. Sales figures include excise taxes collected by the Group within the course of its oil distribution operations. Excise taxes are deducted from sales in order to obtain the “Revenue from sales” indicator.

Revenues from sales of crude oil, natural gas and coal are recorded upon transfer of title, according to the terms of the sales contracts.

Revenues from the production of natural gas properties, in which the Group has an interest with other producers, are recognized based on actual volumes sold during the period. Any difference between volumes sold and entitlement volumes, based on the Group net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate.

Revenues from gas transport are recognized when the services are rendered, based on the quantities transported and measured according to procedures defined in each service contract.

Revenues from sales of electricity, to the Downstream and Chemicals segment, are recorded upon transfer of title, according to the terms of the related contracts.

Revenues from services are recognized when the services have been rendered.

Shipping revenues and expenses from charter activities are recognized on a pro rata basis over a period that commences upon the unloading of the previous voyage and terminates upon the unloading of the current voyage. Shipping revenue recognition starts only when a charter has been agreed to by both the Group and the customer, and revenue begins to be earned.

Oil and gas sales are inclusive of quantities delivered that represent production royalties and taxes when paid in cash and outside the United States and Canada.

Certain transactions within the trading activities (contracts involving quantities that are purchased outside the Group then resold outside the Group) are shown at their net value in sales.

Exchanges of crude oil and petroleum products within normal trading activities do not generate any income: flows are shown at their net value in both the income statement and the balance sheet.

E. SHARE-BASED PAYMENTS

The Group may grant employees stock options, create employee share purchase plans and offer its employees the opportunity to subscribe to reserved capital increases. These employee benefits are recognized as expenses with a corresponding credit to shareholders’ equity.

The expense is determined at fair value by reference to the instruments granted. The fair value of the options is calculated using the Black-Scholes method at the grant date. The expense is allocated on a straight-line basis between the grant date and vesting date.

The cost of employee-reserved capital increases is immediately expensed. A discount reduces the expense to take into account the non-transferability of the shares awarded to the employees over a period of five years.

F. INCOME TAXES

Income taxes shown in the income statement include current income tax expenses and deferred income tax expenses.

The Group uses the liability method whereby deferred income taxes are recorded based on the temporary differences between the financial statement and tax

F-8

basis of assets and liabilities and for carry-forwards of unused tax losses and tax credits.

Deferred tax assets and liabilities are measured using the tax rates that have been enacted or substantially enacted at the balance sheet date. The tax rates used depend on the maturity of renewal of temporary differences, tax losses and other tax credits. The effect of the change in tax rate is recognized either in the consolidated statement of income or in equity depending on the item to which it is related.

Deferred tax assets are recognized when future recovery is probable.

Asset retirement obligations and finance leases give rise to the recognition of assets and liabilities for accounting purposes as described in paragraph Q “Asset retirement obligations” and paragraph K “Leases” of this Note. Deferred income taxes on temporary differences resulting from the difference between the carrying value and taxable basis of such assets and liabilities are recognized.

Deferred tax liabilities on temporary differences resulting from the difference between the carrying value of the equity-method investments and the taxable basis of these investments are recognized. The deferred tax calculation is based on the expected future tax effect (dividend distribution rate or tax rate on the gain or loss upon sale of these investments).

Taxes paid on the Upstream production are included in operating expenses, including those related to historical concessions held by the Group in the Middle East producing countries.

G. EARNINGS PER SHARE

Earnings per share are calculated by dividing net income by the weighted-average number of common shares outstanding during the period.

Diluted earnings per share are calculated by dividing net income by the fully-diluted weighted-average number of common shares outstanding during the period. Treasury shares held by the parent company, TOTAL S.A., and, TOTAL shares held by the Group subsidiaries, are deducted from consolidated shareholders’ equity and are not considered outstanding for purposes of this calculation which also takes into account the dilutive effect of stock options, restricted share grants, and capital increases with a subscription period closing after the end of the fiscal year.

The weighted-average number of fully-diluted shares is calculated in accordance with the treasury stock method provided for by IAS 33. The proceeds, which would be recovered in the event of an exercise of rights related to dilutive instruments, are presumed to be a buyback of

shares at average market price over the period. The number of shares thereby obtained leads to a reduction in the total number of shares that would result from the exercise of rights.

H. OIL AND GAS EXPLORATION AND PRODUCING PROPERTIES

The Group applies IFRS 6 “Exploration for and Evaluation of Mineral Resources”. Oil and gas exploration and production properties and assets are accounted for in accordance with the successful efforts method.

(i)

Exploration costs

Geological and geophysical costs, including seismic surveys for exploration purposes, are expensed as incurred.

Leasehold rights are capitalized as intangible assets when acquired. They are tested for impairment on a regular basis, property-by-property, based on the results of exploration activity and management’s evaluation.

In the event of a discovery, the unproved leasehold rights are transferred to proved leasehold rights at their net book value as soon as proved reserves are booked.

Exploratory wells are tested for impairment on a well-by-well basis and accounted as follows:

•

costs of exploratory wells that have found proved reserves are capitalized. Capitalized successful exploration wells are then depreciated using the unit-of-production method based on proved developed reserves;

•

costs of dry exploratory wells and wells that have not found proved reserves are charged to expense;

•

costs of exploratory wells are temporarily capitalized until a determination is made as to whether the well has found proved reserves if both of the following conditions are met:

•

the well has found a sufficient quantity of reserves to justify its completion as a producing well, if appropriate, assuming that the required capital expenditures are made;

•

the Group is making sufficient progress assessing the reserves and the economic and operating viability of the project. This progress is evaluated on the basis of indicators such as whether additional exploratory works are underway or firmly planned (wells, seismic or significant studies), whether costs are being incurred for development studies and whether the Group is waiting for governmental or other third-party authorization of a proposed project, or availability of capacity on an existing transport or processing facility.

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Costs of exploratory wells not meeting these conditions are charged to expense.

(ii)

Oil and Gas producing assets

Development costs incurred for the drilling of development wells and in the construction of production facilities are capitalized, together with interest costs incurred during the period of construction and estimated discounted costs of asset retirement obligations. The depletion rate is equal to the ratio of oil and gas production for the period to proved developed reserves (unit-of-production method).

With respect to production sharing contracts, this computation is based on the portion of production and reserves assigned to the Group taking into account estimates based on the contractual clauses regarding the reimbursement of exploration and development costs (cost oil) as well as the sharing of hydrocarbon rights (profit oil).

Transportation assets are depreciated using the unit-of-production method based on throughput or by using the straight-line method whichever best reflects the economic life of the asset.

Proved leasehold rights are depreciated using the unit-of-production method based on proved reserves.

I. GOODWILL AND OTHER INTANGIBLE ASSETS

Other intangible assets include goodwill, patents, trademarks, and leasehold rights.

Intangible assets are carried at cost, after deducting any accumulated depreciation and accumulated impairment losses.

Goodwill in a consolidated company is calculated as the excess of the cost of shares, including transaction expenses, over the fair value of the Group’s share of the net assets at the acquisition date. Goodwill is not amortized but is tested for impairment annually or as soon as there is any indication that an asset may be impaired (see paragraph L “Impairment of long-lived assets” of this Note.)

In equity affiliates, the book value of goodwill is included in the book value of the investment. Other intangible assets (except goodwill) have a finite useful life and are amortized on a straight-line basis over 10 to 40 years depending on the useful life of the assets.

Research and development

Research costs are charged to expense as incurred.

Development expenses are capitalized when the following can be demonstrated:

•

the technical feasibility of the project and the availability of the appropriate resources for the completion of the intangible asset;

•

the ability of the asset to generate probable future economic benefits;

•

the ability to measure reliably the expenditures attributable to the asset.

Advertising costs are charged to expense as incurred.

J. OTHER PROPERTY, PLANT AND EQUIPMENT

Other property, plant and equipment are carried at cost, after deducting any accumulated depreciation and accumulated impairment losses. This includes interest expenses incurred until assets are placed in service. Investment subsidies are deducted from the cost of the related expenditures.

Routine maintenance and repairs are charged to expense as incurred. The costs of major turnarounds of refineries and large petrochemical units are capitalized as incurred and depreciated over the period of time between two major turnarounds.

Other property, plant and equipment are depreciated using the straight-line method over their useful life, as follows:


• Furniture, office equipment, machinery and tools		3-12 years
• Transportation equipment		5-20 years
• Storage tanks and related equipment		10-15 years
• Specialized installations and pipelines		10-30 years
• Buildings		10-50 years

K. LEASES

A financial lease transfers substantially all the risks and rewards incidental to ownership from the lessor to the lessee. These contracts are capitalized as assets at fair value or, if lower, at the present value of the minimum lease payments according to the contract. A corresponding financial debt is recognized as financial liabilities. These assets are depreciated over the useful life used by the Group.

Leases that are not financial leases as defined above are recorded as operating leases.

Certain arrangements do not take the legal form of a lease but convey the right to use an asset or a group of assets in return for fixed payments. Such arrangements

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are accounted for as leases and are analyzed to determine whether they should be classified as operating leases or as financial leases.

L. IMPAIRMENT OF LONG-LIVED ASSETS

The recoverable amounts of intangible assets and property, plant and equipment are tested for possible impairment as soon as there is any indication that the assets may be impaired. This test is performed at least annually for goodwill.

The recoverable value is the higher of the sale price (net of sale expenses) and its useful value.

For this purpose, assets are grouped into cash-generating units (or CGUs). A cash-generating unit is a group of assets that generates cash flows that are largely independent of the cash flows of other groups of assets.

The recoverable amount of a CGU is determined by reference to the discounted future cash flows expected from it, based upon management’s expectation of future economic and operating conditions. If the recoverable amount is less than the carrying amount, an impairment loss on property, plant and equipment and leaseholds rights, or on other intangible assets, is recognized either in “Depreciation, depletion and amortization of tangible assets and leaseholds rights” or in “Other expense”, respectively. This impairment loss is first allocated to reduce the carrying amount of any goodwill, then to the other assets of the CGU.

Impairment losses recognized in prior periods could be reversed up to the net book value that the asset would have had if the impairment loss had not been recognized. Impairment losses recognized for goodwill are not reversed.

M. FINANCIAL ASSETS AND LIABILITIES

Financial assets and liabilities are financial loans and receivables, investments in non-consolidated companies, and publicly-traded equity securities, derivative instruments and current and non-current financial liabilities.

The accounting treatment of these financial assets and liabilities is as follows.

(i)

Financial loans and receivables

Financial loans and receivables are recognized at amortized cost. They are tested for impairment, the net book value being compared to estimates of the discounted future recoverable cash flows. These tests are conducted as soon as there is any evidence that their fair value is less than their net book value, and at least annually. The potential loss is recorded in the statement of income.

(ii)

Investments in non-consolidated companies and publicly-traded equity securities

These assets are classified as available for sale and therefore measured at their fair value. For listed securities, this fair value is equal to the market price. For unlisted securities, if the fair value is not reliably determinable, securities are recorded at their historical value. Changes in fair value are recorded in shareholders’ equity. If there is any evidence of a significant or long-lasting loss, an impairment loss is recorded in the consolidated statement of income. This impairment is reversed in the statement of income only when the securities are sold.

(iii)

Derivative instruments

The Group uses derivative instruments to manage its exposure to movements in interest rates, foreign exchange rates and commodity prices. Changes in fair value of derivative instruments are recognized in the statement of income or in shareholders’ equity and are recognized in the balance sheet in the accounts corresponding to their nature, according to the risk management strategy described in Note 29 to the Consolidated Financial Statements. The derivative instruments used by the Group are the following:

•

Cash management

Financial instruments used for cash management purposes are part of a hedging strategy of currency and interest rate risks within global limits set by the Group and are considered to be used for transactions (held for trading). Changes in fair value are systematically recorded in the income statement. The balance sheet value of those instruments is included in “Current financial assets” or “Other current financial liabilities”.

•

Long-term financing (other than euro)

When an external long-term financing is set up, specifically to finance subsidiaries in a currency other than the euro, which is mainly the case for subsidiaries whose functional currency is the U.S. dollar, and when this financing involves currency and interest rate derivatives, these instruments qualify as fair value hedges of the interest rate risk on the external debt and of the currency risk of the loans to subsidiaries. Changes in fair value of derivatives are recognized in the income statement as are changes in fair value of financial debts and loans to subsidiaries.

The fair value of those hedging instruments of long-term financing is included in the assets under « Hedging instruments on non-current financial debt» or in the liabilities under « Non-current financial debt» for the non-current part. The current part (less than one year) is accounted for in “Current financial assets” or “Other current financial liabilities”.

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In case of the anticipated termination of derivative instruments accounted for as fair value hedge, the amount paid or received is recognized in the income statement and:

•

If this termination is due to an early cancellation of the hedged items, the adjustment previously recorded as revaluation of those hedged items is also recognized in the income statement.

•

If the hedged items remain in the balance sheet, the adjustment previously recorded as revaluation of those hedged items is spread over the remaining life of those items.

•

Foreign subsidiaries’ equity hedge

Certain financial instruments hedge against risks related to the equity of foreign subsidiaries whose functional currency is not the euro (mainly the U.S. dollar). They qualify as “net investment hedges”. Changes in fair value are recorded in shareholders’ equity.

The fair value of these instruments is recorded under “Current financial assets” or “Other current financial liabilities”.

•

Financial instruments related to commodity contracts

Financial instruments related to commodity contracts, including all the crude oil, petroleum products, natural gas and power purchasing/selling contracts related to the trading activities, together with the commodity contract derivative instruments such as energy contracts and forward freight agreements, are used to adjust the Group’s exposure to price fluctuations within global trading limits. These instruments are considered, according to the industry practice, as held for trading. Changes in fair value are recorded in the income statement. The fair value of these instruments is recorded in the appropriate operating third party headings “Accounts receivable and other current assets” or “Accounts payable and other creditors” depending whether they are assets or liabilities.

Detailed information about the closing balances is disclosed in Notes 20, 27 and 29 to the Consolidated Financial Statements.

(iv)

Current and non-current financial liabilities

Current and non-current financial liabilities (excluding derivatives) are recognized at amortized cost, except those for which a hedge accounting can be applied as described in the previous paragraph.

(v)

Fair value of financial instruments

Fair values are estimated for the majority of the Group’s financial instruments, with the exception of publicly traded equity securities and marketable securities for which the market price is used.

Estimated fair values, which are based on principles such as discounting future cash flows to present value, must be weighted by the fact that the value of a financial instrument at a given time may be modified depending on the market environment (liquidity especially), and also the fact that subsequent changes in interest rates and exchange rates are not taken into account. In some cases, the estimates have been made based on simplifying assumptions.

As a consequence, the use of different estimates, methodologies and assumptions may have a material effect on the estimated fair value amounts.

The methods used are as follows:

Financial debts, swaps: The market value of swaps and debenture loans that are hedged by those swaps, have been determined on an individual basis by discounting future cash flows with the zero coupon interest rate curves existing at year-end.

Other financial instruments: The fair value of the interest rate swaps and of FRA (Forward Right Agreement) are calculated by discounting future cash flows on the basis of the zero coupon interest rate curves existing at year-end after adjustment for interest accrued yet unpaid.

Forward exchange contracts and currency swaps are valued on the basis of a comparison of the forward rates negotiated with the rates in effect on the financial markets at year-end for similar maturities.

Exchange options are valued based on the Garman-Kohlhagen model including market quotations at year-end.

N. INVENTORIES

Inventories are valued in the consolidated financial statements at the lower of historical cost on market value. Costs for petroleum and petrochemical products are determined according to the FIFO (First-In, First-Out) method and those of other inventories use the weighted-average cost method.

Downstream (Refining – Marketing)

Petroleum product inventories are mainly comprised of crude oil and refined products. Refined products

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principally consist of gasoline, kerosene, diesel, fuel and heating oil and are produced by the Group’s refineries. The turnover of petroleum products does not exceed two months on average.

Crude oil costs include raw material and receiving costs. Refining costs principally include the crude oil costs, production costs (energy, labor, depreciation of producing assets) and allocation of production overhead (taxes, maintenance, insurance, etc.). Start-up costs and general administrative costs are excluded from the cost price of refined products.

Chemicals

Costs of chemical products inventories consist of raw material costs, direct labor costs and an allocation of production overhead. Start-up costs and general administrative costs are excluded from the cost of inventories of chemicals products.

O. TREASURY SHARES

Treasury shares of the Company held by it on its subsidiaries are deducted from consolidated shareholders’ equity. Gains or losses on sales of treasury shares are excluded from the determination of net income and are recognized in shareholders’ equity.

P. OTHER NON-CURRENT LIABILITIES

Non-current liabilities comprise liabilities for which the amount and the timing are uncertain. They arise from environmental risks, legal and tax risks, litigation and other risks.

A provision is recognized when the Group has a present obligation (legal or constructive) as a result of a past event for which it is probable that an outflow of resources will be required and when a reliable estimate can be made of the amount of the obligation. The amount of the liability corresponds to the best possible estimate.

Q. ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations, which result from a legal or constructive obligation, are recognized on the basis of a reasonable estimate of their fair value in the period in which the obligation arises.

The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived assets and depreciated over the useful life of the associated long-lived asset.

An entity is required to measure changes in the liability for an asset retirement obligation due to the passage of time (accretion) by applying a discount rate that reflects the time value of money to the amount of the liability at the beginning of the period. The increase of the provision due to the passage of time is recognized as “Other financial expense”.

R. EMPLOYEE BENEFITS

In accordance with the laws and practices of each country, the Group participates in employee benefit plans offering retirement, death and disability, healthcare and special termination benefits. These plans provide benefits based on various factors such as length of service, salaries, and contributions made to the governmental bodies responsible for the payment of benefits.

These plans can be either defined contribution or defined benefit pension plans and may be entirely or partially funded with investments made in various non-Group instruments such as mutual funds, insurance contracts, and others.

For defined contribution plans, expenses correspond to the contributions paid.

Defined benefit obligations are determined according to the Projected Unit Method. Actuarial gains and losses may arise from differences between actuarial valuation and projected commitments (depending on new calculations or assumptions) and between projected and actual return of plan assets.

The Group applies the corridor method to amortize its actuarial gains and losses. This method amortizes the net cumulative actuarial gains and losses that exceed 10% of the greater of the present value of the defined benefit obligation and the fair value of plan assets over the average expected remaining working lives of the employees participating in the plan.

In case of a change in or creation of a plan, the vested portion of the cost of past services is recorded immediately in the income statement, and the unvested past service cost is amortized over the vesting period.

The net periodic pension cost is recognized under “Other operating expenses”.

S. CONSOLIDATED STATEMENT OF CASH FLOWS

The consolidated statement of cash flows prepared in foreign currencies has been translated into euros using the average exchange rate of the period. Currency translation differences arising from the translation of assets and liabilities denominated in foreign currency into euros using exchange rates at the end of the period

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are shown in the balance sheet under “Effect of exchange rates and changes in reporting entity”. Therefore, the consolidated statement of cash flows will not agree with the figures derived from the consolidated balance sheet.

Cash and cash equivalents

Cash and cash equivalents comprise cash on hand and highly liquid short-term investments that are easily convertible into known amounts of cash and are subject to insignificant risks of changes in value.

Investments with maturity greater than three months and less than twelve months are shown under “Current financial assets”.

Changes in bank overdrafts are included in the financing activities section of the consolidated statement of cash flows.

Non-current debt

Changes in non-current debt have been presented as the net variation to reflect significant changes mainly related to revolving credit agreements.

T. EMISSION RIGHTS

In the absence of a current IFRS standard or interpretation on accounting for emission rights of CO₂, the following principles have been applied:

•

emission rights granted free of charge are accounted for at zero book value;

•

the liabilities resulting from potential differences between available quotas and quotas to be delivered at the end of the compliance period are accounted for as liabilities at fair market value;

•

spot market transactions are recognized at cost in operating income;

•

forward transactions are recognized at their fair market value on the face of the balance sheet. Changes in the fair value of such forward transactions are recognized in operating income.

U. NON-CURRENT ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS

Pursuant to IFRS 5 “Non-current assets held for sale and discontinued operations”, assets and liabilities of affiliates that are held for sale are presented separately on the face of the balance sheet.

Net income from discontinued operations is presented separately on the face of the statement of income. Therefore, the Notes to the Consolidated Financial Statements related to the statement of income refer only to continuing operations.

A discontinued operation is a component of the Group for which cash flows are independent. It represents a major line of business or geographical area of operations which has been disposed of or is held for sale.

V. INFORMATION RELATED TO THE FIRST-TIME APPLICATION OF IFRS

Pursuant to IFRS 1 “First-time adoption of International Financial Reporting Standards”, the Group has chosen to apply the following exemptions:

•

offsetting currency translation adjustment (CTA) against retained earnings, as of January 1, 2004;

•

recording unrecognized actuarial losses and gains related to employee benefit obligations as of January 1, 2004 in retained earnings;

•

no retroactive restatement of business combinations that occurred before January 1, 2004;

•

retrospective application of IFRS 2 “Share-based payment” to all transactions within the scope of IFRS 2 and not solely to the share-based compensation plans granted after November 7, 2002.

The other exemptions included in IFRS 1 “First time adoption” have not been applied at the transition date to the IFRS or did not have any material impact on the consolidated financial statements.

IAS 32 “Financial Instruments: Disclosure and Presentation” and IAS 39 “Financial Instruments: Recognition and Measurements” have been applied as from January 1, 2004. The Group has decided on an early application in 2004 of IFRS 6 “Exploration for and Evaluation of Mineral Resources”. This standard is compatible with previously used methods to record exploration and production costs (see paragraph H “Oil and gas exploration and producing properties” to this Note).

Description of the effects of the transition to IFRS on the net equity and the results of the Group were provided for in the Annual Report on Form 20-F for 2005. This information is presented in the Note 32 to the Consolidated Financial Statements as of December 31, 2005.

The financial data for 2004 and 2003 were presented under French GAAP in the 2004 Registration Document.

W. ALTERNATIVE IFRS METHODS

For measuring and recognizing assets and liabilities, the following choices among alternative methods permitted under IFRS have been made:

•

property, plant and equipment, and intangible assets are measured using historical cost model instead of revaluation model;

F-14

•

interest expense incurred during the construction and acquisition period of tangible and intangible assets is capitalized, as provided for under IAS 23 “Borrowing Costs”;

•

actuarial gains and losses on pension and other post-employment benefit obligations are recognized according to the corridor method as from January 1, 2004 (see paragraph R to this Note);

•

jointly-controlled entities are consolidated using the proportionate method, as provided for in IAS 31 “Interests in Joint Ventures”.

X. NEW ACCOUNTING PRINCIPLES NOT YET IN EFFECT

The standards or interpretations published respectively by the International Accounting Standards Board (IASB) and the International Financial Reporting Interpretations Committee (IFRIC) which were not yet in effect at December 31, 2006, were as follows:

(i)

IFRS 7 “Financial Instruments: disclosures”

In August 2005, the IASB issued IFRS 7 “Financial Instruments: Disclosures”. The new standard replaces IAS 30 “Disclosures in financial statements of Banks and Similar Financial Institutions” and provides amendments to IAS 32 “Financial Instruments: Disclosure and Presentation”. IFRS 7 requires disclosure of qualitative and quantitative information about exposure to risks resulting from financial instruments. Entities shall apply IFRS 7 to annual periods beginning on or after January 1, 2007. The application of IFRS 7 should not have any material impact for the Group given the disclosures already presented in the consolidated statements for the year ended December 31, 2006.

(ii)

IFRS 8 “Operating segments”

In November 2006, the IASB issued IFRS 8 “Operating segments”. The new standard replaces IAS 14 “Segment reporting”. It requires entities to adopt an approach based on internal information used by the management of the entity to determine reportable segments, whereas IAS 14 is based on segment risks and profitability. Entities shall apply IFRS 8 to annual periods beginning on or after January 1, 2009. The application of IFRS 8 should not have any material impact for the Group given the disclosures already presented in the consolidated financial statements of the Group.

(iii)

IFRIC 9 “Reassessment of Embedded Derivatives”

In March 2006, the IFRIC published interpretation IFRIC 9 “Reassessment of Embedded Derivatives”. The

interpretation addresses embedded derivatives within the scope of IAS 39 relating to Financial Instruments and their reassessment. IFRIC 9 concludes that an entity must assess whether an embedded derivative is required to be separated from the host contract and accounted for as a derivative when the entity first becomes a party to the contract. Subsequent reassessment is prohibited unless there is a significant change in the terms of the contract. IFRIC 9 is effective for annual periods beginning on or after June 1, 2006. The application of IFRIC 9 should not have any material effect on the Group’s balance sheet, income statement or consolidated shareholder’s equity.

(iv)

IFRIC 10 “Interim Financial Reporting and Impairment”

In July 2006, the IFRIC published interpretation IFRIC 10 “Interim Financial Reporting and Impairment”. In accordance with IFRIC 10, an entity shall not reverse an impairment loss recognised in a previous interim period in respect of goodwill or an investment in either an equity instrument or a financial asset carried at cost, in subsequent interim or annual period. IFRIC 10 is effective for annual periods beginning on or after November 1, 2006. The application of IFRIC 10 should not have any material effect on the Group’s balance sheet, income statement and consolidated shareholder’s equity.

2. MAIN INDICATORS - INFORMATION BY BUSINESS SEGMENT

Performance indicators excluding the adjustment items, such as adjusted operating income, adjusted net operating income, adjusted net income are meant to facilitate the analysis of the financial performance and the comparison of income between periods.

Adjusting items:

(i)

Special items

Due to their unusual nature or particular significance, certain transactions qualified as “special items” are excluded from the business segment figures. In general, special items relate to transactions that are significant and infrequent or unusual. However, in certain instances, transactions such as restructuring costs or assets disposals, which are not considered to be representative of the normal course of business, may be qualified as special items although they may have occurred within prior years or are likely to occur again within the coming years.

(ii)

The inventory valuation effect

The adjusted results of the Downstream and Chemical segments are also presented according to the

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replacement cost method. This method is used to assess the segments’ performance and ensure the comparability of the segments’ results with those of its competitors, mainly North-American.

In the replacement cost method, which approximates the LIFO (Last-In, First-Out) method, the variation of inventory values in the income statement is determined by the average prices of the period rather than the historical value. The inventory valuation effect is the difference between the results according to the FIFO (First-In, First-Out) and the replacement cost.

(iii)

Portion of intangible assets amortization related to the Sanofi-Aventis merger

The detail of these adjustment items is presented in Note 4 to the Consolidated Financial Statements.

Operating income (measure used to evaluate operating performance)

Revenue from sales after deducting cost of goods sold and inventory variations, other operating expenses, exploration expenses and depreciation, depletion, and amortization.

Operating income excludes the amortization and depreciation of intangible assets other than leasehold rights, currency translation adjustments and gains or losses on the sale of assets.

Net operating income (measure used to evaluate the return on capital employed)

Operating income after deducting the amortization and the depreciation of intangible assets other than leasehold rights, currency translation adjustments and gains or losses on the sale of assets, as well as all other income and expenses related to capital employed (dividends from non-consolidated companies, equity in income in affiliates, capitalized interest expenses), and after income taxes applicable to the above.

The income and expense not included in net operating income which are included in net income are only interest expenses related to non-current liabilities net of interest earned on cash and cash equivalents, after applicable income taxes (net cost of net debt and minority interests).

Adjusted income

Operating income, net operating income, or net income excluding the effect of adjusting items described above.

Capital employed

Non-current assets and working capital requirements, at replacement cost, net of deferred income taxes and non-current liabilities.

ROACE (Return on Average Capital Employed)

Ratio of adjusted net operating income to average capital employed between the beginning and the end of the period.

Net debt

Non-current debt, including current portion, current borrowings, other current financial liabilities less cash and cash equivalent and other current financial assets.

3. CHANGES IN THE GROUP STRUCTURE, MAIN ACQUISITIONS AND DIVESTMENTS

2006

After approval on October 13, 2006 by the European Commission, Banco Santander Central Hispano (Santander) sold 4.35% of CEPSA’s share capital to TOTAL at a price of €4.54 per share, for a total transaction amount of approximately 53 M€. The transaction follows the agreement signed on August 2, 2006 by TOTAL and Santander to implement the provisions of the partial award rendered on March 24, 2006 by the Netherlands Arbitration Institute, which adjudicated the dispute concerning CEPSA.

As a result TOTAL now holds 48.83% of CEPSA.

In 2004, TOTAL announced a reorganization of its Chemical segment to regroup its chlorochemicals, intermediates and performance polymers in a new entity that was named Arkema on October 1, 2004.

The shareholders’ meeting on May 12, 2006 approved a resolution related to the spin-off of Arkema and the distribution of Arkema shares to TOTAL shareholders. Pursuant to this approval, Arkema shares were publicly listed on May 18, 2006 on the Eurolist by Euronext exchange in Paris. For all periods presented, the contribution of Arkema entities to the consolidated net income is presented on the line “Consolidated net income from discontinued operations” on the face of the income statement. Detailed information on the impact of this transaction is presented in Note 32 to the Consolidated Financial Statements.

