pbraform20f_2011.htm - Generated by SEC Publisher for SEC Filing

As filed with the Securities and Exchange Commission on March 30, 2012

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 20-F
ANNUAL REPORT
PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

for the fiscal year ended December 31, 2011

Commission File Number 001-15106 Petróleo Brasileiro S.A.—Petrobras (Exact name of registrant as specified in its charter)	Commission File Number: 001-33121 Petrobras International Finance Company (Exact name of registrant as specified in its charter)

Brazilian Petroleum Corporation—Petrobras (Translation of registrant’s name into English)

The Federative Republic of Brazil (Jurisdiction of incorporation or organization)	Cayman Islands (Jurisdiction of incorporation or organization)

Avenida República do Chile, 65

20031-912 – Rio de Janeiro – RJ

Brazil

(Address of principal executive offices)

Almir Guilherme Barbassa
(55 21) 3224-2040 – barbassa@petrobras.com.br
Avenida República do Chile, 65 – 23^rd Floor
20031-912 – Rio de Janeiro – RJ

Brazil

(Name, telephone, e-mail and/or facsimile number and address of company contact person)

4th Floor, Harbour Place

103 South Church Street

P.O. Box 1034GT – BWI

George Town, Grand Cayman

Cayman Islands

(Address of principal executive offices)

Sérvio Túlio da Rosa Tinoco

(55 21) 3224-1410 – ttinoco@petrobras.com.br
Avenida República do Chile, 65 – 3^rd Floor
20031-912 – Rio de Janeiro – RJ

Brazil

(Name, telephone, e-mail 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:
Petrobras Common Shares, without par value*	New York Stock Exchange*
Petrobras American Depositary Shares, or ADSs (evidenced by American Depositary Receipts, or ADRs), each representing two Common Shares	New York Stock Exchange
Petrobras Preferred Shares, without par value*	New York Stock Exchange*
Petrobras American Depositary Shares (as evidenced by American Depositary Receipts), each representing two Preferred Shares	New York Stock Exchange
2.875% Global Notes due 2015, issued by PifCo	New York Stock Exchange
6.125% Global Notes due 2016, issued by PifCo	New York Stock Exchange
3.875% Global Notes due 2016, issued by PifCo	New York Stock Exchange
3.500% Global Notes due 2017, issued by PifCo	New York Stock Exchange
5.875% Global Notes due 2018, issued by PifCo	New York Stock Exchange
7.875% Global Notes due 2019, issued by PifCo	New York Stock Exchange
5.75% Global Notes due 2020, issued by PifCo	New York Stock Exchange
5.375% Global Notes due 2021, issued by PifCo	New York Stock Exchange
6.875% Global Notes due 2040, issued by PifCo	New York Stock Exchange
6.750% Global Notes due 2041, issued by PifCo	New York Stock Exchange

* Not for trading, but only in connection with the registration of American Depositary Shares pursuant to the requirements of the New York Stock Exchange.

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:

TITLE OF EACH CLASS:

9.125% Global Notes due 2013, issued by PifCo

7.75% Global Notes due 2014, issued by PifCo

8.375% Global Notes due 2018, issued by PifCo

4.875% Global Notes due 2018, issued by PifCo

5.875% Global Notes due 2022, issued by PifCo

6.250% Global Notes due 2026, issued by PifCo

The number of outstanding shares of each class of stock of Petrobras and PifCo as of December 31, 2011 was:

7,442,454,142 Petrobras Common Shares, without par value

5,602,042,788 Petrobras Preferred Shares, without par value

300,050,000 PifCo Common Shares, at par value U.S.$1 per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.

Yes R No £

If this report is an annual or transitional report, indicate by check mark if the registrant is not required to file reports pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934.

