Total Earnings 2010-12-31

Balance Sheet	Income Statement	Cash Flow

20-F 1 y03333e20vf.htm FORM 20-F e20vf

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 20-F


(Mark One)
o		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
x		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to
OR
o		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)

Republic of France
(Jurisdiction of Incorporation or Organization)
2, place Jean Millier
La Défense 6
92400 Courbevoie
France
(Address of Principal Executive Offices)
Patrick de La Chevardière
Chief Financial Officer
TOTAL S.A.
2, place Jean Millier
La Défense 6
92400 Courbevoie
France
Tel: +33 (0)1 47 44 45 46
Fax: +33 (0)1 47 44 49 44

(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)

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.

2,349,640,931 Shares, par value €2.50 each, as of December 31, 2010

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 o

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 o 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 o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).**

Yes o No o

** This requirement is not currently applicable to the registrant.

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 o		Non-accelerated filer o

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:


U.S. GAAP o		International Financial Reporting Standards as issued by the International Accounting Standards Board x		Other o

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow. Item 17 o Item 18 o

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 o No x

TABLE OF CONTENTS


		Page

CERTAIN TERMS			iii
ABBREVIATIONS			iv
CONVERSION TABLE			v
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		9
	History and Development		9
	Business Overview		10
	Other Matters		51
Item 4A.	Unresolved Staff Comments		62
Item 5.	Operating and Financial Review and Prospects		62
Item 6.	Directors, Senior Management and Employees		77
	Directors and Senior Management		77
	Compensation		85
	Corporate Governance		108
	Employees and Share Ownership		114
Item 7.	Major Shareholders and Related Party Transactions		118
Item 8.	Financial Information		120
Item 9.	The Offer and Listing		125
Item 10.	Additional Information		127
Item 11.	Quantitative and Qualitative Disclosures About Market Risk		138
Item 12.	Description of Securities Other than Equity Securities		138
Item 13.	Defaults, Dividend Arrearages and Delinquencies		139
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds		139
Item 15.	Controls and Procedures		140
Item 16A.	Audit Committee Financial Expert		140
Item 16B.	Code of Ethics		140
Item 16C.	Principal Accountant Fees and Services		141
Item 16D.	Exemptions from the Listing Standards for Audit Committees		141
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers		142
Item 16F.	Change in Registrant’s Certifying Accountant		142
Item 16G.	Corporate Governance		143
Item 17.	Financial Statements		145
Item 18.	Financial Statements		145
Item 19.	Exhibits		146
EX-1
EX-12.1
EX-12.2
EX-13.1
EX-13.2
EX-15

Basis of Presentation

Financial information included in this Annual Report is presented according to International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and IFRS as adopted by the European Union (EU) as of December 31, 2010.

Statements Regarding Competitive Position

Unless otherwise indicated, statements made in “Item 4. Information on the Company” referring to TOTAL’s competitive position are based on the Company’s estimates, 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, 2010. For more recent updates regarding TOTAL, you may read and copy any reports, statements or other information TOTAL files with the United States Securities and Exchange Commission (“SEC”). All of TOTAL’s SEC filings made after December 31, 2001, are available to the public at the SEC 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, natural gas liquids (NGL) or bitumen.

“Company’’		TOTAL S.A.

“condensates’’		Condensates are a mixture of hydrocarbons that exist in a gaseous phase at original reservoir temperature and pressure, but that, when produced, exist in a liquid phase at surface temperature and pressure. Condensates are sometimes referred to as C5+.

“crude oil’’		Crude oil is a mixture of compounds (mainly pentanes and heavier hydrocarbons) that exists in a liquid phase at original reservoir temperature and pressure and remains liquid at atmospheric pressure and ambient temperature. “Crude oil” or “oil” are sometimes used as generic terms to designate crude oil plus natural gas liquids (NGL).

“Depositary’’		The Bank of New York Mellon.

“Depositary Agreement’’		The depositary agreement pursuant to which ADSs are issued, a copy of which is attached as Exhibit 1 to the registration statement on Form F-6 (Reg. No. 333-172005) filed with the SEC on February 1, 2011.

“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 extraordinarily high pressure, in the presence of surplus hydrogen, to shorten molecules.

“liquids’’		Liquids consist of crude oil, bitumen and natural gas liquids (NGL).

“LNG’’		Liquefied natural gas.

“LPG’’		Liquefied petroleum gas is a mixture of hydrocarbons, the principal components of which are propane and butane, in a gaseous state at atmospheric pressure, but which is liquefied under moderate pressure and ambient temperature

“NGL’’		Natural gas liquids consist of condensates and liquefied petroleum gas (LPG).

“oil and gas”		Generic term which includes all hydrocarbons (e.g., crude oil, natural gas liquids (NGL), bitumen and natural gas).

“proved reserves’’		Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The full definition of “proved reserves” that we are required to follow in presenting such information in our financial results and elsewhere in reports we file with the SEC is found in Rule 4-10 of Regulation S-X under the U.S. Securities Act of 1933, as amended (including as amended by the SEC “Modernization of Oil and Gas Reporting” Release No. 33-8995 of December 31, 2008).

iii


“proved developed reserves’’		Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. The full definition of “developed reserves” that we are required to follow in presenting such information in our financial results and elsewhere in reports we file with the SEC is found in Rule 4-10 of Regulation S-X under the U.S. Securities Act of 1933, as amended (including as amended by the SEC “Modernization of Oil and Gas Reporting” Release No. 33-8995 of December 31, 2008).

“proved undeveloped reserves’’		Proved undeveloped oil and gas reserves are proved 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. The full definition of “undeveloped reserves” that we are required to follow in presenting such information in our financial results and elsewhere in reports we file with the SEC is found in Rule 4-10 of Regulation S-X under the U.S. Securities Act of 1933, as amended (including as amended by the SEC “Modernization of Oil and Gas Reporting” Release No. 33-8995 of December 31, 2008).

“steam cracker’’		A petrochemical plant that turns naphtha 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.

“ERMI’’		ERMI is an indicator intended to represent the refining margin after variable costs for a theoretical complex refinery located around Rotterdam in Northern Europe that processes a mix of crude oil and other inputs commonly supplied to this region to produce and market the main refined products at prevailing prices in the region.

“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
/d	per day	TWh	terawatt-hour
/y	per year	Wp	watt peak
		Btu	British thermal unit

CONVERSION TABLE



1 acre	= 0.405 hectares

1 b	= 42 U.S. gallons

1 boe	= 1 b of crude oil	= 5,478 cf of gas in 2010^(a)

		= 5,490 cf of gas in 2009

		= 5,505 cf of gas in 2008

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 7.5 b of oil (assuming a specific gravity of 37° API)

1 t of LNG	= approximately 48 kcf of gas

1 Mt/y LNG	= approximately 131 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 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 flow or obtain financing to fund growth and the cost of such financing and liquidity conditions in the capital markets generally;
	•	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 (including actual or proposed sanctions on companies that conduct business in certain countries);
	•	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 issued by the International Accounting Standards Board (IASB) and IFRS as adopted by the European Union for the years ended December 31, 2010, 2009, 2008, 2007 and 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.

SELECTED CONSOLIDATED FINANCIAL DATA


(M€, except per share data)	2010			2009		2008		2007		2006
INCOME STATEMENT DATA
Revenues from sales		140,476			112,153		160,331		136,824		132,689
Net income, Group share		10,571			8,447		10,590		13,181		11,768
Earnings per share		4.73			3.79		4.74		5.84		5.13
Fully diluted earnings per share		4.71			3.78		4.71		5.80		5.09
CASH FLOW STATEMENT DATA^(a)(b)
Cash flow from operating activities		18,493			12,360		18,669		17,686		16,061
Total expenditures		16,273			13,349		13,640		11,722		11,852
BALANCE SHEET DATA^(b)
Total assets		143,718			127,753		118,310		113,541		105,223
Non-current financial debt		20,783			19,437		16,191		14,876		14,174
Minority interests		857			987		958		842		827
Shareholders’ equity — Group share		60,414			52,552		48,992		44,858		40,321
Common shares		5,874			5,871		5,930		5,989		6,064
DIVIDENDS
Dividend per share (euros)		€2.28	^(c)		€2.28		€2.28		€2.07		€1.87
Dividend per share (dollars)		$3.02	^(c)(d)		$3.08		$3.01		$3.14		$2.46
COMMON SHARES^(e)
Average number outstanding of common shares €2.50 par value (shares undiluted)		2,234,829,043			2,230,599,211		2,234,856,551		2,255,294,231		2,293,063,190
Average number outstanding of common shares €2.50 par value (shares diluted)		2,244,494,576			2,237,292,199		2,246,658,542		2,274,384,984		2,312,304,652


(a)		See Consolidated Statement of Cash Flows included in the Consolidated Financial Statements.
(b)		Comparative cash flow information for 2006 includes Arkema, which was spun off on May 12, 2006.
(c)		Subject to approval by the shareholders’ meeting on May 13, 2011.
(d)		Estimated dividend in dollars includes the interim dividend of $1.542 paid in November 2010 and the proposed final dividend of €1.14, converted at a rate of $1.30/€.
(e)		The number of common shares shown has been used to calculate per share amounts.

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.

The following table sets out the average dollar/euro exchange rates expressed in dollars per €1.00 for the years indicated, based on an average of the daily European Central Bank (“ECB”) reference exchange rate.⁽¹⁾ Such rates are used by TOTAL in preparation of its Consolidated Statement of Income and Consolidated Statement of Cash Flow in its Consolidated Financial Statements. 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
2006		1.2556
2007		1.3705
2008		1.4708
2009		1.3948
2010		1.3257

The table below shows the high and low dollar/euro exchange rates for the three months ended December 31, 2010, and for the first three months of 2011, based on the daily ECB reference exchange rates published during the relevant month expressed in dollars per €1.00.

DOLLAR/EURO EXCHANGE RATES


Period	High		Low
October 2010		1.41		1.37
November 2010		1.42		1.30
December 2010		1.34		1.31
January 2011		1.37		1.29
February 2011		1.38		1.34
March 2011^(a)		1.42		1.38


(a)		Through March 21.

The ECB reference exchange rate on March 21, 2011, for the dollar against the euro was $1.42/€.

(1) For the period 2006 — 2010, the averages of the ECB reference exchange rates expressed in dollars per €1.00 on the last business day of each month during the relevant year are as follows: 2006 — 1.26; 2007 — 1.38; 2008 — 1.47; 2009 — 1.40; and 2010 — 1.32.

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 — 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 and financial market conditions;

•	war or other 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 2011, we estimate that a decrease of $1.00 per barrel in the average annual price of Brent crude would have the effect of reducing our annual adjusted net operating income from the Upstream segment by approximately €0.13 billion (calculated with a base case exchange rate of $1.30 per €1.00). In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators could lead to reviews for impairment of the Group’s oil and natural gas properties and could impact reserves. Such reviews would reflect management’s view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on our results of operations in the period in which it occurs. 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 dollars, the international currency of petroleum sales, while a significant portion of our operating expenses and income taxes accrue in euros and other currencies. Movements between the dollar and euro or other currencies may adversely affect our business by negatively impacting our booked revenues and income, and may also result in significant translation adjustments that impact our shareholders’ equity.

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 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 an ongoing 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 as they may evolve. Proved reserves are those reserves which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Reserves are estimated by teams of qualified, experienced and trained earth scientists, petroleum engineers and project engineers, who rigorously review and analyze in detail all available geosciences and engineering data (e.g., seismic, electrical logs, cores, fluids, pressures, flow rates, facilities parameters). This process involves making subjective judgments, including with respect to the estimate of hydrocarbons initially in place, initial production rates and recovery efficiency, based on available geological, technical and economic data. Consequently, estimates of reserves are not exact measurements and are subject to revision. In addition, they may be negatively impacted by a variety of factors which are beyond our control and 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 such factors 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 risked service contracts;

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

•	the actual production performance of our reservoirs.

Our reserves estimates may therefore require substantial downward revisions to the extent our subjective judgments prove not to have been conservative enough based on the available geosciences and engineering data, or our assumptions regarding factors or variables that are beyond our control prove to be incorrect over time. Any downward adjustment would indicate lower future production amounts, which could 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-Pacific and South America. Approximately 32%, 22%, 10% and 8%, respectively, of our 2010 combined liquids and gas 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 have recently suffered from some of these conditions. 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 Asia-Pacific, Indonesia has suffered some 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 exposed to risks regarding the safety and security of our operations. In addition, while our insurance coverage is in line with industry practice, we are not insured against all possible risks.

TOTAL engages in a broad scope of activities, which include drilling, oil and gas production, processing, transportation, refining and petrochemical activities, storage and distribution of petroleum products, and production of base chemical and specialty products, and involve a wide range of operational risks. Among these risks are those of explosion, fire or leakage of toxic products, as well as environmental risks related to emissions and discharges into the air, water or soil and the management of waste. We also face risks, once production is discontinued, because our activities require environmental site remediation. In the transportation area, the type of risk 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 (quality of infrastructure, population density, environmental considerations).