2005

Pursuant to its public offer and takeover bid circular dated August 5, 2005 and extended to September 2, 2005 TOTAL has acquired 78 % of Deer Creek Energy Ltd as of September 13, 2005. Its offer was extended in order to acquire the shares which had not been tendered. The acquisition of all ordinary shares was completed December 13, 2005.

Deer Creek Energy Ltd has an 84% interest in the Joslyn permit in the Athabasca region of the Canadian province of Alberta.

The acquisition cost, net of cash acquired (0.1 B€) for all shares amounts to 1.1 B€. This cost essentially

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represents the value of the company’s leasehold rights that have been recognized as intangible assets on the face of the consolidated balance sheet for 1 B€.

Deer Creek Energy Ltd is fully consolidated in TOTAL’s consolidated financial statements. Its contribution to 2005 consolidated net income is not material.

2004

Following the outcome of a share and cash offer by Sanofi-Synthélabo for Aventis in 2004, the merger via takeover of Aventis, thereby creating the entity Sanofi-Aventis, was approved by the Sanofi-Aventis extraordinary shareholders’ meeting on December 23, 2004 and took effect on December 31, 2004.

The acquisition of Aventis by Sanofi-Synthélabo results in a dilution of the Group’s equity in the company. After deduction of Sanofi-Aventis’ own shares, the Group owns 13.25% of the capital of Sanofi-Aventis as of December 31, 2004 instead of 25.63% of the capital of Sanofi-Synthélabo as of December 31, 2003.

Sanofi-Aventis is consolidated in the Group accounts according to the equity method.

4. BUSINESS SEGMENT INFORMATION

Financial information by business segment is reported in accordance with the internal reporting system and shows internal segment information that is used to manage and measure the performance of TOTAL. The Group’s activities are conducted through three business segments: Upstream, Downstream and Chemicals.

•

The Upstream segment includes the exploration and production of hydrocarbons, gas, power and other energies activities.

•

The Downstream segment includes refining and marketing activities along with trading and shipping activities.

•

The Chemical segment includes Base Chemicals and Specialties.

The Corporate segment includes the operating and financial activities of the holding companies as well as healthcare activities (Sanofi-Aventis).

The operational profit and assets are broken down by business segment prior to the consolidation and inter-segment adjustments.

Sales prices between business segments approximate market prices.

A. INFORMATION BY BUSINESS SEGMENT


2006 (M€)	Upstream		Downstream		Chemicals		Corporate		Inter-company		Total
Non-Group sales	20,782		113,887		19,113		20		—		153,802
Intersegment sales	20,603		4,927		1,169		177		(26,876	)	—
Excise taxes	—		(21,113	)	—		—		—		(21,113	)
Revenues from sales	41,385		97,701		20,282		197		(26,876	)	132,689
Operating expenses	(17,759	)	(93,209	)	(18,706	)	(706	)	26,876		(103,504	)
Depreciation, depletion and amortization of tangible assets and leasehold rights	(3,319	)	(1,120	)	(580	)	(36	)	—		(5,055	)
Operating income	20,307		3,372		996		(545	)	—		24,130
Equity in income (loss) of affiliates and other items	1,211		384		(298	)	797		—		2,094
Tax on net operating income	(12,764	)	(1,125	)	(191	)	206		—		(13,874	)
Net operating income	8,754		2,631		507		458		—		12,350
Net cost of net debt											(210	)
Minority interests and dividends on subsidiaries’ redeemable preferred shares											(367	)
Net income from continuting operations Group share											11,773
Net income from discontinued operations Group share											(5	)
Net income											11,768

F-17


2006 (adjustments)^* (M€)	Upstream		Downstream		Chemicals		Corporate		Intercompany	Total
Non-Group sales
Intersegment sales
Excise taxes
Revenues from sales
Operating expenses	—		(272	)	(158	)	(27	)		(457	)
Depreciation, depletion and amortization of tangible assets and leasehold rights	—		—		(61	)	—			(61	)
Operating income^(a)	—		(272	)	(219	)	(27	)		(518	)
Equity in income (loss) of affiliates and other items^(b)	195		178		(327	)	(295	)		(249	)
Tax on net operating income	(150	)	(59	)	169		(5	)		(45	)
Net operating income^(a)	45		(153	)	(377	)	(327	)		(812	)
Net cost of net debt										—
Minority interests and dividends on subsidiaries’ redeemable preferred shares										14
Net income from continuing operations Group share										(798	)
Net income from discontinued operations Group share										(19	)
Net income										(817	)

*	adjustments include special items, inventory valuation effect and equity share of amortization of intangible assets related to the Sanofi-Aventis merger.


(a) Of which inventory valuation effect
On operating income	—	(272	)	(42	)	—
On net operating income	—	(327	)	(28	)	—
(b) Of which equity share of amortization of intangible assets related to Sanofi-Aventis	—	—		—		(311	)


2006 (adjusted) (M€)	Upstream		Downstream		Chemicals		Corporate		Intercompany		Total
Non-Group sales	20,782		113,887		19,113		20		—		153,802
Intersegment sales	20,603		4,927		1,169		177		(26,876	)	—
Excise taxes	—		(21,113	)	—		—		—		(21,113	)
Revenues from sales	41,385		97,701		20,282		197		(26,876	)	132,689
Operating expenses	(17,759	)	(92,937	)	(18,548	)	(679	)	26,876		(103,047	)
Depreciation, depletion and amortization of tangible assets and leasehold rights	(3,319	)	(1,120	)	(519	)	(36	)	—		(4,994	)
Adjusted operating income	20,307		3,644		1,215		(518	)	—		24,648
Equity in income (loss) of affiliates and other items	1,016		206		29		1,092		—		2,343
Tax on net operating income	(12,614	)	(1,066	)	(360	)	211		—		(13,829	)
Adjusted net operating income	8,709		2,784		884		785		—		13,162
Net cost of net debt											(210	)
Minority interests and dividends on subsidiaries’ redeemable preferred shares											(381	)
Adjusted net income from continuing operations Group share											12,571
Adjusted net income from discontinued operations Group share											14
Adjusted net income											12,585

F-18


2006 (M€)	Upstream		Downstream		Chemicals		Corporate		Intercompany	Total
Total expenditures	9,001		1,775		995		81			11,852
Divestments at sale price	1,458		428		128		264			2,278
Cash flow from operating activities	11,524		3,626		972		(61	)		16,061

Balance Sheet as of December 31, 2006
Property, plant and equipment,	31,875		8,211		4,983		212			45,281
intangible assets, net
Investments in equity affiliates	2,153		1,922		713		7,010			11,798
Loans to equity affiliates and other non-current assets	2,744		1,065		477		585			4,871
Working capital	199		6,067		2,609		(78	)		8,797
Provisions and other non-current liabilities	(11,427	)	(2,093	)	(1,807	)	(1,052	)		(16,379	)
Capital Employed (Balance Sheet)	25,544		15,172		6,975		6,677			54,368
Less inventory valuation effect	—		(2,789	)	(231	)	738			(2,282	)
Capital Employed (Business segment information)	25,544		12,383		6,744		7,415			52,086
ROACE as a percentage (of continuting operations)	35%		23%		13%					26%


2005 (M€)	Upstream		Downstream		Chemicals		Corporate		Intercompany		Total
Non-Group sales	20,888		99,934		16,765		20		—		137,607
Intersegment sales	19,139		4,293		602		170		(24,204	)	—
Excise taxes	—		(20,550	)	—		—		—		(20,550	)
Revenues from sales	40,027		83,677		17,367		190		(24,204	)	117,057
Operating expenses	(18,275	)	(77,517	)	(15,669	)	(624	)	24,204		(87,881	)
Depreciation, depletion and amortization of tangible assets and leasehold rights	(3,331	)	(1,064	)	(579	)	(33	)	—		(5,007	)
Operating income	18,421		5,096		1,119		(467	)	—		24,169
Equity in income (loss) of affiliates and other items	587		422		(348	)	367		—		1,028
Tax on net operating income	(10,979	)	(1,570	)	(170	)	819		—		(11,900	)
Net operating income	8,029		3,948		601		719		—		13,297
Net cost of net debt											(193	)
Minority interests and dividends on subsidiaries’ redeemable preferred shares											(373	)
Net income from continuing operations Group share											12,731
Net income from discontinued operations Group share											(458	)
Net income											12,273

F-19


2005 (adjustments)^* (M€)	Upstream	Downstream		Chemicals		Corporate		Intercompany	Total
Non-Group sales
Intersegment sales
Excise taxes
Revenues from sales
Operating expenses^(a)	—	1,197		49		—			1,246
Depreciation, depletion and amortization of tangible assets and leasehold rights	—	—		(78	)	—			(78	)
Operating income	—	1,197		(29	)	—			1,168
Equity in income (loss) of affiliates and other items^(a)(b)	—	76		(386	)	(545	)		(855	)
Tax on net operating income	—	(241	)	49		590			398
Net operating income	—	1,032		(366	)	45			711
Net cost of net debt									—
Minority interests and dividends on subsidiaries’ redeemable preferred shares									(8	)
Net income from continuing operations Group share									703
Net income from discontinued operations Group share									(433	)
Net income									270

*	adjustments include special items, inventory valuation effect and equity share of amortization of intangible assets related to the Sanofi-Aventis merger.


(a) Of which inventory valuation effect
On operating income	—	1,197	68	—
On net operating income	—	1,032	50	—
(b) Of which equity share of amortization of intangible assets related to Sanofi-Aventis	—	—	—	(337	)


2005 (adjusted) (M€)	Upstream		Downstream		Chemicals		Corporate		Intercompany		Total
Non-Group sales	20,888		99,934		16,765		20		—		137,607
Intersegment sales	19,139		4,293		602		170		(24,204	)	—
Excise taxes	—		(20,550	)	—		—		—		(20,550	)
Revenues from sales	40,027		83,677		17,367		190		(24,204	)	117,057
Operating expenses	(18,275	)	(78,714	)	(15,718	)	(624	)	24,204		(89,127	)
Depreciation, depletion and amortization of tangible assets and leasehold rights	(3,331	)	(1,064	)	(501	)	(33	)	—		(4,929	)
Adjusted operating income	18,421		3,899		1,148		(467	)	—		23,001
Equity in income (loss) of affiliates and other items	587		346		38		912		—		1,883
Tax on net operating income	(10,979	)	(1,329	)	(219	)	229		—		(12,298	)
Adjusted net operating income	8,029		2,916		967		674		—		12,586
Net cost of net debt											(193	)
Minority interests and dividends on subsidiaries’ redeemable preferred shares											(365	)
Adjusted net income from continuing operations Group share											12,028
Adjusted net income from discontinued operations Group share											(25	)
Adjusted net income											12,003

F-20


2005 (M€)	Upstream		Downstream		Chemicals		Corporate		Intercompany	Total
Total expenditures	8,111		1,779		1,115		190			11,195
Divestments at sale price	692		204		59		133			1,088
Cash flow from operating activities	10,111		2,723		946		889			14,669
Balance Sheet as of December 31, 2005
Property, plant and equipment, intangible assets, net	30,140		8,016		6,567		229			44,952
Investments in equity affiliates	1,958		1,575		733		7,087			11,353
Loans to equity affiliates and other non-current assets	2,673		1,386		848		702			5,609
Working capital	(432	)	6,035		3,927		96			9,626
Provisions and other non-current liabilities	(10,817	)	(2,409	)	(2,827	)	(1,387	)		(17,440	)
Capital Employed (Balance Sheet)	23,522		14,603		9,248		6,727			54,100
Less inventory valuation effect	—		(3,182	)	(261	)	786			(2,657	)
Capital Employed (Business segment information)	23,522		11,421		8,987		7,513			51,443
ROACE as a percentage (of continuting operations)	40%		28%		15%					29%


2004 (M€)	Upstream		Downstream		Chemicals		Corporate		Intercompany		Total
Non-Group sales	15,037		86,896		14,886		23		—		116,842
Intersegment sales	14,208		2,836		466		183		(17,693	)	—
Excise taxes			(21,517	)					—		(21,517	)
Revenues from sales	29,245		68,215		15,352		206		(17,693	)	95,325
Operating expenses	(13,213	)	(63,524	)	(13,636	)	(524	)	17,693		(73,204	)
Depreciation, depletion and amortization of tangible assets and leasehold rights	(3,188	)	(1,053	)	(823	)	(31	)	—		(5,095	)
Operating income	12,844		3,638		893		(349	)	—		17,026
Equity in income (loss) of affiliates and other items	148		95		(170	)	3,477		—		3,550
Tax on net operating income	(7,281	)	(1,131	)	(73	)	(152	)	—		(8,637	)
Net operating income	5,711		2,602		650		2,976		—		11,939
Net cost of net debt											(92	)
Minority interests and dividends on subsidiaries’ redeemable preferred shares											(284	)
Net income from continuing operations Group share											11,563
Net income from discontinued operations Group share											(695	)
Net income											10,868

F-21


2004 (adjustments)^* (M€)	Upstream		Downstream		Chemicals		Corporate		Intercompany	Total
Non-Group sales
Intersegment sales
Excise taxes
Revenues from sales
Operating expenses^(a)	—		437		232		—			669
Depreciation, depletion and amortization of tangible assets and leasehold rights	—		(34	)	(299	)	—			(333	)
Operating income	—		403		(67	)	—			336
Equity in income (loss) of affiliates and other items^(a)(b)	(172	)	(3	)	(309	)	2,805			2,321
Tax on net operating income	24		(129	)	90		(392	)		(407	)
Net operating income	(148	)	271		(286	)	2,413			2,250
Net cost of net debt										—
Minority interests and dividends on subsidiaries’ redeemable preferred shares										(12	)
Net income from continuing operations Group share										2,238
Net income from discontinued operations Group share										(501	)
Net income										1,737

*	adjustments include special items, inventory valuation effect and equity share of amortization of intangible assets related to the Sanofi-Aventis merger.


(a) Of which inventory valuation effect
On operating income	—	487	232	—
On net operating income	—	349	157	—
(b) Of which equity share of amortization of intangible assets related to Sanofi-Aventis	—	—	—	(114	)

F-22


2004 (M€) (adjusted)	Upstream		Downstream		Chemicals		Corporate		Intercompany		Total
Non-Group sales	15,037		86,896		14,886		23		—		116,842
Intersegment sales	14,208		2,836		466		183		(17,693	)
Excise taxes	—		(21,517	)	—		—		—		(21,517	)
Revenues from sales	29,245		68,215		15,352		206		(17,693	)	95,325
Operating expenses	(13,213	)	(63,961	)	(13,868	)	(524	)	17,693		(73,873	)
Depreciation, depletion and amortization of tangible assets and leasehold rights	(3,188	)	(1,019	)	(524	)	(31	)	—		(4,762	)
Adjusted operating income	12,844		3,235		960		(349	)	—		16,690
Equity in income (loss) of affiliates and other
items	320		98		139		672		—		1,229
Tax on net operating income	(7,305	)	(1,002	)	(163	)	240		—		(8,230	)
Adjusted net operating income	5,859		2,331		936		563		—		9,689
Net cost of net debt											(92	)

Minority interests and dividends on subsidiaries’ redeemable preferred shares											(272	)
Adjusted net income from continuing operations Group share											9,325
Adjusted net income from discontinued operations Group share											(194	)
Adjusted net income											9,131

2004 (M€)	Upstream		Downstream		Chemicals		Corporate		Intercompany		Total
Total expenditures	6,202		1,675		949		78				8,904
Divestments at sale price	637		200		122		233				1,192
Cash flow from operating activities	10,347		3,269		600		446				14,662

Balance Sheet as of December 31, 2004
Property, plant and equipment, intangible assets, net	24,249		7,466		6,146		221				38,082
Investments in equity affiliates	1,455		1,347		589		6,412				9,803
Loans to equity affiliates and other non-current assets	1,865		1,064		791		706				4,426
Working capital	(1,665	)	3,870		3,436		142				5,783
Provisions and other non-current liabilities	(9,624	)	(2,347	)	(2,610	)	(1,702	)			(16,283	)
Capital Employed (Balance Sheet)	16,280		11,400		8,352		5,779				41,811
Less inventory valuation effect	—		(1,746	)	(199	)	404				(1,541	)
Capital Employed (Business segment information)	16,280		9,654		8,153		6,183				40,270
ROACE as a percentage (of continuing operations)	36%		25%		15%						26%

F-23

B. RECONCILATION BETWEEN BUSINESS SEGMENT INFORMATION AND THE CONSOLIDATED STATEMENT OF INCOME

The table below reconciles the information presented above with the consolidated statement of income:


2006 (M€)	Adjusted		Adjustment items*		Consolidated statement of income
Sales	153,802		—		153,802
Excise taxes	(21,113	)	—		(21,113	)
Revenues from sales	132,689		—		132,689
Purchases, net of inventory variation	(83,020	)	(314	)	(83,334	)
Other operating expenses	(19,393	)	(143	)	(19,536	)
Exploration costs	(634	)	—		(634	)
Depreciation, depletion and amortization of tangible assets and leasehold rights	(4,994	)	(61	)	(5,055	)
Operating income
Corporate	(518	)	(27	)	(545	)
Business segments	25,166		(491	)	24,675
Total operating income	24,648		(518	)	24,130
Other income	423		366		789
Other expense	(330	)	(373	)	(703	)
Financial interest on debt	(1,731	)	—		(1,731	)
Financial income from marketable securities & cash equivalents	1,367		—		1,367
Cost of net debt	(364	)	—		(364	)
Other financial income	592		—		592
Other financial expense	(277	)	—		(277	)
Income taxes	(13,675	)	(45	)	(13,720	)
Equity in income (loss) of affiliates	1,935		(242	)	1,693
Net income from continuing operations (Group without Arkema)	12,952		(812	)	12,140
Net income from discontinued operations (Arkema)	14		(19	)	(5	)
Consolidated net income	12,966		(831	)	12,135
Group share	12,585		(817	)	11,768
Minority interests	381		(14	)	367

*	Adjustments include special items, inventory valuation effect and equity share of amortization of intangible assets related to the Sanofi-Aventis merger.

F-24


2005 (M€)	Adjusted		Adjustment items*		Consolidated statement of income
Sales	137,607		—		137,607
Excise taxes	(20,550	)	—		(20,550	)
Revenues from sales	117,057		—		117,057
Purchases, net of inventory variation	(71,555	)	1,264		(70,291	)
Other operating expenses	(17,141	)	(18	)	(17,159	)
Unsuccessful exploration costs	(431	)	—		(431	)
Depreciation, depletion and amortization of tangible assets and leasehold rights	(4,929	)	(78	)	(5,007	)
Operating income
Corporate	(467	)	—		(467	)
Business segments	23,468		1,168		24,636
Total operating income	23,001		1,168		24,169
Other income	174		—		174
Other expense	(64	)	(391	)	(455	)
Financial interest on debt	(1,214	)	—		(1,214	)
Financial income from marketable securities & cash equivalents	927		—		927
Cost of net debt	(287	)	—		(287	)
Other financial income	396		—		396
Other financial expense	(260	)	—		(260	)
Income taxes	(12,204	)	398		(11,806	)
Equity in income (loss) of affiliates	1,637		(464	)	1,173
Net income from continuing operations (Group without Arkema)	12,393		711		13,104
Net income from discontinued operations (Arkema)	(28	)	(433	)	(461	)
Consolidated net income	12,365		278		12,643
Group share	12,003		270		12,273
Minority interests	362		8		370

*	Adjustments include special items, inventory valuation effect and equity share of amortization of intangible assets related to the Sanofi-Aventis merger.

F-25


2004 (M€)	Adjusted		Adjustment items*		Consolidated statement of income
Sales	116,842		—		116,842
Excise taxes	(21,517	)	—		(21,517	)
Revenues from sales	95,325		—		95,325
Purchases, net of inventory variation	(56,738	)	718		(56,020	)
Other operating expenses	(16,721	)	(49	)	(16,770	)
Exploration costs	(414	)	—		(414	)
Depreciation, depletion and amortization of tangible assets and leasehold rights	(4,762	)	(333	)	(5,095	)
Operating income
Corporate	(349	)	—		(349	)
Business segments	17,039		336		17,375
Total operating income	16,690		336		17,026
Other income	104		3,034		3,138
Other expense	(386	)	(450	)	(836	)
Financial interest on debt	(702	)	—		(702	)
Financial income from marketable securities & cash equivalents	572		—		572
Cost of net debt	(130	)	—		(130	)
Other financial income	321		—		321
Other financial expense	(227	)	—		(227	)
Income taxes	(8,196	)	(407	)	(8,603	)
Equity in income (loss) of affiliates	1,421		(263	)	1,158
Net income from continuing operations (Group without Arkema)	9,597		2,250		11,847
Net income from discontinued operations (Arkema)	(195	)	(503	)	(698	)
Consolidated net income	9,402		1,747		11,149
Group share and dividends on subsidiaries’ redeemable preferred share	9,131		1,737		10,868
Minority interests	271		10		281

*	Adjustments include special items, inventory valuation effect and equity share of amortization of intangible assets related to the Sanofi-Aventis merger.

C. ADJUSTMENT ITEMS BY BUSINESS SEGMENT

The adjustment items for income as per Note 2 to the Consolidated Financial Statements are detailed as follows:

Adjustments to operating income


2006 (M€)	Upstream	Downstream		Chemicals		Corporate		Total
Inventory valuation effect	—	(272	)	(42	)	—		(314	)
Restructuring charges	—	—		(25	)	—		(25	)
Asset impairment charges	—	—		(61	)	—		(61	)
Other	—	—		(91	)	(27	)	(118	)
Total	—	(272	)	(219	)	(27	)	(518	)

F-26

Adjustments to net income


2006 (M€)	Upstream		Downstream		Chemicals		Corporate		Total
Inventory valuation effect	—		(330	)	(28	)	—		(358	)
TOTAL’s equity share of special items recorded by
Sanofi-Aventis	—		—		—		(81	)	(81	)
Adjustment related to Sanofi-Aventis merger	—		—		—		(309	)	(309	)
Restructuring charges	—		—		(154	)	—		(154	)
Asset impairment charges	—		—		(40	)	—		(40	)
Gains/(Losses) on sales of assets	130		174		—		—		304
Other	(71	)			(172	)	64		(179	)
Total	59		(156	)	(394	)	(326	)	(817	)

Adjustments to operating income


2005 (M€)	Upstream	Downstream	Chemicals		Corporate	Total
Inventory valuation effect		1,197	68			1,265
Restructuring charges			(19	)		(19	)
Asset impairment charges			(71	)		(71	)
Other			(7	)		(7	)
Total	—	1,197	(29	)	—	1,168

Adjustments to net income


2005 (M€)	Upstream	Downstream	Chemicals		Corporate		Total
Inventory valuation effect	—	1,022	50				1,072
TOTAL’s equity share of special items recorded by
Sanofi-Aventis	—				(207	)	(207	)
Adjustment related to Sanofi-Aventis merger	—				(335	)	(335	)
Restructuring charges	—		(130	)			(130	)
Asset impairment charges	—		(215	)			(215	)
Gains/(Losses) on sales of assets	—						—
Other	—		(501	)	586		85
Total	—	1,022	(796	)	44		270

Adjustments to operating income


2004 (M€)	Upstream		Downstream		Chemicals		Corporate		Total
Inventory valuation effect	—		487		232		—		719
Restructuring charges	—		(50	)			—		(50	)
Asset impairment charges	—		(34	)	(244	)	—		(278	)
Other	—		—		(55	)	—		(55	)
Total	—		403		(67	)	—		336

Adjustments to net income
2004 (M€)	Upstream		Downstream		Chemicals		Corporate		Total
Inventory valuation effect	—		349		157		—		506
TOTAL’s equity share of special items recorded by Sanofi-Aventis (dilution income included)	—		—		—		2,399		2,399
Adjustment related to Sanofi-Aventis merger	—		—		—		(113	)	(113	)
Restructuring charges	—		(31	)	(112	)	—		(143	)
Asset impairment charges	(114	)	(21	)	(637	)	—		(772	)
Gains/(Losses) on sales of assets	—		—		—		53		53
Other	(34	)	(26	)	(197	)	64		(193	)
Total	(148	)	271		(789	)	2,403		1,737

F-27

D) ADDITIONAL INFORMATION ON IMPAIRMENTS

In the Chemicals segment, impairments of assets (property, plant and equipment and intangible assets) have been recognized for the year ended December 31, 2006, with an impact of 61 M€ in operating income and 40 M€ in net income, Group share. These items are identified in paragraph C of this Note as adjustment items under the heading “Asset impairment charges”.

These impairment losses impact certain Cash Generating Units (CGU) of the Chemicals segment for which there were indications that assets may be impaired, due mainly to changes in the economic environment of their specific businesses. CGUs of the Chemicals segment are worldwide business units, including activities or products with common strategic, commercial and industrial characteristics.

In addition,

•

the recoverable amount of CGUs has been based on their value in use, as defined in paragraph L of Note 1 to the Consolidated Financial Statements “Impairment of long-lived assets”; and

•

future cash flows including specific risks attached to CGU assets have been discounted using an 8% after-tax discount rate.

For the years ended December 31, 2005 and 2004, changes in the economic environment of certain business units of the Chemicals segment triggered the recognition of impairments of assets for, respectively, 71 M€ and 244 M€ in operating income and 215 M€ and 637 M€ in net income, Group share.

No reversal of impairment losses has been recognized in 2004, 2005 and 2006.

5. INFORMATION BY GEOGRAPHICAL AREA


(M€)	France	Rest of Europe	North America	Africa	Far East and rest of the world	Total
2006
Non-Group sales^*	36,890	70,992	13,031	10,086	22,803	153,802
Property, plant and equipment, intangible assets, net	5,860	14,066	4,318	10,595	10,442	45,281
Capital expenditures	1,919	2,355	881	3,326	3,371	11,852
2005
Non-Group sales^*	34,362	53,727	17,663	8,304	23,551	137,607
Property, plant and equipment, intangible assets, net	6,300	14,148	4,748	9,546	10,210	44,952
Capital expenditures	1,967	2,178	1,691	2,858	2,501	11,195
2004
Non-Group sales^*	29,888	45,523	16,765	6,114	18,552	116,842
Property, plant and equipment, intangible assets, net	5,724	13,859	3,096	7,322	8,081	38,082
Capital expenditures	2,125	2,060	762	2,004	1,953	8,904

*	Non-Group sales from continuing operations.

6. OPERATING EXPENSES


Year ended December 31, (M€)	2006		2005		2004
Purchases, net of inventory variation^(a)	(83,334	)	(70,291	)	(56,020	)
Exploration costs	(634	)	(431	)	(414	)
Other operating expenses^(b)	(19,536	)	(17,159	)	(16,770	)
Of which non-current operating liabilities (allowances) reversals	454		394		711
Of which current operating liabilities (allowances) reversals	(111	)	(51	)	(25	)
Operating expenses	(103,504	)	(87,881	)	(73,204	)

(a)

Includes royalties paid on oil and gas production in the Upstream segment (see in particular the taxes paid to Middle East oil producing countries for the Group’s concessions as detailed in Note 31 to the Consolidated Financial Statements “Other information”).

(b)

Principally composed of production and administrative costs (see in particular the payroll costs as detailed in Note 25 to the Consolidated Financial Statements “Payroll and staff”).

F-28

7. OTHER INCOME AND OTHER EXPENSE


As of December 31, (M€)	2006		2005		2004
Gain (loss) on sales of assets	789		98		3,138
Foreign exchange gains	—		76		—
Other income	789		174		3,138
Foreign exchange losses	(30	)	—		(75	)
Amortization of other intangible assets (excl. leasehold rights)	(182	)	(182	)	(375	)
Toulouse-AZF	(100	)	(100	)	(150	)
Other	(391	)	(173	)	(236	)
Other expense	(703	)	(455	)	(836	)

In 2006, gains and losses on sales of assets are mainly related to sales of financial assets. The “Other” heading is comprised of:

•

188 M€ of restructuring charges in the Chemicals segment;

•

32 M€ increase related to various antitrust investigations as described in the Note 30 to the Consolidated Financial Statement “Other risks and contingent liabilities”.

In 2004, the deterioration of the economic cycle generated impairment losses on intangible assets in the

Chemicals segment. As a consequence, an impairment loss of 118 M€ was recorded in 2004 to adjust the carrying amount of the intangible assets to their recoverable amount. The gains (losses) on sales of assets included a pre-tax dilution gain on the Sanofi-Aventis merger of 2,969 M€ in 2004. The “Other” heading mainly included early retirement plans and restructuring costs for 18 M€, and other allowances for various litigation reserves for 46 M€.

8. OTHER FINANCIAL INCOME AND EXPENSE


As of December 31, (M€)	2006		2005		2004
Dividend income on non-consolidated companies	237		164		154
Capitalized financial expenses	236		101		34
Other	119		131		133
Other financial income	592		396		321

Accretion of asset retirement obligation	(182	)	(162	)	(143	)
Other	(95	)	(98	)	(84	)
Other financial expense	(277	)	(260	)	(227	)

9. INCOME TAXES

Since 1966, the Group has been taxed in accordance with the consolidated income tax treatment approved on a renewable basis by the French Ministry of Economy, Finance and Industry. The renewal of the agreement has been granted for the period 2005-2007.