Yes £ No R

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 R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 R (Petrobras) No £

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

Large accelerated filer R (Petrobras) Accelerated filer £ Non-accelerated filer R (PifCo)

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

U.S.GAAP £ International Financial Reporting Standards as issued by the International Accounting Standards Board R Other £

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 £ Item 18 £

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes £ No R

FORWARD-LOOKING STATEMENTS

Many statements made in this annual report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act), that are not based on historical facts and are not assurances of future results. Many of the forward-looking statements contained in this annual report may be identified by the use of forward-looking words, such as “believe,” “expect,” “anticipate,” “should,” “planned,” “estimate” and “potential,” among others. We have made forward-looking statements that address, among other things:

· our marketing and expansion strategy;

· our exploration and production activities, including drilling;

· our activities related to refining, import, export, transportation of petroleum, natural gas and oil products, petrochemicals, power generation, biofuels and other sources of renewable energy;

· our projected and targeted capital expenditures and investments and other costs, commitments and revenues;

· our liquidity and sources of funding;

· development of additional revenue sources; and

· the impact, including cost, of acquisitions.

Our forward-looking statements are not guarantees of future performance and are subject to assumptions that may prove incorrect and to risks and uncertainties that are difficult to predict. Our actual results could differ materially from those expressed or forecast in any forward-looking statements as a result of a variety of factors. These factors include, among other things:

· our ability to obtain financing;

· general economic and business conditions, including crude oil and other commodity prices, refining margins and prevailing exchange rates;

· our ability to find, acquire or gain access to additional reserves and to develop our current reserves successfully;

· global economic conditions;

· uncertainties inherent in making estimates of our oil and gas reserves, including recently discovered oil and gas reserves;

· competition;

· technical difficulties in the operation of our equipment and the provision of our services;

· changes in, or failure to comply with, laws or regulations;

· receipt of governmental approvals and licenses;

· international and Brazilian political, economic and social developments;

· natural disasters, accidents, military operations, acts of sabotage, wars or embargoes;

GLOSSARY OF PETROLEUM INDUSTRY TERMS

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

ANEEL	The Agência Nacional de Energia Elétrica (National Electrical Energy Agency), or ANEEL, is the federal agency that regulates the electricity industry in Brazil.
ANP	The Agência Nacional de Petróleo, Gás Natural e Biocombustíveis (National Petroleum, Natural Gas and Biofuels Agency), or ANP, is the federal agency that regulates the oil, natural gas and renewable fuels industry in Brazil.
°API	Standard measure of oil density developed by the American Petroleum Institute.
Barrels	Barrels of crude oil.
BSW	Basic sediment and water, a measurement of the water and sediment content of flowing crude oil.
Catalytic cracking	A process by which hydrocarbon molecules are broken down (cracked) into lighter fractions by the action of a catalyst.
Coker	A vessel in which bitumen is cracked into its fractions.
Condensate	Light hydrocarbon substances produced with natural gas, which condense into liquid at normal temperature and pressure.
CNPE	The Conselho Nacional de Política Energética (National Energy Policy Council), or CNPE, is an advisory body of the President of the Republic responsible for formulating energy policies and guidelines.
Deep water	Between 300 and 1,500 meters (984 and 4,921 feet) deep.
Distillation	A process by which liquids are separated or refined by vaporization followed by condensation.
EWT	Extended well test.
Exploration Area	A region in Brazil under a regulatory contract without a known hydrocarbon accumulation or with a hydrocarbon accumulation that has not yet been declared commercial.
FPSO	Floating Production, Storage and Offloading Unit.
Heavy crude oil	Crude oil with API density less than or equal to 22°.
Intermediate crude oil	Crude oil with API density higher than 22° and less than or equal to 31°.
Light crude oil	Crude oil with API density higher than 31°.
LNG	Liquefied natural gas.
LPG	Liquefied petroleum gas, which is a mixture of saturated and unsaturated hydrocarbons, with up to five carbon atoms, used as domestic fuel.

MME	The federal Ministry of Mines and Energy, or MME.
NGLs	Natural gas liquids, which are light hydrocarbon substances produced with natural gas, which condense into liquid at normal temperature and pressure.
Oil	Crude oil, including NGLs and condensates.
Pre-salt reservoir	A geological formation containing oil or natural gas deposits located beneath a salt layer.
Post-salt reservoir	A geological formation containing oil or natural gas deposits located above a salt layer.
Proved reserves	Consistent with the definitions in the SEC’s Amended Rule 4-10(a) of Regulation S-X, 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to December 31, 2011, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced or we must be reasonably certain that we will commence the project within a reasonable time. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
Proved developed reserves.	Proved developed reserves are 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.
Proved undeveloped reserves	Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Proved undeveloped reserves do not include reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