Certain branches or activities face specific additional risks. In Exploration & Production, we face risks related to the physical characteristics of our oil or gas fields. These include the risks of eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and risks of fire or explosion. These events may cause injury or death, damage or destroy crude oil or natural gas wells as well as equipment and other property, lead to a disruption 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 risk-based approach to avoid or minimize the impact on human health, flora and fauna, the ecosystem and biodiversity. TOTAL’s activities in the Chemicals segment and the Refining & Marketing division also entail additional health, safety and environmental risks related to the overall life cycle of the products manufactured, as well as raw materials used in the manufacturing process, such as catalysts, additives and monomer feedstocks. These risks can arise from the intrinsic characteristics of the products involved (flammability, toxicity, or long-term environmental impacts such as greenhouse gas emissions), their use (including by customers), emissions and discharges resulting from their manufacturing process, and from recycling or disposing of materials and wastes at the end of their useful life.

If an event occurs leading to personal injury, death, property damage or discharge of hazardous materials into the environment, contractual terms may provide for indemnification obligations, either by TOTAL in favor of third-parties or by third-parties for TOTAL’s benefit. With respect to joint ventures operated by TOTAL, contractual terms generally provide that TOTAL assumes liability for damages caused by its gross negligence or willful misconduct. With respect to joint ventures in which TOTAL has an interest but that are operated by others, contractual terms generally provide that the operator assumes liability for damages caused by its gross negligence or willful misconduct. All other liabilities of any type of joint venture are generally assumed by the partners in proportion to their respective ownership interests. With respect to third party providers of goods and services, the amount and nature of liabilities assumed by the third party depends on the context and may be limited by contract. With respect to the Group’s customers, TOTAL seeks to ensure that its products meet applicable specifications and that TOTAL abides by all applicable consumer protection laws.

To manage these risks, we maintain worldwide third-party liability insurance coverage for all of our subsidiaries. In addition, we also maintain insurance to protect us against the risk of damage to Group property and/or business disruption. Our insurance and risk management policies are described under “Item 4. Other Matters — Insurance and risk management”. While we believe our insurance coverage is in line with industry practice and sufficient to cover normal risks in our operations, we are not insured against all possible risks. In the event of a major environmental disaster, for example, our liability may exceed the maximum coverage provided by our third-party liability insurance. The loss we could suffer in the event of such a disaster would depend on all the facts and circumstances and would be subject to a whole range of uncertainties, including legal uncertainty as to the scope of liability for consequential damages, which may include economic damage not directly connected to the disaster. The Group cannot guarantee that it will not suffer any uninsured loss and there can be no assurance,

particularly in the case of a major environmental disaster or industrial accident, that such loss would not have a material adverse effect on the Group.

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.

Our workforce and the public are exposed to risks inherent to our operations that potentially could lead to injuries, loss of life or environmental damage and could result in regulatory action, legal liability and damage to our reputation.

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 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.

In addition, growing public concerns in the EU and globally that rising greenhouse gas emissions and climate change may significantly affect the environment and society could adversely affect our businesses, including by the addition of stricter regulations that increase our operating costs, affect product sales and reduce profitability.

If our established financial reserves prove inadequate, 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, modify or cease certain operations or implement temporary shutdowns of facilities, which could diminish our productivity and materially and adversely impact our results of operations, including profits.

Security threats require continuous assessment and response measures. Acts of terrorism against our plants and offices, pipelines, transportation or computer systems could severely disrupt businesses and operations and could cause harm to people.

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. and EU sanctions and our activities in Iran could lead to sanctions under relevant U.S. and EU legislation.

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

In 1996, the United States adopted legislation implementing sanctions against non-U.S. companies doing business in Iran and Libya (the Iran and Libya Sanctions Act, referred to as “ILSA”), which in 2006 was amended to concern only business in Iran (then renamed the Iran Sanctions Act, referred to as “ISA”).

Pursuant to this statute, the President of the United States is authorized to initiate an investigation into the activities of non-U.S. companies in Iran and the possible imposition of sanctions (from a list that includes denial of financing by the U.S. Export-Import Bank, limitations on the amount of loans or credits available from U.S. financial institutions and prohibition of U.S. federal procurements from sanctioned persons) 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. 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 regulations which prohibit TOTAL from complying with any requirement or prohibition based on or resulting directly or indirectly from certain enumerated legislation, including ILSA (now ISA). It also prohibits TOTAL from having its waiver for South Pars extended to other activities.

In each of the years since the passage of ILSA and until 2007, TOTAL made investments in Iran in excess of $20 million (excluding the investments made as part of the development of South Pars). Since 2008, TOTAL’s position has consisted essentially in being reimbursed for its past investments as part of buyback contracts signed between 1995 and 1999 with respect to permits on which the Group is no longer the operator. In 2010, TOTAL’s production in Iran represented less than 0.1% of the Group’s worldwide production.

ISA was amended in July 2010 by the Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010 (“CISADA”), which expanded the scope of ISA and restricted the President’s ability to grant waivers. In addition to sanctionable investments in Iran’s petroleum sector, parties may now be sanctioned for any transaction exceeding $1 million or series of transactions exceeding $5 million in any 12-month period for knowingly providing to Iran refined petroleum products, and for knowingly providing to Iran goods, services, technology, information or support that could directly and significantly either (i) facilitate the maintenance or expansion of Iran’s domestic production of refined petroleum products, or (ii) contribute to the enhancement of Iran’s ability to import refined petroleum products. The sanctions to be imposed against violating firms generally prohibit transactions in foreign exchange by the sanctioned company, prohibit any transfers of credit or payments between, by, through or to any financial institution to the extent that such transfers or payments involve any interest of the sanctioned company, and require blocking of any property of the sanctioned company that is subject to the jurisdiction of the United States. Investments in the petroleum sector commenced prior to the adoption of CISADA appear to remain subject to the pre-amended version of ISA. The new sanctions added by CISADA would be available with respect to new investments in the petroleum sector or any other sanctionable activity occurring on or after July 1, 2010. Prior to CISADA’s enactment, TOTAL discontinued now-prohibited sales of refined products to Iran.

On September 30, 2010, the U.S. State Department announced that the U.S. government, pursuant to the “Special Rule” provision of ISA added by CISADA that allows it to avoid making a determination of sanctionability under ISA with respect to any party that provides certain assurances, would not make such a determination with respect to TOTAL. The U.S. State Department further indicated at that time that, as long as TOTAL acts in accordance with its commitments, TOTAL will not be regarded as a company of concern for its past Iran-related activities.

France and the European Union have adopted measures, based on United Nations Security Council resolutions, which restrict the movement of certain individuals and goods to or from Iran as well as certain financial transactions with Iran, in each case when such individuals, goods or transactions are related to nuclear proliferation and weapons activities or likely to contribute to their development. In July and October 2010, the European Union adopted new restrictive measures regarding Iran (the “EU Measures”). Among other things, the supply of key equipment and technology in the following sectors of the oil and gas industry in Iran are prohibited: refining, liquefied natural gas, exploration and production. The prohibition extends to technical assistance, training and financial assistance in connection with such items. Extension of loans or credit to, acquisition of shares in, entry into joint ventures with or other participation in enterprises in Iran (or Iranian-owned enterprises outside of Iran) engaged in any of the targeted sectors also is prohibited. Moreover, with respect to restrictions on transfers of funds and on financial services, any transfer of at least €40,000 or equivalent to an Iranian individual or entity shall require a prior authorization of the competent authorities of the EU Member States.

TOTAL continues to closely monitor legislative and other developments in France, the European Union and the United States in order to determine whether its limited activities in Iran could subject it to the application of sanctions. However, the Group cannot assure that current or future regulations or developments regarding Iran will not have a negative impact on its business or reputation.

The United States also imposes sanctions based on the United Nations Security Council resolutions described above, as well as broad and comprehensive economic sanctions, which are administrated by the U.S. Treasury Department’s Office of Foreign Assets Control (referred to as “OFAC”). These OFAC sanctions generally apply to U.S. persons and activities taking place in the United States or that are otherwise subject to U.S. jurisdiction. Since August 16, 2010, transactions between Iranian entities and non-U.S. financial institutions holding U.S. bank accounts in the United States have been subject to OFAC restrictions. Sanctions administered by OFAC target Cuba, Iran, Myanmar (Burma), Sudan and Syria. TOTAL does not believe that these sanctions are applicable to any of its activities in these countries.

In addition, many U.S. states have adopted legislation requiring state pension funds to divest themselves of securities in any company with active business operations in Iran or Sudan. State insurance regulators have adopted similar initiatives relating to investments by insurance companies in companies doing business with the Iranian oil and gas, nuclear, and defense sectors. TOTAL has no business operations in Sudan and, to date, has not made any significant investments or industrial investments there. The Genocide Intervention Network (formerly known as Sudan Divestment Task Force) report states that TOTAL should be regarded as “inactive” in Sudan by the U.S. states that have adopted such divestment legislation. CISADA and the Sudan Accountability and Divestment Act, which was adopted by the U.S. Congress on December 31, 2007, support these state legislative initiatives. If TOTAL’s operations in Iran or Sudan were determined to fall within the prohibited scope of these laws, and TOTAL were not to qualify for any available exemptions, certain U.S. institutions holding interests in TOTAL may be required to sell their interests. If significant, sales of securities resulting from such laws and/or regulatory initiatives could have an adverse effect on the prices of TOTAL’s securities.

For more information on TOTAL’s presence in Cuba, Iran, Sudan and Syria, see “Item 4. Other Matters — Business Activities in Cuba, Iran, Sudan and Syria”.

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 fifth largest publicly-traded integrated international oil and gas company in the world.⁽¹⁾

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

TOTAL also has operations in Base Chemicals (petrochemicals and fertilizers) and Specialty Chemicals, mainly for the industrial market. In addition, TOTAL has interests in the coal mining and power generation sectors.

(1) Based on market capitalization (in dollars) as of December 31, 2010.

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’s registered office is 2, place Jean Millier, La Défense 6, 92400 Courbevoie, France. Its telephone number is +33 (0)1 47 44 45 46.

The length of the life of the Company is 99 years from March 22, 2000, unless it is dissolved or extended prior to such date.

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

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 elsewhere herein.


			Rest of		North
(M€)	France		Europe		America		Africa		Rest of world		Total
2010
Non-Group sales^(a)		36,820		72,636		12,432		12,561		24,820		159,269
Property, plant and equipment, intangible assets, net		5,666		14,568		9,584		20,166		13,897		63,881
Capital expenditures		1,062		2,629		3,626		4,855		4,101		16,273

2009
Non-Group sales^(a)		32,437		60,140		9,515		9,808		19,427		131,327
Property, plant and equipment, intangible assets, net		6,973		15,218		8,112		17,312		11,489		59,104
Capital expenditures		1,189		2,502		1,739		4,651		3,268		13,349

2008
Non-Group sales^(a)		43,616		82,761		14,002		12,482		27,115		179,976
Property, plant and equipment, intangible assets, net		7,260		13,485		5,182		15,460		10,096		51,483
Capital expenditures		1,997		2,962		1,255		4,500		2,926		13,640


(a)		Non-Group sales from continuing operations.

Upstream

TOTAL’s Upstream segment includes the Exploration & Production and Gas & Power divisions. The Group has exploration and production activities in more than forty countries and produces oil or gas in thirty 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 aims at continuing to combine long-term growth and profitability at the level of the best in the industry.

TOTAL evaluates exploration opportunities based on a variety of geological, technical, political and economic factors (including taxes and license terms), and on projected oil and gas prices. Discoveries and extensions of existing fields accounted for approximately 46% of the 2,445 Mboe added to the Upstream segment’s proved reserves during the three-year period ended December 31, 2010 (before deducting production and sales of reserves in place and adding any acquisitions of reserves in place during this period). The remaining 54% comes from revisions of previous estimates.

In 2010, the exploration investments of consolidated subsidiaries amounted to €1,472 million (comprising exploration bonuses included in the unproved property acquisition costs). The main exploration investments were made in Angola, Norway, Brazil, the United Kingdom, the United States, Indonesia, Nigeria and Brunei. In 2009, the

exploration investments of consolidated subsidiaries amounted to €1,486 million (comprising exploration bonuses included in the unproved property acquisition costs). The main exploration investments were made in the United States, Angola, the United Kingdom, Norway, Libya, Nigeria and the Republic of the Congo. In 2008, exploration investments of consolidated subsidiaries amounted to €1,243 million (comprising exploration bonuses included in the unproved property acquisition costs) notably in Angola, Nigeria, Norway, the United Kingdom, Australia, the United States, Libya, Brunei, Gabon, Cameroon, Indonesia, China, the Republic of the Congo and Canada.

The Group’s consolidated Exploration & Production subsidiaries’ development investments amounted to €8 billion in 2010, primarily in Angola, Nigeria, Kazakhstan, Norway, Indonesia, the Republic of the Congo, the United Kingdom, the United States, Canada, Thailand, Gabon and Australia. The Group’s consolidated Exploration & Production subsidiaries’ development investments amounted to nearly €8 billion in 2009, primarily in Angola, Nigeria, Norway, Kazakhstan, Indonesia, the Republic of the Congo, the United Kingdom, the United States, Gabon, Canada, Thailand, Russia and Qatar. In 2008, development investments amounted to €7 billion, predominantly in Angola, Nigeria, Norway, Kazakhstan, Indonesia, the Republic of the Congo, the United Kingdom, Gabon, Canada, the United States, and Qatar.