French income and foreign withholding taxes do not provide for the temporary differences between the financial statement carrying amount and tax bases of investments in foreign subsidiaries which are considered

to be permanent investments. Undistributed earnings of foreign subsidiaries considered to be reinvested indefinitely amounted to 21,717 M€ as of December 31, 2006. The determination of the tax effect relating to such reinvested income is not reliably feasible.

In addition, no provision for income taxes on unremitted earnings (approximately 8,491 M€) of the Group’s French subsidiaries has been made since the remittance of such earnings would be tax exempt for the subsidiaries in which the Company owns 95% or more of the outstanding shares.

F-29

Income taxes are detailed as follows:


As of December 31, (M€)	2006		2005		2004
Current income taxes	(12,997	)	(11,362	)	(7,641	)
Deferred income taxes	(723	)	(444	)	(962	)
Total income taxes	(13,720	)	(11,806	)	(8,603	)

Before netting deferred tax assets and liabilities by fiscal entities, the components of deferred tax balances as of December 31, 2005 and 2006 are as follows:


As of December 31, (M€)	2006		2005
Net operating losses and tax carry forwards	633		484
Employee benefits	830		949
Other temporarily non-deductible provisions	2,157		2,637
Gross deferred tax assets	3,620		4,070
Valuation allowance	(572	)	(536	)
Net deferred tax assets	3,048		3,534

Excess tax over book depreciation	(8,180	)	(7,769	)
Other temporary tax deductions	(1,237	)	(1,435	)
Gross deferred tax liability	(9,417	)	(9,204	)
Net deferred tax liability	(6,369	)	(5,670	)

After netting deferred tax assets and liabilities by fiscal entity, deferred taxes are presented on the balance sheet as follows:


As of December 31, (M€)	2006		2005
Deferred tax assets, non-current (Note 14 “Other non-current assets”)	806		1,392
Deferred tax assets, current (Note 16 “Accounts receivables & other current assets”)	94		126
Deferred tax liabilities, non-current (Deferred tax)	(7,139	)	(6,976	)
Deferred tax liabilities, current	(130	)	(212	)
Net amount	(6,369	)	(5,670	)

The net deferred tax variation in the balance sheet is analyzed as follows:


As of December 31, (M€)	2006		2005
Opening balance	(5,670	)	(5,100	)
Deferred tax on income for continuing operations	(723	)	(444	)
Deferred tax on income for discontinued operations	(10	)	53
Deferred tax on shareholders’ equity^(a)	(17	)	176
Consolidated scope changes^(b)	(311	)	29
Currency translation adjustment	362		(384	)
Closing balance	(6,369	)	(5,670	)

(a)

This amount includes mainly current income taxes and deferred taxes for transactions on treasury shares and for changes in fair value of listed securities classified as financial assets available for sale.

(b)

This amount includes mainly the impact of the spin-off of Arkema.

F-30

Reconciliation between provision for income taxes and pre-tax income (excluding Arkema):


As of December 31, (M€)	2006		2005		2004
Net income from continuing operations	12,140		13,103		11,847
Provision for income taxes	13,720		11,806		8,603
Pre-tax income	25,860		24,909		20,450
French statutory tax rate	34.43%		34.93%		35.43%
Theoretical tax charge	(8,904	)	(8,701	)	(7,245	)
Difference between French and foreign income tax rates	(5,484	)	(4,128	)	(2,740	)
Tax effect of equity in income (loss) of affiliates	583		410		410
Permanent differences	324		253		982
Adjustments on prior years income taxes	(87	)	(55	)	(44	)
Adjustments on deferred tax related to tax rates variations	(88	)	576		104
Change in valuation allowance	(62	)	(151	)	(71	)
Other	(2	)	(10	)	1
Net provision for income taxes	(13,720	)	(11,806	)	(8,603	)

The French statutory tax rate includes the standard corporate tax rate (33.33%) and additional taxes applicable that bring the overall tax rate to 34.43% in 2006 (34.93% in 2005).

Permanent differences are mainly due to impairment of goodwill and to dividends from non-consolidated companies as well as the specific taxation rules

applicable to some activities and within the consolidated income tax treatment.

Net operating losses and tax credit carryforwards:

Deferred tax assets related to net operating losses and tax carryforwards were available in various tax juridictions, expiring in the following years:


As of December 31, (M€)	2006		2005
	Basis	Tax	Basis	Tax
2006	—	—	225	106
2007	234	115	165	81
2008	210	102	144	70
2009	157	80	68	32
2010^(a)	299	104	27	11
2011 and after	23	9	—	—
Unlimited	638	223	559	184
Total	1,561	633	1,188	484

(a)

Net operating losses and tax credit carryforwards for 2010 and subsequent years related to fiscal 2005.

10. INTANGIBLE ASSETS


As of December 31, (M€)	2006				2005
	Cost	Depreciation and amortization		Net	Cost	Depreciation and amortization		Net
Goodwill	1,759	(635	)	1,124	2,479	(1,318	)	1,161
Proved and unproved leasehold rights	5,457	(2,473	)	2,984	5,213	(2,659	)	2,554
Other intangible assets	2,377	(1,780	)	597	2,684	(2,015	)	669
Total intangible assets	9,593	(4,888	)	4,705	10,376	(5,992	)	4,384

F-31


(M€)	Net intangible assets as of January 1	Acquisitions	Disposals		Net depreciation and amortization of intangible assets		Currency translation adjustment		Other	Net intangible assets as of December 31
2006	4,384	675	(25	)	(282	)	(337	)	290	4,705
2005	3,176	274	(91	)	(370	)	296		1,099	4,384

In 2005, the heading “Other” includes mainly the impact of mineral rights of Deer Creek Energy Ltd for 1,015 M€ (see Note 3 to the Consolidated Financial Statements).

A summary of changes in the carrying amount of goodwill by business segment for the year ended December 31, 2006 is as follows:


(M€)	Net goodwill as of January 1, 2006	Increases	Impairments	Other		Net goodwill as of December 31, 2006
Upstream	96	—	—	(1	)	95
Downstream	123	19	—	(4	)	138
Chemicals	917	84	—	(135	)	866
Holding	25	—	—	—		25
Total	1,161	103	—	(140	)	1,124

11. PROPERTY, PLANT AND EQUIPMENT


As of December 31, (M€)	2006				2005
	Cost	Depreciation and amortization		Net	Cost	Depreciation and amortization		Net
Upstream properties
Proved properties	60,063	(39,211	)	20,852	58,980	(38,646	)	20,334
Unproved properties	20	(1	)	19	8	(1	)	7
Work in progress	7,080	(22	)	7,058	6,136	(29	)	6,107
Subtotal	67,163	(39,234	)	27,929	65,124	(38,676	)	26,448
Other property, plant and equipment
Land and preparation costs	1,550	(445	)	1,105	1,646	(392	)	1,254
Machinery, plant and equipment (including transportation equipment)	20,724	(14,131	)	6,593	23,533	(16,699	)	6,834
Buildings	5,392	(3,289	)	2,103	6,444	(4,070	)	2,374
Construction in progress	1,228	(14	)	1,214	1,482	(31	)	1,451
Other	6,154	(4,522	)	1,632	7,805	(5,598	)	2,207
Subtotal	35,048	(22,401	)	12,647	40,910	(26,790	)	14,120
Total property, plant and equipment	102,211	(61,635	)	40,576	106,034	(65,466	)	40,568


(M€)	Net tangible assets as of January 1	Acquisitions	Disposals		Net depreciation and amortization of tangible assets		Currency translation adjustment		Other		Net tangible assets as of December 31
2006	40,568	9,209	(175	)	(5,010	)	(2,373	)	(1,643	)	40,576
2005	34,906	8,208	(336	)	(5,282	)	3,013		59		40,568

As of December 31, 2006, the “Other” heading includes mainly the impact of the spin-off of Arkema for 1,310 M€.

F-32

Property, plant and equipment presented above include the following amounts for facilities and equipment under finance leases that have been capitalized:


As of December 31, (M€)	2006				2005
	Cost	Depreciation and amortization		Net	Cost	Depreciation and amortization		Net
Machinery, plant, and equipment	518	(244	)	274	491	(212	)	279
Buildings	40	(27	)	13	26	(18	)	8
Development works	—	—		—	—	—		—
Total	558	(271	)	287	517	(230	)	287

12. EQUITY AFFILIATES: INVESTMENTS AND LOANS


(M€)	As of December 31,
	2006 % owned		2005 % owned		2006 equity value	2005 equity value	2006 equity in income (loss)		2005 equity in income (loss)		2004 equity in income (loss)
NLNG	15.00	%	15.00	%	887	726	329		190		158
CEPSA (Upstream share)	48.83	%	45.28	%	253	311	104		99		75
Qatargas	10.00	%	10.00	%	186	156	119		46		42
Gasoducto Gasandes Argentina	56.50	%	56.50	%	115	132	7		7		6
SCP Limited	10.00	%	10.00	%	100	89	—		—		—
Ocensa	15.20	%	15.20	%	64	71	—		—		—
Société du Terminal Méthanier De Fos Cavaou^(c)	30.30	%	—		63	—	(4	)	—		—
Moattama Gas Transportation Cy	31.24	%	31.24	%	61	64	63		45		40
Hidroneuquen Piedra del Aguila^(a)	—		41.30	%	—	61	—		4		41
Total Tractebel Emirates Power Company	50.00	%	50.00	%	61	55	3		3		4
Qatar Liquefied Gas Company Limited^(c)	8.35	%	—		55	—	—		—		—
Abu Dhabi Gas Ind, Ltd	15.00	%	15.00	%	48	54	—		—		—
Gas Invest SA	27.24	%	27.24	%	53	47	12		(3	)	(59	)
Gasoducto Gasandes sa (Chili)	56.50	%	56.50	%	39	40	—		—		2
Humber Power Ltd^(a)	—		—		—	—	—		16		24
CFMH^(a)	—		—		—	—	—		—		35
Other	—		—		168	145	13		28		35
Total Upstream					2,153	1,951	646		435		403
CEPSA (Downstream share)	48.83	%	45.28	%	1,735	1,372	246		321		211
Wepec^(b)	22.41	%	22.41	%	62	74	1		11		—
Other	—		—		125	129	26		24		15
Total Downstream					1,922	1,575	273		356		226
CEPSA (Chemicals share)	48.83	%	45.28	%	503	431	26		39		29
Qatar Petrochemical Company Ltd	20.00	%	20.00	%	147	141	45		39		32
Other	—		—		63	161	—		4		9
Total Chemicals					713	733	71		82		70
Sanofi-Aventis	13.13	%	13.19	%	7,010	7,087	556		299		459
CEPSA (Holding share)	48.83	%	45.28	%	—	—	147		—		—
Other	—		—		—	7	—		1		—
Total Holding					7,010	7,094	703		300		459
Total investments					11,798	11,353	1,693		1,173		1,158
Loans					1,533	1,299
Total investments and loans					13,331	12,652

(a)

Investment disposed of in 2005 and 2006.

(b)

Investment accounted for under the equity method beginning in 2005.

(c)

New acquisitions 2006.

F-33

The market value of the Group’s share in CEPSA amounted to 7,762 M€ as of December 31, 2006. The market value of the Group’s share in Sanofi-Aventis amounted to 12,485 M€ as of December 31, 2006.


CEPSA
Condensed Balance Sheet as of December 31, 2006 (M€)
Non-current assets	4,465	Shareholders’ equity	4,838
Current assets	4,259	Non-current liabilities	1,356
		Current liabilities	2,530
Total	8,724	Total	8,724

Income Statement Information as of December 31, 2006 (M€)
Revenues			18,473
Consolidated net income, Group share			812


Sanofi-Aventis
Condensed Balance Sheet as of December 31, 2006 (M€)
Non-current assets	65,603	Shareholders’ equity	45,820
Current assets	12,160	Non-current liabilities	21,665
		Current liabilities	10,278
Total	77,763	Total	77,763

Income Statement information as of December 31, 2006 (M€)
Revenues			28,373
Consolidated net income, Group share			4,006

13. OTHER INVESTMENTS


As of December 31, (M€)	2006			2005
	Carrying amount	Unrealized gain (loss)	Balance sheet value	Carrying amount	Unrealized gain (loss)	Balance sheet value
I.C.E. (Inter Continental Exchange)^(a)	—	—	—	1	138	139
Santander Central Hispano (SCH)^(a)	—	—	—	93	88	181
Areva	69	135	204	69	79	148
Arkema	16	8 2	98	—	—	—
Other publicly traded equity securities	1	1	2	1	—	1
Total publicly traded equity securities^(b)	86	218	304	164	305	469
BBPP	80	—	80	89		89
Oman LNG LLC	6	—	6	7		7
BTC Limited	185	—	185	177		177
Other equity securities	675	—	675	774		774
Total other equity securities^(b)	946	—	946	1,047	—	1,047
Other investments	1,032	218	1,250	1,211	305	1,516

(a)

Shares sold in 2006.

(b)

Including impairments of 668 M€ in 2006 and 820 M€ in 2005.

These investments are recognized under “Financial assets available for sale” (see paragraph M of Note 1 to the Consolidated Financial Statements).

F-34

14. OTHER NON-CURRENT ASSETS


As of December 31, (M€)	2006				2005
	Gross value	Valuation allowance		Net value	Gross value	Valuation allowance		Net value
Deferred income tax assets	806	—		806	1,392	—		1,392
Loans and advances^(a)	1,513	(488	)	1,025	1,786	(584	)	1,202
Other	257	—		257	200	—		200
Total	2,576	(488	)	2,088	3,378	(584	)	2,794

(a)	Excluding loans to equity affiliates.

15. INVENTORIES


As of December 31, (M€)	2006				2005
	Gross value	Valuation allowance		Net value	Gross value	Valuation allowance		Net value
Crude oil and natural gas	4,038	(90	)	3,948	3,619	—		3,619
Refined products	5,373	(44	)	5,329	5,584	(14	)	5,570
Chemical products	1,544	(90	)	1,454	2,803	(175	)	2,628
Other inventories	1,231	(216	)	1,015	1,097	(224	)	873
Total	12,186	(440	)	11,746	13,103	(413	)	12,690

16. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS


As of December 31, (M€)	2006				2005
	Gross value	Valuation allowance		Net value	Gross value	Valuation allowance		Net value
Accounts receivable	17,882	(489	)	17,393	20,174	(562	)	19,612
Other receivables	1,878	—		1,878	1,534	—		1,534
Recoverable taxes	2,098	—		2,098	2,119	—		2,119
Deferred income tax	94	—		94	126	—		126
Prepaid expenses	745	—		745	799	—		799
Other current assets	2,471	(39	)	2,432	2,284	(63	)	2,221
Other current assets	7,286	(39	)	7,247	6,862	(63	)	6,799

17. SHAREHOLDERS’ EQUITY

NUMBER OF TOTAL SHARES

The Company’s common shares, par value €2.50 per share as of December 31, 2006, are the only category of shares. Following the decision of the shareholders’ meeting held on May 12, 2006, through the 15^th resolution, a four-for-one stock split took place on May 18, 2006. Shares may be held in either bearer or registered form.

Double voting rights are granted to holders of shares that are fully-paid and held in the name of the same shareholder for at least two years. Double voting rights are also assigned to restricted shares in the event of an increase in share capital by incorporation of reserves,

profits or premiums based on shares already held that are entitled to double voting rights.

Pursuant to the Company’s by-laws (statuts) no shareholder may cast a vote at a shareholders’ meeting, either by himself or through an agent, representing more than 10% of the total voting rights for the Company’s shares. This limit applies to the aggregated amount of voting rights held directly, indirectly or through voting proxies. However, in the case of double voting rights, this limit may be extended to 20%.

These restrictions no longer apply if any individual or entity, acting alone or in concert, acquires at least two-thirds of the total share capital of the Company following a public tender offer for all of the Company’s shares.

F-35

The authorized capital amounts to 4,081,629,794 shares as of December 31, 2006 against 1,034,280,640 as of December 31, 2005 and 1,069,761,134 as of December 31, 2004 (or respectively 4,137,122,560 and 4,279,044,536 pursuant to the four-for-one split of the shares of May 18, 2006).


		Historical figures		Restated historical figures⁽⁵⁾
As of January 1, 2004		649,118,236		2,596,472,944
Shares issued in connection with:	Capital increase reserved for employees	3,434,830		13,739,320
	Exercise of TOTAL share subscription options	950		3,800
	Exchange guarantee offered to the beneficiaries of Elf Aquitaine share subscription options	2,335,024		9,340,096
Cancellation of shares^(a)		(19,873,932	)	(79,495,728	)
As of January 1, 2005		635,015,108		2,540,060,432
Shares issued in connection with:	Exercise of TOTAL share subscription options	133,257		533,028
	Exchange guarantee offered to the beneficiaries of Elf Aquitaine share subscription options	1,043,499		4,173,996
Cancellation of shares^(b)		(21,075,568	)	(84,302,272	)
As of January 1, 2006		615,116,296		2,460,465,184
Shares issued in connection with:	Four-for-one split of shares par value	1,845,348,888		—
	Capital increase reserved for employees	11,141,320		11,141,320
	Exercise of TOTAL share subscription options	849,319		849,319
	Exchange guarantee offered to the beneficiaries of Elf Aquitaine share subscription options	332,130		332,130
Cancellation of shares^(c)		(47,020,000	)	(47,020,000	)
As of December 31, 2006^(d)		2,425,767,953		2,425,767,953

(a)

Decided by the Board of Directors on November 9, 2004.

(b)

Decided by the Board of Directors on July 19, 2005 and November 3, 2005.

(c)

Decided by the Board of Directors on July 18, 2006.

(d)

Including 161,200,707 treasury shares deducted from consolidated shareholders’ equity.

(e)

Historical figures are restated to reflect the four-for-one split of the shares on May 18, 2006.

The variation of the weighted-average number of diluted shares used in the calculation of earnings per share is detailed as follows:


	2006
Number of shares as of January 1,^(a)	2,460,465,184
Number of shares issued during the year (pro rated)
Exercise of TOTAL share subscription options	304,461
Exercise of TOTAL share purchase options	3,756,803
Exchange guarantee offered to the beneficiaries of Elf Aquitaine share subscription options	169,146
Capital increase reserved for employees	9,284,433
TOTAL shares held by TOTAL S.A. or by its subsidiaries and deducted from shareholders’ equity	(180,916,837	)
Weighted-average number of shares	2,293,063,190
Dilutive effect
TOTAL share subscription and purchase options	14,758,984
TOTAL restricted shares	3,218,410
Exchange guarantee offered to the beneficiaries of Elf Aquitaine share subscription options	833,908
Capital increase reserved for employees	430,160
Weighted-average number of diluted shares	2,312,304,652

(a)

Historical figures are restated as per the four-for-one split of the shares of May 18, 2006.

F-36

CAPITAL INCREASE RESERVED FOR GROUP EMPLOYEES

At the shareholders’ meeting held on May 17, 2005, the shareholders delegated to the Board of Directors the authority to increase the share capital of the Company in one or more transactions and within a maximum period of 26 months from the date of the meeting, by an amount not exceeding 1.5% of the share capital outstanding on the date of the meeting of the Board of Directors at which a decision to proceed with an issuance is made reserving subscriptions for such issuance to the Group employees participating in a company savings plan. It is being specified that the amount of any such capital increase reserved for Group employees will be counted against the aggregate maximum nominal amount of share capital increases authorized by the shareholders’ meeting held on May 17, 2005 for issuing new ordinary shares or other securities granting immediate or future access to the Company’s share capital with preferential subscription rights (4 B€ in nominal value).

Pursuant to this delegation of authorization, the Board of Directors, during its November 3, 2005 meeting, implemented a first capital increase reserved for employees within the limit of 3 million shares with a par value of €10 per share (or 12 million shares with a par value of €2.50 per share), at a price of €166.60 per share with a par value of €10 (or € 41.65 per share with a par value of €2.50), with dividend rights as of January 1, 2005. The subscription period ran from February 6, 2006 to February 24, 2006, and 2,785,330 shares with a par value of €10 per share (or 11,141,320 shares with a par value of €2.50 per share), were subscribed within the framework of this capital increase.

SHARE CANCELLATION

Pursuant to the authorization granted by the shareholders’ meeting held on May 7, 2002 authorizing reduction of capital by cancellation of shares held by the Company within the limit of 10% of the outstanding capital every twenty-four months, the Board of Directors decided on July 18, 2006 to cancel 47,020,000 shares with a par value of €2.50 per share, at an average price of €52.31 per share.

TREASURY SHARES (TOTAL SHARES HELD BY TOTAL S.A.)

As of December 31, 2006, TOTAL S.A held 60,869,439 of its own shares, representing 2.51% of its share capital, detailed as follows:

•

23,272,755 shares allocated to covering TOTAL share purchase option plans for Group employees;

•

4,591,684 shares allocated to TOTAL restricted share plans for Group employees; and

•

33,005,000 shares purchased for cancellation between July and December 2006 pursuant to the authorization granted by the shareholders’ meeting held on May 12, 2006. The Board of Directors held on January 10, 2007 decided to cancel these 33,005,000 shares at an average price of €52.52 per share.

These shares are deducted from the consolidated shareholders’ equity.

TOTAL SHARES HELD BY THE GROUP SUBSIDIARIES

As of December 31, 2006, TOTAL S.A. held indirectly through its subsidiaries 100,331,268 of its own shares, representing 4.14% of its share capital, detailed as follows:

•

2,023,672 shares held by a consolidated subsidiary, Total Nucléaire, 100% indirectly owned by TOTAL S.A.;

•

98,307,596 shares held by subsidiaries of Elf Aquitaine (Financière Valorgest, Sogapar and Fingestval)

These shares are deducted from the consolidated shareholders’ equity.

DIVIDEND PER SHARE

During the year 2006, TOTAL S.A. paid on May 18, 2006, the balance of the dividend of €3.48 per share, par value of €10 per share, or €0.87 per share, par value €2.50 per share for the fiscal year 2005, as well as on November 17, 2006, an interim dividend of €0.87 per share, par value of €2.50 per share, for the fiscal year 2006.

A resolution will be submitted at the shareholders’ meeting of May 11, 2007 to pay a dividend of €1.87 per share, par value of €2.50 for the fiscal year 2006, which leaves a balance to be paid of €1.00 per share after deduction of the interim dividend of €0.87 paid on November 17, 2006.

PAID-IN SURPLUS

In accordance with French law, the paid-in surplus corresponds to share premiums of the parent company which can be capitalized or used to offset losses if the legal reserve has reached its minimum required level. The amount of the paid-in surplus may also be distributed subject to taxation unless the unrestricted reserves of the parent company are distributed prior to or simultaneously with this item.

As of December 31, 2006, the paid-in surplus was 31,156 M€ (34,563 M€ as of December 31, 2005).

F-37

RESERVES

Under French laws, 5% of net income must be transferred to the legal reserve until the legal reserve reaches 10% of the nominal value of the share capital. This reserve cannot be distributed to the shareholders other than upon liquidation but can be used to offset losses.

If wholly distributed, the unrestricted reserves of the parent company would be taxed for an approximate amount of 70 M€ as of December 31, 2006 (70 M€ as of December 31, 2005).

ITEMS RECOGNIZED DIRECTLY IN EQUITY

Shareholders’ equity was directly credited with (2,676) M€ in 2006 due to the following items:


Amounts (M€)	2006		2005
Cumulative translation adjustment, Group share	(2,595	)	2,850
Changes in deferred taxes on treasury shares	—		242
Changes in fair value of financial assets available for sale	(61	)	160
Other	24		16
Group share	(2,632	)	3,268
Minority interests and preferred shares	(44	)	51
Total items recognized directly in equity	(2,676	)	3,319

18. EMPLOYEE BENEFITS OBLIGATIONS

Provisions for employee benefits obligations consist of the following:


As of December 31, (M€)	2006	2005
Pension benefits liabilities	1,918	2,524
Other benefits liabilities	647	718
Restructuring reserves (early retirement plans)	208	171
Total	2,773	3,413

F-38

The fair value of the defined benefit obligation and plan assets in the consolidated financial statements is detailed as follows:


	Pension benefits				Other benefits
As of December 31, (M€)	2006		2005		2006		2005

Change in benefit obligation
Benefit obligation at beginning of year	9,647		8,117		774		675
Service cost	174		168		11		14
Interest cost	392		411		30		36
Curtailments	(6	)	—		(1	)	—
Settlements	(243	)	(14	)	—		—
Special termination benefits	—		—		—		—
Plan participants’ contributions	11		15		—		—
Benefits paid	(444	)	(436	)	(36	)	(48	)
Plan amendments	17		139		7		2
Actuarial losses (gains)	(151	)	1,003		(21	)	57
Translation adjustement and other^(a)	(655	)	244		(116	)	38
Benefit obligation at year-end	8,742		9,647		648		774

Change in fair value of plan assets
Fair value of plan assets at beginning of year	(6,274	)	(5,362	)	—		—
Expected return on plan assets	(353	)	(356	)	—		—
Actuarial losses (gains)	(104	)	(364	)	—
Settlements	201		12		—		—
Plan participants’ contributions	(11	)	(15	)	—		—
Employer contributions^(b)	(617	)	(323	)	—		—
Benefits paid	327		337		—		—
Foreign currency translation and other^(c)	430		(203	)	—		—
Fair value of plan assets at year-end	(6,401	)	(6,274	)	—		—

Unfunded status	2,341		3,373		648		774
Unrecognized prior service cost	(149	)	(171	)	23		35
Unrecognized actuarial (losses) gains	(423	)	(777	)	(24	)	(91	)
As set ceiling	4		5		—		—
Net recognized amount	1,773		2,430		647		718
Accrued benefit cost	1,918		2,524		647		718
Prepaid benefit cost	(145	)	(94	)	—		—

(a)

In 2006, the change in foreign currency translation and other includes the spin-off of Arkema which amounts to (587) and (107) M€ of benefit obligation for pension benefits and other pension benefits, respectively.

(b)	In 2006, the Group covered certain employee pension benefit plans through insurance companies for an amount of 269 M€.

(c)

In 2006, the change in foreign currency translation and other includes the spin-off of Arkema which amounts to 375 M€ of fair value of plan assets.

As of December 31, 2006, the present value of pension benefits and other benefits which are entirely or partially funded amounted to 7,358 M€ and the present value of the unfunded benefits amounted to 2,032 M€ (respectively 8,046 M€ and 2,375 M€ as of December 31, 2005).


As of December 31, (M€)	2006		2005		2004
Pension benefits
Benefit obligation	8,742		9,647		8,117
Fair value of plan assets	(6,401	)	(6,274	)	(5,362	)
Unfunded status	2,341		3,373		2,755
Other benefits
Benefit obligation	648		774		675
Fair value of plan assets	—		—		—
Unfunded status	648		774		675

F-39

The Group expects to contribute 324 M€ to its pension plans in 2007.


Estimated future payments (M€)	Pension benefits	Other benefits
2007	433	39
2008	449	35
2009	454	36
2010	471	35
2011	484	36
2012-2016	2,597	183


Asset allocation	Pension benefits
As of December 31, (M€)	2006	2005
Equity securities	42%	46%
Debt securities	48%	48%
Monetary	6%	3%
Real estate	4%	3%

The Group’s assumptions for expected returns on assets are built up by asset class and by country based on long-term bond yields and risk premiums.


Assumptions used to determine benefits obligations	Pension benefits		Other benefits
As of December 31, (M€)	2006	2005	2006	2005
Discount rate	4.69%	4.51%	4.89%	4.56%
Average expected rate of salary increase	4.14%	3.63%	—	—
Expected rate of healthcare inflation
- Initial rate	—	—	5.57%	5.41%
- Ultimate rate	—	—	3.65%	4.00%


Assumptions used to determine the net periodic benefit cost (income)	Pension benefits			Other benefits
As of December 31, (M€)	2006	2005	2004	2006	2005	2004
Discount rate	4.51%	5.12%	5.41%	4.56%	5.28%	5.83%
Average expected rate of salary increase	3.63%	3.66%	3.74%	—	—	—
Expected return on plan assets	6.14%	6.57%	6.96%	—	—	—
Expected rate of healthcare inflation
- Initial rate	—	—	—	5.41%	5.70%	6.37%
- Ultimate rate	—	—	—	4.00%	4.15%	3.83%

The components of the net periodic benefit cost (income) in 2006 and 2005 are:


	Pension benefits						Other benefits
As of December 31, (M€)	2006		2005		2004		2006		2005		2004
Service cost	174		168		141		11		14		10
Interest cost	392		411		414		30		36		31
Expected return on plan assets	(353	)	(356	)	(348	)	—		—		—
Amortization of transition obligation (asset)	—		—		—		—		—		—
Amortization of prior service cost	41		64		29		(2	)	(6	)	55
Amortization of actuarial losses (gains)	26		—		14		(2	)	2		—
Asset ceiling	—		5		—		—		—		—
Curtailments	(4	)	—		—		(1	)	—		—
Settlements	(15	)	(3	)	39		—		—		—
Special termination benefits	—		—		10		—		—		—
Net periodic benefit cost (income)	261		289		299		36		46		96
Net periodic benefit cost (income) from continuing operations (Group without Arkema)	256		233		215		35		40		85
Net periodic benefit cost (income) from discontinued operations (Arkema)	5		56		84		1		6		11

F-40

The assumptions for changes in healthcare costs have a significant impact on the valuations of commitments for coverage of medical expenses. A positive or negative change of one-percentage-point in the healthcare inflation rate would have approximately the following impact:


(M€)	1% point increase	1% point decrease
Benefit obligation as of December 31, 2006	65	(54)
Net periodic benefit cost (income)	5	(4)

19. OTHER NON-CURRENT LIABILITIES


As of December 31, (M€)	2006	2005
Litigations and accrued penalty claims	497	839
Provisions for environmental contingencies	574	768
Asset retirement obligations	3,893	3,710
Other non-current liabilities	1,215	1,421
Deposits received	288	313
Total	6,467	7,051

In 2006, other non-current liabilities included namely:

•

the contingency reserve related to the Toulouse-AZF plant explosion (civil liability) for 176 M€ as of December 31, 2006;

•

provisions related to restructuring activities in the Chemicals segment for 72 M€ as of December 31, 2006.