SS	Semi-submersible unit.
Synthetic oil and synthetic gas	A mixture of hydrocarbons derived by upgrading (i.e., chemically altering) natural bitumen from oil sands, kerogen from oil shales, or processing of other substances such as natural gas or coal. Synthetic oil may contain sulfur or other non-hydrocarbon compounds and has many similarities to crude oil.
TLWP	Tension Leg Wellhead Platform.
Total depth	Total depth of a well, including vertical distance through water and below the mudline.
Ultra-deep water	Over 1,500 meters (4,921 feet) deep.

CONVERSION TABLE

1 acre	=	0.004047 km²
1 barrel	=	42 U.S. gallons	=	Approximately 0.13 t of oil
1 boe	=	1 barrel of crude oil equivalent	=	6,000 cf of natural gas
1 m³ of natural gas	=	35.315 cf	=	0.0059 boe
1 km	=	0.6214 miles
1 km²	=	247 acres
1 meter	=	3.2808 feet
1 t of crude oil	=	1,000 kilograms of crude oil	=	Approximately 7.5 barrels of crude oil (assuming an atmospheric pressure index gravity of 37° API)

ABBREVIATIONS

bbl	Barrels
bn	Billion (thousand million)
bnbbl	Billion barrels
bncf	Billion cubic feet
bnm³	Billion cubic meters
boe	Barrels of oil equivalent
bbl/d	Barrels per day
cf	Cubic feet
GOM	Gulf of Mexico
GW	Gigawatts
GWh	One gigawatt of power supplied or demanded for one hour
km	Kilometer
km²	Square kilometers
m³	Cubic meter
mbbl	Thousand barrels
mbbl/d	Thousand barrels per day
mboe	Thousand barrels of oil equivalent
mboe/d	Thousand barrels of oil equivalent per day
mcf	Thousand cubic feet
mcf/d	Thousand cubic feet per day
mm³	Thousand cubic meters
mm³/d	Thousand cubic meters per day
mmbbl	Million barrels
mmbbl/d	Million barrels per day
mmboe	Million barrels of oil equivalent
mmboe/d	Million barrels of oil equivalent per day
mmcf	Million cubic feet
mmcf/d	Million cubic feet per day
mmm³	Million cubic meters
mmm³/d	Million cubic meters per day
mmt/y	Million metric tons per year
MW	Megawatts
MWavg	Amount of energy (in MWh) divided by the time (in hours) in which such energy is produced or consumed
MWh	One megawatt of power supplied or demanded for one hour
ppm	Parts per million
P$	Argentine pesos
R$	Brazilian reais
t	Metric ton
Tcf	Trillion cubic feet
U.S.$	United States dollars
/d	Per day
/y	Per year

PRESENTATION OF FINANCIAL INFORMATION

In this annual report, references to “real,” “reais” or “R$” are to Brazilian reais and references to “U.S. dollars” or “U.S.$” are to the United States dollars. Certain figures included in this annual report have been subject to rounding adjustments; accordingly, figures shown as totals in certain tables may not be an exact arithmetic aggregation of the figures that precede them.

Petrobras

The audited consolidated financial statements of Petrobras and our consolidated subsidiaries as of and for each of the three years ended December 31, 2011, 2010 and 2009 and the accompanying notes contained in this annual report have been presented in U.S. dollars and prepared in accordance with International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB). See Item 5. “Operating and Financial Review and Prospects” and Note 2.1 to our audited consolidated financial statements. Petrobras applies IFRS in its statutory financial statements prepared in accordance with Brazilian Corporate Law and regulations promulgated by the Comissão de Valores Mobiliários (Securities and Exchange Commission of Brazil, or CVM). Brazilian Corporate Law was amended in 2007 to permit accounting practices adopted in Brazil (Brazilian GAAP) to converge with IFRS.

We discontinued U.S. GAAP and adopted IFRS, as issued by the IASB, as the basis for the preparation and presentation of our financial statements and reporting with the SEC beginning with our financial statements as of and for the year ending December 31, 2011 presented in this annual report. This annual report on Form 20-F and all of our future reports filed with the SEC will only present financial information prepared in accordance with IFRS.