Reserves

The definitions used for proved, proved developed and proved undeveloped oil and gas reserves are in accordance with the United States Securities & Exchange Commission (SEC) Rule 4-10 of Regulation S-X as amended by the SEC Modernization of Oil and Gas Reporting release issued on December 31, 2008. 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 regulatory, economic and operating conditions.

TOTAL’s oil and gas reserves are consolidated annually, taking into account, among other factors, levels of production, field reassessment, additional reserves from discoveries and acquisitions, disposal of reserves and other economic factors. Unless otherwise indicated, any reference to TOTAL’s proved reserves, proved developed reserves, proved undeveloped reserves and production reflects the Group’s entire share of such reserves or such 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 under the cost method. For further information concerning changes in TOTAL’s proved reserves for the years ended December 31, 2010, 2009 and 2008, see “Supplemental Oil and Gas Information (Unaudited)”.

The reserves estimation process involves making subjective judgments. Consequently, estimates of reserves are not exact measurements and are subject to revision under well-established control procedures.

The reserves booking process requires, among other things:


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

•	that management makes significant funding commitments towards the development of the reserves prior to booking.

For further information regarding the preparation of reserves estimates, see “Supplemental Oil and Gas Information (Unaudited)”.

Proved reserves

In accordance with the amended Rule 4-10 of Regulation S-X, proved reserves for the years ended on or after December 31, 2009, are calculated using a 12-month average price determined as the unweighted arithmetic average of the first-day-of-the-month price for each month of the relevant year unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The reference prices for 2010 and 2009 were respectively $79.02/b and $59.91/b for Brent crude. The proved reserves for the year ended December 31, 2008 were calculated using December 31 price ($36.55/b).

As of December 31, 2010, TOTAL’s combined proved reserves of oil and gas were 10,695 Mboe (53% of which were proved developed reserves). Liquids (crude oil, natural gas liquids and bitumen) represented approximately 56% of these reserves and natural gas the remaining 44%. These reserves were located in Europe (mainly in Norway and the United Kingdom), in Africa (mainly in Angola, Gabon, Libya, Nigeria and the Republic of the Congo), in the Americas (mainly in Canada, the United States, Argentina, and Venezuela), in the Middle East (mainly in Qatar, the United Arab Emirates, and Yemen), and in Asia (mainly in Indonesia and Kazakhstan).

As of December 31, 2009, TOTAL’s combined proved reserves of oil and gas were 10,483 Mboe (56% of which were proved developed reserves). Liquids (crude oil, natural gas liquids and bitumen) represented approximately 54% of these reserves and natural gas the

remaining 46%. These reserves were located in Europe (mainly in Norway and the United Kingdom), in Africa (mainly in Angola, Gabon, Libya, Nigeria and the Republic of the Congo), in the Americas (mainly in Canada, the United States, Argentina, and Venezuela), in the Middle East (mainly in Oman, Qatar, the United Arab Emirates, and Yemen), and in Asia (mainly in Indonesia and Kazakhstan).

As of December 31, 2008, TOTAL’s combined proved reserves of oil and gas were 10,458 Mboe (50% of which were proved developed reserves). Liquids represented approximately 54% of these reserves and natural gas the remaining 46%. These reserves were located in Europe (mainly in Norway and the United Kingdom), in Africa (mainly in Algeria, Angola, Gabon, Libya, Nigeria and the Republic of the Congo), in the Americas (mainly in Canada, Bolivia, Argentina, and Venezuela), in the Middle East (mainly in Oman, Qatar, the United Arab Emirates, and Yemen), and in Asia (mainly in Indonesia and Kazakhstan).

Sensitivity to oil and gas prices

Changes in the price used as a reference for the proved reserves estimation result in non-proportionate inverse changes in proved reserves associated with production sharing and risked service contracts (which together represent approximately 30% of TOTAL’s reserves as of December 31, 2010). Under such contracts, TOTAL is entitled to a portion of the production, the sale of which is meant to cover expenses incurred by the Group. As oil prices increase, fewer barrels are necessary to cover the same amount of expenses. Moreover, the number of barrels retrievable under these contracts may vary according to criteria such as cumulative production, the rate of return on investment or the income-cumulative expenses ratio. This decrease is partly offset by an extension of the duration over which fields can be produced economically. However, the increase in reserves due to extended field life resulting from higher prices is generally less than the decrease in reserves under production sharing or risked service contracts due to such higher prices. As a result, higher prices lead to a decrease in TOTAL’s reserves.

Production

For the full year 2010, average daily oil and gas production was 2,378 kboe/d compared to 2,281 kboe/d in 2009.

Liquids accounted for approximately 56% and natural gas accounted for approximately 44% of TOTAL’s combined liquids and natural gas production in 2010.

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

Consistent with industry practice, TOTAL often holds a percentage interest in its fields rather than a 100% interest, with the balance being held by joint venture partners (which may include other international oil companies, state-owned 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 the table “Presentation of production activities by geographic area” on the following pages for a description of TOTAL’s producing assets.

As in 2009 and 2008, substantially all of the liquids production from TOTAL’s Upstream segment in 2010 was marketed by the Trading & Shipping division of TOTAL’s Downstream segment. See the table “— Business Overview — Trading & Shipping — Supply and sales of crude oil”.

The majority of TOTAL’s natural gas production is sold under long-term contracts. However, its North American production, and to some extent its production from the United Kingdom, Norway and Argentina, is sold on the spot market. The long-term contracts under which TOTAL sells its natural gas 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. Though the price of natural gas tends to fluctuate in line with crude oil prices, a slight delay may occur before changes in crude oil prices are reflected in long-term natural gas prices. Due to the interaction between the contract price of natural gas and crude oil prices, contract prices are not usually affected by short-term market fluctuations in the spot price of natural gas. Some of TOTAL’s long-term contracts, notably in Argentina, Indonesia, Nigeria, Norway and Qatar, specify the delivery of quantities of natural gas that may or may not be fixed and determinable. Such delivery commitments vary substantially, both in duration and in scope, from contract to contract throughout the world. For example, in some cases, contracts require delivery of natural gas on an as-needed basis, and, in other cases, contracts call for the delivery of varied amounts of natural gas over different periods of time. Nevertheless, TOTAL estimates the fixed and determinable quantity of gas to be delivered over the period 2011-2013 to be 3,665 Bcf. The Group expects to satisfy most of these obligations through the production of its proved reserves of natural gas, with, if needed, additional sourcing from spot market purchases. See “Supplemental Oil and Gas Information (Unaudited)”.

PRODUCTION BY GEOGRAPHIC AREA


	2010						2009						2008
			Natural						Natural						Natural
	Liquids		gas		Total		Liquids		gas		Total		Liquids		gas		Total
	kb/d		Mcf/d		kboe/d		kb/d		Mcf/d		kboe/d		kb/d		Mcf/d		kboe/d
Africa		616		712		756		632		599		749		654		659		783
Algeria		25		87		41		47		143		74		51		145		79
Angola		157		34		163		186		33		191		200		33		205
Cameroon		9		2		9		12		2		12		13		2		14
The Congo, Republic of		115		27		120		101		27		106		85		23		89
Gabon		63		20		67		67		20		71		73		20		76
Libya		55		—		55		60		—		60		74		—		74
Nigeria		192		542		301		159		374		235		158		436		246
North America		30		199		65		20		22		24		11		15		14
Canada^(a)		10		—		10		8		—		8		8		—		8
United States		20		199		55		12		22		16		3		15		6
South America		76		569		179		80		564		182		119		579		224
Argentina		14		381		83		15		364		80		14		365		81
Bolivia		3		94		20		3		91		20		3		105		22
Colombia		11		34		18		13		45		23		14		45		23
Trinidad & Tobago		3		2		3		5		2		5		6		2		6
Venezuela		45		58		55		44		62		54		82		62		92
Asia-Pacific		28		1,237		248		33		1,228		251		29		1,236		246
Australia		—		6		1		—		—		—		—		—		—
Brunei		2		59		14		2		49		12		2		60		14
Indonesia		19		855		178		25		898		190		21		857		177
Myanmar		—		114		14		—		103		13		—		117		14
Thailand		7		203		41		6		178		36		6		202		41
CIS		13		56		23		14		52		24		12		75		26
Azerbaijan		3		54		13		3		50		12		4		73		18
Russia		10		2		10		11		2		12		8		2		8
Europe		269		1,690		580		295		1,734		613		302		1,704		616
France		5		85		21		5		100		24		6		103		25
The Netherlands		1		234		42		1		254		45		1		244		44
Norway		183		683		310		199		691		327		204		706		334
United Kingdom		80		688		207		90		689		217		91		651		213
Middle East		308		1,185		527		307		724		438		329		569		432
United Arab Emirates		207		76		222		201		72		214		228		74		243
Iran		2		—		2		8		—		8		9		—		9
Oman		23		55		34		22		56		34		23		59		34
Qatar		49		639		164		50		515		141		44		434		121
Syria		14		130		39		14		34		20		15		2		15
Yemen		13		285		66		12		47		21		10		—		10
Total production		1,340		5,648		2,378		1,381		4,923		2,281		1,456		4,837		2,341
Including share of equity and non-consolidated affiliates		300		781		444		286		395		359		347		298		403
Algeria		19		4		20		20		3		21		19		4		20
Colombia		7		—		7		6		—		6		5		—		5
Venezuela		45		6		46		44		6		45		82		6		83
United Arab Emirates		199		66		212		191		62		202		218		64		231
Oman		22		55		32		22		56		34		23		59		34
Qatar		8		367		75		3		221		42		—		165		30
Yemen		—		283		52		—		47		9		—		—		—


(a)		The Group’s production in Canada consists of bitumen only. All of the Group’s bitumen production is in Canada.

PRESENTATION OF PRODUCTION ACTIVITIES BY GEOGRAPHIC AREA

The table below sets forth, by country, TOTAL’s producing assets, the year in which TOTAL’s activities started, the Group’s interest in each asset and whether TOTAL is operator of the asset.


TOTAL’s producing assets as of December 31, 2010^(a)


	Year of
	entry into		Operated	Non-operated
	the country		(Group share in %)	(Group share in %)
Africa
Algeria		1952
				Ourhoud (19.41%)^(b)
				RKF (48.83%)^(b)
				Tin Fouye Tabankort (35.00%)

Angola		1953	Blocks 3-85, 3-91 (50.00%)
			Girassol, Jasmim,
			Rosa, Dalia (Block 17) (40.00%)
				Cabinda (Block 0) (10.00%)
				Kuito, BBLT, Tombua-Landana (Block 14) (20.00%)

Cameroon		1951	Bakingili (25.50%)
			Bavo-Asoma (25.50%)
			Boa Bakassi (25.50%)
			Ekundu Marine (25.50%)
			Kita Edem (25.50%)
			Kole Marine (25.50%)
				Mokoko - Abana (10.00%)
				Mondoni (25.00%)

The Congo, Republic of		1928	Kombi-Likalala (65.00%)
			Nkossa (53.50%)
			Nsoko (53.50%)
			Moho Bilondo (53.50%)
			Sendji (55.25%)
			Tchendo (65.00%)
			Tchibeli-Litanzi-Loussima (65.00%)
			Tchibouela (65.00%)
			Yanga (55.25%)
				Loango (50.00%)
				Zatchi (35.00%)

Gabon		1928	Anguille (100.00%)
			Anguille Nord Est (100.00%)
			Anguille Sud-Est (100.00%)
			Atora (40.00%)
			Avocette (57.50%)
			Ayol Marine (100.00%)
			Baliste (50.00%)
			Barbier (100.00%)
			Baudroie Marine (50.00%)
			Baudroie Nord Marine (50.00%)
			Coucal (57.50%)
			Girelle (100.00%)
			Gonelle (100.00%)
			Grand Anguille Marine (100.00%)
			Grondin (100.00 %)
			Hylia Marine (75.00%)
			Lopez Nord (100.00%)
			Mandaros (100.00%)
			M’Boumba (100.00%)
			Mérou Sardine Sud (50.00%)
			Pageau (100.00%)
			Port Gentil Océan (100.00%)
			Port Gentil Sud Marine (100.00%)
			Tchengue (100.00%)
			Torpille (100.00%)
			Torpille Nord Est (100.00%)
				Rabi Kounga (47.50%)


	Year of
	entry into		Operated	Non-operated
	the country		(Group share in %)	(Group share in %)
Libya		1959		C 17 (Mabruk) (15.00%)
				C 137 (Al Jurf) (20.25%)
				NC 115 (El Sharara) (3.90%)
				NC 186 (2.88%)

Nigeria		1962	OML 58 (40.00%)
			OML 99 Amenam-Kpono (30.40%)
			OML 100 (40.00%)
			OML 102 (40.00%)	OML 102 - Ekanga (40.00%)
			OML 130 (24.00%)
				Shell Petroleum Development Company (SPDC 10.00%)
				OML 118 - Bonga (12.50%)

North America
Canada		1999		Surmont (50.00%)