In 2005, the other non-current liabilities included namely:

•

the contingency reserve related to the Toulouse-AZF plant explosion (civil liability) for 133 M€ as of December 31, 2005;

•

provisions related to restructuring activities in the Chemicals segment for 171 M€ as of December 31, 2005.

VARIATION IN OTHER NON-CURRENT LIABILITIES (M€)


	As of January 1,	Allowances	Reversals		Currency translation adjustment		Other		As of December 31,
2006	7,051	884	(821	)	(273	)	(374	)	6,467
2005	6,274	1,347	(1,025	)	375		80		7,051

In 2006, allowances of the period (884 M€) included mainly:

•

an additional allowance of the contingency reserve related to the Toulouse-AZF plant explosion (civil liability), for 100 M€;

•

environmental contingencies in the Chemicals segment for 96 M€;

•

provisions related to restructuring of activities in the Chemicals segment for 88 M€;

•

an allowance of 32 M€ for litigation reserves in connection with antitrust investigations, as described in Note 30 to the Consolidated Financial Statements “Other risks and contingent liabilities”.

In 2005, allowances of the period (1,347 M€) included mainly:

•

an additional allowance of the contingency reserve related to the Toulouse-AZF plant explosion (civil liability), for 100 M€;

•

environmental contingencies in the Chemicals segment for 283 M€;

•

provisions related to restructuring of activities in the Chemicals segment for 107 M€;

•

an allowance of 292 M€ for litigation reserves in connection with antitrust investigations, as described in Note 30 to the Consolidated Financial Statements “Other risks and contingent liabilities”.

In 2006, the main reversals of the period (821 M€) were related to the incurred expenses which included notably:

•

the contingency reserve related to the Toulouse-AZF plant explosion (civil liability), written back for 57 M€;

•

provisions for restructuring and social plans written back for 43 M€;

•

environmental contingencies in the Chemicals segment written back for 56 M€.

In 2005, the main reversals of the period (1,025 M€) were related to the incurred expenses which included notably:

•

the contingency reserve related to the Toulouse-AZF plant explosion (civil liability), written back for 77 M€;

•

provisions for restructuring and early retirement plans written back for 106 M€;

•

environmental contingencies in the Chemicals segment written back for 197 M€.

F-41

VARIATION OF THE ASSET RETIREMENT OBLIGATION (M€)


	As of January 1,	Accretion	Revision in estimates	New obligations	Spending on existing obligations		Currency translation adjustment		Other	As of December 31,
2006	3,710	182	66	274	(174	)	(191	)	26	3,893
2005	3,334	162	51	86	(202	)	250		29	3,710

20. FINANCIAL DEBT AND RELATED FINANCIAL INSTRUMENTS

A. NON-CURRENT FINANCIAL DEBT AND RELATED FINANCIAL INSTRUMENTS


	2006					2005
As of December 31, (M€)	Secured	Unsecured		Total		Secured	Unsecured		Total
(Assets)/Liabilities

Non-current financial debt	771	13,403		14,174		490	13,303		13,793
of which hedging instruments of non-current financial debt (liabilities)^(a)	—	193		193		—	128		128
Hedging instruments of non-current financial debt (Assets)^(a)	—	(486	)	(486	)	—	(477	)	(477	)
Non-current financial debt - net of hedging instruments	771	12,917		13,688		490	12,826		13,316

Debenture loans, net of hedging instruments	—	11,120		11,120		—	10,703		10,703
Bank and other, floating rate	398	1,589		1,987		105	1,715		1,820
Bank and other, fixed rate	2	208		210		3	408		411
Financial lease obligations	371	—		371		382	—		382
Non-current financial debt - net of hedging instruments	771	12,917		13,688		490	12,826		13,316

(a)	See the description of these hedging instruments (paragraph M(iii) “Long-term financing” of Note 1 to the Consolidated Financial Statements).

Fair value of debenture loans, as of December 31, 2006, after taking into account hedged currency and interest rates swaps, can be detailed as follows (as the effect of the Group’s credit risk is not material, it has not been taken into account in the calculation of fair value):



(M€)	Year of issue	Fair value after hedging as of December 31, 2005		Fair value after hedging as of December 31, 2006		Currency	Maturity	Initial rate before hedging instruments
Parent company
Bond	1996	166		—		FRF	2006	6.900%
Bond	1996	404		362		FRF	2008	6.750%
Bond	1997	83		75		FRF	2007	5.030%
Bond	1997	70		63		ESP	2007	6.800%
Bond	1997	146		126		FRF	2009	6.200%
Bond	1998	32		29		FRF	2008	PIBOR 3 months + 0.380%
Bond	1998	141		132		FRF	2009	5.125%
Bond	1998	142		128		FRF	2013	5.000%
Bond	1999	275		—		EUR	2006	3.875%
Bond	2000	107		—		CHF	2006	3.500%
Bond	2000	75		68		EUR	2010	5.650%
Current (less than one year)		(548	)	(138	)
Total parent company		1,093		845

Elf Aquitaine SA
Bond 1999		998		996		EUR	2009	4.500%
Current portion (less than one year)		—		—
Total Elf Aquitaine SA		998		996

F-42


(M€)	Year of issue	Fair value after hedging as of December 31, 2005	Fair value after hedging as of December 31, 2006	Currency	Maturity	Initial rate before hedging instruments
TOTAL CAPITAL
Bond	2002	309	276	CHF	2007	3.000%
Bond	2002	64	57	USD	2007	4.740%
Bond	2002	255	228	USD	2007	5.125%
Bond	2002	18	15	USD	2012	5.890%
Bond	2002	204	183	CHF	2007	3.000%
Bond	2002	213	190	USD	2007	4.750%
Bond	2002	43	38	USD	2007	LIBOR USD 3 months +0.060%
Bond	2002	43	38	USD	2007	LIBOR USD 3 months + 0.0650%
Bond	2002	195	174	GBP	2007	5.000%
Bond	2002	113	101	CHF	2007	2.500%
Bond	2002	101	90	GBP	2007	5.000%
Bond	2003	69	61	GBP	2007	5.000%
Bond	2003	52	43	AUD	2008	5.000%
Bond	2003	450	402	EUR	2008	3.500%
Bond	2003	56	50	CAD	2008	4.250%
Bond	2003	26	23	USD	2013	4.500%
Bond	2003	212	190	USD	2008	3.250%
Bond	2003	49	46	AUD	2008	5.000%
Bond	2003	91	81	EUR	2008	3.500%
Bond	2003	142	127	EUR	2008	3.500%
Bond	2003	185	165	CHF	2008	2.010%
Bond	2003	181	162	CHF	2009	2.385%
Bond	2003	123	110	CHF	2008	2.010%
Bond	2003	61	55	AUD	2009	6.250%
Bond	2003-2004	467	418	USD	2009	3.500%
Bond	2003	196	175	CHF	2010	2.375%
Bond	2004	395	353	GBP	2010	4.875%
Bond	2004	138	123	CHF	2010	2.385%
Bond	2004	535	479	EUR	2010	3.750%
Bond	2004	67	60	AUD	2009	6.000%
Bond	2004	33	29	AUD	2009	6.000%
Bond	2004	156	140	GBP	2010	4.875%
Bond	2004	65	58	AUD	2011	5.750%
Bond	2004	65	58	CAD	2010	4.000%
Bond	2004	226	202	GBP	2010	4.875%
Bond	2004	42	38	USD	2008	3.250%
Bond	2004	42	38	USD	2008	3.250%
Bond	2004	115	103	GBP	2007	5.000%
Bond	2004	85	76	USD	2008	3.250%
Bond	2004	131	118	CAD	2011	4.875%
Bond	2004	255	228	USD	2011	4.125%
Bond	2004	58	51	NZD	2014	6.750%
Bond	2004	85	76	USD	2011	4.125%
Bond	2004	142	127	CHF	2012	2.375%
Bond	2005	337	302	EUR	2012	3.250%
Bond	2005	220	197	CHF	2012	2.135%
Bond	2005	42	38	USD	2009	3.500%
Bond	2005	65	58	AUD	2011	5.750%
Bond	2005	68	61	CAD	2011	4.000%
Bond	2005	170	152	USD	2011	4.125%
Bond	2005	106	95	EUR	2012	3.250%
Bond	2005	136	122	CHF	2011	1.625%
Bond	2005	63	63	AUD	2012	5.750%

F-43


(M€)	Year of issue	Fair value after hedging as of December 31, 2005	Fair value after hedging as of December 31, 2006	Currency	Maturity	Initial rate before hedging instruments
Bond	2005	57	57	NZD	2012	6.500%
Bond	2005	65	65	CHF	2012	2.135%
Bond	2005	226	226	CHF	2011	1.625%
Bond	2005	98	97	CHF	2012	2.375%
Bond	2005	295	284	GBP	2012	4.625%
Bond	2006	—	130	CHF	2016	2.385%
Bond	2006	—	62	AUD	2012	5.625%
Bond	2006	—	72	CAD	2012	4.125%
Bond	2006	—	100	EUR	2012	3.250%
Bond	2006	—	147	GBP	2007	5.000%
Bond	2006	—	65	CHF	2016	2.385%
Bond	2006	—	64	CHF	2016	2.385%
Bond	2006	—	63	CHF	2016	2.385%
Bond	2006	—	129	CHF	2018	3.135%
Bond	2006	—	100	EUR	2010	3.750%
Bond	2006	—	74	GBP	2012	4.625%
Bond	2006	—	300	EUR	2011	3.875%
Bond	2006	—	50	EUR	2010	3.750%
Bond	2006	—	127	CHF	2014	2.635%
Bond	2006	—	474	USD	2011	5.000%
Bond	2006	—	100	EUR	2012	3.250%
Bond	2006	—	42	EUR	2011	EURIBOR 3 months +0,040%
Bond	2006	—	300	EUR	2011	3.875%
Bond	2006	—	151	EUR	2011	3.875%
Bond	2006	—	120	USD	2011	5.000%
Bond	2006	—	74	GBP	2010	4.875%
Bond	2006	—	50	EUR	2010	3.750%
Bond	2006	—	300	EUR	2011	3.875%
Bond	2006	—	126	CHF	2013	2.510%
Current portion (less than one year)	2006	—	(1,686)
Total TOTAL CAPITAL^(a)		8,501	9,206

Other consolidated subsidiaries		111	73
Total		10,703	11,120

^(a)

TOTAL CAPITAL S.A. is a wholly-owned indirect subsidiary of the Company (with the exception of one share each held by the members of its board of directors, as required under French law). It acts as a financing vehicle for the Group. Its debt securities are fully and unconditionally guaranteed by the Company as to payment of principal, premium, if any, interest and any other amounts due.

Loan repayment schedule (excluding current portion)


As of December 31, 2006 (M€)	Non-current financial debt	of which hedging instruments of non-current financial debt (liabilities)	Currency and interest rate swaps (assets)		Non-current financial debt after swaps	%
2008	2,604	4	(245	)	2,359	17	%
2009	2,320	14	(82	)	2,238	16	%
2010	3,083	2	(104	)	2,979	22	%
2011	3,177	75	(20	)	3,157	23	%
2012 and beyond	2,990	98	(35	)	2,955	22	%
Total	14,174	*193*	(486	)	13,688	100	%

F-44


As of December 31, 2005 (M€)	Non-current financial debt	of which hedging instruments of non-current financial debt (liabilities)		Currency and interest rate swaps (assets)		Non-current financial debt after swaps	%
2007	2,896	(12	)	(223	)	2,673	20%
2008	2,256	(10	)	(117	)	2,139	16%
2009	2,403	1		(94	)	2,309	17%
2010	1,958	50		(22	)	1,936	15%
2011 and beyond	4,280	99		(21	)	4,259	32%
Total	13,793	*128*		(477	)	13,316	100%

Analysis by currency and interest rate

These analyses take into account interest rate and foreign currency swaps to hedge non-current financial debt.


As of December 31, (M€)	2006	%	2005	%
U.S. Dollar	6,981	51%	9,778	73%
Euro	5,382	39%	2,324	18%
Other currencies	1,325	10%	1,214	9%
Total	13,688	100%	13,316	100%


As of December 31, (M€)	2006	%	2005	%
Fixed rates	896	7%	1,089	8%
Floating rates	12,792	93%	12,227	92%
Total	13,688	100%	13,316	100%

Impact on net income

The amount of the cost of net debt after hedging instruments is disclosed in the consolidated statement of income under “Cost of net debt”.

The effective interest rate resulting from the cost of net debt approximates market conditions for the current debt. This effective rate may differ substantially from the interest rate of non-current loans as disclosed above, as the hedging instruments of interest rates are swaps that convert Group financing conditions to short-term market conditions (three-month average).

The 2006 gain for hedging instruments on debenture loans amounts to 18 M€ after tax ((23) M€ expense in 2005 and (12) M€ expense in 2004).

B. CURRENT BORROWINGS, BANK OVERDRAFTS AND RELATED FINANCIAL INSTRUMENTS

Current borrowings consist mainly of commercial paper or treasury bills or drawings on bank loans. These instruments bear interest at rates that are close to market rates.


As of December 31, (M€)	2006		2005
Current financial debt and bank overdrafts	3,348		2,928
Current portion of non-current financial debt	2,510		992
Current borrowings and bank overdrafts	5,858		3,920
Current portion of financial instruments for interest rate swaps liabilities	—		6
Other current financial instruments - liabilities	75		27
Other current financial liabilities (Note 27)	75		33
Current deposits beyond three months	(3,496	)	—
Current portion of financial instruments for interest rate swaps - assets	(341	)	(44	)
Other current financial instruments - assets	(71	)	(290	)
Current financial assets (Note 27)	(3,908	)	(334	)

Current borrowings, bank overdrafts and related financial assets and liabilities, net	2,025		3,619

F-45

Changes in the value of current financial instruments are, in accordance with the methods described in paragraph M of Note 1 to the Consolidated Financial Statements, recognized in the net income of the period under “Financial interest on debt”, except for instruments qualified as net investment hedge, which are recognized directly in shareholders’ equity, for an amount of (5) M€ as of December 31, 2006 ((146) M€ as of December 31, 2005).

21. OTHER CREDITORS AND ACCRUED LIABILITIES


As of December 31, (M€)	2006	2005
Advances from customers	1,430	1,416
Accruals and deferred income	163	253
Payable to states (including taxes and duties)	7,204	7,644
Payroll	879	1,015
Other	2,833	2,741
Total	12,509	13,069

22. LEASE CONTRACTS

The Group leases real estate, service stations, ships, and other equipment (see Note 11 to the Consolidated Financial Statements).

The future minimum lease payments on operating and financial leases to which the Group is committed are shown as follows:


As December 31, 2006 (M€)	Operating leases	Financial leases
2007	381	52
2008	378	56
2009	307	56
2010	246	51
2011	153	54
2012 and beyond	422	218
Total minimum payments	1,887	487
Less financial expenses		(87	)
Nominal value of contracts		400
Less current portion of financial leases		(29	)
Outstanding liability		371


As December 31, 2005 (M€)	Operating leases	Financial leases
2006	273	51
2007	210	47
2008	170	50
2009	119	41
2010	95	41
2011 and beyond	441	199
Total minimum payments	1,308	429
Less financial expenses		28
Nominal value of contracts		457
Less current portion of financial leases		(75	)
Outstanding liability		382


As of December 31, 2004 (M€)	Operating leases	Financial leases
2005	203	52
2006	169	47
2007	116	44
2008	105	46
2009	68	39
2010 and beyond	327	231
Total minimum payments	988	459
Less financial expenses		(104	)
Nominal value of contracts		355
Less current portion of financial leases		(30	)
Outstanding liability		325

Net rental expense incurred under operating leases for year ended December 31, 2006, was 380 M€, 272 M€ in 2005 and 244 M€ in 2004.

F-46

23. COMMITMENTS AND CONTINGENCIES


		Maturity and installments
As of December 31, 2006 (M€)	Total	Less than 1 year	Between 1 and 5 years	More than 5 years
Non-current debt obligations net of hedging instruments (Note 20)	13,317	—	10,548	2,769
Current portion of non-current debt obligations net of hedging instruments (Note 20)	2,140	2,140	—	—
Capital (financial) lease obligations (Note 22)	400	29	185	186
Asset retirement obligations (Note 19)	3,893	221	576	3,096
Subtotal obligations recorded in the balance sheet	19,750	2,390	11,309	6,051
Operating lease obligations (Note 22)	1,887	381	1,084	422
Purchase obligations	37,327	3,551	9,696	24,080
Subtotal obligations not recorded in the balance sheet	39,214	3,932	10,780	24,502
Total of contractual obligations	58,964	6,322	22,089	30,553
Guarantees given for excise taxes	1,807	587	22	1,198
Collateral given against borrowings	1,079	16	691	372
Indemnities related to sales of businesses	113	38	40	35
Other guarantees given	4,155	1,694	401	2,060
Total of other commitments given	7,154	2,335	1,154	3,665
Mortgages and liens received	329	11	77	241
Other commitments received	2,965	2,089	315	561
Total of commitments received	3,294	2,100	392	802


		Maturity and installments
As of December 31, 2005 (M€)	Total	Less than 1 year	Between 1 and 5 years	More than 5 years
Non-current debt obligations net of hedging instruments (Note 20)	12,934	0	8,877	4,057
Current portion of non-current debt obligations net of hedging instruments (Note 20)	879	879	0	0
Capital (financial) lease obligations (Note 22)	457	75	180	202
Asset retirement obligations (Note 19)	3,710	174	446	3,090
Subtotal obligations recorded in the balance sheet	17,980	1,128	9,503	7,349
Operating lease obligations (Note 22)	1,308	273	594	441
Purchase obligations	24,177	3,402	8,112	12,663
Subtotal obligations not recorded in the balance sheet	25,485	3,675	8,706	13,104
Total of contractual obligations	43,465	4,803	18,209	20,453
Guarantees given for excise taxes	2,827	2,552	29	246
Collateral given against borrowings	1,089	19	823	247
Indemnities related to sales of businesses	221	162	32	27
Other guarantees given	5,252	2,305	1,841	1,106
Total of other commitments given	9,389	5,038	2,725	1,626
Mortgages and liens received	280	10	158	112
Other commitments received	3,587	2,400	561	626
Total of commitments received	3,867	2,410	719	738

F-47

A. CONTRACTUAL OBLIGATIONS

Debt obligations

“Non-current debt obligations” are included in “Non-current financial debt” and “Hedging instruments of non-current financial debt” on the balance sheet. It includes the non-current portion of issue swaps and swaps hedging debenture loans, and excludes non-current finance lease obligations of 371 M€.

The current portion of non-current debt is included in “Current borrowings”, “Current financial assets” and “Other current financial liabilities” on the balance sheet. It includes the current portion of issue swaps and swaps hedging debenture loans and excludes the current portion of capital lease obligations of 29 M€.

The information regarding contractual obligations linked to indebtedness is presented in Note 20 to the Consolidated Financial Statements.

Lease contracts

The information regarding operating and finance leases is presented in Note 22 to the Consolidated Financial Statements.

Asset retirement obligations

This item represents the discounted present value of Upstream asset retirement obligations, primarily asset removal costs at the completion date. The information regarding contractual obligations linked to asset retirement obligations is presented in Note 19 to the Consolidated Financial Statements.

Purchase obligations

Purchase obligations are obligations under contractual agreements to purchase goods or services, including capital projects, that are enforceable and legally binding on the company, and that specify all significant terms, including the amount and the timing of the payments. These obligations include mainly: unconditional hydrocarbon purchase contracts (except where an active, highly-liquid market exists and the hydrocarbons are expected to be re-sold shortly after purchase), reservation of transport capacities in pipelines, unconditional exploration and development work in the Upstream segment, and contracts for capital investment projects in the Downstream segment.

B. OTHER COMMITMENTS GIVEN

Guarantees given for excise taxes

Guarantees given on customs duties, which amount to 1,807 M€ as of December 31, 2006, mainly consist of guarantees given to other oil and gas companies in order to comply with French tax authorities’ requirements for oil and gas imports in France. A payment would be triggered by a failure of the guaranteed party with respect to the French tax authorities. The default of the guaranteed parties is however considered to be highly remote by the Group.

Collateral given against borrowings

The Group guarantees bank debt and finance lease obligations of certain unconsolidated affiliates. Expiration dates vary, and guarantees will terminate on payment and/or cancellation of the obligation. A payment would be triggered by failure of the guaranteed party to fulfill its obligation covered by the guarantee, and no assets are held as collateral for these guarantees. The amount of these guarantees total approximately 1,079 M€ as of December 31, 2006 for debt guarantees with maturities up to 2019.

Indemnities related to sales of businesses

In the ordinary course of business, the Group executes contracts involving standard indemnities in the industry and indemnifications specific to a transaction such as sale of a business. These indemnifications might include claims against any of the following: environmental, tax and shareholder matters, intellectual property rights, governmental regulations and employment-related matters, dealer, supplier, and other commercial contractual relationships. Performance under these indemnities would generally be triggered by a breach of terms of the contract or by a third party claim. The Group regularly evaluates the probability of having to incur costs associated with these indemnifications.

Guarantees related to business sales consist mainly of guarantees given for the sale of the Inks division in 1999 and the sale of the Paints business in 2003.

The guarantees related to antitrust investigations granted as part of the agreement relating to the spin-off of Arkema are described in Note 30 to the Consolidated Financial Statements.

F-48

Other guarantees given

Non-consolidated subsidiaries

The Group also guarantees the current liabilities of some of non-consolidated subsidiaries. Performance under these guarantees would be triggered by a financial default of the entity. As of December 31, 2006, the total amount of these guarantees is estimated to be 68 M€.

Other guarantees given

In the ordinary course of business and consistent with generally accepted and recognized industry practice, the

Group enters into numerous agreements with other parties. These commitments are often entered into for commercial purposes or for regulatory purposes and for other operating agreements. As of December 31, 2006, these other commitments include guarantees given to customers or suppliers for 1,544 M€, guarantees on letters of credit for 1,416 M€ and other operating commitments for 1,195 M€.

In line with the business practices of oil and gas companies for the development of gas fields, the Group is involved in long-term sale agreements on quantities of natural gas. The price of these contracts is indexed to prices of petroleum products and other forms of energy.

24. SHARE-BASED PAYMENTS

A. TOTAL SHARE SUBSCRIPTION PLANS


	2003 Plan^(a)		2004 Plan^(b)		2005 Plan^(c)		2006 Plan^(d)		Total
Exercise price until May 23, 2006 included (€)^(e)	33.30		39.85		49.73		—
Exercise price since May 24, 2006 (€)^(e)	32.84		39.30		49.04		50.60
Expiration date	07/16/2011		07/20/2012		07/19/2013		07/18/2014
Number of options^(f)
Existing options as of January 1, 2004	11,741,224		—		—		—		11,741,224
Granted	—		13,462,520		—				13,462,520
Cancelled	(8,400	)	(48,000	)	—				(56,400	)
Exercised	(3,800	)	—		—				(3,800	)
Existing options as of January 1, 2005	11,729,024		13,414,520						25,143,544
Granted	—		24,000		6,104,480				6,128,480
Cancelled	(10,000	)	(16,400	)	(10,400	)			(36,800	)
Exercised	(522,228	)	(10,800	)	—				(533,028	)
Existing options as of January 1, 2006	11,196,796		13,411,320		6,094,080				30,702,196
Granted	—		—		134,400		5,727,240		5,861,640
Cancelled	(22,200	)	(57,263	)	(43,003	)	(1,080	)	(123,546	)
Adjustment following the spin-off of Arkema^(g)	163,180		196,448		90,280		—		449,908
Exercised	(729,186	)	(120,133	)	—		—		(849,319	)
Existing options as of December 31, 2006	10,608,590		13,430,372		6,275,757		5,726,160		36,040,879

(a)

Grants decided by the Board of Directors on July 16, 2003 pursuant to the authorization given by the shareholders’ meeting held on May 17, 2001. The options are exercisable only after a two-year period from the date the option is granted to the individual employee and must be exercised within eight years from the date of grant. Underlying shares may not be sold for four years from the date of grant.

(b)

Grants decided by the Board of Directors on July 20, 2004 pursuant to the authorization given by the shareholders’ meeting held on May 14, 2004. The options are exercisable only after a two-year period from the date the option is granted to the individual employee and must be exercised within eight years from this date. Underlying shares may not be sold for four years from the date of grant.

(c)

Grants decided by the Board of Directors on July 19, 2005 pursuant to the authorization given by the shareholders’ meeting held on May 14, 2004. The options are exercisable only after a two-year period from the date the option is granted to the individual employee and must be exercised within eight years from this date. Underlying shares may not be sold for four years from the date of grant.

(d)

Grants decided by the Board of Directors on July 18, 2006 pursuant to the authorization given by the shareholders’ meeting held on May 14, 2004. The options are exercisable only after a two-year period from the date the option is granted to the individual employee and must be exercised within eight years from this date. Underlying shares may not be sold for four years from the date of grant.

(e)

To reflect the four-for-one stock split, the exercise prices of TOTAL share subscription options were divided by four. Moreover, following the spin-off of Arkema, the exercise prices of TOTAL share subscription options were multiplied by an adjustment factor equal to 0.986147 with effect as of May 24, 2006.

(f)

The number of options was multiplied by four to reflect the four-for-one stock split.

(g)

Adjustments decided by the Board of Directors on March 14, 2006, in application of Articles 174-9, 174-12 and 174-13 of the Decree No.67-236 of March 23, 1967 in force during this Board of Directors and during TOTAL S.A. shareholders’ meeting of May 12, 2006, as part of the spin-off of Arkema. These adjustments have been made on May 22, 2006 with effect as of May 24, 2006.

F-49

B. TOTAL SHARE PURCHASE PLAN


	1998 Plan^(a)		1999 Plan^(b)		2000 Plan^(c)		2001 Plan^(d)		2002 Plan^(e)		Total
Exercise price until May 23, 2006 included (€)^(f)	23.44		28.25		40.68		42.05		39.58
Exercise price since May 24, 2006 (€)^(f)	—		27.86		40.11		41.47		39.03
Expiration date	03/17/2006		06/15/2007		07/11/2008		07/10/2009		07/09/2010
Number of options^(g)
Existing options as of January 1, 2004	2,890,152		5,626,468		9,636,180		10,734,500		11,452,800		40,340,100
Granted	—		—		—		—		—		—
Cancelled	—		—		(5,200	)	(10,800	)	(3,200	)	(19,200	)
Exercised	(1,334,104	)	(1,520,352	)	(5,200	)	—		(3,088	)	(2,862,744	)
Existing options as of January 1, 2005	1,556,048		4,106,116		9,625,780		10,723,700		11,446,512		37,458,156
Granted	—		—		—		—		—		—
Cancelled	(400	)	(1,200	)	(7,000	)	(4,000	)	(9,800	)	(22,400	)
Exercised	(965,996	)	(2,052,484	)	(3,108,836	)	(1,983,800	)	(153,232	)	(8,264,348	)
Existing options as of January 1, 2006	589,652		2,052,432		6,509,944		8,735,900		11,283,480		29,171,408
Granted	—		—		—		—		—		—
Cancelled	(72,692	)	—		(7,272	)⁽ⁱ⁾	(15,971	)	(26,694	)	(122,629	)
Adjustment following the spin-off of Arkema^(h)	—		25,772		84,308		113,704		165,672		389,456
Exercised	(516,960	)	(707,780	)	(1,658,475	)	(1,972,348	)	(2,141,742	)	(6,997,305	)
Existing options as of December 31, 2006	—		1,370,424		4,928,505		6,861,285		9,280,716		22,440,930

(a)

Grants decided by the Board of Directors on March 17, 1998 pursuant to the authorization given by the shareholders’ meeting held on May 21, 1997. The options were exercisable only after a five-year period from the date the option was granted to the individual employee and had to be exercised within eight years from this date. This plan expired on March 17, 2006.