We first adopted IFRS, as issued by IASB, for our financial statements for the year December 31, 2010, which were filed with the local securities regulator in Brazil and made available to the public. Our transition date from Brazilian GAAP to IFRS was January 1, 2009 and we used certain elective transitional treatments under IFRS 1 in such financial statements filed with the local securities regulator in Brazil.

Since we have previously adopted IFRS in Brazil, we are not a “first time adopter” of IFRS for purposes of this annual report on Form 20-F. We are presenting bridging disclosures to IFRS in the form of a reconciliation from U.S. GAAP to IFRS as issued by the IASB of our net income for the years ended December 31, 2010 and 2009 and our shareholders’ equity at December 31, 2010. This reconciliation is included in Note 36 in our audited consolidated financial statements.

Our IFRS financial statements filed with the local securities regulator in Brazil use the real as its presentation currency, while the financial statements included herein use the U.S. Dollar as its presentation currency. As described more fully in Note 2.3 to our audited consolidated financial statements, the U.S. dollar amounts as of the dates and for the periods presented in our audited consolidated financial statements have been recalculated or translated from the real amounts in accordance with the criteria set forth in IAS 21 – “The effects of changes in foreign exchange rates.” U.S. dollar amounts presented in this annual report have been translated from reais at the period-end exchange rate for balance sheet items and the average exchange rate prevailing during the period for income statement and cash flow items.

Unless the context otherwise indicates:

· historical data contained in this annual report that were not derived from the audited consolidated financial statements have been translated from reais on a similar basis;

· forward-looking amounts, including estimated future capital expenditures and investments, have all been based on our Petrobras 2020 Strategic Plan, which covers the period from 2009 to 2020, and on our 2011-2015 Business Plan, and have been projected on a constant basis and have been translated from reais at an estimated average exchange rate of R$1.73 to U.S.$1.00, in accordance with our 2011-2015 Business Plan. In addition, in accordance with our 2011-2015 Business Plan, future calculations involving an assumed price of crude oil have been calculated using a Brent crude oil price of between U.S.$80 and U.S.$95 from 2012 through 2015, adjusted for our quality and location differences, unless otherwise stated; and

· estimated future capital expenditures and investments are based on the most recently budgeted amounts, which may not have been adjusted to reflect all factors that could affect such amounts.

PifCo

PifCo has in the past engaged in both commercial operations and in financing activities for us. In August 2011, as part of its transition to become our finance subsidiary, PifCo transferred two of its wholly owned subsidiaries – Petrobras Europe Limited (PEL) and Petrobras Singapore Private Limited (PSPL) – to Petrobras International Braspetro B.V (PIB BV). PifCo ceased its commercial operations altogether and has become our finance subsidiary, functioning as a vehicle to raise funds for us primarily through the issuance of debt securities in the international capital markets, among other means.

PifCo’s functional currency is the U.S. dollar. PifCo’s audited consolidated financial statements as of and for each of the years ended December 31, 2011, 2010 and 2009 and the accompanying notes contained in this annual report have been presented in U.S. dollars and prepared in accordance with IFRS and include PifCo’s two wholly owned subsidiaries: Petrobras Finance Limited (PFL) and Bear Insurance Company (BEAR).

PRESENTATION OF INFORMATION CONCERNING RESERVES

Petrobras continues to utilize the SEC rules for estimating and disclosing oil and gas reserve quantities included in this annual report. In accordance with these rules, adopted by Petrobras at year-end 2009, the year-end 2011 and 2010 reserve volumes have been estimated using the average prices calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period and include non-traditional reserves, such as synthetic oil and gas. In addition, the amended rules also adopted a reliable technology definition that permits reserves to be added based on field-tested technologies. The adoption of the SEC’s rules for estimating and disclosing oil and gas reserves and the FASB’s issuance of the Accounting Standards Update No. 2010-03 “Oil and Gas Reserve Estimation and Disclosure” in January 2010 generated no material impact on our reported reserves or on our consolidated financial position or results of operations.