United States		1957		Several assets in the Barnett Shale area (25.00%)
				Tahiti (17.00%)

South America
Argentina		1978	Aguada Pichana (27.27%)
			Aries (37.50%)
			Cañadon Alfa Complex (37.50%)
			Carina (37.50%)
			Hidra (37.50%)
			San Roque (24.71%)
				Sierra Chata (2.51%)

Bolivia		1995		San Alberto (15.00%)
				San Antonio (15.00%)

Colombia		1973		Caracara (34.18%)⁽ⁱ⁾
				Cusiana (11.60%)
				Espinal (7.32%)⁽ⁱ⁾
				San Jacinto/Rio Paez (8.14%)⁽ⁱ⁾

Trinidad & Tobago		1996		Angostura (30.00%)

Venezuela		1980		PetroCedeño (30.323%)
				Yucal Placer (69.50%)

Asia-Pacific
Australia		2005		GLNG (20.00%)

Brunei		1986	Maharaja Lela Jamalulalam (37.50%)

Indonesia		1968	Bekapai (50.00%)
			Handil (50.00%)
			Peciko (50.00%)
			Sisi-Nubi (47.90%)
			Tambora (50.00%)
			Tunu (50.00%)
				Badak (1.05%)
				Nilam - gas and condensates (9.29%)
				Nilam - oil (10.58%)

Myanmar		1992	Yadana (31.24%)

Thailand		1990		Bongkot (33.33%)

CIS
Azerbaijan		1996		Shah Deniz (10.00%)

Russia		1989	Kharyaga (40.00%)

Europe
France		1939	Lacq (100.00%)
			Meillon (100.00%)
			Pecorade (100.00%)


	Year of
	entry into		Operated	Non-operated
	the country		(Group share in %)	(Group share in %)
			Vic-Bilh (73.00%)
			Lagrave (100.00%)
			Lanot (100.00%)
				Dommartin-Lettrée (56.99%)
			Itteville (78.73%)
			La Croix-Blanche (100.00%)
			Rousse (100.00%)
			Vert-le-Grand (90.05%)
			Vert-le-Petit (100.00%)

Norway		1965	Skirne (40.00%)
				Åsgard (7.68%)
				Ekofisk (39.90%)
				Eldfisk (39.90%)
				Embla (39.90%)
				Gimle (4.90%)
				Glitne (21.80%)
				Gungne (10.00%)
				Heimdal (16.76%)
				Huldra (24.33%)
				Kristin (6.00%)
				Kvitebjørn (5.00%)
				Mikkel (7.65%)
				Morvin (6.00%)
				Oseberg (10.00%)
				Oseberg East (10.00%)
				Oseberg South (10.00%)
				Sleipner East (10.00%)
				Sleipner West (9.41%)
				Snøhvit (18.40%)
				Snorre (6.18%)
				Statfjord East (2.80%)
				Sygna (2.52%)
				Tor (48.20%)
				Tordis (5.60%)
				Troll I (3.69%)
				Troll II (3.69%)
				Tune (10.00%)
				Tyrihans (23.18%)
				Vale (24.24%)
				Vigdis (5.60%)
				Vilje (24.24%)
				Visund (7.70%)
				Yttergryta (24.50%)

The Netherlands		1964	F6a gaz (55.66%)
			F6a huile (65.68%)
			F15a Jurassic (38.20%)
			F15a/F15d Triassic (32.47%)
			F15d (32.47%)
			J3a (30.00%)
			K1a (40.10%)
			K1b/K2a (54.33%)
			K2c (54.33%)
			K3b (56.16%)
			K3d (56.16%)
			K4a (50.00%)
			K4b/K5a (36.31%)
			K5b (45.27%)
			K6/L7 (56.16%)
			L1a (60.00%)


	Year of
	entry into		Operated	Non-operated
	the country		(Group share in %)	(Group share in %)
			L1d (60.00%)
			L1e (55.66%)
			L1f (55.66%)
			L4a (55.66%)
				E16a (16.92%)
				E17a/E17b (14.10%)
				J3b/J6 (25.00%)
				Q16a (6.49%)

United Kingdom		1962	Alwyn North, Dunbar, Ellon, Grant
			Nuggets (100.00%)
			Elgin-Franklin (EFOG 46.17%)^(c)
			Forvie Nord (100.00%)
			Glenelg (49.47%)
			Jura (100.00%)
			Otter (81.00%)
			West Franklin (EFOG 46.17%)^(c)
				Alba (12.65%)
				Armada (12.53%)
				Bruce (43.25%)
				Markham unitized fields (7.35%)
				ETAP (Mungo. Monan) (12.43%)
				Everest (0.87%)
				Keith (25.00%)
				Maria (28.96%)
				Seymour (25.00%)
Middle East
U.A.E.		1939	Abu Dhabi -Abu Al Bu Khoosh (75.00%)
				Abu Dhabi offshore (13.33%)^(d)
				Abu Dhabi onshore (9.50%)^(e)
				GASCO (15.00%)
				ADGAS (5.00%)

Oman		1937		Various fields onshore (Block 6) (4.00%)^(f)
				Mukhaizna field (Block 53) (2.00%)^(g)

Qatar		1936	Al Khalij (100.00%)
				North Field - Block NF Dolphin (24.50%)
				North Field - Block NFB (20.00%)
				North Field -Qatargas 2 Train 5 (16.70%)

Syria		1988	Deir Ez Zor (Al Mazraa, Atalla North, Jafra, Marad, Qahar, Tabiyeh) (100.00%)^(h)

Yemen		1987	Kharir/Atuf (bloc 10) (28.57%)
				Various fields onshore (Block 5) (15.00%)


(a)		The Group’s interest in the local entity is approximately 100% in all cases except for Total Gabon (58.3%), Total E&P Cameroon (75.80%) and certain entities in the United Kingdom, Algeria, Abu Dhabi and Oman (see notes b through i below).
(b)		TOTAL has an indirect 19.41% interest in the Ourhoud field and a 48.83% indirect interest in the RKF field through its interest in CEPSA (equity affiliate).
(c)		TOTAL has a 35.8% indirect interest in Elgin Franklin through its interest in EFOG.
(d)		Through ADMA (equity affiliate), TOTAL has a 13.33% interest and participates in the operating company, Abu Dhabi Marine Operating Company.
(e)		Through ADPC (equity affiliate), TOTAL has a 9.50% interest and participates in the operating company, Abu Dhabi Company for Onshore Oil Operation.
(f)		TOTAL has a direct interest of 4.00% in Petroleum Development Oman LLC, operator of Block 6, in which TOTAL has an indirect interest 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% through OLNG in Qalhat LNG (train 3).
(g)		TOTAL has a direct interest of 2.00% in Block 53.
(h)		Operated by DEZPC which is 50.00% owned by TOTAL and 50.00% owned by SPC.
(i)		TOTAL has an indirect 34.18% interest in the Caracara Block, 8.14% in the San Jacinto/Rio Paez Block and 7.32% in the Espinal Block through its interest in CEPSA (equity affiliate).

Africa

In 2010, TOTAL’s production in Africa was 756 kboe/d, representing 32% of the Group’s overall production, compared to 749 kboe/d in 2009 and 783 kboe/d in 2008.

In Algeria, TOTAL’s production amounted to 41 kboe/d in 2010, compared to 74 kboe/d in 2009 and 79 kboe/d in 2008. This decline is mainly due to the termination of the Hamra contract in October 2009. The Group’s production came from its direct interest in the TFT field (Tin Fouyé Tabenkort, 35%) and from its 48.83% interest in CEPSA⁽¹⁾, a partner of Sonatrach (the Algerian national oil and gas company) on the Ourhoud and Rhourde El Krouf fields. TOTAL also holds a direct 37.75% interest in the Timimoun gas project alongside Sonatrach (51%) and CEPSA (11.25%) as well as a 47% interest in the Ahnet gas project alongside Sonatrach (51%) and Partex (2%).


•	On the TFT field, the compression project commissioned in 2010 is expected to extend plateau production to 185 kboe/d.


•	Basic engineering studies for the Timimoun project were launched in 2010 following approval by the ALNAFT national agency. Start-up of the project is scheduled in 2014 with commercial production of natural gas estimated at approximately 160 Mcf/d (1.6 Bm³/y) at plateau.

•	As part of the Ahnet project, a development plan is expected to be submitted to the authorities before mid-2011, with start-up of production scheduled for 2015 and an expected plateau production of at least 400 Mcf/d (4 Bm³/y).

In Angola, the Group’s production was 163 kboe/d in 2010, compared to 191 kboe/d in 2009 and 205 kboe/d in 2008. Production comes mainly from Blocks 17, 0 and 14. Highlights of the period 2008 to 2010 included several discoveries on Blocks 15/06 and 17/06, and progress on the major Pazflor and CLOV projects.


•	Deep-offshore Block 17 (40%, operator) is TOTAL’s principal asset in Angola. It is composed of four major zones: Girassol, Dalia, Pazflor and CLOV.

On the Girassol pole, production from the Girassol, Jasmim and Rosa fields was more than 190 kb/d in 2010.

On the Dalia pole, production was more than 240 kb/d in 2010.

On the third pole, Pazflor, comprised of the Perpetua, Zinia, Hortensia and Acacia fields, production is scheduled to begin in late 2011. This project provides for the installation of an FPSO with a production capacity of 220 kb/d.

The development of CLOV, the fourth pole, was launched in 2010 with the award of the main contracts. This development will result in the installation of a fourth FPSO with a production capacity of 160 kb/d. Start-up of production is expected in 2014.


•	On Block 14 (20%), production on the Tombua-Landana field started in August 2009 and adds to production from the Benguela-Belize-Lobito-Tomboco and Kuito fields.

•	On ultra-deep offshore Block 32 (30%, operator), appraisal is continuing and pre-development studies for a first production zone in the central/southeastern portion of the block are underway (Kaombo project).

•	On Block 15/6 (15%), four major discoveries were announced in 2010. Studies are underway to demonstrate the feasibility of a first development area that would include the discoveries located on the northwest portion of the block.

TOTAL also has operations on exploration Blocks 33 (55%, operator) and 17/06 (30%, operator).

At year-end 2010, TOTAL sold its 5% interest in Block 31.

TOTAL is also developing in LNG through the Angola LNG project (13.6%) with the construction of a gas liquefaction plant near Soyo. The plant will be supplied in particular by the gas associated with production from Blocks 0, 14, 15, 17 and 18. Construction work is ongoing and start-up is expected in 2012.

In Cameroon, the Group’s production was 9 kboe/d in 2010, compared to 12 kboe/d in 2009 and 14 kboe/d in 2008.

In November 2010, TOTAL finalized an agreement in principle with Perenco to sell the Group’s 75.8% interest in its Exploration & Production subsidiary in Cameroon. The agreement is subject to the approval by the Cameroonian authorities.

In Côte d’Ivoire, TOTAL signed in October 2010 an agreement to acquire a 60% interest (operator) in the CI-100 exploration license. The transaction has been approved by the relevant authorities. The 2,000 km² license is located approximately 100 km southeast of Abidjan in water depths ranging from 1,500 to 3,100 meters. Exploration work will include a new 1,000 km² 3D seismic survey, which will complete coverage of the block, and a first well is expected to be drilled in 2012.

(1) In February 2011, TOTAL signed an agreement to dispose of its 48.83% interest in CEPSA. The transaction is conditioned on obtaining all requisite approvals.

In Egypt, TOTAL signed a concession agreement in February 2010 and became operator of Block 4 (El Burullus offshore Est) with an interest of 90%. The license, located in the Nile Basin where a number of gas discoveries have been made, covers a 4-year initial exploration period and includes a commitment to carrying out 3D seismic work and drilling exploration wells. The seismic campaign started in November 2010 and ended in February 2011.

In Gabon, the Group’s share of production was 67 kboe/d in 2010, compared to 71 kboe/d in 2009 and 76 kboe/d in 2008, due to the natural decline of fields. Total Gabon⁽¹⁾ is one of the Group’s oldest subsidiaries in sub-Saharan Africa.


•	On the Anguille field, five development wells were drilled in 2010 from existing platforms and the construction of a new well platform has been launched.


•	On the deep-offshore Diaba license (Total Gabon 63.75%, operator), following the 2D seismic survey that was shot in 2008 and 2009, a 6,000 km² 3D seismic was shot in 2010.

•	Licenses for the Avocette and Coucal fields have been renewed in the form of an operating and production sharing agreement effective as of January 1, 2011, each for a 10-year period renewable for two subsequent 5-year periods.

•	Total Gabon farmed into the onshore Mutamba-Iroru (50%), DE7 (30%), and Nziembou (20%) exploration licenses in 2010.

In Libya, the Group’s production was 55 kb/d in 2010, compared to 60 kb/d in 2009 and 74 kb/d in 2008. Declining production was primarily due to the implementation of OPEC quotas and new contractual provisions for Blocks C 17 (75%)⁽²⁾, C 137 (75%)⁽²⁾, NC 115 (30%)⁽²⁾ and NC 186 (24%)⁽²⁾ on which TOTAL is a partner. The EPSA IV agreements (exploration and production sharing agreements) on Blocks C 137 and C 17 were ratified by the Libyan government in January 2010 and now extend to 2032.