(b)

Grants decided by the Board of Directors on June 15, 1999 pursuant to the authorization given by the shareholders’ meeting held on May 21, 1997. The options are exercisable only after a five-year period from the date the option is granted to the individual employee and must be exercised within eight years from this date.

(c)

Grants decided by the Board of Directors on July 11, 2000 pursuant to the authorization given by the shareholders’ meeting held on May 21, 1997. The options are exercisable only after a four-year period from the date the option is granted to the individual employee and must be exercised within eight years from this date. For beneficiaries holding contracts with French companies or working in France, the shares arising from the exercise of options may not be sold for five years from the date of grant.

(d)

Grants decided by the Board of Directors on July 10, 2001 pursuant to the authorization given by the shareholders’ meeting held on May 17, 2001. The options are exercisable only after January 1, 2005 and must be exercised within eight years from the date of grant. For beneficiaries holding contracts with French companies or working in France, the shares arising from the exercise of options may not be sold for four years from the date of grant.

(e)

Grants decided by the Board of Directors on July 9, 2002 pursuant to the authorization given by the shareholders’ meeting held on May 17, 2001. The options are exercisable only after a two-year period from the date the option is granted to the individual employee and must be exercised within eight years from this date. Underlying shares may not be sold for four years from the date of grant.

(f)

To reflect the four-for-one stock split, the exercise prices of TOTAL share purchase options were divided by four. Moreover, following the spin-off of Arkema, the exercise prices of TOTAL share purchase options were multiplied by an adjustment factor equal to 0.986147 with effect as of May 24, 2006.

(g)

The number of options was multiplied by four to reflect the four-for-one stock split.

(h)

Adjustments decided by the Board of Directors on March 14, 2006 in application of Articles 174-9, 174-12 and 174-13 of the Decree No.67-236 of March 23, 1967 in force during this Board of Directors and during TOTAL S.A. shareholders’ meeting of May 12, 2006, as part of the spin-off of Arkema. These adjustments have been made on May 22, 2006 with effect as of May 24, 2006.

(i)

Including the confirmation in 2006 by the Company of the award of 500 stock options (for underlying shares with a par value of €10 per share) that had been cancelled erroneously in 2001.

F-50

EXCHANGE GUARANTEE GRANTED TO THE HOLDERS OF ELF AQUITAINE SHARE SUBSCRIPTION OPTIONS

Pursuant to the public exchange offer for Elf Aquitaine shares which was made in 1999, the Group made a commitment to guarantee the holders of Elf Aquitaine share subscription options, at the end of the period referred to in Article 163 bis C of the French Tax Code (CGI), and until the end of the period for the exercise of the options, the possibility to exchange their future Elf Aquitaine shares for TOTAL shares, on the basis of the exchange ratio of the offer (19 TOTAL shares for 13 Elf Aquitaine shares).

In order to take into account the spin-off of S.D.A. (Société de Développement Arkema) by Elf Aquitaine, the spin-off of Arkema by TOTAL S.A. and the

four-for-one TOTAL stock split, the Board of Directors of TOTAL S.A., in accordance with the terms of the share exchange undertaking, decided on March 14, 2006 to adjust the exchange ratio described above. Following the approval by Elf Aquitaine shareholder’s meeting on May 10, 2006 of the spin-off of S.D.A. by Elf Aquitaine, the approval by TOTAL S.A. shareholder’s meeting on May 12, 2006 of the spin-off of Arkema by TOTAL S.A. and the four-for-one TOTAL stock split, the exchange ratio was adjusted to six TOTAL shares for one Elf Aquitaine on May 22, 2006.

As of December 31, 2006, a maximum of 193,150 Elf Aquitaine shares, either outstanding or to be created, were covered by this guarantee, as follows:


Elf Aquitaine subscription plan^(a)	1999 Plan No.1	1999 Plan No.2	Total
Exercise price until May 23, 2006 included (€)^(b)	115.60	171.60
Exercise price since May 24, 2006 (€)^(b)	114.76	170.36
Expiration date	03/30/2009	12/9/2009
Outstanding position as of December 31, 2006	180,932	6,044	186,976
Outstanding Elf Aquitaine shares covered by the exchange guarantee as of December 31, 2006	6,174	—	6,174
Total of Elf Aquitaine shares, either outstanding or to be created, covered by the exchange guarantee for TOTAL shares as of December 31, 2006	187,106	6,044	193,150
TOTAL shares likely to be created within the scope of the application of the exchange guarantee as of December 31, 2006	1,122,636	36,264	1,158,900

(a)

Adjustments of the number of options decided by the Board of Directors on March 10, 2006 in application of Articles 174-9, 174-12 and 174-13 of the Decree No.67-236 of March 23, 1967 in force on March 10, 2006 and during Elf Aquitaine shareholders’ meeting on May 10, 2006, as part of the spin-off of S.D.A. These adjustments have been made on May 22, 2006 with effect as of May 24, 2006.

(b)

To take the spin-off of SDA into account, the exercise prices of Elf Aquitaine subscription shares were adjusted by a factor which equals to 0.9992769 with effect on May 24, 2006.

Thus, as of December 31, 2006, at most 1,158,900 shares of the Group were likely to be created within the framework of the application of this exchange guarantee.

F-51

D. GRANT OF TOTAL RESTRICTED SHARES


	2005 Plan^(a)(b)		2006 Plan^(c)
Date of Board of Directors meeting	07/19/2005		07/18/2006
Number of restricted shares
Outstanding as of January 1, 2005	—		—
Notified	2,280,520		—
Cancelled	(5,992	)	—
Finally granted	—		—
Outstanding as of January 1, 2006	2,274,528		—
Notified	—		2,275,364
Cancelled	(7,432	)	(3,068	)
Finally granted	—		—
Outstanding as of December 31, 2006	2,267,096		2,272,296

(a)

Grants decided by the Board of Directors on July 19, 2005 pursuant to the authorization given by the shareholders’ meeting held on May 17, 2005. The grant of these shares, which have been bought back in 2005 by the Company on the market, will become final after a two-year vesting period (acquisition of the right to restricted shares) on July 20, 2007, subject to a performance condition. This condition states that the number of restricted shares finally granted will be based on the Return On Equity (ROE) of the Group. The ROE will be calculated on the consolidated accounts published by TOTAL and related to the fiscal year preceding the year of the final grant, in the present case fiscal 2006. Moreover, the transfer of the restricted shares, that might hence be finally granted, will not be permitted between the date of final grant and the end of a two-year mandatory holding period, on July 20, 2009.

(b)

The number of restricted shares was multiplied by four to reflect the four-for-one stock split.

(c)

Grants decided by the Board of Directors on July 18, 2006 pursuant to the authorization given by the shareholders’ meeting held on May 17, 2005. The grant of these shares, which have been bought back in 2006 by the Company on the market, will become final after a two-year vesting period (acquisition of the right to restricted shares) on July 19, 2008, subject to a performance condition. This condition states that the number of restricted shares finally granted will be based on the Return On Equity (ROE) of the Group. The ROE will be calculated on the consolidated accounts published by TOTAL and related to the fiscal year preceding the year of the final grant, in the present case fiscal 2007. Moreover, the transfer of the restricted shares, that might hence be finally granted, will not be permitted between the date of final grant and the end of a two-year mandatory holding period, on July 19, 2010.

E. SHARE-BASED PAYMENT EXPENSES

Share-based payment expenses for the year 2006 amounts to 157 M€ and can be broken down as follow:

•

74 M€ for TOTAL share subscription and share purchase plans;

•

83 M€ for TOTAL restricted shares plan.

Share-based payment expenses for the year 2005 amounts to 131 M€ and can be broken down as follow:

•

86 M€ for TOTAL share subscription purchase plans;

•

25 M€ for TOTAL restricted shares plan;

•

20 M€ for TOTAL for capital increase reserved for employees (Note 17 to the Consolidated Financial Statements).

Share-based payment expenses for the year 2004 amounts to 138 M€ and can be broken down as follow:

•

118 M€ for TOTAL share subscription and share purchase plans;

•

20 M€ for TOTAL for capital increase reserved for employees.

The fair value of the options granted in 2006, 2005 and 2004 has been valued according to the Black-Scholes method and based on the following hypothesis:


For the year ended December 31,	2006	2005	2004
Risk free interest rate (%)	4.1	2.9	3.8
Expected dividends (%)	4.2	3.7	3.0
Expected volatility (%)^(a)	29.3	23.2	22.0
Vesting period (years)	2.0	2.0	2.0
Exercise period (years)	8.0	8.0	8.0
Weighted-average fair value of the granted options (€ per option)^(b)	11.3	10.0	7.8

(a)

The expected volatility is based on the implied volatility of TOTAL shares options and of share indices options traded on the markets.

(b)

The 2004 and 2005 figures have been restated to reflect the four-for-one stock split on May 18, 2006.

F-52

25. PAYROLL AND STAFF


For the year ended December 31, (M€)	2006	2005	2004
PERSONNEL EXPENSES^(a)
Wages and salaries (including social charges)	5,828	5,610	5,057
GROUP EMPLOYEES^(a)
France
• Management	10,313	9,958	9,620
• Other	27,518	27,817	28,149
International
• Management	13,263	13,455	12,754
• Other	43,976	43,824	42,494
Total	95,070	95,054	93,017

(a)

Number of employees and personnel expenses of fully-consolidated subsidiaries (excluding Arkema).

26. STATEMENT OF CASH FLOWS

A. Non-current financial debt

Changes in non-current financial debt have been presented as the net variation to reflect significant changes mainly related to revolving credit agreements. The detailed analysis is as follows:


For the year ended December 31, (M€)	2006		2005
Insuance of non-current debt	3,857		2,910
Repayment of non-current debt	(135	)	(32	)
Net amount	3,722		2,878

B. Changes in working capital


For the year ended December 31, (M€)	2006		2005
Inventories	(500	)	(2,971	)
Accounts receivable	494		(4,712	)
Prepaid expenses and other current assets	(1,425	)	(991	)
Accounts payable	141		3,575
Other creditors and accrued liabilities	849		1,097
Net amount	(441	)	(4,002	)

C. Additional information on cash flow


For the year ended December 31, (M€)	2006		2005
Interests paid	(1,648	)	(985	)
Interests received	1,261		826
Income tax on cashed out profits	(10,439	)	(8,159	)
Dividends received	899		758

F-53

27. FAIR VALUE OF FINANCIAL INSTRUMENTS

A. FINANCIAL INSTRUMENTS NOT RELATED TO COMMODITY CONTRACTS

The difference between the carrying amount in the balance sheet and the fair value of financial instruments is as follows:


	2006				2005
ASSETS/(LIABILITIES) As of December 31, (M€)	Carrying amount		Fair Value		Carrying amount		Fair Value
Publicly traded equity securities	304		304		469		469
Other equity securities	946		946		1,047		1,047
Other investments (Note 13)	1,250		1,250		1,516		1,516
Loans and advances (Note 14)	1,025		1,025		1,202		1,202
Debenture loans (non-current portion, before swaps)^(a)	(11,413	)	(11,413	)	(11,025	)	(11,025	)
Issue swaps and swap hedging debenture loans (liabilities)^(a)	(193	)	(193	)	(128	)	(128	)
Issue swaps and swap hedging debenture loans (assets)^(b)	486		486		450		450
Debenture loans after swaps (non-current portion) (Note 20A)	(11,120	)	(11,120	)	(10,703	)	(10,703	)
Bank and other loans, before swaps (non-current portion) - floating rate^(a)	(1,987	)	(1,987	)	(1,847	)	(1,847	)
Non-current currency and interest rate swaps hedging bank loans^(b)	—		—		27		27
Bank and other loans, after swaps - floating rate (non-current portion) (Note 20A)	(1,987	)	(1,987	)	(1,820	)	(1,820	)
Bank and other loans (non-current portion) - fixed rate^(a) (Note 20A)	(210	)	(207	)	(411	)	(406	)
Finance lease obligations (non-current portion)^(a) (Notes 20A and 22)	(371	)	(371	)	(382	)	(382	)
Debenture loans (current portion, before swaps)	(2,320	)	(2,320	)	(624	)	(624	)
Bank and other loans (except finance lease obligations) (current portion)	(161	)	(161	)	(334	)	(333	)
Finance lease obligations (current portion) (Note 22)	(29	)	(29	)	(34	)	(34	)
Issue swaps and swaps hedging debenture loans (fixed rate) (current portion) (assets)	341		341		44		44
Issue swaps and swaps hedging debenture loans (fixed rate) (current portion) (liabilities)	—		—		(6	)	(6	)
Current portion of non-current financial debt (Note 20B) after swaps	(2,169	)	(2,169	)	(954	)	(953	)
Current deposit beyond three months	3,496		3,496		—		—
Other interest rates swaps - assets	12		12		7		7
Currency swaps and forward exchange contracts - assets^(c)	59		59		283		283
Current financial assets held for trading (Note 20B)	3,567		3,567		290		290
Other interest rates swaps - liabilities	(8	)	(8	)	(4	)	(4	)
Currency swaps and forward exchange contracts - liabilities^(c)	(67	)	(67	)	(23	)	(23	)
Current financial liabilities held for trading (Note 20B)	(75	)	(75	)	(27	)	(27	)
Total	(10,090	)	(10,087	)	(11,289	)	(11,283	)
Total of fair value not recognized in the balance sheet			3				6

(a)

Included in “Non-current financial debt” in Note 20A to the Consolidated Financial Statements.

(b)

Included in “Hedging instruments of non-current financial debt” in Note 20A to the Consolidated Financial Statements.

(c)

Currency swaps are used to manage TOTAL’s current position to be able to borrow or to invest on markets other than the euro market. Therefore their market values, when significant, are compensated by the value of the current financial loans and debts to which they relate.

F-54

The classification by strategy and the notional amount of the derivative instruments included in the table above is as follows:

As of December 31, 2006 (M€)

Notional amount^(a)

ASSETS/(LIABILITIES)

Fair
Value

Total

2007

2008

2009

2010

2011

2012 and
after

Financial instruments hedging non-current financial debt

Issue swaps and swap hedging debenture
issues - non-current (liabilities)

(193

)

5,691

Issue swaps and swap hedging debenture
issues - non-current (assets)

486

5,317

Issue swaps and swap hedging debenture
issues - non-current

293

11,008

1,756

2,018

1,870

2,740

2,624

Non-current currency and interest rate swaps
hedging bank loans

Issue swaps and swap hedging debenture
issues - less than one year (liabilities)

475

Issue swaps and swap hedging debenture
issues - less than one year (assets)

341

1,341

Issue swaps and swap hedging debenture
issues - less than one year

341

1,816

Financial instruments hedging net investment

N/A

Financial instruments held for trading

Current deposits beyond three months

3,496

Other interest rate swaps - assets

6,488

Other interest rate swaps - liabilities

)

9,580

Other swaps assets and liabilities

16,068

16,062

—

Currency swaps and forward exchange contracts - assets

5,003

Currency swaps and forward exchange contracts - liabilities

(67

)

6,065

Currency swaps and forward exchange contracts - assets and liabilities

)

11,068

10,513

287

201

—

As of December 31, 2005 (M€)

Notional amount^(a)

ASSETS/(LIABILITIES)

Fair
Value

Total

2006

2007

2008

2009

2010

2011 and
after

Financial instruments hedging non-current financial debt

Issue swaps and swap hedging debenture issues - non-current (liabilities)

(128

)

4,387

Issue swaps and swap hedging debenture issues - non-current (assets)

450

6,166

Issue swaps and swap hedging debenture issues - non-current

322

10,553

1,854

1,960

2,137

1,782

2,820

Non-current currency and interest rate swaps hedging bank loans

Issue swaps and swap hedging debenture issues - less than one year (liabilities)

)

167

Issue swaps and swap hedging debenture issues - less than one year (assets)

381

Issue swaps and swap hedging debenture issues - less than one year

548

Financial instruments hedging net investment

N/A

Financial instruments held for trading

Other interest rate swaps - assets

4,960

Other interest rate swaps - liabilities

)

9,022

Other swaps assets and liabilities

13,982

13,976

Currency swaps and forward exchange contracts - assets

283

8,579

Currency swaps and forward exchange contracts - liabilities

(23

)

2,372

Currency swaps and forward exchange contracts - assets and liabilities

260

10,951

10,542

184

(a)

These amounts set the levels of notional involvement and are not indicative of a contingent gain or loss.

F-55

B. FINANCIAL INSTRUMENTS RELATED TO COMMODITY CONTRACTS

These financial instruments are recognized at their fair value and recorded under “Accounts receivable and other current assets” or “Accounts payable and other creditors” depending whether they are assets or liabilities.


As of December 31, 2006 (M€)
ASSETS / (LIABILITIES)	Notional value - assets^(a)	Notional value - liabilities^(a)	Carrying amount		Fair Value
Commodities instruments on crude oil, petroleum products and freight rates
Petroleum products and crude oil swaps^(a)	8,258	9,459	(43	)	(43	)
Swap freight agreements	56	86	2		2
Forwards^(b)	5,145	5,830	(11	)	(11	)
Options^(c)	6,046	4,835	66		66
Futures^(d)	1,274	2,434	79		79
Options on futures^(c)	143	165	(4	)	(4	)
Total - Commodities instruments on crude oil, petroleum products and freight rates			89		89

Commodities instruments on gas and power
Swaps^(a)	890	716	(25	)	(25	)
Forwards	9,973	9,441	(73	)	(73	)
Options^(c)	18	58	2		2
Futures^(d)	92	46	31		31
Total - Commodities instruments on gas and power			(65	)	(65	)
Total			24		24
Total of fair value not recognized in the balance sheet					—


As of December 31, 2005 (M€)
ASSETS / (LIABILITIES)	Notional value - assets^(a)	Notional value - liabilities^(a)	Carrying amount		Fair Value
Commodities instruments on crude oil, petroleum products and freight rates
Petroleum products and crude oil swaps^(a)	5,474	6,356	13		13
Swap freight agreements	46	47	—		—
Forwards^(b)	4,839	5,156	(14	)	(14	)
Options^(c)	5,426	3,770	79		79
Futures^(d)	627	2,045	(35	)	(35	)
Options on futures^(c)	398	178	13		13
Total - Commodities instruments on crude oil, petroleum products and freight rates			56		56

Commodities instruments on gas and power
Swaps^(a)	1,205	1,017	28		28
Forwards^(b)	8,940	9,133	19		19
Options^(c)	60	41	—		—
Futures^(d)	177	43	35		35
Total - Commodities instruments on gas and power			82		82
Total			138		138
Total of fair value not recognized in the balance sheet					—

(a)

Swaps (including “Contracts for differences”): the “Notional value” columns correspond to receive-fixed and pay-fixed swaps.

(b)

(c)

Options: the “Notional value” columns correspond to the nominal value of options (calls or puts) purchased and sold, valued based on the strike price.

(d)

Futures: the “Notional value” columns correspond to the net purchasing/selling positions, valued based on the closing rate on the organized exchange market.

Contracts on crude oil and petroleum products have been primarily entered into on a short-term basis (less than one year).

F-56

28. RELATED PARTIES

The main transactions and balances with related parties (principally all the investments carried under the equity method and subsidiaries excluded from consolidation) are detailed as follows:


As of December 31, (M€)	2006	2005
Balance Sheet
Receivables
Debtors and other debtors	411	353
Loans (excl. loans to equity companies)	457	465
Payables
Creditors and other creditors	424	406
Debts	25	19

For the year ended December 31, (M€)	2006	2005
Income Statement
Sales	1,996	1,593
Purchases	3,123	2,482
Financial expenses	—	—
Financial income	60	56

DIRECTORS AND EXECUTIVE OFFICERS COMPENSATION

The aggregate amount paid directly or indirectly by the French and foreign affiliates of the Company as compensation to the executive officers of TOTAL (the members of the Management Committee and the Treasurer) was 19.7 M€ in 2006 (31 persons) compared with 18.8 M€ in 2005 (30 persons).

The compensation allocated to members of the Board of Directors for directors’ fees totaled 0.82 M€ in 2006, pursuant to the resolution of the shareholders’ meeting of May 17, 2005.

The expense recorded for share-based payments to the executive officers of the Group was 16.6 M€ in 2006 (13 M€ in 2005).

The benefits provided for the executive officers, excluding employee severance packages or retirement plans, are post-retirement plans financed by the Company, which represent 109.7 M€ provisioned as of December 31, 2006 compared with 108.9 M€ as of December 31, 2005. In 2006, the expense recorded amounted to 13.7 M€ (9.2 M€ in 2005).

29. MARKET RISKS

A) Oil and gas market related risks

Due to the nature of its business, the Group has a significant involvement in oil and gas trading as part of its normal operations to attempt to optimize revenues from its crude oil and gas production and obtain favorable pricing for supplies for its refineries.

In its international oil trading activities, the Group follows a policy of not selling its future oil and gas production for future delivery. However, in connection with these trading activities, the Group, like most other oil companies, uses energy derivative instruments to adjust its exposure to price fluctuations of crude oil, refined products, natural gas and electricity. Furthermore, the Group also uses freight-rate derivative contracts in its shipping activities to adjust its exposure to freight-rate fluctuations. To hedge against this risk, the Group uses various instruments such as futures, forwards, swaps and options on organized markets or over-the-counter markets.

To measure market risks related to the prices of oil and gas products, the Group uses a “value at risk” method. Under this method, for the Group’s trading activities of crude oil, refined products and freight rate derivatives, there is a 97.5% probability that unfavorable daily market variations would result in a loss of less than 11.4 M€ per day, defined as the “value at risk”, based on positions as of December 31, 2006. Over the year 2006, the average value at risk was 8.6 M€, the lowest value at risk was 4.3 M€, the highest value at risk was 12.9 M€.

As part of its gas and electricity trading activity, the Group also uses derivative instruments such as futures, forwards, swaps and options in both organized and over-the-counter markets. In general, the transactions are settled at maturity date through physical delivery. There is a 97.5% probability that unfavorable daily market variations would result in a loss of less than 6.0 M€ per day, based on positions as of December 31, 2006. Over the year 2006, the average value at risk was 9.1 M€, the lowest value at risk was 3.5 M€, and the highest value at risk was 21.7 M€.

The Group has implemented strict policies and procedures to manage and monitor these market risks. Trading and financial controls are carried out separately and an integrated information system enables real-time monitoring of trading activities.

F-57

Limits on trading positions are approved by the Group’s Executive Committee and are monitored daily. To increase flexibility and encourage liquidity, hedging operations are performed with numerous independent operators, including other oil companies, major energy consumers and financial institutions. The Group has established limits for each counterpart, and outstanding amounts for each counterpart are monitored on a regular basis.

B) Financial markets related risks

Within its financing and cash management activities, the Group uses derivative instruments in order to manage its exposure to changes in interest rates and foreign exchange rates. This includes mainly interest rates and currency swaps. The Group might also use on an occasional basis futures, caps, floors and options contracts. The current operations and their accounting treatment are detailed in paragraph M of Note 1 and Notes 20 and 27 to the Consolidated Financial Statements.

Risks relative to cash management activities and to interest rate and foreign exchange financial instruments are managed in accordance with rules set by the Group’s Management. Liquidity positions and the management of financial instruments are centralized in the Treasury Department.

Cash management activities are organized into a specialized department for operations on financial markets. The Financial Control Department handles the daily monitoring of limits and positions and calculates results. It values financial instruments and, if necessary, performs sensitivity analysis.

(i) Management of currency exposure

The Group seeks to minimize the currency exposure of each exposed entity by reference to its functional currency (primarily the euro, U.S. dollar, pound sterling, and Norwegian krone).

forward market. The Group rarely hedges estimated cash flows and, in this case, may use options.

With respect to currency exposure linked to non-current assets accounted for in a currency other than the euro, the Group has a hedging policy which results in reducing the associated currency exposure by financing in the same currency.

Short-term net currency exposure is periodically monitored with limits set by the Group’s executive management. The Group’s central treasury entities manage this currency exposure and centralizes borrowing activities on the financial markets (the proceeds of which are then loaned to the borrowing subsidiaries), cash centralization for the Group companies and investments of these funds on the monetary markets.

(ii) Management of short-term interest rate exposure and cash

Cash balances, which are primarily composed of euros and U.S. dollars, are managed with three main objectives set out by management (to maintain maximum liquidity, to optimize revenue from investments considering existing interest rate yield curves, and to minimize the cost of borrowing), over a horizon of less than 12 months and on the basis of a daily interest rate benchmark, primarily through short-term interest rate swaps and short-term currency swaps, without modification of the currency exposure.

(iii) Management of interest rate risk on non-current debt

The Group’s policy consists of incurring non-current debt primarily at a floating rate or at a fixed rate depending on opportunities at the issuance with regards to the level of interest rates, in dollars or in euros according to the general corporate purposes. Long-term interest rate and currency swaps can hedge debenture loans at their issuance in order to create a variable rate synthetic debt. In order to partially modify the interest rate structure of the long-term debt, TOTAL can also enter into long-term interest rate swaps.

F-58

(iv) Sensitivity analysis on interest rate and foreign exchange risk


As of December 31, 2006 (M€)	Carrying amount		Estimated fair value		Change in fair value with a 10% interest rate increase		Change in fair value with a 10% interest rate decrease
ASSETS/(LIABILITIES)
Debenture loans (non-current portion, before swaps)	(11,413	)	(11,413	)	26		(26	)
Issue swaps and swaps hedging debenture loans	(193	)	(193	)	—
Issue swaps and swaps hedging debenture loans (assets)	486		486		—
Total issue swaps and swaps hedging debenture loans - assets and liabilities	293		293		(26	)	26
Fixed-rate bank loans	(210	)	(207	)	6		(6	)
Current portion of non-current debt after swap (excluding capital lease obligations)	(2,140	)	(2,140	)	1		(1	)
Other interest rates swaps	12		12		(1	)	1
Currency swaps and forward exchange contracts	(8	)	(8	)	1		(1	)
Currency options	—		—		—		—


As of December 31, 2005 (M€)	Carrying amount		Estimated fair value		Change in fair value with a 10% interest rate increase		Change in fair value with a 10% interest rate decrease
ASSETS/(LIABILITIES)
Debenture loans (non-current portion, before swaps)	(11,025	)	(11,025	)	126		(129	)
Issue swaps and swaps hedging debenture loans	(128	)	(128	)	—		—
Issue swaps and swaps hedging debenture loans (assets)	450		450		—		—
Total issue swaps and swaps hedging debenture loans - assets and liabilities	322		322		(115	)	117
Fixed-rate bank loans	(411	)	(406	)	7		(7	)
Current portion of non-current debt after swap (excluding capital lease obligations)	(920	)	(919	)	1		(1	)
Other interest rates swaps	3		3		(3	)	3
Currency swaps and forward exchange contracts	260		260		4		(4	)
Currency options	—		—		—		—

F-59

As a result of its policy for management of currency exposure previously described, the Group believes that its short-term currency exposure is not material. The Group’s sensitivity to long-term currency exposure is primarily influenced by the net equity of the subsidiaries whose functional currency is the U.S. dollar and, to a lesser extent, the pound sterling and the Norwegian krone.

This sensitivity is reflected by the historical evolution of the currency translation adjustment imputed in the statement of changes in shareholders’ equity which, in the course of the last three fiscal years, is essentially related to the evolution of the U.S. dollar and is set forth in the table below:


	Dollar/euro exchange rates	Currency translation adjustments (M€)
As of December 31, 2006	1.32	(1,383	)
As of December 31, 2005	1.18	1,421
As of December 31, 2004	1.36	(1,429	)

The non-current debt in dollars described in Note 20 to the Consolidated Financial Statements is generally raised by the central treasury entities either in U.S. dollars or in euros, or in other currencies which are then systematically exchanged for dollars or euros according to the general corporate purposes, through issue swaps. The proceeds from these debt issuances are principally loaned to affiliates whose accounts are kept in U.S. dollars and any remaining balance is held in dollar-denominated investments. Thus, the net sensitivity of these positions to currency exposure is not material.

Short-term currency swaps for the nominal amounts appear in Note 27 to the Consolidated Financial Statements are used with the aim of optimizing the centralized management of the cash of the Group. Thus the sensitivity to currency fluctuations which may be induced is likewise considered negligible.

As a result of this policy, the impact of currency exchange on consolidated income, as illustrated in Note 7 to the Consolidated Financial Statements, has not been significant despite the considerable fluctuation of

the dollar (loss of 30 M€ in 2006, gain of 76 M€ in 2005 and loss of 75 M€ in 2004).

(v)

Management of counterparty risk

The Group has established standards for market transactions according to which bank counterparties must be approved in advance, based on an assessment of the counterparty’s financial soundness and its rating (Standard & Poors, Moody’s), which must be of high quality.

An overall authorized credit limit is set for each bank and is divided among the subsidiaries and the Group’s central treasury entities according to their needs.