DeGolyer and MacNaughton (D&M) used our reserves estimates to conduct a reserves audit of 95.5% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2011 from certain properties we own in Brazil and offshore from Brazil. In addition, D&M used its own estimates of our reserves to conduct a reserves evaluation of 53% of the net proved crude oil, NGL and natural gas reserves as of December 31, 2011 from certain properties we own in South America (outside of Brazil). The reserves estimates were prepared in accordance with the reserves definitions of Rule 4-10(a) of Regulation S-X of the SEC. All reserves estimates involve some degree of uncertainty. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Operations” for a description of the risks relating to our reserves and our reserve estimates.

On January 13, 2012, we filed reserve estimates for Brazil with the ANP, in accordance with Brazilian rules and regulations, totaling net volumes of 13.22 billion barrels of crude oil and condensate and 14.93 trillion cubic feet of natural gas. The reserve estimates filed with the ANP and those provided herein differ by approximately 28% in terms of oil equivalent. This difference is due to: (i) the ANP requirement to estimate proved reserves through the technical-economical abandonment of production wells, as opposed to limiting reserve estimates to the life of the concession contracts as required by Rule 4-10 of Regulation S-X; and (ii) different technical criteria for booking proved reserves, including the use of current oil prices as opposed to the SEC requirement that the 12-month average price be used to determine the economic producibility of reserves in Brazil.

We also file reserve estimates from our international operations with various governmental agencies under the guidelines of the Society of Petroleum Engineers, or SPE. The aggregate reserve estimates from our international operations, under SPE guidelines, amounted to 0.471 billion barrels of crude oil and NGLs and 1.406 billion cubic feet of natural gas, which is approximately 14% higher than the reserve estimates calculated under Regulation S-X, as provided herein. This difference occurs because of different technical criteria for booking proved reserves, including the use of current oil prices as opposed to the SEC requirement that the 12-month average price be used to determine the economic producibility of international reserves. In addition, we have not yet included the volumes from the Gulf of Mexico fields that do not have a production history available for analogous reservoirs.

PART I

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

This section contains selected consolidated financial data, presented in U.S. dollars and prepared in accordance with IFRS as of and for each of the three years ended December 31, 2011, 2010 and 2009, derived from our audited consolidated financial statements, which were audited by KPMG Auditores Independentes.

The summary financial data prepared in accordance with IFRS is not comparable to the summary financial data prepared in accordance with U.S. GAAP in our prior annual reports on Form 20-F.

The information below should be read in conjunction with, and is qualified in its entirety by reference to, our audited consolidated financial statements and the accompanying notes and Item 5. “Operating and Financial Review and Prospects.”

BALANCE SHEET DATA - PETROBRAS

IFRS Summary Financial Data

	As of December 31,
	2011	2010	2009
	(U.S.$ million)
Assets:
Cash and cash equivalents	19,057	17,655	16,222
Accounts receivable, net	11,756	10,845	8,147
Inventories	15,165	11,808	11,103
Other current assets	18,614	23,251	6,706
Non-current assets	21,957	22,637	19,991
Investments in non-consolidated companies and other investments	6,530	6,957	4,620
Property, plant and equipment, net	182,465	168,104	128,754
Intangible assets	43,866	48,937	3,899
Total assets	319,410	310,194	199,442
Liabilities and shareholders’ equity:
Total current liabilities	36,364	33,577	31,067
Total long-term liabilities(1)	33,218	30,251	23,809
Long-term debt(2)	72,718	60,417	48,963
Total liabilities	142,300	124,245	103,839
Shareholders’ equity
Shares authorized and issued:
Paid in capital	107,355	107,341	33,790
Reserves and other comprehensive income	68,483	76,769	60,579
Petrobras’ shareholders’ equity	175,838	184,110	94,369
Non-controlling interest	1,272	1,839	1,234
Total equity	177,110	185,949	95,603
Total liabilities and shareholders’ equity	319,410	310,194	199,442