Having regard to the security context in Libya in the first quarter of 2011, the Group’s production in Libya has been significantly reduced since early March. Furthermore, the Group is reviewing the impacts on its operations and the measures to be taken for the projects mentioned below.


•	On Block C 17, the Dahra and Garian fields are in the development phase.


•	On Block C 137, drilling of two offshore exploration wells is planned for 2011.

•	On Blocks NC 115 and NC 186, the nearly 5,000 km² seismic campaign is expected to be completed in 2011.

•	On the Murzuk Basin, following a successful appraisal well drilled on the discovery made on a portion of Block NC 191 (100%⁽²⁾, operator), a development plan was submitted to the authorities in 2009.

•	In December 2010, the Group relinquished Block 42 2/4 (60%⁽²⁾, operator) located in the Cyrenaic Basin at the contract expiration date following an exploration well’s disappointing results.

In Madagascar, TOTAL acquired in 2008 a 60% interest in the Bemolanga permit (operator), which contains oil sand accumulations. A first appraisal phase was launched to confirm the bitumen resources needed for a mining development. Drilling operations were carried out in two phases during the dry season between July and November 2009 and between April and July 2010.

In Mauritania, TOTAL has exploration operations on the Ta7 and Ta8 licenses (60%, operator), located in the Taoudenni Basin alongside Sonatrach (20%) and Qatar Petroleum International (20%).


•	On the Ta8 license, drilling of the exploration well ended in 2010. Results from the well are disappointing.

•	On Block Ta7, shooting of a 1,000 km 2D seismic started in 2011.

In Nigeria, the Group’s production amounted to 301 kboe/d in 2010, compared to 235 kboe/d in 2009 and 246 kboe/d in 2008. This increase is due in particular to improved security conditions in the Niger Delta. TOTAL has been present in Nigeria since 1962. It operates seven production licenses (OML) out of the forty-four in which it holds an interest, and two exploration licenses (OPL) out of the eight in which it holds an interest. The Group is also active in LNG through Nigeria LNG and the Brass LNG project. In 2010, TOTAL acquired a 45.9% interest in Block 1 in the Joint Development Zone governed by Nigeria and São Tomé and Príncipe and was awarded operatorship in this block.


•	TOTAL holds a 15% interest in the Nigeria LNG gas liquefaction plant, located on Bonny Island, with an overall capacity of 22 Mt/y of LNG. In 2010, an improvement in the security situation for onshore facilities resulted in increased LNG production. NLNG’s utilization rate was approximately 72% in 2010, compared to approximately 50% in 2009.

(1) Total Gabon is a Gabonese company whose shares are listed on Euronext Paris. TOTAL holds 58%, the Republic of Gabon holds 25% and the public float is 17%.

(2) Interest held in the foreign consortium.


	Preliminary work prior to launching the Brass LNG project (17%), which calls for the construction of two trains, each with a capacity of 5 Mt/y, continued in 2010.

•	TOTAL strengthened its ability to supply gas to the LNG projects in which it has interests and to meet the growing domestic demand in gas:


	–	On the OML 136 license (40%), the positive results for the Agge 3 appraisal well confirmed the development potential of the license. Development studies are underway.

	–	As part of its joint venture with the Nigerian National Petroleum Corporation (NNPC), TOTAL launched a project to increase the production capacity of the OML 58 license (40%, operator) from 370 Mcf/d to 550 Mcf/d of gas in 2011. A second phase of this project, which is currently being assessed, is expected to allow the development of other reserves through these facilities.

	–	On the OML 112/117 licenses (40%), TOTAL continued development studies in 2010 for the Ima gas field.


•	On the OML 102 license (40%, operator), TOTAL is expected to make the final investment decision for the Ofon phase 2 project in 2011 with a start-up scheduled in 2014. The Group also launched in 2010 an appraisal campaign for the Etisong field, located 15 km from the Ofon field, which is currently producing.

•	On the OML 130 license (24%, operator), the Akpo field, which started up in March 2009, reached in 2010 plateau production of 225 kboe/d (in 100%). The Group is actively developing the Egina field, for which a development plan was approved by the Nigerian authorities. Basic engineering studies carried out in Nigeria are now completed and call for tenders for the projects have been launched.

•	On the OML 138 license (20%, operator), development of the Usan project (180 kb/d, production capacity) continued in 2010, in particular with the drilling of production wells, the construction of the FPSO and the start of the installation of sub-sea equipment. Production is expected to start-up in 2012.

•	TOTAL also consolidated deep offshore positions with the ongoing development of the Bonga Northwest project on the OML 118 license (12.5%).

Improved security conditions in the Niger Delta region resulted in a substantial increase in the production operated by the Shell Petroleum Development Company (SPDC) joint venture, in which TOTAL owns 10%. The Soku processing plant resumed operations in 2009 and the Gbaran-Ubie development project was completed in 2010 with the commissioning of the 1 Bcf/d production facility.

In 2010, TOTAL disposed of the interests it held (10%) through the operated SPDC joint venture in the
OML 4, 38 and 41 licenses.

In the Republic of the Congo, the Group’s share of production was 120 kboe/d in 2010, compared to 106 kboe/d in 2009 and 89 kboe/d in 2008.


•	On the Moho Bilondo field (53.5%, operator), which started up in April 2008, drilling of development wells continued in 2010. The field reached plateau production of 90 kboe/d (in 100%) in June 2010. Growth potential of the northern part of the field was confirmed by the Moho North Marine 3 appraisal well drilled at year-end 2008 following the Moho North Marine 1 and 2 discoveries, and later in 2009 by the Moho North Marine 4 exploration well that discovered new resources. Finally, two positive appraisal wells (Bilondo Marine 2 & 3) drilled at year-end 2010 in the southern portion of the field confirmed an additional growth potential as an extension of existing facilities.

•	Production on Libondo (65%, operator), which is part of the Kombi-Likalala-Libondo operating license, started up in March 2011. Anticipated plateau production is 8 kb/d (in 100%). A substantial portion of the equipment was sourced locally in Pointe-Noire through the redevelopment of a construction site that had been idle for several years.

In Sudan, the Group holds interests in an exploration license in the southern part of the country, although no activity is currently underway in this country. For additional information on TOTAL’s operations in Sudan, see “— Other Matters — Business Activities In Cuba, Iran, Sudan and Syria”.

North America

In 2010, TOTAL’s production in North America was 65 kboe/d, representing 3% of the Group’s overall production, compared to 24 kboe/d in 2009 and 14 kboe/d in 2008.

In Canada, TOTAL signed in December 2010 a strategic partnership with Suncor related to the Fort Hills and Joslyn mining projects and the Voyageur upgrader. This partnership allows TOTAL to reorganize around two major poles the different oil sands assets that it has acquired over the last few years: a mining and upgrading pole, which includes the TOTAL-operated Joslyn (38.25%) and Suncor-

operated Fort Hills (39.2%) mining projects as well as the Suncor-operated Voyageur upgrader (49%), and a SAGD⁽¹⁾ pole focused on Surmont’s (50%) ongoing development. The Group also holds a 50% interest in the Northern Lights (operator) mining project and 100% of a number of leases (Oil Sand Leases) acquired through several auction sales. The Group’s 2010 production amounted to 10 kb/d, compared to 8 kb/d in 2009 and 2008.


•	On the Surmont lease, commercial production in SAGD mode from the first development phase (Surmont Phase 1A) started in late 2007.


	Construction work for phases 1B and 1C was completed, which should allow these phases to reach production level estimated at 24 kb/d (in 100%). The wells of phase 1B gradually started production in 2009 and 2010 and those of phase 1C are expected to be connected and to start production in 2011.

	In early 2010, the partners of the project decided to launch the construction of the second phase of development. Start-up of production from Surmont Phase 2 is scheduled in 2015 and overall production capacity from Surmont (phases 1 and 2) is expected to increase to 110 kb/d (in 100%).

•	The Joslyn lease, located approximately 140 km north of Surmont, is expected to be developed through mining in two phases of 100 kb/d of bitumen each.

	The comprehensive review of the first phase (Joslyn North Mine), notably to meet the requirements of the February 2009 new regulation related to tailings management, was completed in February 2010 concurrent with the filing of an updated administrative file. Continuation of the preparation work for Joslyn North Mine was approved in early March 2010 and basic engineering studies were launched that are expected to end in mid-2011. Public hearings that are necessary for the project to be approved by the Canadian authorities were held in September and October 2010. The project was recommended as being in the public’s interest on January 27, 2011, subject to TOTAL satisfying twenty conditions mainly related to the protection of the environment. Preliminary site preparation work is expected to be carried out from the winter 2011-2012 and production is scheduled to start in 2017/2018. However, the final schedule is subject to the Energy Resources Conservation Board’s (ERCB) administrative approval process. As part of the partnership agreement signed at year-end 2010 with Suncor, the Group decreased its interest in Joslyn to 38.25% from 75%.

•	TOTAL closed in September 2010 the acquisition of UTS and its sole asset: a 20% interest in the Fort Hills lease. In December 2010, as part of their partnership, TOTAL acquired from Suncor an additional 19.2% interest in the Fort Hills lease and increased its interest to 39.2%. Start-up of the Fort Hills project, which was approved by the relevant authorities for a first development phase of 160 kb/d, is expected in 2016.

•	TOTAL also acquired in late December 2010 a 49% interest in Suncor’s Voyageur upgrader project. TOTAL and Suncor agreed to develop the Fort Hills and Voyageur projects in parallel. This Voyageur upgrader project that Suncor mothballed at year-end 2008 will resume in 2011 and will start up concurrently with the Fort Hills project. As a consequence, the Group has abandoned its upgrader project in Edmonton.

•	In 2008, the Group closed the acquisition of Synenco, the two principal assets of which are a 60% interest in the Northern Lights project and 100% of the adjacent McClelland lease. In early 2009, the Group sold to Sinopec, the other partner in the project, a 10% share in the Northern Lights project and a 50% share in the McClelland lease, reducing its interest in each of the assets to 50%. The Northern Lights project, located approximately 50 km north of Joslyn, is expected to be developed through mining techniques.

In the United States, the Group’s 2010 production amounted to 55 kboe/d, compared to 16 kboe/d in 2009 and 6 kboe/d in 2008. This increase is due in particular to the acquisition of an interest in the Barnett Shale Basin at year-end 2009.


•	In the Gulf of Mexico:


	–	The deep-offshore Tahiti oil field (17%) started producing in May 2009 and rapidly reached plateau production of 135 kboe/d. Phase 2 was launched in September 2010 with the drilling of the first water injection well.

	–	Development of the first phase of the deep-offshore Chinook project (33.33%) is ongoing. The production test is scheduled to start in the first half of 2011.

	–	The TOTAL (40%) — Cobalt (60%, operator) alliance’s exploration drilling campaign was

(1) Steam Assisted Gravity Drainage.


		launched in 2009 and the drilling of the first wells produced disappointing results. This campaign was disrupted due to the U.S. government’s moratorium on offshore drilling operations from May to October 2010 and may resume by mid-2011. In April 2009, TOTAL and Cobalt had signed an agreement related to the merger of their deep offshore acreage. Cobalt is operating the exploration phase.


	–	In April 2010, the Group disposed of its interests in the Matterhorn and Virgo operated fields.


•	Following the signature of an agreement in December 2009, a joint venture was set up with Chesapeake to produce shale gas in the Barnett Shale Basin, Texas. As part of this joint venture, TOTAL holds 25% of Chesapeake’s portfolio in the Barnett Shale area. In 2010, 400 wells were drilled to increase gas production from 700 Mcf/d at the beginning of the year to 800 Mcf/d at year-end. Engineers from TOTAL are assigned to the teams led by Chesapeake.

•	In January 2009, the Group closed the acquisition of a 50% interest in American Shale Oil LLC (AMSO) to develop oil shale technology. The pilot to develop this technology is underway in Colorado.

•	In Alaska, TOTAL acquired in 2008 a 30% interest in several onshore exploration blocks known as “White Hills”. Most of them were relinquished in mid-2009 following disappointing results.

In Mexico, TOTAL is conducting various studies in cooperation with state-owned PEMEX under a technical cooperation agreement signed in 2003 which is in the process of being renewed.

South America

In 2010, TOTAL’s production in South America was 179 kboe/d, representing 8% of the Group’s overall production, compared to 182 kboe/d in 2009 and 224 kboe/d in 2008.

In Argentina, where TOTAL has been present since 1978, the Group operates a quarter of the country’s gas production⁽¹⁾. The Group’s production was 83 kboe/d in 2010, compared to 80 kboe/d in 2009 and 81 kboe/d in 2008.


•	In the Neuquén Basin, the connection of satellite discoveries and an increase in compression capacity resulted in the extension of the San Roque (24.7%, operator) and Aguada Pichana (27.3%, operator) fields’ plateau production.


	In 2009, TOTAL and the Argentinean authorities signed an agreement extending the Aguada Pichana and San Roque concessions for ten years (from 2017 to 2027). As part of this agreement, 3D seismic was shot in late 2009 in the Las Carceles canyons area to allow the development of Aguada Pichana to continue westward.