(vi)

Stock Market risk

The Group holds interests in a number of publicly-traded companies (see Note 13 to the Consolidated Financial Statements). The market values of these holdings fluctuate due to various factors, including stock market trends, valuations of the sectors in which the companies operate, and the economic and financial condition of each individual company.

(vii)

Liquidity risk

TOTAL S.A. has confirmed lines of credit granted by international banks, which would allow it to manage its short-term liquidity needs as required.

The total amount of these lines of credit as of December 31, 2006, was $7,701 million, of which $7,649 million was unused. The terms and availability of these lines of credit are not conditioned on the Company’s financial ratios, its financial ratings or on the absence of events that could have a material adverse impact on its financial situation. The total amount, as of December 31, 2006, of confirmed lines of credit granted by international banks to Group companies, including TOTAL S.A., was $11,638 million of which $9,268 million was unused. Lines of credit given to Group companies other than TOTAL S.A. are not used for general Group purposes. They are used to finance general activities of that company or for specific projects.

F-60

The following table shows the maturity of the financial assets and debts of the Group as of December 31, 2006 (see Note 20 to the Consolidated Financial Statements).


ASSETS/(LIABILITIES) As of December 31, 2006 (M€)	Less than 1 year		Between 1 year and 5 years		More than 5 years		Total
Financial debt after swaps	(2,025	)	(10,733	)	(2,955	)	(15,713	)
Cash and cash equivalents	2,493		—		—		2,493
Net amount	468		(10,733	)	(2,955	)	(13,220	)

ASSETS/(LIABILITIES) As of December 31, 2005 (M€)	Less than 1 year		Between 1 year and 5 years		More than 5 years		Total
Financial debt after swaps	(3,619	)	(9,057	)	(4,259	)	(16,935	)
Cash and cash equivalents	4,318		—		—		4,318
Net amount	699		(9,057	)	(4,259	)	(12,617	)

30. OTHER RISKS AND CONTINGENT LIABILITIES

TOTAL is not currently aware of any event, litigation, risks or contingent liabilities that could materially adversely affect the financial condition, assets, results or business of the Group.

Antitrust Investigations

1) Following investigations into certain commercial practices in the chemicals industry in the United States, certain chemical subsidiaries of the Arkema group are involved in several civil liability lawsuits in the United States and Canada for violations of antitrust laws. TOTAL S.A. has been named in certain of these suits as the parent company.

In Europe, the European Commission commenced investigations in 2000, 2003 and 2004 into alleged anti-competitive practices involving certain products sold by Arkema⁽¹⁾ or its subsidiaries. In January 2005, under one of these investigations, the European Commission fined Arkema 13.5 M€ and jointly fined Arkema and Elf Aquitaine 45 M€. Arkema and Elf Aquitaine have appealed these decisions to the Court of First Instance of the European Union.

held jointly and severally liable for, respectively, 65.1 M€ and 181.35 M€ of these fines while TOTAL S.A. was held jointly and severally liable, respectively, for 42 M€ and 140.4 M€. TOTAL S.A., Elf Aquitaine and Arkema have appealed these decisions to the Court of First Instance of the European Union.

No facts have been alleged that would implicate TOTAL S.A. or Elf Aquitaine in the practices questioned in these proceedings and the fines received are based solely on their status as parent companies.

2) As part of the agreement relating to the spin-off of Arkema, TOTAL S.A. or certain other Group companies agreed to grant Arkema guarantees for certain risks related to antitrust proceedings arising from events prior to the spin-off.

These guarantees cover, for a period of ten years, 90% of amounts paid by Arkema related to (i) fines imposed by European authorities or European member-state for competition law violations, (ii) fines imposed by American courts or antitrust authorities for federal antitrust violations or violations of the competition laws of U.S. states, (iii) damages awarded in civil proceedings related to the government proceedings mentioned above, and (iv) certain costs related to these proceedings.

(1)

Arkema is used in this section to designate those companies of the Arkema group whose ultimate parent company is Arkema S.A. Arkema became an independent company after being spun-off from TOTAL S.A. in May 2006.

F-61

The guarantee covering anticompetition violations in Europe applies to amounts that rise above a 176.5 M€ threshold.

If one or more individuals or legal entities, acting alone or together, directly or indirectly holds more than one third of the voting rights of Arkema, or if the Arkema transfers more than 50% of its assets (as calculated under the enterprise valuation method, as of the date of the transfer) to a third party or parties acting together, irrespective of the type or number of transfers, these guarantees will become void.

On the other hand, the agreements provide that Arkema will indemnify TOTAL S.A. or any Group company for 10% of any amount that TOTAL S.A. or any such Group company is required to pay under any of the proceedings covered by these guarantees.

3) The Group has recorded provisions amounting to 138 M€ in its consolidated accounts as of December 31, 2006 to cover the risks mentioned above.

4) Moreover, as a result of investigations started by the European Commission in October 2002 concerning certain Refining & Marketing subsidiaries of the Group, TOTAL Nederland N.V. received a statement of objections in October 2004. A statement of objections regarding these practices has also been addressed to TOTAL S.A. These proceedings resulting in Total Nederland NDV being fined 20.25 M€ and in TOTAL S.A. being held jointly responsible for 13.5 M€ of this amount, although no facts implicating TOTAL S.A. in the practices under investigation were alleged.

TOTAL S.A. and Total Nederland N.V. have appealed this decision to the Court of First Instance of the European Union.

5) Given the discretionary powers granted to the European Commission for determining fines, it is not currently possible to determine with certainty the outcome of these investigations and proceedings. TOTAL S.A. and Elf Aquitaine are contesting their liability and the method of determining these fines. Although it is not possible to predict the outcome of these proceedings, the Group believes that they will not have a material adverse affect on its financial condition or results.

BUNCEFIELD

HSE report detailing the circumstances and the exact cause of the explosion is expected to be released before the end of this year. At this stage, responsibility for the explosion has not yet been determined.

VENEZUELA

In Venezuela, on March 31, 2006, the government terminated all operating contracts signed in the 1990s and decided to transfer the management of fields concerned to new mixed companies to be created with the state-owned company PDVSA (Petroleos de Venezuela S.A.) as the majority owner. The government and the Group did not reach an agreement on the terms of the transfer of operation of the Jusepin field under the initial timetable and negotiations to resolve the situation are ongoing.

The government has expressed its intention to apply the law on hydrocarbons of 2001 to the “Strategic Associations” which operate the extra-heavy oil from the Orinoco region to create new mixed companies with PDVSA as the majority owner. Discussions regarding the Sincor project are underway.

The Venezuelan government has modified the initial agreement for the Sincor project several times. In May, 2006, the organic law on hydrocarbons was amended with immediate effect to establish a new extraction tax, calculated on the same basis as for royalties and bringing the overall tax rate to 33.33%. In September, 2006, the corporate income tax was modified to increase the rate on oil activities (excluding natural gas) to 50%. This new tax rate will come into effect in 2007.

In 2006, the Group received two corporation tax adjustment notices. The first concerned the company holding the Group’s interest in the Jusepin operating contract, for which the 2001-2004 examination was closed in the first half 2006, whereas the examination for 2005 is still underway. The second is related to the company holding the Group’s interest in the Sincor project, for which the Group is awaiting an answer from the tax authorities regarding the observations provided by the Group concerning 2001.

31. OTHER INFORMATION

A) RESEARCH AND DEVELOPMENT COSTS

Research and development costs incurred by the Group in 2006 amounted to 569 M€, corresponding to 0.4% of the turnover.

The staff dedicated in 2006 to these research and development activities are estimated at 4,091 people.

F-62

B) TAXES PAID TO MIDDLE EAST OIL-PRODUCING COUNTRIES FOR THE PORTION WHICH TOTAL HELD HISTORICALLY AS CONCESSIONS

Taxes paid for the portion that TOTAL held historically as concessions (Abu Dhabi offshore and onshore, Dubai offshore, Oman and Abu Al Bu Khoosh) included in operating expenses amounted to 2,906 M€ in 2006 (2,242 M€ in 2005).

C) EMISSION RIGHTS

The principles governing the accounting for Emission Rights are presented in paragraph T of Note 1 to the consolidated financial statements.

At December 31, 2006, the Emission Rights delivered to Group sites were sufficient with respect to the emissions in 2006. Thus, the Group recognized no provisions for allowances to be returned.

32. SPIN-OFF OF ARKEMA

The spin-off of Arkema led to the distribution of Arkema shares to TOTAL shareholders (other than TOTAL S.A). This operation can be analyzed as an exchange of non-monetary assets for TOTAL S.A. shareholders.

As IFRS does not contain specific rules for this type of transaction, the accounting treatment of the spin-off in TOTAL’s consolidated financial statements has been based on U.S. GAAP, and more particularly on opinion APB 29 (Accounting Principles Board Opinions) “Accounting for Non-monetary Transactions”.

All assets and liabilities which were spun off have been derecognized on the basis of their net book value, with a corresponding decrease of consolidated shareholders’ equity and no impact on the Group’s consolidated net income.

The spin-off of Arkema was approved by the shareholders’ meeting held on May 12, 2006. Since Arkema’s results for the period between April 1, 2006 and May 12, 2006, were not material, the deconsolidation has been completed on the basis of Arkema book values as of March 31, 2006, also taking into account the capital increase that took place in April 2006.

In accordance with IFRS 5 “Non-current assets held for sale and discontinued operations”, the contribution of Arkema entities has been reported as discontinued operations since Arkema can be clearly distinguished and has been spun off in a single and coordinated plan.

Financial information related to the Arkema’s contribution to the consolidated accounts of the Group is presented below. This contributive information is not directly comparable to the combined and pro-forma accounts filed by Arkema for the purpose of the public listing of its shares, as the latter have been based on specific conventions mainly related to the consolidation perimeter, accounting options and indicators.

Tax losses of Arkema entities, as they occurred, have been used in the consolidated tax return of the Group.


Statement of income For the year ended December 31, (M€)	2006		2005		2004
Revenues from sales	1,497		5,561		5,156
Purchases and other operating expenses	(1,377	)	(5,274	)	(4,869	)
Depreciation of tangible assets	(53	)	(404	)	(627	)

Operating income	67		(117	)	(340	)
Equity in income (loss) of affiliates, others	(42	)	(325	)	(325	)
Taxes	(30	)	(19	)	(33	)
Net Income	(5	)	(461	)	(698	)

Balance sheet As of December 31, (M€)	2006^(a)		2005		2004
Non-current assets	1,995		2,011		2,160
Working capital	1,501		1,337		1,129
Provisions and other non-current liabilities	(1,090	)	(1,116	)	(1,230	)
Capital employed	2,406		2,232		2,059
Net debt	(144	)	(551	)	(1,221	)
Shareholders’ equity	2,262		1,681		838

(a)

Detailed assets and liabilities which have been spun-off as of May 12, 2006.

F-63


Statement of cash flows For the year ended December 31, (M€)	2006		2005		2004
Cash flow from operating activities	53		(348	)	(41	)
Cash flow used in investing activities	(76	)	(263	)	(261	)
Cash flow from financing activities	(109	)	(18	)	(17	)
Net increase/decrease in cash and cash equivalents	(132	)	(629	)	(319	)
Effect of exchange rates and changes in reporting entity	113		622		327
Cash and cash equivalents at the beginning of the period	84		91		83
Cash and cash equivalent at the end of the period	65		84		91

Earnings per share and diluted earnings per share are presented below for continuing and discontinued operations.


Earnings per share (€)	2006	2005		2004
Earnings per share of continuing operations	5.13	5.42		4.78
Earnings per share of discontinued operations	0.00	(0.19	)	(0.28	)
Earnings per share	5.13	5.23		4.50

Diluted earnings per share (€)	2006	2005		2004
Diluted earnings per share of continuing operations	5.09	5.39		4.76
Diluted earnings per share of discontinued operations	—	(0.19	)	(0.28	)
Diluted earnings per share	5.09	5.20		4.48

F-64

33. LIST OF THE PRINCIPAL CONSOLIDATED SUBSIDIARIES AS OF DECEMBER 31, 2006

As of December 31, 2006, 718 subsidiaries were consolidated of which 614 were fully consolidated, 13 were proportionately consolidated (P) and 91 were accounted for under the equity method (E).

The following is a list of the principal consolidated subsidiaries:


UPSTREAM			UPSTREAM (continued)
Brass Holdings Company Ltd		(99.8%)	Total E & P Nederland B.V.	(99.8%)
CDF Energie		(100%)	Total E & P Nigeria	(100%)
Deer Creek Energy		(100%)	Total E & P Norge AS	(99.8%)
Elf Exploration Production		(99.5%)	Total E & P Oman	(99.8%)
Elf Petroleum Iran		(99.8%)	Total E & P Qatar	(99.8%)
Elf Petroleum Nigeria Ltd.		(99.8%)	Total E & P Qatargas II Holdings Ltd	(99.8%)
Qatar Liquefied Gas Co. Ltd II	E	(8.3%)	Total E & P Russie	(99.8%)
Qatar Liquefied Gas Company Ltd	E	(10.0%)	Total E & P Syrie	(99.8%)
Tepma Colombie		(99.8%)	Total E & P Thailand	(99.8%)
Total (BTC) Ltd		(99.8%)	Total E & P USA, Inc.	(100%)
Total Abu Al Bu Khoosh		(99.8%)	Total E & P Yémen	(99.8%)
Total Austral		(99.8%)	Total Energie Développement	(100%)
Total Coal International		(100%)	Total Energie Gaz	(99.5%)
Total Coal South Africa Ltd		(100%)	Total Gabon	(58.0%)
Total E & P Algérie		(99.8%)	Total Gas & Power North America	(100%)
Total E & P Angola		(99.8%)	Total Gasandes S.A.	(100%)
Total E & P Australia		(100%)	Total Gaz & Electricité Holdings France	(99.5%)
Total E & P Azerbaidjan B.V.		(99.8%)	Total Holdings Nederland B.V.	(99.8%)
Total E & P Bolivie		(99.8%)	Total Infrastructures Gaz France	(99.5%)
Total E & P Bornéo B.V.		(99.8%)	Total LNG Angola	(99.8%)
Total E & P Cameroun		(75.4%)	Total LNG Nigeria Ltd	(99.5%)
Total E & P Canada Ltd		(100%)	Total Midstream UK Ltd	(99.8%)
Total E & P Chine		(100%)	Total Oil & Gas Venezuela B.V.	(99.8%)
Total E & P Congo		(99.5%)	Total Profils Pétroliers	(99.8%)
Total E & P France		(99.5%)	Total Qatar Oil & Gas	(99.8%)
Total E & P Indonésie		(99.8%)	Total Sirri	(99.8%)
Total E & P Kazakhstan		(100%)	Total South Pars	(99.8%)
Total E & P Libye		(99.8%)	Total Upstream UK Ltd	(99.8%)
Total E & P Mauritanie		(100%)	Total Venezuela	(100%)
Total E & P Myanmar		(99.8%)

F-65


DOWNSTREAM			CHEMICALS
Air Total International		(100%)	Atotech BV		(99.8%)
AS24		(99.8%)	Bostik Holding S.A.		(99.5%)
Atlantic Trading & Marketing		(100%)	Bostik S.A.		(99.5%)
CEPSA	E	(48.6%)	Cray Valley S.A.		(100%)
Chartering & Shipping Services S.A.		(100%)	Grande Paroisse S.A.		(99.5%)
S.A. de la Raffinerie des Antilles	P	(50.0%)	Hutchinson Corporation		(100%)
Socap International		(99.5%)	Hutchinson S.A.		(100%)
Total (Africa) Ltd		(99.5%)	Qatar Petrochemical Company Ltd	E	(19.9%)
Total (China) Investments		(100%)	Qatofin Company Ltd	E	(48.8%)
Total (Philippines) Corp.		(99.8%)	Rosier		(56.6%)
Total Belgium		(100%)	Samsung-Total Petrochemicals	P	(49.9%)
Total Deutschland GmbH		(99.8%)	Total Petrochemicals France		(99.5%)
Total Fluides		(99.8%)	Total Petrochemicals Iberica		(100%)
Total France		(99.8%)	Total Petrochemicals USA		(100%)
Total International Ltd.		(100%)
Total Italia		(99.8%)	CORPORATE AND OTHER ACTIVITIES
Total Kenya		(78.3%)	Elf Aquitaine		(99.5%)
Total Lubrifiants S.A.		(99.8%)	Elf Aquitaine Fertilisants		(99.5%)
Total Mineralöl und Chemie GmbH		(99.8%)	Omnium des Participations S.A.		(100%)
Total Nederland N.V.		(99.8%)	Omnium Insurance and Reinsurance Cy		(100%)
Total Nigeria		(61.6%)	Petrofina S.A.		(100%)
Total Outre-Mer		(100%)	Sanofi-Aventis	E	(13.1%)
Total Raffinaderij Nederland	P	(55.0%)	Socap Ltd		(99.5%)
Total Raffinerie Mitteldeutschland		(99.8%)	Sofax Banque		(99.5%)
Total Sénégal		(94.9%)	Total Capital		(100%)
Total South Africa		(66.8%)	Total Chimie		(100%)
Total South East Asia		(99.8%)	Total E & P Holdings		(99.8%)
Total Turkiye		(99.9%)	Total Finance S.A.		(100%)
Total UK Ltd		(99.8%)	Total Holdings Europe		(99.8%)
TotalGaz		(99.8%)	Total Holdings UK Ltd		(99.8%)
TotalGaz Argentina		(99.8%)	Total Holdings USA, Inc.		(100%)
TOTSA Total Oil Trading S.A.		(99.5%)	Total Treasury		(100%)
Urbaine des Pétroles		(99.8%)

34. SUMMARY OF DIFFERENCES BETWEEN ACCOUNTING PRINCIPLES FOLLOWED BY THE COMPANY AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The accompanying consolidated financial statements have been prepared in accordance with IFRS, which differ in certain respects from accounting standards applicable in the United States of America (“U.S. GAAP”).

These differences have been reflected in the financial information set forth in paragraph M below and mainly relate to the following items.

A. Business combinations

Pursuant to an exemption provided by IFRS1 “First time adoption of International Financial Reporting Standards”, the Group elected not to restate business combinations completed prior to January 1, 2004, in accordance with IFRS 3 “Business Combinations”.

(i) Acquisition of PetroFina and Elf

Under U.S. GAAP, the acquisitions of PetroFina and Elf did not qualify as pooling-of-interests and therefore would have been accounted for as purchases. The cost of the acquisition was allocated on the basis of the estimated fair value of the assets acquired and liabilities assumed. Independent valuations were performed for the major subsidiaries of PetroFina and Elf; those valuations were validated by in-house analysis for determining the estimated fair value of oil and gas properties acquired.

F-66

The main differences between IFRS and U.S. GAAP resulting from the purchase price allocation of PetroFina and Elf were as follows:

•

Equity investees revaluations: Under IFRS, equity investees held by PetroFina and Elf were maintained at their carrying value in the consolidated financial statements as authorized under IFRS. Under U.S. GAAP, these investees were recorded at fair value as part of the purchase price allocation. This line item primarily includes the difference between the fair market value and the carrying value of Sanofi-Synthelabo and CEPSA at the date of acquisition of Elf. For U.S. GAAP purposes, this difference was amortized on a straight line basis over 30 years until December 31, 2001 when amortization was suspended upon adoption of FAS No. 141 and 142. U.S. GAAP adjustments to net income also include the impact of the sale of interest in these equity investees.

This caption also includes an additional net charge of 1,475 M€ for the year ended December 31, 2004 related to the Sanofi-Aventis gain on dilution as the carrying value of the equity interest under U.S. GAAP was higher than under IFRS.

•

Goodwill on consolidated companies: This line item includes the non-allocated portion of the purchase price of Elf and PetroFina. Under IFRS, no goodwill was recognized as a result of these acquisitions. Under U.S. GAAP, this goodwill was amortized on a straight line basis over 30 years until December 31, 2001 when amortization was suspended upon adoption of FAS No. 141 and 142. The remaining difference in net income for the years ended December 31, 2005 and 2004, between IFRS and U.S. GAAP corresponds to the subsequent realization of pre-acquisition tax losses carried forward.

This caption also includes impairment charges recorded in the Chemicals segment of 686 M€ and 1,245 M€ for the years ended December 31, 2005 and 2004, respectively (refer to paragraph A(ii)).

•

Property, plant and equipment revaluation: This line item represents the portion of the Elf and PetroFina purchase price that was allocated to fixed assets. It includes primarily Upstream properties, plant and equipment for which fair market value was determined based on future cash flows generated by proved reserves and risk adjusted probable reserves.

(ii) Business Combinations—Goodwill and Other Intangible Assets

Under U.S. GAAP and effective July 1, 2001, the Group adopted FASB Statement No. 141, “Business Combinations” (“FAS No. 141”) which requires that all business combinations be accounted for under the purchase method of accounting. FAS No. 141 also specifies the types of acquired intangible assets that are required to be recognized and reported separate from goodwill.

Effective January 1, 2002, the Group adopted for U.S. GAAP reporting purposes FASB Statement No. 142 “Goodwill and Other Intangible Assets” (“FAS No. 142”) for all acquired goodwill and intangible assets. Under FAS No. 142, goodwill is no longer amortized but is tested for impairment on at least an annual basis. Intangible assets with indefinite lives are also no longer amortized but instead are tested for impairment at least annually. Intangible assets with finite lives are amortized over their estimated useful life. Goodwill acquired after June 30, 2001 has been subject to non-amortization provisions since the acquisition date.

Additionally, goodwill on equity method investments is no longer amortized in U.S. GAAP since January 1, 2002. However it continues to be tested for impairment in accordance with APB No. 18 “The Equity Method of Accounting for Investments in Common Stock”. Under IFRS, goodwill amortization ceased from January 1, 2004.

In accordance with FAS No. 142, the impairment test for goodwill involves a two-step process. Step one consists of a comparison of a reporting unit’s fair value to its carrying value, the fair value being the sum of discounted future cash flows generated by the reporting unit. If the carrying value is greater than its fair value, then step two must also be completed. Step two requires a computation of the implied fair value of a reporting unit’s goodwill in comparison to the carrying amount of goodwill. Any excess of the carrying amount of goodwill over its implied fair value must be recorded as an impairment charge. The Group completed the annual goodwill impairment tests required by FAS No. 142 in the fourth quarters of 2004, 2005 and 2006.

As of December 31, 2004 and December 31, 2005, the fair values calculated exceeded their carrying values for all reporting units except in the Chemicals segment. In the Chemicals segment, impairments were triggered by a deterioration in the market conditions for commodity Chemicals. As a result, net impairment charges of 875 M€ and 1,245 M€ were recorded for the years ended December 31, 2005 and December 31, 2004 respectively.

F-67

When compared to the charge recorded under IAS 36, this represents additional impairment charges of 825 M€ and 1,245 M€ for 2005 and 2004, respectively, which is detailed as follows:


	For the year ended December 31,
(M€)	2006	2005		2004
A(i) Business combinations—Acquisition of PetroFina and Elf Aquitaine	—	(686	)	(1,245	)
A(ii) Business combinations—Goodwill and Other Intangible Assets	—	(139	)	—
Total	—	(825	)	(1,245	)

This additional impairment charge is explained by the higher carrying amount of goodwill under U.S.GAAP as compared to IFRS.

There are no other intangible assets with indefinite useful lives and all intangible assets other than goodwill are subject to amortization.

The components of other intangible assets were as follows:


	As of December 31,
(M€)	2006		2005		2004
Amortized intangible assets
Gross carrying amount	2,386		2,851		2,670
Accumulated amortization	(1,776	)	(2,047	)	(1,901	)
Total other intangible assets, net	610		804		769

A summary of changes in the carrying amount of goodwill by business segment for the year ended December 31, 2006 is as follows (net of accumulated amortization):


(M€)	As of January 1, 2006	Acquisitions	Impairment	Other^(a)		As of December 31, 2006
Upstream	15,561	—	—	(9	)	15,552
Downstream	11,406	24	—	(15	)	11,415
Chemicals	2,970	101	—	(160	)	2,911
Total	29,937	125	—	(184	)	29,878

(a)

The caption “Other” mainly consists of the impact of the foreign currency translation of (62) M€ and the impact of the Arkema spin-off for (106) M€.

B. Financial Instruments

The difference between U.S. GAAP and IFRS relates to currency and interest rate swaps that were contracted by the Group as part of the issuance of most debenture loans issued to finance the Upstream activity. A significant portion of long-term debentures are issued in, or converted to U.S. dollars as the cash flows of the Upstream activity are mainly denominated in U.S. dollars. Depending on market conditions, debenture loans may be issued in euros or other European currencies at fixed rates which are immediately swapped into U.S. dollar floating rate debt.

Under IFRS, these currency and interest rate swaps qualify as fair value hedges:

•

of the corresponding debt for their interest rate component,

•

and of the associated U.S. dollar intercompany loan for their foreign currency component.

Such hedge accounting based on a split of a derivative into several components, is not allowed under FAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”. In addition, these currency and interest rate swaps, which were entered into for hedging purposes do not meet the criteria for classification as hedges under FAS No. 133.

As a consequence, hedge accounting has not been applied to such derivatives in the reconciliation to U.S. GAAP.

C. Impairment of assets

Under IFRS, the Group follows IAS 36 “Impairment of Assets”, whereas under U.S. GAAP, it follows FAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets”. IAS 36 provides for assets to be tested for impairment purposes by comparing the assets’ carrying value with the higher of the fair value less costs to sell or its value in use. The value in use is based on the associated discounted future cash flows.

F-68

Under U.S. GAAP, an initial step is required whereby the carrying value is compared with the undiscounted future cash flows. An impairment is recognized only if the carrying value is greater than the undiscounted cash flows.

The different methods under the two standards result in the impairment of certain fixed assets under IFRS but not under U.S. GAAP. As a result, these assets are impaired under IFRS but are still being amortized under U.S. GAAP.

D. Employee benefit obligations

Pursuant to an exemption provided by IFRS 1 “First-time adoption of IFRS”, the Group has elected to record unrecognized actuarial gains and losses as of January 1, 2004 to retained earnings.

Under U.S. GAAP, this exemption is not applicable and generates a difference relating to the amortization of actuarial gains and losses recognized in income.

Under IFRS, in accordance with IAS 19, the Group applies the corridor method to amortize its actuarial gains and losses. The unrecognized gains and losses are amortized over the average expected remaining working lives of the employees participating in the plan.

Under U.S. GAAP, pursuant to the amendment provided by FAS 158 “Employers’ Accounting for Defined Benefit

Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)”, surpluses and deficits of funded schemes for pension and other post-retirement benefits are recognized as assets and liabilities in the financial statements and changes in that funded status are recognized through comprehensive income in the year in which the changes occur. Therefore, all unrecognized actuarial gains and losses, prior service costs and credits and net transition obligations as well as subsequent changes in the funded status are accounted for as a component of accumulated other comprehensive income, net of tax and are subsequently recognized as a component of net periodic benefit costs in accordance with FAS 87 “Employers’ Accounting for Pensions” and FAS 106 “Employers’ Accounting for Postretirement Benefits other than Pensions”, using the corridor method.

The provisions of FAS 158, which is effective as of December 31, 2006, amend the provisions of FAS 87 “Employers’ Accounting for Pensions” which notably required the recognition of a minimum liability adjustment when a pension plan had an unfunded accumulated benefit obligation.

The effect of the transition from the provisions of FAS 87 and FAS 106 to those of FAS 158, net of tax, is recognized as part of accumulated other comprehensive income as of December 31, 2006 and is reported below:


(M€)	Before Application of Statement 158		Adjustments		After Application of Statement 158
Other non-current assets	18,324		515		18,839
Other non-current liabilities	17,161		1,526		18,687
Accumulated other comprehensive income	(4,789	)	(1,011	)	(5,800	)
Total shareholders’ equity	72,895		(1,011	)	71,884

The estimated amount of actuarial losses, prior service cost and net transition asset that will be recognized as a component of net benefit cost in 2007 is 114 M€.

E. Stock Compensation

For the years ended December 31, 2006 and December 31, 2005

Under IFRS, the Group applies IFRS 2 “Share-based payment” to employee stock options and share purchase plans and to capital increases reserved for employees. The benefits are determined at fair value by reference to the granted instruments. The fair value of the options is calculated using the Black-Scholes method at the grant date. The expense is allocated on a straight-line basis between the grant date and vesting date. The cost of employee-reserved capital increases is immediately expensed.

Under U.S. GAAP, the Group elected to adopt FAS No. 123(R) “Share-Based Payments” on January 1, 2005, using the “modified prospective” method. This is a change in accounting principles as the Group previously accounted for stock-based compensation based on the provisions of APB No. 25. Compensation cost is recognized beginning with the effective date (January 1, 2005) (i) based on the requirements of Statement 123(R) for all share-based payments granted after the effective date and (ii) based on the requirements of Statement 123 for all awards granted to employees prior to the effective date of Statement 123(R) that remain unvested on the effective date.

The respective recognition and measurement provisions of IFRS 2 and FAS No. 123(R) did not generate a reconciling item for the years ended December 31, 2006 and 2005.