INCOME STATEMENT DATA - PETROBRAS

IFRS Summary Financial Data

	For the Year Ended December 31,
	2011	2010	2009
	(U.S.$ million, except for share and per share data)
Sales revenues	145,915	120,452	91,146
Net income before financial results, profit sharing and income taxes	27,285	26,372	22,923
Net income for the year(1)(2)	20,121	20,055	15,308
Weighted average number of shares outstanding:
Common	7,442,454,142	5,683,061,430	5,073,347,344
Preferred	5,602,042,788	4,189,764,635	3,700,729,396
Net income before financial results, profit sharing and income taxes per:
Common and Preferred Shares	2.09	2.67	2.61
Common and Preferred ADS	4.18	5.34	5.22
Basic and diluted earnings per:(1)
Common and Preferred Shares	1.54	2.03	1.74
Common and Preferred ADS	3.08	4.06	3.48
Cash dividends per:(3)
Common and Preferred shares	0.53	0.70	0.59
Common and Preferred ADS	1.06	1.40	1.18

BALANCE SHEET DATA - PifCo

IFRS Summary Financial Data

	As of December 31,
	2011	2010	2009
	(U.S.$ million)
Assets:
Total current assets	6,516	11,800	21,773
Property and equipment, net- discontinued operations	–	1	1
Total non-current assets	16,998	6,125	4,523
Total assets	23,514	17,926	26,297
Liabilities and stockholders’ deficit:
Total current liabilities	3,311	5,891	13,174
Total long-term liabilities(1)	20,930	12,377	13,203
Total liabilities	24,241	18,268	26,377
Total stockholder’s deficit	(727)	(342)	(80)
Total liabilities and stockholder’s deficit	23,514	17,926	26,297

(1) Excludes current portion of long-term debt.

INCOME STATEMENT DATA - PifCo

IFRS Summary Financial Data

	For the Year Ended December 31,
	2011	2010	2009
	(U.S.$ million)
Financial results, net	(477)	(724)	(1,296)
Net income from discontinuing operations	119	476	1,794
Net (loss)/income for the year	(376)	(261)	487

RISK FACTORS

Risks Relating to Our Operations

Exploration and production of oil in deep and ultra-deep waters involves risks.

Exploration and production of oil involves risks that are increased when carried out in deep and ultra-deep waters. The majority of our exploration and production activities are carried out in deep and ultra-deep waters, and the proportion of our deepwater activities will remain constant or increase due to the location of our pre-salt reservoirs in deep and ultra-deep waters. Our activities, particularly in deep and ultra-deep waters, present several risks, such as the risk of oil spills, explosions in platforms and drilling operations and natural disasters. The occurrence of any of these events or other incidents could result in personal injuries, loss of life, severe environmental damage with the resulting containment, clean-up and repair expenses, equipment damage and liability in civil and administrative proceedings.

Our insurance policies do not cover all liabilities, and insurance may not be available for all risks. There can be no assurance that incidents will not occur in the future, that insurance will adequately cover the entire scope or extent of our losses or that we will not be found liable in connection with claims arising from these and other events.

International prices of crude oil, oil products and natural gas may impact us differently than our competitors and may cause our results to differ from our competitors in periods of higher international prices.

The majority of our revenue is derived primarily from sales of crude oil and oil products in Brazil and, to a lesser extent, natural gas. Changes in crude oil prices typically result in changes in prices for oil products and natural gas. Historically, international prices for crude oil, oil products and natural gas have fluctuated widely as a result of many factors. These factors include:

· global and regional economic and geopolitical developments in crude oil producing regions, particularly in the Middle East and Africa;

· the ability of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain crude oil production levels and defend prices;

· global and regional supply and demand for crude oil, oil products and natural gas;

· global financial crises, such as the global financial crisis of 2008;

· competition from other energy sources;

· domestic and foreign government regulations; and

· weather conditions.

Our pricing policy in Brazil is intended to be at parity with international product prices over the long term, but we do not adjust our prices for diesel, gasoline and LPG to immediately reflect price changes in the international markets. Significant and sustained decreases in the price of crude oil could have a negative impact on our revenues and may cause us to reduce or alter the timing of our capital expenditures and investments, and this could adversely affect our production forecasts in the medium term and our reserves estimates in the future. Thus, substantial or extended declines in international crude oil prices may have a material adverse effect on our business, results of operations and financial condition and the value of our proved reserves. When, however, we are a net importer by volume of oil and oil products, increases in the price of crude oil may have a negative impact on our costs of sales and margins if we are required to import oil and oil products to meet Brazilian demand, since the cost to acquire such products may exceed the selling price in Brazil. Additionally, material rapid or sustained increases in the international price of crude oil and oil products may also result in reduced downstream margins for us and negatively affect our results. We are also exposed to this risk during periods of depreciation of the real in relation to the U.S. dollar, as we sell oil and oil products in Brazil in reais and international prices for crude oil and oil products are set in U.S. dollars. A depreciation of the real reduces our prices in U.S. dollar terms.