In early 2011, TOTAL acquired interests in four licenses located in the Neuquén basin in order to assess their shale gas potential. The Group acquired 42.5% interests in and the operatorship of the Aguada de Castro and Pampa las Yeguas II licenses, a 40% interest in the Cerro Las Minas license and a 45% interest in the Cerro Partido license.

•

In Tierra del Fuego, where the Group notably operates the offshore Carina and Aries fields (37.5%), gas production capacity increased from 424 Mcf/d to 565 Mcf/d in 2007 thanks to the installation of a fourth medium-pressure compressor to debottleneck the facilities. Work to increase the capacity of the pipeline that routes the gas to the region of Buenos Aires was completed in July 2010. This allowed the Group to increase production up to the maximum capacity of the processing plant during the southern winter.

In Bolivia, the Group’s share of production, primarily gas, amounted to 20 kboe/d in 2010, stable compared to 2009, compared to 22 kboe/d in 2008. TOTAL holds interests in six licenses: three producing licenses — San Alberto and San Antonio (15%) and Block XX Tarija Oeste (41%); and three licenses in the exploration or appraisal phase — Aquio and Ipati (60%, operator) and Rio Hondo (50%).


•	Production started up in February 2011 on the gas and condensates Itaú field located on Block XX Tarija Oeste; it is routed to the existing facilities of the neighboring San Alberto field. In 2010, TOTAL decreased its interest to 41% in Block XX Tarija Oeste after divesting 34% and is no longer the operator.

•	In 2004, TOTAL discovered the Incahuasi gas field on the Ipati Block. Following the interpretation of the 3D seismic shot in 2008, an appraisal well is ongoing on the adjacent Aquio Block to confirm the extension of the discovery to the north. In 2010, TOTAL signed an agreement to dispose of 20% in the Aquio and Ipati licenses. Under this agreement, which is subject to the approval by the Bolivian authorities, TOTAL’s interest in the licenses will be 60%.

(1) Source: Argentinean Ministry of Federal Planning, Public Investment and Services — Energy Secretary.

In 2008, TOTAL entered into a cooperation agreement with Gazprom and Yacimientos Petrolíferos Fiscales Bolivianos to explore the Azero Block as part of a joint venture company. TOTAL and Gazprom will be partners with equal interests in this joint venture company.

In Brazil, TOTAL holds interests in three exploration blocks: Blocks BC-2 (41.2%) and BM-C-14 (50%) in the Campos Basin, and Block BM-S-54 (20%) in the Santos Basin.


•	On Block BC-2, following seismic reprocessing, a pre-salt prospect was found under the Xerelete (formerly Curió) discovery made in 2001 at a water depth of 2,400 m.

•	The southern extremity of Xelerete is located on Block BM-C-14, which is adjacent to Block BC-2. A unitization agreement was completed by the partners on both blocks. This agreement is subject to approval by the ANP (Agência National do Petroléo).

•	In June 2010, the Group acquired a 20% interest in the BM-S-54 license. Preliminary assessment of data from the exploration drilling, which was completed in November 2010, was positive and a second drilling is expected in 2011.

In Colombia, where TOTAL has been present since 1973, the Group’s production was 18 kboe/d in 2010, compared to 23 kboe/d in 2009 and 2008. Following the termination of the Santiago de Los Andes license, TOTAL relinquished the Cupiagua field, and its interest in the joint venture that owns the two remaining licenses (that cover the Cusiana field) decreased to 11.6% from 19%. TOTAL also has a 50% interest in the Niscota exploration license. TOTAL is also active in the country through its interest in CEPSA⁽¹⁾, which has operated the Caracara Block since 2008.


•	On Cusiana, construction of the facilities intended to increase gas production capacity from 180 Mcf/d to 250 Mcf/d was completed in December 2010. In addition, start up of a project to extract 6 kb/d of LPG is expected in 2011.


•	On Niscota, drilling of the Huron-1 well led to the discovery in 2009 of a gas and condensate field. A 3D seismic survey completed in 2010 aimed at determining the size of the discovery and the location of new appraisal wells. Drilling of an appraisal well is expected in 2011.

In French Guiana, TOTAL acquired a 25% interest in the Guyane Maritime license in December 2009. The acquisition is subject to approval by the French authorities. The license, located about 150 km off the coast, covers an area of approximately 32,000 km² in water depths ranging from 2,000 to 3,000 meters. 3D seismic acquisition and interpretation work were carried out in 2009 and 2010. Drilling of an exploration well is expected in 2011.

In Trinidad & Tobago, where TOTAL has been present since 1996, the Group’s production was 3 kb/d in 2010, compared to 5 kb/d in 2009 and 6 kb/d in 2008. TOTAL holds a 30% interest in the offshore Angostura field located on Block 2C. A second phase, for the development of gas reserves, is underway, with production expected to begin in the second quarter of 2011.

In Venezuela, where TOTAL has been present since 1980, the Group’s production was 55 kboe/d in 2010, compared to 54 kboe/d in 2009 and 92 kboe/d in 2008. TOTAL holds interests in PetroCedeño (30.323%), Yucal Placer (69.5%) and in the offshore exploration Block 4, located in the Plataforma Deltana (49%).


•	Pursuant to the decision by the Venezuelan authorities to terminate all operating contracts signed in the 1990s, the Sincor association in which TOTAL held an interest was transformed into a mixed public/private company: PetroCedeño. Under this agreement that led to the transfer of operatorship to PetroCedeño, TOTAL’s interest in the project decreased from 47% to 30.323% and PDVSA’s interest increased to 60%. The transformation process was completed in February 2008.

	PDVSA agreed to compensate TOTAL for the reduction of its interest in Sincor by assuming $326 million of debt and by paying, mostly in crude oil, $834 million. The compensation process was completed in 2009.

•	On Block 4, the exploration campaign, which involved three wells, was completed in 2007. In 2008, the authorities agreed to let the partners retain the Cocuina discovery zone (lots B and F) and relinquish the rest of the block.

•	In early 2008, TOTAL signed two agreements for joint studies with PDVSA on the Junin 10 Block, in the Orinoco Belt.

Asia-Pacific

In 2010, TOTAL’s production in the Asia-Pacific region was 248 kboe/d, representing 10% of the Group’s overall production, compared to 251 kboe/d in 2009 and 246 kboe/d in 2008.

In Australia, where TOTAL has held leasehold rights since 2005, the Group owns 24% of the Ichthys project, 27.5% of the GLNG project and ten offshore exploration licenses,

(1) In February 2011, TOTAL signed an agreement to dispose of its 48.83% interest in CEPSA. The transaction is conditioned on obtaining all requisite approvals.

including four that it operates, off the northwest coast in the Browse, Vulcan and Bonaparte Basins. In 2010, the Group produced 1 kboe/d due to its interest in GLNG.


•	FEED studies for the development of the gas and condensates Ichthys field located in the Browse Basin are ongoing. The studies launched in 2009 include a floating platform designed for gas production, treatment and export, an FPSO to stabilize and export condensates, an 885 km gas pipeline and a liquefaction plant located in Darwin.

	Production capacity is expected to be 8.4 Mt/y of LNG and 1.6 Mt/y of LPG as well as production capacity of 100 kb/d of condensates. The operator plans a start-up of the field at year-end 2016.

•	In late 2010, TOTAL acquired a 20% interest in the GLNG project, followed by an additional 7.5% interest for which the acquisition was closed in March 2011. This integrated gas production, transport and liquefaction project is based on the development of coal gas from the Fairview, Roma, Scotia and Arcadia fields. The final investment decision was made in January 2011 and start-up is expected in 2015. LNG production is expected to eventually reach 7.2 Mt/y.

•	Major seismic acquisition activity occurred in 2008 on the four exploration licenses operated by TOTAL, followed by the interpretation of data in 2009. A drilling campaign involving two wells started in early 2011 on the WA403 license (60%, operator).

•	In 2010, following unsuccessful results, TOTAL relinquished the exploration licenses located in the Carnarvon Basin.

In Brunei, where TOTAL has been present since 1986, the Group operates the offshore Maharaja Lela Jamalulalam gas and condensates field located on Block B (37.5%). The Group’s production was 14 kboe/d in 2010, compared to 12 kboe/d in 2009 and 14 kboe/d in 2008. The gas is delivered to the Brunei LNG liquefaction plant.

On Block B, a new drilling campaign started in July 2009 that includes a development well, which started production in April 2010, and two exploration wells drilled in 2010 in the southern portion of the field that discovered oil and gas. Development studies for these new reserves are underway.

On deep-offshore exploration Block CA1 (54%, operator), formerly Block J, exploration operations that had been suspended since May 2003 due to a border dispute between Brunei and Malaysia resumed in September 2010. Both countries reached a border agreement in 2009 that led to adapting the production sharing agreement signed in 2003, resulting in two new partners selected by the government of Malaysia farming into the exploration block. TOTAL’s share decreased to 54% from 60% and TOTAL remains the operator. A drilling campaign involving several wells is expected to start in the second half of 2011.

In China, the Group is present on the South Sulige Block, located in the Ordos Basin, in the Inner Mongolia province. Appraisal work was conducted on this block between 2006 and 2008, in particular seismic acquisition, the drilling of four new wells and tests on existing wells. The development plan proposed by TOTAL in January 2010, in partnership with China National Petroleum Corporation (CNPC), was then adjusted to take advantage of the synergies achieved with the development of CNPC-operated Great Sulige. It was adopted in November 2010 by both partners and the approval process with the authorities is ongoing.

Both partners agreed that TOTAL’s share in cofinancing the development would be 49% and CNPC’s share would be 51% (operator). The development will be operated by CNPC where a number of specialists from TOTAL will be assigned.

In Indonesia, TOTAL has been present since 1968 with production of 178 kboe/d in 2010, compared to 190 kboe/d in 2009 and 177 kboe/d in 2008.

TOTAL’s operations in Indonesia are primarily concentrated on the Mahakam permit (50%, operator), which covers several gas fields, including Peciko and Tunu. TOTAL also holds an interest in the Sisi-Nubi gas field (47.9%, operator). TOTAL delivers most of its natural gas production to the Bontang LNG plant operated by the Indonesian company PT Badak. The overall capacity of the eight liquefaction trains of the Bontang plant is 22 Mt/y.

In 2010, gas production operated by TOTAL amounted to 2,488 Mcf/d. The gas operated and delivered by TOTAL accounted for nearly 80% of Bontang LNG’s supply. In addition to gas production, operated condensates and oil production from the Handil and Bekapai fields amounted to 49 kb/d and 23 kb/d, respectively.


•	On the Mahakam permit:


	–	Drilling of additional wells on the Tunu field continued in 2010 as part of the twelfth and thirteenth development phases. The 3D seismic campaign on the central/southeastern portion of the field was completed in 2010 and drilling of development wells to discover shallow gas reservoir started in 2010.


	–	On Peciko, following the start-up of a new platform (phase 5) in late 2008, a new phase of drilling operations (phase 7) started in 2009 and continued in 2010. New low-pressure compression capacities (phase 6) were commissioned in May 2010.

	–	On Bekapai, debottlenecking operations to increase gas production were completed in July 2010.

	–	Development of the South Mahakam permit continued with the award of the Engineering, Procurement and Construction contract (EPC) in August 2010 to develop the Stupa, West Stupa and East Mandu discoveries. Start-up of production is expected in early 2013.


•	On the Sisi-Nubi field, which began production in 2007, drilling operations continue. The gas from Sisi-Nubi is produced through Tunu’s processing facilities.

•	In 2008, a seismic campaign was conducted on the Southeast Mahakam exploration block (50%, operator), located in the Mahakam Delta. Drilling of the first exploration well (Trekulu 1) was completed in late 2010.

•	In May 2010, the Group acquired a 24.5% interest in two exploration blocks — Arafura and Amborip VI — located in the Arafura sea. Drilling of a first well started in mid-November 2010 on the Amborip VI license, which was followed by a second drilling that started in early 2011 on the Arafura license.

•	In October 2010, the Group closed the acquisition of a 15% interest in the Sebuku license where the Ruby gas discovery is located, the development of which was launched in mid-February 2011 with targeted production of 100 Mcf/d of natural gas and expected start-up in 2013.

In October 2010, the Group signed an agreement with the consortium Nusantara Regas (Pertamina-PGN) for the delivery of 11.75 Mt of LNG over the period 2012-2022 to a re-gasification terminal located near Jakarta.

The Heads of Agreement that TOTAL, Inpex and state-owned Pertamina signed in 2009 with a consortium of LNG buyers in Japan (Western Buyers) came into effect in March 2010. As part of this agreement, the Bontang LNG plant is expected to deliver 25 Mt of LNG to Japan for the period 2011-2020. The gas supplied will come from the Mahakam permit.

In Malaysia, TOTAL signed a production sharing contract in 2008 with state-owned Petronas for the offshore exploration Blocks PM303, which TOTAL relinquished in early 2011, and PM324 (70%, operator).

A drilling campaign in high pressure/high temperature conditions is expected to be launched in the second half of 2011 on Block PM324.

TOTAL also signed in November 2010 a new production and sharing agreement with Petronas for the deep offshore exploration Block SK 317 B (85%, operator) located off the state of Sarawak.