F-69

For the year ended December 31, 2004

Under IFRS, the Group applied IFRS 2 “Share-based payment” to employee stock option and share purchase plans and to capital increases reserved for employees.

Under U.S. GAAP, the Company elected to continue to account for stock-based compensation based on the provisions of APB No. 25. Compensation cost for share subscription plans, share purchase plans and capital increases reserved to employees, if any, was measured as the excess of the quoted market price of the Company’s stock at the date of grant over the amount an employee must pay to acquire the stock.

F. Trading Inventories

Under IFRS, inventories held by the Group for its energy trading activities are measured at fair value less costs to sell, based on the scope exception provided by paragraph 3 b) of IAS 2 “Inventories” for commodity broker-traders.

Under U.S. GAAP, EITF No.02-3 “Issues involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” prohibits measurement at fair value of physical inventories included in energy trading activities.

G. Tax effect of intercompany transfers

Profits resulting from inter-company transfers of inventories are eliminated from net income and from the carrying value of inventories that remain within the Group.

Under IFRS, a deferred tax asset is recognized for the difference between the new tax basis of the inventories in the buyer’s jurisdiction and their carrying value as reported in the consolidated financial statements. That deferred tax is computed using the buyer’s tax rate.

U.S. GAAP prohibits recognition of such a deferred tax asset, but requires taxes computed and paid by the seller to be deferred and recognized when inventories are sold to a third party.

H. Change in accounting policies

For the year ended December 31, 2005

Under IFRS, the Group has applied the component-based approach of IAS 16 “Property, Plant and Equipment” for tangible assets since January 1, 2004, which resulted in a change in accounting for major turnarounds at refineries and large petrochemical units as compared to the accounting previously applied under

French GAAP. Previously, the Group had accrued these costs in advance but under IAS 16 these costs are capitalized at the time of expenditure and amortized over the period between major turnarounds. This change also leads to the reclassification of the related cash flows from operating to investing activities in the consolidated statement of cash flows. These changes were effective January 1, 2005; thus the 2005 income statement is prepared under the new method. In addition, the 2004 comparatives (previously reported under French GAAP with turnarounds accrued in advance) are also restated to reflect the new accounting method.

Under U.S. GAAP, the Group changed its accounting policy from the accrual method to the built-in overhaul method as of January 1, 2005. The change in accounting represents a change in accounting policy as defined by APB No. 20 “Accounting Changes”, and a cumulative catch-up entry is recorded in the 2005 income statement.

This change primarily concerns the major refineries within the Downstream segment and, to a lesser extent, the petrochemical units within the Chemicals segment.

For the year ended December 31, 2005, the cumulative effect of this change had a positive impact under U.S. GAAP of 333 M€ on income before taxes and 238 M€ on net income.

I. Acquisition of Deer Creek

In 2005, TOTAL acquired 100% of Deer Creek Energy Ltd, a company whose sole asset is an 84% interest in the Joslyn permit in the Athabasca region of the Canadian Province of Alberta. The acquisition cost, net of cash acquired for all shares amounts to 1,104 M€. This cost primarily represents the fair value of the company’s leasehold rights that have been recognized under IFRS as intangible assets for 1,015 M€.

No deferred income tax liability has been recognized for the difference between the fair value of the leasehold rights acquired and their tax value in accordance with paragraph 15 of IAS 12 “Income taxes”.

However, as FAS 109—“Accounting for Income taxes” includes no initial recognition exception, a deferred income tax liability has been recognized in accordance with EITF 98-11 “Accounting for Acquired Temporary Differences in Certain Purchase Transactions That Are Not Accounted For As Business Combinations”.

Under U.S. GAAP, the amounts assigned to the leasehold rights and the related deferred income tax liability at the acquisition date was 1,562 M€ and (547) M€, respectively. This difference in accounting treatment has no impact on net equity.

F-70

J. Cumulative translation adjustment

Pursuant to an exemption provided by IFRS 1 “First-time adoption of IFRS”, the Group has elected to offset the cumulative translation adjustment (CTA) against retained earnings, as of January 1, 2004. That reclassification has no impact on shareholders’ equity, net income and their reconciliation to U.S. GAAP.

K. Leasehold rights

Under IAS 16, the Group has reclassified leasehold rights from “Property, plant and equipment” to “Intangible assets” as of January 1, 2004. Under U.S. GAAP, leasehold rights are accounted for as “Property, plant and equipment”, thus generating a classification difference between the IFRS and the U.S. GAAP balance sheet. This classification difference has no impact on the reconciliation of shareholders’ equity between IFRS and U.S. GAAP.

L. Arkema spin-off

The spin-off of Arkema led to the distribution of Arkema shares to TOTAL shareholders (other than TOTAL S.A itself). This operation is analyzed as a distribution of non monetary assets to TOTAL shareholders.

Due to certain U.S. GAAP adjustments described above, the amount of the assets and liabilities which were spun off under U.S. GAAP differs from that under IFRS. These differences have an impact on the reconciliation of

shareholders’ equity between IFRS and U.S. GAAP, which is summarized as follows:


(M€)	As of December 31, 2006
Net assets distributed - IFRS	(2,254	)
Impairment of assets (C)	(60	)
Employee benefit obligations (D)	(62	)
Tax effect of U.S. GAAP adjustments	52
Cumulative translation adjustment of U.S. GAAP adjustments	17
Net assets distributed - U.S. GAAP	(2,307	)

In addition, under U.S. GAAP, the spin-off resulted in a reduction of the difference in cumulative translation adjustment between U.S. GAAP and IFRS amounting to (172) M€ and accumulated before January 1, 2004. Under IFRS, this cumulative translation adjustment had been offset against retained earnings as of January 1, 2004 as described in paragraph J. This reduction has no impact on shareholders’ equity and its reconciliation to U.S. GAAP as of December 31, 2006, December 31, 2005 and December 31, 2004.

The spin-off of Arkema was approved at the shareholders’ meeting held on May 12, 2006. Since Arkema’s results for the period between April 1, 2006 and May 12, 2006 were not material, they have only been consolidated up to March, 31, 2006.

Due to certain U.S. GAAP adjustments described above, income from discontinued operations under U.S. GAAP differs from that determined under IFRS:


(M€)	For the year ended December 31, 2006		For the year ended December 31, 2005		For the year ended December 31, 2004
Income (loss) from discontinued operations under IFRS	(5	)	(461	)	(698	)
Business combinations - Acquisition of PetroFina and Elf (A)(i)	—		(686	)	(1,245	)
Business combinations - Goodwill and Other Intangible Assets (A)(ii)	—		(139	)	—
Impairment of assets (C)	(1	)	(7	)	54
Employee benefit obligations (D)	(3	)	(5	)	(28	)
Tax effect of U.S. GAAP adjustments	1		3		(18	)
Income (loss) from discontinued operations under U.S. GAAP	(8	)	(1,295	)	(1,935	)

F-71

M. Reconciliation to U.S. GAAP

(i) Net Income and Shareholders’ equity

The following is a summary of the adjustments to net income for the years ended December 31, 2006, December 31, 2005, and December 31, 2004, as well as the shareholders’ equity for the periods ended December 31,2006, December 31, 2005, and December 31, 2004, which would be required if U.S. GAAP had been applied instead of IFRS.

These U.S. GAAP adjustments are presented net of the portion applicable to minority interests.


	Shareholders’ equity
	As of December 31,
(M€)	2006		2005		2004
Amounts per accompanying consolidated financial statements	40,321		40,645		31,608
U.S. GAAP adjustments
Increase (decrease) due to:
Equity investees revaluations, net	1,550		1,506		1,256
Goodwill on consolidated companies	28,517		28,517		29,278
Property, plant and equipment revaluation	2,939		3,302		3,643
Total Acquisition of Petrofina and Elf (A)(i)	33,006		33,325		34,177
Business combinations—Goodwill and Other Intangible Assets (A)(ii)	404		407		537
Financial instruments (B)	(64	)	200		296
Impairment of assets (C)	91		158		345
Employee benefit obligations (D)	(597	)	240		676
Trading inventories (F)	(18	)	(28	)	—
Tax effect of intercompany transfers (G)	162		—		—
Effect of change in accounting policies (H)	—		—		(333	)
Other	—		(24	)	63
Tax effect of U.S. GAAP adjustments	(1,380	)	(1,887	)	(2,238	)
Cumulative translation adjustment of U.S. GAAP adjustments	(41	)	19		(23	)
Amounts under U.S. GAAP	71,884		73,055		65,108


	Net income
	For the year ended December 31,
(M€)	2006		2005		2004
Amounts per accompanying consolidated financial statements	11,768		12,273		10,868
U.S. GAAP adjustments
Increase (decrease) due to:
Equity investees revaluations, net	(18	)	255		(2,130	)
Goodwill on consolidated companies^(a)	—		(761	)	(1,362	)
Property, plant and equipment revaluation	(365	)	(341	)	(374	)
Other purchase accounting adjustments	—		—		(23	)
Total Acquisition of Petrofina and Elf (A)(i)	(383	)	(847	)	(3,889	)
Business combinations—Goodwill and Other Intangible Assets (A)(ii)	(3	)	(139	)	—
Financial instruments (B)	(221	)	(96	)	(32	)
Impairment of assets (C)	(7	)	(189	)	70
Employee benefit obligations (D)	(119	)	(182	)	(68	)
Stock compensation (E)	—		—		62
Trading inventories (F)	9		(27	)	—
Tax effect of intercompany transfers (G)	162		—		—
Effect of change in accounting policies (H)	—		333		—
Other	11		11		(77	)
Tax effect of U.S. GAAP adjustments	183		460		287
Amounts under U.S. GAAP	11,400		11,597		7,221

(a)

This caption includes impairment charges recorded in the Chemicals segment of 686 M€ and 1,245 M€ for the years ended December 31, 2005 and 2004, respectively.

F-72

(ii)

U.S. GAAP Consolidated Statements of Income

The U.S. GAAP summarized condensed consolidated statements of income for the years ended December 31, 2006, 2005, and 2004 presented below reflect the differences between U.S. GAAP and IFRS discussed above.


	For the year ended December 31,
(M€)	2006		2005		2004
Sales and other income	132,689		117,057		95,325
Total revenues	132,689		117,057		95,325
Crude oil and product purchases	83,326		69,820		56,019
Production, selling, general and administrative expenses	18,989		17,386		16,652
Depreciation, depletion and amortization	5,650		5,722		5,791
Unsuccessful exploration costs	634		431		414
Dividends on subsidiaries’ redeemable preferred shares	—		—		6
Interest expense (income), net	453		352		144
Other financial expense (income), net	80		(154	)	16
Taxes	1,079		854		683
Total expenses	110,211		94,411		79,725
Earnings from equity interests and affiliates	1,923		1,834		618
Gains (losses) on sales of assets	755		86		1,583
Income before taxes and minority interests	25,156		24,566		17,801
Income taxes	13,381		11,549		8,372
Income from continuing operations	11,775		13,018		9,429
Income (loss) from discontinued operations (Arkema)	(8	)	(1,295	)	(1,935	)
Income before minority interests	11,767		11,723		7,494
Minority interests	(367	)	(364	)	(273	)
Income before cumulative effect of accounting change	11,400		11,359		7,221
Cumulative effect of accounting change, net of tax	—		238
Net income	11,400		11,597		7,221
Basic earnings per share^(a)
Net earnings per share from continuing operations	4.97		5.39		3.79
Net earnings (loss) per share from discontinued operations	—		(0.55	)	(0.80	)
Net earnings per share before cumulative effect of accounting change	4.97		4.84		2.99
Cumulative effect of accounting change, net of tax	—		0.10		—
Net earnings per share—basic^(a)	4.97		4.94		2.99
Diluted earnings per share^(a)
Net earnings per share from continuing operations	4.93		5.36		3.78
Net earnings (loss) per share from discontinued operations	—		(0.55	)	(0.80	)
Net earnings per share before cumulative effect of accounting change	4.93		4.81		2.98
Cumulative effect of accounting change, net of tax	—		0.10		—
Net earnings per share—diluted^(a)	4.93		4.91		2.98

(a)

2005 and 2004 amounts are restated as per the four-for-one stock split that took place on May 18, 2006.

F-73

(iii)

U.S. GAAP Summarized Consolidated Balance Sheets

The U.S. GAAP summarized condensed consolidated balance sheets as of December 31, 2006, 2005, and 2004 presented below reflect the differences between U.S. GAAP and IFRS discussed above:


	As of December 31,
(M€)	2006		2005		2004
Assets
Current assets
Cash and cash equivalents	2,493		4,321		3,858
Accounts receivable	17,393		19,603		13,987
Inventories	11,729		12,662		9,310
Other current assets	11,155		7,145		5,335
Total current assets	42,770		43,731		32,490
Property, plant and equipment, net	47,058		47,131		40,065
Intangibles, net	30,488		30,741		31,541
Other non-current assets	18,839		19,369		18,141
Total assets	139,155		140,972		122,237
Liabilities and shareholders’ equity
Current liabilities
Accounts payable	15,080		16,409		11,672
Other liabilities	18,442		17,030		14,919
Total current liabilities	33,522		33,439		26,591
Non-current liabilities
Non-current debt, net of current portion	14,232		13,573		11,140
Other non-current liabilities	18,687		20,070		18,753
Total non-current liabilities	32,919		33,643		29,893
Minority interests	830		835		645
Shareholders’ equity:
Common shares	6,064		6,151		6,350
Paid-in surplus	35,195		37,072		40,524
Retained earnings	42,245		36,884		28,756
Accumulated other comprehensive income	(5,800	)	(2,621	)	(5,492	)
Treasury shares	(5,820	)	(4,431	)	(5,030	)
Total shareholders’ equity	71,884		73,055		65,108
Total liabilities and shareholders’ equity	139,155		140,972		122,237

F-74

(iv)

Additional information: income taxes

Breakdown between current and deferred income taxes is as follows:


	For the year ended December 31,
(M€)	2006		2005		2004
Current income taxes	(12,997	)	(11,362	)	(7,641	)
Deferred income taxes	(384	)	(187	)	(731	)
Total	(13,381	)	(11,549	)	(8,372	)

The components of deferred income tax balances under U.S. GAAP as of December 31, 2006, 2005, and 2004 are as follows:


	For the year ended December 31,
(M€)	2006		2005		2004
Net operating losses and tax credit carryforwards	633		484		933
Employee benefits	1,045		845		841
Other temporarily non-deductible provisions	2,319		2,652		2,279
Gross deferred income tax assets	3,997		3,981		4,053
Valuation allowance	(572	)	(536	)	(342	)
Net deferred income tax assets	3,425		3,445		3,711
Property, plant and equipment	(10,270	)	(10,012	)	(8,667	)
Other temporary tax deductions	(1,200	)	(1,514	)	(2,007	)
Gross deferred income tax liability	(11,470	)	(11,526	)	(10,674	)
Net deferred income tax liabilities	(8,045	)	(8,081	)	(6,963	)

Analysis of tax items in the U.S. GAAP balance sheet is as follows:


	For the year ended December 31,
(M€)	2006		2005		2004
Non-current deferred income tax assets	1,183		1,303		1,534
Current deferred income tax assets	94		126		232
Non-current deferred income tax liabilities	(9,192	)	(9,298	)	(8,621	)
Current deferred income tax liabilities	(130	)	(212	)	(108	)
Total	(8,045	)	(8,081	)	(6,963	)

F-75

(v)

Comprehensive income

The Company applies for U.S. GAAP purposes FAS No. 130, “Reporting Comprehensive Income”, which requires companies to report all changes in equity during a period, except those resulting from investment by owners and distribution to owners, in a financial statement for the period in which they are recognized. The Company discloses comprehensive income, which encompasses net income, foreign currency translation adjustments, unrealized gains or losses on the Company’s available for sale securities and the minimum pension liability adjustment, in the Consolidated Statement of Shareholders’ Equity.


(M€)	Comprehensive income		Common shares		Paid-in surplus		Retained earnings		Accumulated other comprehensive income		Treasury shares		Total shareholders’ equity
As of January 1, 2004			6,491		42,721		26,047		(4,119	)	(4,613	)	66,527
Net income^(a)	7,221						7,221						7,221
Other comprehensive income, net of tax
Unrealized foreign currency translation adjustments	(1,406	)
Realized foreign currency translation adjustments	—
Unrealized gains on equity securities	48
Gains on equity securities included in net income	(41	)
Minimum pension liability adjustment	26
Other comprehensive income	(1,373	)							(1,373	)			(1,373	)
Comprehensive income	5,848
Cash dividend							(4,293	)					(4,293	)
Issuances of common shares			58		680		(202	)					536
Stock compensation^(a)							76						76
Treasury shares^(a)			(199	)	(2,877	)	14				(417	)	(3,479	)
Other							(107	)					(107	)
As of December 31, 2004			6,350		40,524		28,756		(5,492	)	(5,030	)	65,108

(a)

Stock compensation cost and elimination of gains on treasury shares are reflected in net income above.

F-76


(M€)	Comprehensive income		Common shares		Paid-in surplus		Retained earnings		Accumulated other comprehensive income		Treasury shares		Total shareholders’ equity
As of January 1, 2005			6,350		40,524		28,756		(5,492	)	(5,030	)	65,108
Net income^(a)	11,597						11,597						11,597
Other comprehensive income, net of tax
Unrealized foreign currency translation adjustments	2,892
Realized foreign currency translation adjustments	—
Unrealized gains on equity securities	140
Gains on equity securities included in net income	—
Minimum pension liability adjustment	(161	)
Other comprehensive income	2,871								2,871				2,871
Comprehensive income	14,468
Cash dividend							(3,510	)					(3,510	)
Issuances of common shares			12		195		(107	)					100
Stock compensation^(a)							131						131
Treasury shares^(a)			(211	)	(3,647	)	34				599		(3,225	)
Other							(17	)					(17	)
As of December 31, 2005			6,151		37,072		36,884		(2,621	)	(4,431	)	73,055

(a)

Stock compensation cost and elimination of gains on treasury shares are reflected in net income above.

F-77


(M€)	Comprehensive income		Common shares		Paid-in surplus		Retained earnings		Accumulated other comprehensive income		Treasury shares		Total shareholders’ equity
As of January 1, 2006			6,151		37,072		36,884		(2,621	)	(4,431	)	73,055
Net income^(a)	11,400						11,400						11,400
Other comprehensive income, net of tax
Unrealized foreign currency translation adjustments	(2,686	)
Realized foreign currency translation adjustments	7
Unrealized gains on equity securities	104
Gains on equity securities included in net income	(214	)
Minimum pension liability adjustment	621
Other comprehensive income	(2,168	)							(2,168	)			(2,168	)
Comprehensive income	9,232
Cash dividend							(3,999	)					(3,999	)
Issuances of common shares			30		480		(11	)					499
Adjustment to initially apply FAS 158, net of tax									(1,011	)			(1,011	)
Minimum liability adjustment reversal: 452
Recognition of net actuarial gain (losses) and prior service credit (cost) on pension and other benefits: (1,463)
Stock compensation^(a)							157						157
Treasury shares^(a)			(117	)	(2,341	)					(1,405	)	(3,863	)
Arkema spin-off					(16	)	(2,307	)			16		(2,307	)
Other							121						121
As of December 31, 2006			6,064		35,195		42,245		(5,800	)	(5,820	)	71,884

(a)

Stock compensation cost and elimination of gains on treasury shares are reflected in net income above.

F-78

Disclosure of Accumulated Other Comprehensive Income Balances

The components of accumulated other comprehensive income (loss) balances are as follows:


	As of December 31,
	2006						2005						2004
(M€)	Pre-tax Amount		Tax Exp. (Credit)		Net Amount		Pre-tax Amount		Tax Exp. (Credit)		Net Amount		Pre-tax Amount		Tax Exp. (Credit)		Net Amount
Net foreign currency translation adjustments	(4,507	)	—		(4,507	)	(1,828	)	—		(1,828	)	(4,720	)	—		(4,720	)
Net unrealized gain (loss)	183		(13	)	170		360		(80	)	280		163		(23	)	140
Minimum pension liability adjustment	—		—		—		(1,624	)	551		(1,073	)	(1,353	)	441		(912	)
Net actuarial gain (loss) and prior service credit (cost) on pension and other benefits	(2,230	)	767		(1,463	)
Accumulated other comprehensive (loss) income	(6,554	)	754		(5,800	)	(3,092	)	471		(2,621	)	(5,910	)	418		(5,492	)

(vi) Gains on equity securities

Gross realized gains and gross realized losses on sales of available-for-sale securities were:


	As of December 31,
(M€)	2006		2005	2004
Gross realized gains	477		46	105
Gross realized losses	(6	)	—	(19	)

The carrying amount of available-for-sale securities and their approximate fair value were as follows:


(M€)	Cost	Gross Unrealized Gains	Gross Unrealized Losses	Fair Value
As of December 31, 2004	126	151	–	277
As of December 31, 2005	121	348	—	469
As of December 31, 2006	86	218	—	304

N. Accounting for exploratory drilling costs

In April 2005, the FASB issued a FASB Staff Position FSP FAS 19-1, “Accounting for suspended well costs” to amend FAS No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies”. The FSP is compatible with the IFRS accounting principles applied by TOTAL.

The FSP provides for continued capitalization of exploratory drilling costs past one year if a company is making sufficient progress on assessing the reserves and the economic and operating viability of the project. The FSP also provides certain disclosure requirements with respect to capitalized exploratory drilling costs.

As of January 1, 2005, TOTAL adopted FASB Staff Position FAS 19-1, “Accounting for Suspended Well Costs”. There were no capitalized exploratory well costs charged to expense upon the adoption of FSP 19-1.

F-79

Exploratory drilling costs are temporarily capitalized pending determination of whether the well has found proved reserves if both of the following conditions are met:

•

The well has found a sufficient quantity of reserves to justify, if appropriate, its completion as a producing well, assuming that the required capital expenditure is made; and

•

Satisfactory progress toward ultimate development of the reserves is being achieved, with the Company making sufficient progress assessing the reserves and the economic and operating viability of the project.

The Company evaluates the progress made on the basis of regular project reviews which take into account the following factors:

•

First, if additional exploratory drilling or other exploratory activities (such as seismic work or

other significant studies) are either underway or firmly planned, the Company deems there is satisfactory progress. For these purposes, exploratory activities are considered firmly planned only if they are included in the Company’s three-year exploration plan/budget. At December 31, 2006, the Company had capitalized 342 M€ of exploratory drilling costs on this basis, as further set forth below.

•

Capitalized exploratory costs

The following table sets forth the net changes in capitalized exploratory costs for 2006, 2005 and 2004:


(M€)	2006		2005		2004
Beginning Balance	590		430		422
Additions pending determination of proved reserves	569		192		269
Amounts previously capitalized and expensed during the year	(67	)	(65	)	(40	)
Amounts transferred to Development	(127	)	(22	)	(196	)
Foreign exchange changes	(73	)	55		(25	)
Ending balance	892		590		430

The following table sets forth a breakdown of capitalized exploratory costs at year end 2006, 2005 and 2004 by category of exploratory activity:


As of December 31, (M€)	2006	2005	2004
Projects with recent or planned exploratory activity	815	482	389
Wells for which drilling is not completed	132	63	91
Wells with drilling in past 12 months	341	200	126
Wells with future exploratory activity firmly planned^(a)	342	219	172
future exploratory drilling planned	248	156	148
other exploratory activity planned^(b)	94	63	24
Projects with completed exploratory activity	77	108	41
Projects not requiring major capital expenditures	—	—	—
Projects requiring major capital expenditures	77	108	41
Total	892	590	430
Number of wells at end of year	117	85	56

(a)

All projects included in this line require major capital expenditures.

(b)

At the end of 2006, this relates to six wells whose continuing capitalization is justified by firmly planned seismic activity for two wells (subject to the completion of legislative ratification of contracts regarding one well) and significant studies for the remaining four wells.

F-80

At the end of 2006, there was no amount of capitalized exploratory drilling cost that was associated with areas not requiring major capital expenditures before production could begin, where more than one year had elapsed since the completion of drilling.

At the end of 2006, an amount of 77 M€ was associated with suspended wells in areas where major capital expenditures will be required and no future exploratory activity is firmly planned. This amount corresponds to seven projects (20 wells) and is mainly associated to the projects further described below:

The first project (Usan) relates to a deepwater oil discovery in Nigeria for which eight wells were drilled between 2001 and 2005 and 27 M€ were capitalised as at December 31, 2006. These exploration works allowed the Group to launch several development engineering studies in 2005 that went on in 2006. The state-owned oil company, NNPC, has approved a development plan based on the construction of a Floating Production Storage and Offloading (FPSO) facility for which a call for tenders was issued. Contractor bids are currently being evaluated.

The second project (Laggan) relates to a deepwater gas discovery in the UK (west of the Shetland Islands), for which one well has been drilled in 2004 for a capitalised amount of 17 M€ as at December 31, 2006. In 2006 TOTAL and its partners continued geoscience studies required for the definition of the field development concept and the appraisal of potential new exploration areas. A task force was created with the neighbouring permits operators in order to promote a global development strategy for the area.

The third project (Bonga SW) relates to a deepwater oil discovery in Nigeria for which three wells were drilled between 2001 and 2003 and for which 7 M€ were capitalized as at December 31, 2006. During 2006, together with operator and co-venturers, the Group worked on the elaboration of a field development plan and pursued negotiations aiming at possible unitization of the field with adjacent licenses. This led to the signature of a “pre-unitization” agreement with partners in 2006.


As of December 31, (M€ and number of wells)	2006		2005		2004
As of December 31, (M€ and number of wells)	amount	number	amount	number	amount	number
Wells for which drilling is not completed	132	19	63	12	91	13
Wells with completed drilling
Less than 1 year	341	39	200	29	126	12
Between 1 and 4 years	392	53	304	40	198	29
Between 4 years and 8 years	19	4	23	4	15	2
More than 8 years	8	2	—	—	—	—
Total	892	117	590	85	430	56

O. Impact of New U.S. GAAP Accounting Standards

(i) Accounting for Certain Hybrid Financial Instruments

FAS No. 155 "Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and No. 140" was issued in February 2006 and is effective for all financial instruments acquired, issued, or subject to a remeasurement event occurring after the beginning of an entity's first fiscal year that begins after September 15,2006. FAS No.155 provides entity with relief from having to separately determine the fair value of an embedded derivative that would otherwise be required to be bifurcated from its host contract in accordance with FAS No. 133. FAS No. 155 allows an entity to make an irrevocable election to measure such hybrid financial instrument at fair value in its entirety with changes in fair value recognized in earnings.

The adoption of FAS No. 155 will have no material effect on the Group's earnings and shareholder's equity, as determined under U.S GAAP.

(ii) Accounting for Servicing of Financial Assets

FAS No. 156 "Accounting for Servicing of Financial Assets, an amendment of FASB Statements No. 140" was issued in March 2006 and is effective prospectively to all transactions occurring after the beginning of an entity's first fiscal year that begins after September 15, 2006. FAS No. 156 requires that an entity separately recognize a servicing asset or a servicing liability when it undertakes an obligation to service a financial asset under a servicing contract in certain situations.

The adoption of FAS No. 156 will have no material effect on the Group's earnings and shareholder's equity, as determined under U.S GAAP.

(iii) Fair Value Measurements

FAS No. 157 “Fair Value Measurements” was issued in September 2006 and is effective prospectively for fiscal years beginning after November 15, 2007. FAS No. 157 provides a single definition of fair value, together with a

F-81

framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. The statement also sets out a fair value hierarchy.

The adoption of FAS No. 157 is not expected to have significant effect on the Group's earnings and shareholder's equity, as determined under U.S GAAP.

(iv) Accounting for Defined Benefit Pension and Other Postretirement Plans

FAS No. 158 “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No.87, 88, 106, 132(R)”, was issued in September 2006 and is effective for fiscal years ending after December 15,2006. FAS No. 158 requires a full recognition of the plan overfunded or underfunded status of its benefit plans in the balance sheet. Therefore, unrecognized actuarial gain and loss and prior service costs and credits need to be recognized in Other Comprehensive Income and are “recycled” to the income statement based on current amortization and recognition criteria. In addition, the statement also required a company to measure its plan assets and benefit obligations as of its year-end balance sheet date.

The provision to require measurement at the company’s entity’s balance sheet date will be effective for fiscal years ending after December 15, 2008.The adoption of the provisions of FAS No. 158 relating to the measurement date will have no material effect on the Group's earnings and shareholder's equity, as determined under U.S GAAP.

(v) FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”—an interpretation of FASB Statement No. 109

On July 2006, the FASB issued FIN No. 48 which is effective for fiscal years beginning after December 15, 2006, and should be applied to all tax positions upon initial adoption. FIN No. 48 clarifies the accounting for income taxes by prescribing a “more-likely-than-not” recognition threshold a tax position is required to meet before being recognized in the financial statements.

Once the recognition threshold has been met, FIN No. 48 requires to recognize the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with the taxing authority.