Our ability to maintain our long-term growth objectives for oil production depends on our ability to successfully develop our reserves, and failure to do so could prevent us from achieving our long-term goals for growth in production.

Our ability to maintain our long-term growth objectives for oil production, including those defined in our 2011-2015 Business Plan, is highly dependent upon our ability to successfully develop our existing reserves and, in the long term, upon our ability to obtain additional reserves. The development of the sizable reservoirs in deep and ultra-deep waters, including the pre-salt reservoirs that have been assigned to us by the Brazilian federal government, has demanded and will continue to demand significant capital investments. A primary operational challenge, particularly for the pre-salt reservoirs, will be allocating our resources to build the necessary infrastructure at considerable distances from the shore and securing a qualified labor force and offshore oil services to develop reservoirs of such size and magnitude in a timely manner, a challenge that is particularly heightened by the fact that we are required to acquire a minimum level of goods and services from Brazilian providers. We cannot guarantee that we will have or will be able to obtain, in the time frame that we expect, sufficient resources necessary to exploit the reservoirs in deep and ultra-deep waters that the Brazilian federal government has licensed and assigned to us, or that it may license to us in the future, including as a result of the enactment of the new regulatory model for the oil and gas industry in Brazil.

Our exploration activities also expose us to the inherent risks of drilling, including the risk that we will not discover commercially productive crude oil or natural gas reserves. The costs of drilling wells are often uncertain, and numerous factors beyond our control (such as unexpected drilling conditions, equipment failures or incidents, and shortages or delays in the availability of drilling rigs and the delivery of equipment) may cause drilling operations to be curtailed, delayed or cancelled. These risks are heightened when we drill in deep and ultra-deep waters. In addition, increased competition in the oil and gas sector in Brazil may increase the costs of obtaining additional acreage in bidding rounds for new concessions. We may not be able to maintain our long-term growth objectives for oil production unless we conduct successful exploration and development activities of our large reservoirs in a timely manner.

We may not obtain, or it may be difficult for us to obtain, financing for our planned investments, which may have a material adverse effect on us.

Under our 2011-2015 Business Plan, we intend to invest U.S.$224.7 billion between 2011 and 2015. In addition, approximately 27% of our existing debt, or U.S.$22.2 billion, will mature in the next three years. In order to implement our 2011-2015 Business Plan, including the development of our oil and natural gas exploration activities in the pre- and post-salt layers and the development of refining capacity sufficient to process increasing production volumes, we will need to raise significant amounts of debt capital in the financial and capital markets, including by, among other means, loans and issuing debt securities. We cannot guarantee that we will be able to obtain the necessary financing to implement our Business Plan and to roll-over our existing debt in a timely and advantageous manner in order to implement our 2011-2015 Business Plan.

Our crude oil and natural gas reserve estimates involve some degree of uncertainty, which could adversely affect our ability to generate income.

The proved crude oil and natural gas reserves set forth in this annual report are our estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made) according to applicable regulations. Our proved developed crude oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties in estimating quantities of proved reserves related to prevailing crude oil and natural gas prices applicable to our production, which may lead us to make revisions to our reserve estimates. Downward revisions in our reserve estimates could lead to lower future production, which could have an adverse effect on our results of operations and financial condition.

We do not own any of the subsoil accumulations of crude oil and natural gas in Brazil.