In Myanmar, TOTAL operates the Yadana field (31.2%). Located on offshore Blocks M5 and M6, this field produces gas that is delivered mainly to PTT (the Thai state-owned company) to be used in Thai power plants. The Yadana field also supplies the domestic market via a land pipeline and, since June 2010, via a sub-sea pipeline built and operated by Myanmar’s state-owned company MOGE.

The Group’s production was 14 kboe/d in 2010, compared to 13 kboe/d in 2009 and 14 kboe/d in 2008.

In Thailand, the Group’s production was 41 kboe/d in 2010, compared to 36 kboe/d in 2009 and 41 kboe/d in 2008. The rise in production in 2010 is the result of sustained gas demand, driven by economic growth in the country. The Group’s main asset is the offshore Bongkot gas and condensates field (33.3%). PTT purchases all of the natural gas and condensates production.


•	On the northern portion of the Bongkot field, the 3F (three wellhead platforms) and 3G (two platforms) development phases came onstream in 2008 and 2009, respectively. New investments allow gas demand to be met and plateau production to be maintained:


	–	the three platforms from the 3H development phase were installed in 2010 and production started up in early 2011;

	–	phase 3J (two platforms) was launched in late 2010; and

	–	additional low-pressure compressors have been installed to increase gas production.


•	The southern portion of the field (Great Bongkot South) is also being developed in several phases. This development is designed to include a processing platform, a residential platform and thirteen production platforms. Construction of the facilities, which began in 2009, accelerated in 2010 and production is expected to start up in early 2012.

In 2009, three successful exploration wells were drilled on Bongkot that are expected to be developed subsequently to maintain plateau production. In 2010, an exploration well was drilled on Bongkot North and a second well was drilled on Block G12-48 (33.3%), which neighbors the

Bongkot field. The positive results from both wells are under interpretation.

In Vietnam, TOTAL holds a 35% interest in the production sharing contract for the offshore 15-1/05 exploration block following an agreement signed in 2007 with PetroVietnam. A 1,600 km² 3D seismic survey was shot in the summer of 2008 on this block. Two oil discoveries were made on the southern portion of the block, one in November 2009 and the other in October 2010. A new drilling campaign that involves five wells started in November 2010.

In 2009, TOTAL and PetroVietnam signed a production sharing agreement for Blocks DBSCL-02 and DBSCL-03. The onshore blocks, located in the Mekong Delta region, are held by TOTAL (75%, operator) and PetroVietnam (25%). A first 2D seismic survey was shot between November 2009 and April 2010.

Commonwealth of Independent States (CIS)

In 2010, TOTAL’s production in the CIS was 23 kboe/d, representing 1% of the Group’s overall production, compared to 24 kboe/d in 2009 and 26 kboe/d in 2008.

In Azerbaijan, TOTAL has been present since 1996 with production of 13 kboe/d in 2010, compared to 12 kboe/d in 2009 and 18 kboe/d in 2008. The Group’s production is focused on the Shah Deniz field (10%). TOTAL holds a 10% interest in South Caucasus Pipeline Company, owner of the SCP (South Caucasus Pipeline) gas pipeline that transports the gas produced in Shah Deniz to the Turkish and Georgian markets. TOTAL also holds a 5% interest in BTC Co., owner of the BTC (Baku-Tbilisi-Ceyhan) oil pipeline, which connects Baku and the Mediterranean Sea.


•	Gas deliveries to Turkey and Georgia from the Shah Deniz field continued throughout 2010, at a lower pace for Turkey due to weaker demand. In 2010, SOCAR, the Azerbaijan state-owned company, took gas quantities superior to those provided for by the agreement.

	An agreement was made with Botas, a Turkish state-owned company, to revise the price of gas sold to Turkey as part of Shah Deniz Phase 1, applicable with retroactive effect from April 15, 2008.

	Development studies and business negotiations for the sale of additional gas needed to launch a second development phase in Shah Deniz continued in 2010. SOCAR and Botas signed in June 2010 a Memorandum of Understanding for the sale of additional gas volumes and the transfer conditions for volumes intended for the European market. This agreement is expected to allow FEED studies to start in 2011 for the second phase.

•	On the BTC oil pipeline, notably used to transport the condensates produced at Shah Deniz, equipment was installed in 2009 to inject additives to reduce drag. This resulted in the oil pipeline capacity increasing from 1 Mb/d to 1.2 Mb/d.

In 2009, TOTAL and SOCAR signed an exploration, development and production sharing agreement for a license located on the Absheron block in the Caspian Sea. TOTAL (40%) is the operator during the exploration phase and a joint operating company will manage operations during the development phase. Drilling of an exploratory well started in early 2011.

In Kazakhstan, TOTAL has held since 1992 an interest in the North Caspian license that covers notably the Kashagan field where the substantial reserves may eventually allow production to reach more than 1 Mb/d (in 100%).

The Kashagan project is expected to be developed in several phases. The development plan for the first phase (300 kb/d) was approved in February 2004 by the Kazakh authorities, allowing work to begin on the field. Drilling of development wells, which began in 2004, continued in 2010. The consortium continues to target first commercial production by year-end 2012.

In October 2008, the members of the North Caspian Sea Production Sharing Agreement (NCSPSA) consortium and the Kazakh authorities signed agreements to end the disagreement that began in August 2007. Their implementation led to a reduction of TOTAL’s share in NCSPSA from 18.52% to 16.81%. The operating structure was reconfigured and the North Caspian Operating Company (NCOC), a joint operating company, was entrusted with the operatorship in January 2009. NCOC supervises and coordinates NCSPSA’s operations.

In Russia, where TOTAL has been present since 1989, the Group’s production was 10 kboe/d in 2010, compared to 12 kboe/d in 2009 and 8 kboe/d in 2008. Production comes mainly from the Kharyaga field (40%, operator).

•

In 2007, TOTAL and Gazprom signed an agreement for the first phase of development on the giant Shtokman gas and condensates field, located in the Barents Sea. Under this agreement, Shtokman Development AG (TOTAL, 25%) was created in 2008 to design, build, finance and operate this first development phase whose overall production capacity is expected to be 23.7 Bm³/y (0.4 Mboe/d). Engineering studies are underway for the portion of the project that will allow the transport of gas by pipeline through the Gazprom network (offshore development, gas pipeline and onshore gas and condensates processing facilities — Teriberka site),


	with a final investment decision expected in 2011, and for the LNG part of the project that will allow the export of 7.5 Mt/y of LNG from a new harbor located in Teriberka, representing approximately half of the gas produced by the first development phase.


•	In December 2009, TOTAL closed the acquisition from Novatek of a 49% interest in Terneftegas, which holds a development and production license on the onshore Termokarstovoye field. An appraisal well was drilled in 2010, the results of which are expected to lead to a final investment decision by year-end 2011.

•	On the Kharyaga field, work related to the development plan of phase 3 is ongoing. This development plan is intended to maintain plateau production at the 30 kboe/d (in 100%) level reached in late 2009. In December 2009, TOTAL signed an agreement, effective January 1, 2010, to sell 10% of the field to state-owned Zarubezhneft, and decreased its interest to 40%.

•	In October 2009, TOTAL signed an agreement setting forth the principles of a partnership with KazMunaiGas (KMG) for the development of the Khvalynskoye gas and condensates field, located offshore in the Caspian Sea on the border between Kazakhstan and Russia, under Russian jurisdiction. Gas production is expected to be transported to Russia. Pursuant to this agreement, TOTAL is planning to acquire a 17% interest in KMG’s share.

•	On March 2, 2011, TOTAL and Novatek signed two agreements in principle providing for:


	–	TOTAL becoming the main international partner on the Yamal LNG project with a 20% interest, and Novatek holding a 51% interest in the project. As part of the agreement, the transaction is expected to be closed by July 2011.

	–	TOTAL taking a 12.08% interest in Novatek with both parties intending that TOTAL increases its interest to 15% within 12 months and to 19.40% within 36 months.

Europe

In 2010, TOTAL’s production in Europe was 580 kboe/d, representing 24% of the Group’s overall production, compared to 613 kboe/d in 2009 and 616 kboe/d in 2008.

In Denmark, TOTAL was awarded in June 2010 an 80% interest in and the operatorship for licenses 1/10 (Nordjylland) and 2/10 (Frederoskilde), following the approval by the Danish Energy Agency. These onshore licenses cover areas of 3,000 km² and 2,300 km², respectively, and are expected to be appraised for shale gas.

In France, the Group’s production was 21 kboe/d in 2010, compared to 24 kboe/d in 2009 and 25 kboe/d in 2008. TOTAL’s major assets are the Lacq (100%) and Meillon (100%) gas fields, located in the southwest part of the country.

On the Lacq field, operated since 1957, a carbon capture and storage pilot was commissioned in January 2010. In connection with this project, a boiler has been modified to operate in an oxy-fuel combustion environment and the carbon dioxide emitted is captured and re-injected in the depleted Rousse field. As part of the Group’s sustainable development policy, this project will allow the Group to assess one of the technological possibilities for reducing carbon dioxide emissions.

In 2010, TOTAL was awarded the Montélimar (100%) license to assess the shale gas potential of the area once authorizations to operate are given.

In Italy, the Tempa Rossa field (50%, operator), discovered in 1989 and located on the unitized Gorgoglione concession (Basilicate region), is one of TOTAL’s principal assets in the country.

Site preparation work started in early August 2008, but the proceedings initiated by the Prosecutor of the Potenza Court against Total Italia led to a freeze in the preparation work. New calls for tenders have been launched related to certain contracts that had been cancelled. Drilling of the Gorgoglione 2 appraisal well that started in May 2010 is ongoing. The partners on Tempa Rossa are expected to make the final investment decision in 2011 for this project that has an expected capacity of 55 kboe/d. The extension plan for the Tarente refinery export system, needed for the development of the Tempa Rossa field, was submitted to the Italian authorities in May 2010 for an approval expected in 2011. Start-up of production is currently expected in 2015.

In Norway, where the Group has been present since the mid-1960s, TOTAL holds interests in seventy-eight production licenses on the Norwegian continental shelf, fifteen of which it operates. Norway is the largest single-country contributor to the Group’s production, with volumes of 310 kboe/d in 2010, compared to 327 kboe/d in 2009 and 334 kboe/d in 2008.


•	In the Norwegian North Sea, production was 226 kboe/d in 2010. The most substantial contribution to production, for the most part non-operated, comes from the Greater Ekofisk Area (Ekofisk, Eldfisk, Embla, etc.), located in the south.


	The Greater Hild Area (Hild East, Central, West, etc.) is located in the north.


	–	Several projects are ongoing or are under study in the Greater Ekofisk Area, where the Group has a 39.9% participation in the Ekofisk and Eldfisk fields. The Ekofisk South and Eldfisk 2 projects are expected to be launched in 2011 after receiving the approval from the Norwegian authorities.

	–	In 2010, the Group sold its interests in the Valhall/Hod fields.

	–	On the Greater Hild Area, the Group holds a 49% interest (operator). The development scheme was selected at year-end 2010. The project is expected to be approved in 2011 and production is scheduled to start up in 2016.

	–	On Frigg, decommissioning is completed.


•	In the Norwegian Sea, the Haltenbanken area includes the Tyrihans (23.2%), Mikkel (7.7%) and Kristin (6%) fields as well as the Åsgard (7.7%) field and its satellites Yttergryta (24.5%) and Morvin (6%). Morvin started up in August 2010 as planned, with two producing wells. In 2010, the Group’s production in the Haltenbanken area was 61 kboe/d.

•	In the Barents Sea, LNG production on Snøhvit (18.4%) started in 2007. This project includes development of the natural gas fields, Snøhvit, Albatross and Askeladd, as well as the construction of the associated liquefaction facilities. Due to design problems, the plant experienced reduced capacity during the start-up phase. A number of maintenance turnarounds were scheduled to fix the issue and the plant is now operating at its design capacity (4.2 Mt/y).

Between 2008 and 2010, exploration and appraisal work was carried out on various licenses. In the Norwegian North Sea, the oil discovery on Dagny (PL 048, 21.8%) and the Pan/Pandora (PL 120, 11%) discovery, made in 2008, substantially increased the potential of the Sleipner and Visund areas, respectively. Pan/Pandora is to be developed as a fast track satellite. The development project is expected to be launched in 2011 after receipt of approval from the Norwegian authorities. The Dagny project is scheduled for approval in 2012.

A number of discoveries were made in 2009, in particular on Beta Vest (PL 046, 10%) near Sleipner, Katla (PL 104, 10%), located south of Oseberg, and Vigdis North East (PL 089, 5.6%), located south of Snorre. Katla and Vigdis North East are expected to be developed as fast track satellites, with the approval of the projects by the partners on both licenses planned for the first half of 2011. In the Central North Sea, TOTAL (40% operator) made a gas and condensate discovery in 2010 on the David structure (PL 102C -Heimdal area). The structure could be developed through a tie-back to Heimdal via Skirne-Byggve. In the Barents Sea, TOTAL was awarded in 2009 a new exploration license — PL 535 (40%) — during the twentieth licensing round. On this license, a 3D seismic acquisition was completed in 2009 and drilling is expected to begin in 2011. In 2011, TOTAL was awarded four new exploration licenses, including one for which TOTAL is operator, during the 2010 APA (Awards in Predefined Areas).