The Interpretation also requires making explicit disclosures about uncertainties in Company's income tax positions.

The adoption of FIN No. 48 is not expected to have significant effect on the Group's earnings and shareholder's equity, as determined under U.S GAAP.

(vi) Planned Major Maintenance Activities

On September 2006, the FASB issued FSP No. AUG AIR-1 “Accounting for Planned Major Maintenance Activities” which is effective for the fiscal year beginning after December 15, 2006 and should be applied retrospectively. The FSP prohibits the use of the accrue-in advance method of accounting for planned major maintenance activities. It continues to permit the application of the other three alternative methods of accounting for planned major maintenance activities: direct expense, built-in overhaul, and deferral.

The adoption of the FSP No. AUG AIR-1 will have no material effect on the Group's earnings and shareholder's equity, as determined under U.S GAAP, as the Group already applies the built-in overhaul method as described in paragraph H of this Note.

(vii) Fair Value Option for Financial Assets and Financial Liabilities

FAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities” was issued in February 2007 and is effective as of the beginning of the first fiscal year that begins after November 15, 2007. FAS No. 159 offers an irrevocable option to carry the vast majority of financial assets and liabilities at fair value, with changes in fair value recorded in earnings. The adoption of FAS No. 159 is not expected to have significant effect on the Group's earnings and shareholder's equity, as determined under U.S. GAAP.

F-82

TOTAL

SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS


(M€)	Balance at beginning of period	Charged to other accounts^(a)		Charged to costs and expenses	Deductions^(b)	Balance at end of period
VALUATION AND QUALIFYING ACCOUNTS DEDUCTED FROM THE RELATED ASSETS ACCOUNTS
2006
Investments and other non-current assets^(c)	1,405	(91	)	61	219	1,156
Inventories	413	(91	)	118	—	440
Accounts receivable	562	(66	)	—	7	489
Other current assets	63	(24	)	—	—	39
Total	2,443	(272	)	179	226	2,124
2005
Investments and other non-current assets^(c)	1,416	39		48	98	1,405
Inventories	394	31		—	12	413
Accounts receivable	488	37		37	—	562
Other current assets	37	27		—	1	63
Total	2,335	134		85	111	2,443
2004
Investments and other non-current assets⁽³⁾	1,334	129		51	98	1,416
Inventories	305	49		40	—	394
Accounts receivable	518	(18	)	—	13	487
Other current assets	42	(2	)	—	2	38
Total	2,199	158		91	113	2,335

LONG-TERM LIABILITIES
2006
Employee benefits	3,413	(490	)	359	509	2,773
Other liabilities and deferred income taxes	13,715	(1,395	)	1,884	886	13,318
Total	17,128	(1,885	)	2,243	1,395	16,091
2005
Employee benefits	3,607	9		305	508	3,413
Other liabilities and deferred income taxes	12,390	888		2,319	1,882	13,715
Total	15,997	897		2,624	2,390	17,128
2004
Employee benefits	3,816	(17	)	442	634	3,607
Other liabilities and deferred income taxes	11,555	142		2,306	1,613	12,390
Total	15,371	125		2,748	2,247	15,997

(a)

Amounts charged to other accounts include (i) currency translation adjustments and (ii) the impact of the Arkema spin-off.

(b)

Deductions correspond to (i) amounts reversed into income, which offset charges for which the reserves were created and (ii) adjustments to deferred income tax assets and liabilities.

(c)

The breakdown between investments and other non-current assets is as follows:


	As of December 31,
(M€)	2006	2005	2004
Investments	668	821	809
Other non-current assets	488	584	607
	1,156	1,405	1,416

F-83

TOTAL

SUPPLEMENTAL OIL AND GAS INFORMATION (Unaudited)

Information shown in the following tables is presented in accordance with Statement of Financial Accounting Standards No. 69 (FAS No. 69, “Disclosures About Oil and Gas Producing Activities”).

As explained in Note 34 to the Consolidated Financial Statements (“Summary of Differences Between Accounting Principles followed by the Company and United States Generally Accepted Accounting Principles”), the consolidated financial statements have been prepared in accordance with IFRS, which differ in certain respects from those applicable in the United States of America (“U.S. GAAP”).

The acquisitions of Petrofina and Elf Aquitaine that were originally accounted for as pooling-of-interests in accordance with French GAAP, have not been restated under IFRS, pursuant to an exemption provided by IFRS 1 “First-time adoption of International Financial Reporting Standards.” Under U.S. GAAP, the acquisitions of PetroFina and Elf Aquitaine do not qualify as pooling-of-interests and therefore would have been accounted for as purchases.

Under IFRS, the Group follows IAS36 “Impairment of Assets”, whereas under U.S. GAAP, it follows FAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets”. Pursuant to an exemption provided by IFRS 1 “First-time adoption of IFRS”, the Group has elected to record unrecognized actuarial gains and losses as of January 1, 2004 to retained earnings. Under

U.S. GAAP, this exemption is not applicable and generates a difference relating to the amortization of actuarial gains and losses recognized in income.

Therefore, the FAS No. 69 disclosures, which are based on the Company’s primary financial statements prepared in accordance with IFRS, have been supplemented with an additional set of tables derived from U.S. GAAP figures.

For more detail about the differences between the accounting principles followed by the Company and United States Generally Accepted Accounting Principles, see Note 34 to the Consolidated Financial Statements (“Summary of Differences Between Accounting Principles followed by the Company and United States Generally Accepted Accounting Principles”) included elsewhere herein.

Capitalized costs

Capitalized costs represent the amounts of capitalized proved and unproved property costs, including support equipment and facilities, along with the related accumulated depreciation, depletion and amortization.

The following tables present details of capitalized costs related to the Group’s oil and gas exploration and production activities as of the dates and on the basis indicated.

S-1


	Consolidated subsidiaries
(M€)	Europe		Africa		North America		Asia		Rest of World		Total
*IFRS basis*
December 31, 2006
Proved properties	28,217		19,569		1,884		3,678		9,861		63,209
Unproved properties	89		807		193		243		181		1,513
Total capitalized costs	28,306		20,376		2,077		3,921		10,042		64,722
Accumulated depreciation	(20,456	)	(11,271	)	(553	)	(1,588	)	(4,604	)	(38,472	)
Net capitalized costs	7,850		9,105		1,524		2,333		5,438		26,250
Company’s share of equity affiliates’ net capitalized costs			321						1,331		1,652
December 31, 2005
Proved properties	26,922		19,227		2,209		3,524		9,825		61,707
Unproved properties	63		731		110		14		133		1,051
Total capitalized costs	26,985		19,958		2,319		3,538		9,958		62,758
Accumulated depreciation	(19,190	)	(11,708	)	(1,216	)	(1,453	)	(4,646	)	(38,213	)
Net capitalized costs	7,795		8,250		1,103		2,085		5,312		24,545
Company’s share of equity affiliates’ net capitalized costs			296						409		705
December 31, 2004
Proved properties	25,035		16,206		1,551		2,605		7,509		52,906
Unproved properties	51		544		113		17		104		829
Total capitalized costs	25,086		16,750		1,664		2,622		7,613		53,735
Accumulated depreciation	(17,512	)	(10,385	)	(881	)	(1,010	)	(3,567	)	(33,355	)
Net capitalized costs	7,574		6,365		783		1,612		4,046		20,380
Company’s share of equity affiliates’ net capitalized costs			214						501		715

*U.S. GAAP basis*
December 31, 2006
Proved properties	30,971		21,429		1,994		3,678		9,861		67,933
Unproved properties	89		807		193		243		181		1,513
Total capitalized costs	31,060		22,236		2,187		3,921		10,042		69,446
Accumulated depreciation	(21,758	)	(11,839	)	(657	)	(1,588	)	(4,604	)	(40,446	)
Net capitalized costs	9,302		10,397		1,530		2,333		5,438		29,000
Company’s share of equity affiliates’ net capitalized costs			321						1,331		1,652
December 31, 2005
Proved properties	29,685		21,087		2,370		3,524		9,825		66,491
Unproved properties	63		731		110		14		133		1,051
Total capitalized costs	29,748		21,818		2,480		3,538		9,958		67,542
Accumulated depreciation	(20,343	)	(12,194	)	(1,320	)	(1,453	)	(4,646	)	(39,956	)
Net capitalized costs	9,405		9,624		1,160		2,085		5,312		27,586
Company’s share of equity affiliates’ net capitalized costs			296						409		705
December 31, 2004
Proved properties	27,798		18,146		1,712		2,605		7,540		57,801
Unproved properties	51		544		113		17		104		829
Total capitalized costs	27,849		18,690		1,825		2,622		7,644		58,630
Accumulated depreciation	(18,492	)	(10,774	)	(970	)	(1,012	)	(3,457	)	(34,705	)
Net capitalized costs	9,357		7,916		855		1,610		4,187		23,925
Company’s share of equity affiliates’ net capitalized costs			214						501		715

S-2

Costs incurred

The tables below present the costs incurred in the Group’s oil and gas property acquisition, exploration and development activities, including both capitalized and expensed amounts.


	Consolidated subsidiaries
(M€)	Europe	Africa	North America	Asia	Rest of World	Total
*IFRS and U.S. GAAP basis*
December 31, 2006
Proved property acquisition	58	3	125	—	53	239
Unproved property acquisition	—	20	31	240	11	302
Exploration costs	229	538	112	69	204	1,152
Development costs^(a)	1,284	2,272	403	544	1,251	5,754

Total costs incurred	1,571	2,833	671	853	1,519	7,447

December 31, 2005
Proved property acquisition	—	25	17	—	74	116
Unproved property acquisition	—	56	3	—	—	59
Exploration costs	108	298	39	15	125	585
Development costs^(a)	1,201	1,907	338	491	1,232	5,169

Total costs incurred	1,309	2,286	397	506	1,431	5,929

December 31, 2004
Proved property acquisition	—	2	—	—	29	31
Unproved property acquisition	—	—	5	3	—	8
Exploration costs	99	279	94	29	142	643
Development costs^(a)	1,084	1,588	203	379	874	4,128

Total costs incurred	1,183	1,869	302	411	1,045	4,810

(a)

Including asset retirement costs capitalized during the year and any gain or losses recognized upon settlement of asset retirement obligations during the year.

Group’s share of equity affiliates’ costs of property acquisition, exploration and development:


December 31, 2006	71	716	787
December 31, 2005	45	145	190
December 31, 2004	56	184	240

Costs to develop Proved Undeveloped Reserves

The following table presents the amounts spent to develop the proved undeveloped reserves in 2004, 2005 and 2006, as well as the amounts included in the most recent standardized measure of future net cash flows to develop proved undeveloped reserves in each of the next three years.

(M€)

2004

2005

2006

2007

2008

2009

Costs to develop Proved Undeveloped Reserves (consolidated subsidiaries)

3,567

4,751

5,128

6,064

^(a)

5,583

^(a)

3,796

^(a)

^(a)

Estimates.

S-3

Results of operations of oil and gas producing activities

The following tables include revenues and expenses associated directly with the Group’s oil and gas producing activities. They do not include any interest costs.


	Consolidated subsidiaries
(M€)	Europe		Africa		North America		Asia		Rest of World		Total
*IFRS basis*
Year ended December 31, 2006
Revenues
Sales to unaffiliated parties	3,285		2,550		1		2,276		2,457		10,569
Transfers to affiliated parties	7,333		8,179		167		374		1,124		17,177
Total Revenues	10,618		10,729		168		2,650		3,581		27,746
Production costs	(910	)	(731	)	(57	)	(184	)	(307	)	(2,189	)
Exploration expenses	(140	)	(246	)	(40	)	(58	)	(149	)	(633	)
Depreciation, depletion and amortization and valuation allowances	(1,256	)	(844	)	(78	)	(301	)	(519	)	(2,998	)
Other expenses^(a)	(227	)	(1,274	)	(3	)	(25	)	(881	)	(2,410	)
Pretax income from producing activities	8,085		7,634		(10	)	2,082		1,725		19,516
Income tax	(5,115	)	(5,335	)	(14	)	(1,008	)	(803	)	(12,275	)
Results of oil and gas producing activities	2,970		2,299		(24	)	1,074		922		7,241

Year ended December 31, 2005
Revenues
Sales to unaffiliated parties	2,384		1,911		22		1,767		2,594		8,678
Transfers to affiliated parties	6,629		8,080		474		340		924		16,447
Total Revenues	9,013		9,991		496		2,107		3,518		25,125
Production costs	(851	)	(605	)	(43	)	(173	)	(285	)	(1,957	)
Exploration expenses	(85	)	(148	)	(46	)	(20	)	(132	)	(431	)
Depreciation, depletion and amortization and valuation allowances	(1,164	)	(851	)	(184	)	(273	)	(543	)	(3,015	)
Other expenses^(a)	(207	)	(1,052	)	(9	)	(20	)	(680	)	(1,968	)
Pretax income from producing activities	6,706		7,335		214		1,621		1,878		17,754
Income tax	(4,089	)	(5,056	)	(88	)	(773	)	(731	)	(10,737	)
Results of oil and gas producing activities	2,617		2,279		126		848		1,147		7,017

Year ended December 31, 2004
Revenues
Sales to unaffiliated parties	2,027		1,163		40		1,446		1,820		6,496
Transfers to affiliated parties	4,917		6,081		548		250		645		12,441
Total Revenues	6,944		7,244		588		1,696		2,465		18,937
Production costs	(783	)	(578	)	(49	)	(162	)	(248	)	(1,820	)
Exploration expenses	(40	)	(146	)	(90	)	(31	)	(107	)	(414	)
Depreciation, depletion and amortization and valuation allowances	(1,190	)	(829	)	(245	)	(252	)	(486	)	(3,002	)
Other expenses^(a)	(176	)	(764	)	(5	)	(15	)	(288	)	(1,248	)
Pretax income from producing activities	4,755		4,927		199		1,236		1,336		12,453
Income tax	(2,700	)	(3,233	)	(88	)	(591	)	(250	)	(6,862	)
Results of oil and gas producing activities	2,055		1,694		111		645		1,086		5,591

(a)

Including production taxes and FAS No. 143 accretion expense (137 M€ in 2004, 146 M€ in 2005, 162 M€ in 2006).

Group’s share of equity affiliates’ results of oil and gas producing activities:


December 31, 2006	125	257	382
December 31, 2005	113	166	279
December 31, 2004	80	200	280

S-4


	Consolidated subsidiaries
(M€)	Europe		Africa		North America		Asia		Rest of World		Total
*U.S. GAAP basis*

Year ended December 31, 2006
Revenues
Sales to unaffiliated parties	3,285		2,550		1		2,276		2,457		10,569
Transfers to affiliated parties	7,333		8,179		167		374		1,124		17,177
Total Revenues	10,618		10,729		168		2,650		3,581		27,746
Production costs	(910	)	(731	)	(57	)	(184	)	(307	)	(2,189	)
Exploration expenses	(140	)	(246	)	(40	)	(58	)	(149	)	(633	)
Depreciation, depletion and amortization and valuation allowances	(1,407	)	(924	)	(78	)	(301	)	(519	)	(3,229	)
Other expenses^(a)	(227	)	(1,274	)	(3	)	(25	)	(881	)	(2,410	)
Pretax income from producing activities	7,934		7,554		(10	)	2,082		1,725		19,285
Income tax	(5,131	)	(5,290	)	6		(1,008	)	(802	)	(12,225	)
Results of oil and gas producing activities	2,803		2,264		(4	)	1,074		923		7,060

Year ended December 31, 2005
Revenues
Sales to unaffiliated parties	2,384		1,911		22		1,767		2,594		8,678
Transfers to affiliated parties	6,629		8,080		474		340		924		16,447
Total Revenues	9,013		9,991		496		2,107		3,518		25,125
Production costs	(851	)	(605	)	(43	)	(173	)	(285	)	(1,957	)
Exploration expenses	(85	)	(148	)	(46	)	(20	)	(132	)	(431	)
Depreciation, depletion and amortization and valuation allowances	(1,358	)	(974	)	(199	)	(273	)	(677	)	(3,481	)
Other expenses^(a)	(207	)	(1,052	)	(9	)	(20	)	(680	)	(1,968	)
Pretax income from producing activities	6,512		7,212		199		1,621		1,744		17,288
Income tax	(3,990	)	(5,011	)	(83	)	(773	)	(712	)	(10,569	)
Results of oil and gas producing activities	2,522		2,201		116		848		1,032		6,719

Year ended December 31, 2004
Revenues
Sales to unaffiliated parties	2,027		1,163		40		1,446		1,820		6,496
Transfers to affiliated parties	4,917		6,081		548		250		645		12,441
Total Revenues	6,944		7,244		588		1,696		2,465		18,937
Production costs	(787	)	(578	)	(49	)	(162	)	(247	)	(1,823	)
Exploration expenses	(40	)	(146	)	(90	)	(31	)	(107	)	(414	)
Depreciation, depletion and amortization and valuation allowances	(1,403	)	(925	)	(255	)	(252	)	(507	)	(3,342	)
Other expenses^(a)	(176	)	(764	)	(5	)	(15	)	(288	)	(1,248	)
Pretax income from producing activities	4,538		4,831		189		1,236		1,316		12,110
Income tax	(2,574	)	(3,179	)	(81	)	(591	)	(247	)	(6,672	)
Results of oil and gas producing activities	1,964		1,652		108		645		1,069		5,438

(a)

Including production taxes and FAS No. 143 accretion expense (137 M€ in 2004, 146 M€ in 2005,162 M€ in 2006).

Group’s share of equity affiliates’ results of oil and gas producing activities:


December 31, 2006	125	257	382
December 31, 2005	113	166	279
December 31, 2004	80	200	280

S-5

Oil and gas reserves

The following tables present, for crude oil, condensates and natural gas liquids reserves and for natural gas reserves, an estimate of the Group’s oil and gas quantities by geographical areas at December 31, 2006, 2005 and 2004.

Quantities shown concern:

•

proved developed and undeveloped reserves together with changes in quantities for 2006, 2005 and 2004.

•

proved developed reserves.

The definitions used for proved oil and gas reserves, proved developed oil and gas reserves and proved undeveloped reserves are in accordance with the applicable U.S. Securities & Exchange Commission regulation, Rule 4-10 of Regulation S-X. Proved reserves are estimated using geological and engineering data to determine with reasonable certainty whether the crude oil or natural gas in known reservoirs is recoverable

under existing economic and operating conditions. This process involves making subjective judgments; consequently, estimates of reserves are not exact measurements and are subject to revision. The reserve estimates shown below do not include quantities that may or may not be produced, due to changes in economic conditions or pursuant to new technologies. For additional information on TOTAL’s reserves estimation process, see “Item 4. Information on the Company—Exploration & Production—Reserves” included elsewhere herein.

The percentage of proved developed reserves has remained relatively stable over the past five years, indicating that proved reserves are consistently moved from undeveloped to developed status. Over time, undeveloped reserves will be reclassified to the developed category as new wells are drilled, existing wells are recompleted and/or facilities to produce from existing and future wells are installed. Major development projects typically take two to four years from the time of recording proved reserves to the start of production from these reserves.

S-6

Estimated proved reserves of crude oil and natural gas

The following tables reflect the estimated proved reserves of crude oil and natural gas as of December 31, 2004, 2005 and 2006, and the changes therein.


	Crude Oil, Condensate and Natural Gas Liquids (Mb)
	Europe		Africa		North America		Asia		Rest of World		Total		Equity Affiliates and Non- Consolidated
Balance as of January 1, 2004	1,073		2,948		99		79		1,952		6,151		1,172
Revisions of previous estimates	93		(26	)	(13	)	11		(119	)	(54	)	(15	)
Extensions, discoveries and other	43		46		—		—		227		316		61
Acquisitions of reserves in place	12		—		—		—		—		12		—
Sales of reserves in place	(1	)	(18	)	—		—		—		(19	)	—
Production for the year	(154	)	(255	)	(6	)	(11	)	(91	)	(517	)	(104	)
Balance as of December 31, 2004	1,066		2,695		80		79		1,969		5,889		1,114
Revisions of previous estimates	32		(15	)	96		(7	)	6		112		(4	)
Extensions, discoveries and other	23		21		—		—		—		44		—
Acquisitions of reserves in place	—		7		58		—		—		65		—
Sales of reserves in place	—		—		—		—		(36	)	(36	)	—
Production for the year	(143	)	(245	)	(3	)	(10	)	(91	)	(492	)	(100	)
Balance as of December 31, 2005	978		2,463		231		62		1,848		5,582		1,010
Revisions of previous estimates	40		146		1		6		65		258		4
Extensions, discoveries and other	13		113		—		—		—		126		60
Acquisitions of reserves in place	—		—		22		—		—		22		3
Sales of reserves in place	(6	)	—		(2	)	—		(21	)	(29	)	(16	)
Production for the year	(132	)	(220	)	(2	)	(11	)	(78	)	(443	)	(106	)
Balance as of December 31, 2006	893		2,502		250		57		1,814		5,516		955

Minority interests in proved developed and undeveloped reserves as of (Mb):

December 31, 2004	22				80		—		—		—		102
December 31, 2005	19				77		—		—		—		96
December 31, 2006	17				82		—		—		—		99

Proved developed and undeveloped reserves of equity and non-consolidated affiliates as of (Mb):

December 31, 2004					73						1,041		1,114
December 31, 2005					59						951		1,010
December 31, 2006					56						899		955

Proved developed reserves as of (Mb):

December 31, 2004	734		1,351		15		48		477		2,625		772
December 31, 2005	692		1,318		13		44		423		2,490		709
December 31, 2006	629		1,436		19		40		418		2,542		665

Proved developed reserves of equity and non-consolidated affiliates as of (Mb):

December 31, 2004					67						705		772
December 31, 2005					51						658		709
December 31, 2006					49						616		665

S-7


	Natural Gas (Bcf)
	Europe		Africa		North America		Asia		Rest of World		Total		Equity Affiliates and Non- Consolidated
Balance as of January 1, 2004	6,571		3,603		466		5,309		4,726		20,675		1,592
Revisions of previous estimates	84		609		(91	)	(137	)	355		820		65
Extensions, discoveries and other	148		728		—		18		450		1,344		63
Acquisitions of reserves in place	68		—		—		—		—		68		—
Sales of reserves in place	(44	)	—		(7	)	—		—		(51	)	—
Production for the year	(812	)	(161	)	(88	)	(448	)	(188	)	(1,697	)	(94	)
Balance as of December 31, 2004	6,015		4,779		280		4,742		5,343		21,159		1,626
Revisions of previous estimates	383		141		8		(227	)	240		545		(7	)
Extensions, discoveries and other	145		27		—		—		43		215		2,954
Acquisitions of reserves in place	—		3		—		—		—		3		—
Sales of reserves in place	—		—		—		—		—		—		—
Production for the year	(753	)	(152	)	(64	)	(458	)	(225	)	(1,652	)	(93	)
Balance as of December 31, 2005	5,790		4,798		224		4,057		5,401		20,270		4,480
Revisions of previous estimates	127		133		(8	)	116		(106	)	262		(9	)
Extensions, discoveries and other	283		32		—		—		—		315		2,105
Acquisitions of reserves in place	—		—		12		—		—		12		1
Sales of reserves in place	(31	)	—		(160	)	—		(1	)	(192	)	—
Production for the year	(717	)	(176	)	(16	)	(470	)	(222	)	(1,601	)	(104	)
Balance as of December 31, 2006	5,452		4,787		52		3,703		5,072		19,066		6,473

Minority interests in proved developed and undeveloped reserves as of (Bcf):


December 31, 2004	111	84	—	—	—	195	—
December 31, 2005	101	80	—	—	—	181	—
December 31, 2006	92	88	—	—	—	180	—

Proved developed and undeveloped reserves of equity and non-consolidated affiliates as of (Bcf):


Year ended December 31, 2004	18	1,608	1,626
Year ended December 31, 2005	17	4,463	4,480
Year ended December 31, 2006	20	6,453	6,473

Proved developed reserves as of (Bcf):


December 31, 2004	4,300	2,071	232	2,862	1,548	11,013	1,562
December 31, 2005	4,130	2,285	187	2,910	1,758	11,270	1,525
December 31, 2006	3,632	2,643	39	2,592	2,395	11,301	1,331

Proved developed reserves of equity and non-consolidated affiliates as of (Bcf):


Year ended December 31, 2004	18	1,544	1,562
Year ended December 31, 2005	17	1,508	1,525
Year ended December 31, 2006	20	1,311	1,331

S-8

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

1.	estimates of proved reserves and the corresponding production profiles are based on technical and economic conditions at year end;

2.	the estimated future cash flows from proved reserves are determined based on prices at December 31, with future price changes considered only to the extent provided by contractual arrangements in existence at year-end;

3.	the future cash flows incorporate estimated production costs (including production taxes), future

development costs and asset retirement costs. All estimates are based on year-end technical and economic conditions;

4.	future income taxes are computed by applying the year-end statutory tax rate to future net cash flows after consideration of permanent differences and future income tax credits; and

5.	future net cash flows are discounted at a standard discount rate of 10 percent.

These principles applied are those required by FAS No. 69 and do not necessarily reflect the expectations of real revenues from these reserves, nor their present value; hence, they do not constitute criteria of investment decision. An estimate of the fair value of reserves should also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

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The following is the projected standardized measure of discounted future net cash flows relating to proved oil and gas reserves:


	Consolidated subsidiaries
(M€)	Europe		Africa		North America		Asia		Rest of World		Total
*IFRS and U.S. GAAP basis*
December 31, 2004
Future cash inflows	49,233		76,576		2,695		13,737		42,437		184,678
Future production costs	(7,389	)	(13,170	)	(792	)	(2,077	)	(10,561	)	(33,989	)
Future development costs	(6,448	)	(10,001	)	(356	)	(2,316	)	(4,436	)	(23,557	)
Future income taxes	(23,711	)	(33,859	)	(304	)	(4,091	)	(8,613	)	(70,578	)
Future net cash flows, after income taxes	11,685		19,546		1,243		5,253		18,827		56,554
Discount at 10%	(4,085	)	(8,919	)	(455	)	(2,167	)	(12,091	)	(27,717	)
Standardized measure of discounted future net cash flows	7,600		10,627		788		3,086		6,736		28,837
December 31, 2005
Future cash inflows	80,179		119,119		6,646		18,046		71,417		295,407
Future production costs	(8,842	)	(19,402	)	(3,213	)	(2,381	)	(17,709	)	(51,547	)
Future development costs	(6,581	)	(13,087	)	(789	)	(2,761	)	(5,019	)	(28,237	)
Future income taxes	(43,824	)	(54,598	)	(528	)	(5,802	)	(15,285	)	(120,037	)
Future net cash flows, after income taxes	20,932		32,032		2,116		7,102		33,404		95,586
Discount at 10%	(7,592	)	(13,856	)	(868	)	(2,744	)	(21,132	)	(46,192	)
Standardized measure of discounted future net cash flows	13,340		18,176		1,248		4,358		12,272		49,394
December 31, 2006
Future cash inflows	59,051		108,847		5,915		16,061		59,065		248,939
Future production costs	(10,057	)	(19,223	)	(2,443	)	(2,136	)	(18,706	)	(52,565	)
Future development costs	(9,379	)	(15,929	)	(968	)	(3,866	)	(6,121	)	(36,263	)
Future income taxes	(28,069	)	(45,714	)	(459	)	(4,522	)	(12,271	)	(91,035	)
Future net cash flows, after income taxes	11,546		27,981		2,045		5,537		21,967		69,076
Discount at 10%	(4,545	)	(12,171	)	(1,092	)	(1,927	)	(14,293	)	(34,028	)
Standardized measure of discounted future net cash flows	7,001		15,810		953		3,610		7,674		35,048

Minority interests in future net cash flows as of:

Year ended December 31, 2004	297		287								584
Year ended December 31, 2005	515		546								1,061
Year ended December 31, 2006	255		418								673

Group’s share of equity affiliates’ future net cash flows as of:

Year ended December 31, 2004			494						1,101		1,595
Year ended December 31, 2005			598						2,930		3,528
Year ended December 31, 2006			549						3,545		4,094

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Changes in the standardized measure of discounted future net cash flows

The following table indicates the changes in the standardized measure of discounted future net cash flows for the periods indicated.


	For the year ended December 31,
(M€)	2006		2005		2004
Consolidated
Beginning of year	49,394		28,837		29,118
Sales and transfers, net of production costs	(21,335	)	(17,104	)	(12,791	)
Net change in sales and transfer prices, net of production costs	(11,481	)	52,711		12,919
Extensions, discoveries and improved recovery, net of future production and development costs	1,534		1,126		974
Changes in estimated future development costs	(7,666	)	(1,106	)	(1,215	)
Previously estimated development costs incurred during the year	5,150		5,333		3,790
Revisions of previous quantity estimates	(1,382	)	6,313		(2,684	)
Accretion of discount	4,939		2,444		2,912
Net change in income taxes	16,268		(28,943	)	(4,255	)
Purchases of reserves in place	574		41		292
Sales of reserves in place	(947	)	(258	)	(223	)
End of year	35,048		49,394		28,837

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