In the Netherlands, TOTAL has been active in natural gas exploration and production since 1964 and currently holds twenty-four offshore production permits, including twenty that it operates, and an offshore exploration permit, E17c (16.92%) awarded in 2008. In 2010, the Group’s share of production amounted to 42 kboe/d, compared to 45 kboe/d in 2009 and 44 kboe/d in 2008. In 2008, TOTAL acquired Goal Petroleum (Netherlands) B.V.


•	On the K5F field (40.39%, operator), production began in 2008. This project is comprised of two sub-sea wells connected to the existing production and transport facilities. K5F is the first project in the world to use only electrically driven sub-sea well heads and systems.

•	Development of the K5CU project (49%, operator) was launched in 2009 and production started up in early 2011. This development includes four wells supported by a platform that has been installed in September 2010 and is connected to the K5A platform by a 15 km gas pipeline.

In late 2010, TOTAL disposed of 18.19% of its shares in the NOGAT gas pipeline and decreased its interest to 5%.

In the United Kingdom, TOTAL has been present since 1962 with production in 2010 of 207 kboe/d, compared to 217 kboe/d in 2009 and 213 kboe/d in 2008. 86% of this production comes from operated fields located in two major zones: the Alwyn zone in the northern North Sea, and the Elgin/Franklin zone in the Central Graben.


•	On the Alwyn zone, start-up of satellite fields or new reservoir compartments allowed production to be maintained. The processing and compressing capacities of the Alwyn platform increased from 530 Mcf/d to 575 Mcf/d during the summer of 2008 planned shutdown for maintenance.

	The N52 well drilled on Alwyn (100%) in a new compartment of the Statfjord reservoir came onstream in February 2010 with initial flow of 15 kboe/d (gas and condensates).

The Jura field (100%), discovered in late 2006, started production in May 2008 through two sub-sea wells connected to the oil pipeline linking Forvie North and Alwyn. The production capacity of this field is 50 kboe/d (gas and condensates).

Development studies were completed on Islay (100%), a second gas and condensates discovery made in 2008 and located in a faulted panel immediately east of Jura, and the development was approved in July 2010. Start-up of production is expected in the second half of 2011 with a production capacity of 15 kboe/d.

In late 2008, TOTAL increased its interest in the Otter field from 54.3% to 81%. An agreement to dispose of this interest was reached in 2010 and is expected to be completed under two phases between 2011 and 2012.

The development of the Elgin (35.8%) and Franklin fields (35.8%), in production since 2001, contributed substantially to the Group’s operations in the United Kingdom. On the Elgin field, the infill well drilled between November 2008 and September 2009 came onstream in October 2009 with production of 18 kboe/d. Drilling of a second infill well was completed in 2010 with production of 12 kboe/d starting up in May. Drilling of such a well in a high pressure/high temperature highly depleted field is a significant technical milestone.

Additional development of West Franklin through a second phase (drilling of three additional wells and installation of a new platform connected to Elgin) was approved in November 2010. This phase is expected to result in the development of approximately 85 Mboe in 100%. Start-up of production is expected at year-end 2013.

As part of an agreement signed in 2005, TOTAL acquired a 25% interest in two blocks located near Elgin and Franklin by drilling an appraisal well on the Kessog structure. This interest was increased to 50% in 2009.


•	In the West of Shetland area, TOTAL increased its interest to 80% in the Laggan and Tormore fields in early 2010.

	The final investment decision for the Laggan/Tormore project was made in March 2010 and commercial production is scheduled to start in 2014 with an expected capacity of 90 kboe/d. The joint development scheme selected by TOTAL and its partner includes sub-sea production facilities and off-gas treatment (gas and condensates) at a plant located near the Sullom Voe terminal in the Shetland Islands. The gas would then be exported to the Saint-Fergus terminal via a new pipeline connected to the Frigg pipeline (FUKA).

In 2010, the Group’s interest in the P967 license (operator), which includes the Tobermory gas discovery, increased to 50% from 43.75%. This license is located north of Laggan/Tormore.

In early 2011, a gas and condensate discovery was made on the Edradour license (75%, operator).

TOTAL holds interests in ten assets operated by third parties, the most important in terms of reserves being the Bruce (43.25%) and Alba (12.65%) fields. The Group disposed of its interest in the Nelson field (11.5%) in 2010.

Middle East

In 2010, TOTAL’s production in the Middle East was 527 kboe/d, representing 22% of the Group’s overall production, compared to 438 kboe/d in 2009 and 432 kboe/d in 2008.

In the United Arab Emirates, where TOTAL has been present since 1939, the Group’s production in 2010 was 222 kboe/d, compared to 214 kboe/d in 2009 and 243 kboe/d in 2008. The changes that have been recorded since 2008 are mainly due to the implementation of OPEC quotas.

In Abu Dhabi, TOTAL holds a 75% interest in the Abu Al Bu Khoosh field (operator), a 9.5% interest in the Abu Dhabi Company for Onshore Oil Operations (ADCO), which operates the five major onshore fields in Abu Dhabi, and a 13.3% interest in Abu Dhabi Marine (ADMA), which operates two offshore fields. TOTAL also has a 15% stake in Abu Dhabi Gas Industries (GASCO), which produces LPG and condensates from the associated gas produced by ADCO, and a 5% stake in Abu Dhabi Gas Liquefaction Company (ADGAS), which produces LNG, LPG and condensates.

In early 2009, TOTAL signed agreements for a 20-year extension of its participation in the GASCO joint venture starting on October 1, 2008.

In early 2011, TOTAL and IPIC, a government-owned entity in Abu Dhabi, signed a Memorandum of Understanding with a view to developing projects of common interest in the upstream oil and gas sectors.

The Group holds a 25% interest in Dolphin Energy Ltd. alongside Mubadala, a company owned by the government of the Abu Dhabi Emirate, to market gas produced in Qatar in particular to the United Arab Emirates.

The Group also holds a 33.3% interest in Ruwais Fertilizer Industries (FERTIL), which produces urea. FERTIL 2, a new project, was launched in 2009 to build a new granulated urea unit with a capacity of 3,500 t/d (1.2 Mt/y). This project

is expected to allow FERTIL to more than double production so as to reach nearly 2 Mt/y in January 2013.

In Iraq, TOTAL bid in 2009 and 2010 on the three calls for tenders launched by the Iraqi Ministry of Oil. The PetroChina-led consortium that includes TOTAL (18.75%) was awarded the development and production contract for the Halfaya field during the second call for tenders held in December 2009. This field is located in the province of Missan, north of Basra. The agreement became effective in March 2010 and the preliminary development plan was approved by the Iraqi authorities in late September 2010. Development operations have started. It plans for first production of nearly 70 kb/d of oil in 2012.

In Iran, the Group’s production, under buyback agreements, amounted to 2 kboe/d in 2010, compared to 8 kboe/d in 2009 and 9 kboe/d in 2008. For additional information on TOTAL’s operations in Iran, see “— Other Matters — Business Activities In Cuba, Iran, Sudan and Syria”.

In Oman, the Group’s production in 2010 was 34 kboe/d, stable compared to 2009 and 2008. The Group produces oil on Block 6 mainly and on Block 53 as well as liquefied natural gas through its interests in the Oman LNG (5.54%)/Qalhat LNG (2.04%)⁽¹⁾ liquefaction plant, which has a capacity of 10.5 Mt/y.

In Qatar, TOTAL has been present since 1936 and holds interests in the Al Khalij field (100%), the NFB Block (20%) in the North field, the Qatargas 1 liquefaction plant (10%), Dolphin (24.5%) and train 5 of Qatargas 2 (16.7%). The Group’s production was 164 kboe/d in 2010, compared to 141 kboe/d in 2009 and 121 kboe/d in 2008. Production substantially increased with the start-up of Qatargas 2.


•	Production from Dolphin started during the summer of 2007 and reached its full capacity in the first quarter of 2008. The contract, signed in 2001 with state-owned Qatar Petroleum, provides for the sale of 2 Bcf/d of gas from the North field for a 25-year period. The gas is processed in the Dolphin plant in Ras Laffan and exported to the United Arab Emirates through a 360 km gas pipeline.


•	Production from train 5 of Qatargas 2, which started in September 2009, reached its full capacity (7.8 Mt/y) at year-end 2009. TOTAL has owned an interest in this train since 2006. In addition, TOTAL began to off-take part of the LNG produced in compliance with the contracts signed in 2006, which provide for the purchase of 5.2 Mt/y of LNG from Qatargas 2 by the Group.

The Group also holds a 10% interest in Laffan Refinery, a 146 kb/d condensate splitter that started up in September 2009.

In Syria, TOTAL is present on the Deir Ez Zor license (100%, operated by DEZPC, 50% of which is owned by TOTAL) and through the Tabiyeh contract that became effective in October 2009. The Group’s production for both assets was 39 kboe/d in 2010, compared to 20 kboe/d in 2009 and 15 kboe/d in 2008.

Three agreements were ratified:


•	in 2008, the 10-year extension, to 2021, of the production sharing agreement of the Deir Ez Zor license;

•	in 2009, the Tabiyeh agreement, which primarily provides for an increase in the production from the gas and condensates Tabiyeh field; and

•	in 2009, the Cooperation Framework Agreement, which provides for the development of oil projects in partnership with the Syrian company General Petroleum Corporation.

For additional information on TOTAL’s operations in Syria, “— Other Matters — Business Activities In Cuba, Iran, Sudan and Syria”.

In Yemen, TOTAL has been present since 1987 with production of 66 kboe/d in 2010, compared to 21 kboe/d in 2009 and 10 kboe/d in 2008.

TOTAL has an interest in the Yemen LNG project (39.62%). As part of this project, the liquefaction plant built in Balhaf on the southern coast of Yemen is supplied with the gas produced on Block 18, located near Marib in the center of the country, through a 320 km gas pipeline. The two liquefaction trains were commissioned in October 2009 and April 2010. Overall production capacity from both trains is 6.7 Mt/y of LNG.

TOTAL also has interests in the country’s two oil basins, as the operator on Block 10 (Masila Basin, East Shabwa license, 28.57%) and as a partner on Block 5 (Marib Basin, Jannah license, 15%).

In 2010, TOTAL consolidated positions in onshore exploration through the acquisition of a 36% interest in Block 72 and by increasing its interest to 50.1% from 30.9% in Block 70. TOTAL also acquired 40% interests in Blocks 69 and 71 in 2007. Appraisal of gas discoveries on Block 71 is underway. The first well drilled on Block 70 discovered positive oil shows. The potential of this discovery has yet to be assessed.

(1) Indirect interest through the 36.8% share in Qalhat LNG owned by Oman LNG.

OIL AND GAS ACREAGE


As of December 31,			2010				2009				2008
(in thousand of acres at			Undeveloped		Developed		Undeveloped		Developed		Undeveloped		Developed
year-end)			acreage^(a)		acreage		acreage^(a)		acreage		acreage^(a)		acreage
Europe	Gross			6,802		776		5,964		667		5,880		647

	Net			3,934		184		2,203		182		2,191		181

Africa	Gross			72,639		1,229		85,317		1,137		85,883		1,112

	Net			33,434		349		45,819		308		41,608		292

Americas	Gross			16,816		1,022		9,834		776		8,749		484

	Net			5,755		319		4,149		259		4,133		186

Middle East	Gross			29,911		1,396		33,223		204		33,223		199

	Net			2,324		209		2,415		97		2,415		69

Asia	Gross			36,519		539		29,609		397		25,778		387

	Net			17,743		184		16,846		169		12,529		131

Total	Gross			162,687		4,962		163,947		3,181		159,513		2,829

	Net^(b	⁾		63,190		1,245		71,432		1,015		62,876		859


(a)		Undeveloped acreage includes leases and concessions,
(b)		Net acreage equals the sum of the Group’s fractional interest in gross acreage.

NUMBER OF PRODUCTIVE WELLS

As of December 31,

2010

2009

2008

Gross

Net

Gross

Net

Gross

Net

productive

(number of wells at year-end)

wells

wells^(a)

wells

wells^(a)

wells

wells^(a)

20-F	2019-12-31	Filed 2020-03-20
20-F	2018-12-31	Filed 2019-03-20
20-F	2017-12-31	Filed 2018-03-16
20-F	2016-12-31	Filed 2017-03-17
20-F	2015-12-31	Filed 2016-03-16
20-F	2014-12-31	Filed 2015-03-26
20-F	2013-12-31	Filed 2014-03-27
20-F	2012-12-31	Filed 2013-03-28
20-F	2011-12-31	Filed 2012-03-26
20-F	2010-12-31	Filed 2011-03-28
20-F	2009-12-31	Filed 2010-04-01

TOT 20F Annual Report

Total Earnings 2010-12-31

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EX-1	y03333exv1.htm
EX-12.1	y03333exv12w1.htm
EX-12.2	y03333exv12w2.htm
EX-13.1	y03333exv13w1.htm
EX-13.2	y03333exv13w2.htm
EX-15	y03333exv15.htm