Under Brazilian law, the Brazilian federal government owns all subsoil accumulations of crude oil and natural gas in Brazil and the concessionaire owns the oil and gas it produces from those subsoil accumulations pursuant to concession agreements. We possess the exclusive right to develop the volumes of crude oil and natural gas included in our reserves pursuant to concession agreements awarded to us by the Brazilian federal government and we own the hydrocarbons we produce under those concession agreements. Access to crude oil and natural gas reserves is essential to an oil and gas company’s sustained production and generation of income, and our ability to generate income would be adversely affected if the Brazilian federal government were to restrict or prevent us from exploiting these crude oil and natural gas reserves. In addition, we may be subject to fines by the ANP and our concessions may be revoked if we do not comply with our obligations under our concessions.

The Assignment Agreement we entered into with the Brazilian federal government is a related party transaction.

The transfer of oil and gas exploration and production rights to us related to specific pre-salt areas is governed by the Assignment Agreement, which is a contract between the Brazilian federal government, our controlling shareholder, and us. The negotiation of the Assignment Agreement involved significant issues, including negotiations regarding (1) the area covered by the transfer of rights, consisting of exploratory blocks; (2) the price to be paid for the transfer of rights; and (3) the terms of the subsequent revision of the contract price and volume under the Assignment Agreement.

This contract includes provisions for a subsequent revision of the contract terms, which are subject to oil and industry prices at the time the revision is made. At the time the Assignment Agreement was negotiated, the initial contract price paid by us was based on an assumed Brent oil crude price of U.S.$80. Once the revision process is concluded pursuant to the terms of the Assignment Agreement, if it is determined that the revised contract price is higher than the initial contract price, we will either make an additional payment to the Brazilian federal government or reduce the amount of barrels of oil equivalent subject to the Assignment Agreement. See Item 10. “Material contracts—Petrobras—Assignment Agreement.”Over the course of the life of the Assignment Agreement, novel issues may arise in the implementation of the revision process and other provisions that will require negotiations between related parties.

We are subject to numerous environmental, health and safety regulations and industry standards that are becoming more stringent and may result in increased capital and operating expenditures and decreased production.

Our activities are subject to a wide variety of federal, state and local laws, regulations and permit requirements relating to the protection of human health, safety and the environment, both in Brazil and in other jurisdictions in which we operate, as well as to evolving industry standards and best practices. Particularly in Brazil, our oil and gas business is subject to extensive regulation by several governmental agencies, including the ANP, the ANEEL, the Brazilian Water Transportation Agency (Agência Nacional de Transportes Aquaviários) and the Brazilian Land Transportation Agency (Agência Nacional de Transportes Terrestres).

Failure to observe or comply with these laws and regulations could result in penalties that could adversely affect our operations. In Brazil, for example, we could be exposed to administrative and criminal sanctions, including warnings, fines and closure orders for non-compliance with these environmental, health and safety regulations, which, among other things, limit or prohibit emissions or spills of toxic substances produced in connection with our operations. Waste disposal and emissions regulations may also require us to clean up or retrofit our facilities at substantial cost and could result in substantial liabilities. The Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis (Brazilian Institute of the Environment and Renewable Natural Resources, or IBAMA) and the ANP routinely inspect our facilities, and may impose fines, restrictions on operations, or other sanctions in connection with its inspections, including unexpected, temporary production shutdowns. In addition, we are subject to environmental laws that require us to incur significant costs to cover damage that a project may cause to the environment. These additional costs may have a negative impact on the profitability of the projects we intend to implement or may make such projects economically unfeasible.

As environmental, health and safety regulations become more stringent, and as new laws and regulations relating to climate change, including carbon controls, become applicable to us, and as industry standards evolve, it is probable that our capital expenditures and investments for compliance with such laws and regulations and industry standards will increase substantially in the future. In addition, if compliance with such laws and regulations and industry standards results in significant unplanned production shutdowns, this may have a material adverse effect on our production. We also cannot guarantee that we will be able to maintain or renew our licenses and permits if they are revoked or if the applicable environmental authorities oppose or delay their issuance or renewal. Increased expenditures to comply with environmental, health and safety regulations, to mitigate the environmental impact of our operations or to restore the biological and geological characteristics of the areas in which we operate may result in reductions in other strategic investments. Any substantial increase in expenditures for compliance with environmental, health or safety regulations or reduction in strategic investments and significant decreases in our production from unplanned shutdowns may have a material adverse effect on our results of operations or financial condition.

We may incur losses and spend time and money defending pending litigations and arbitrations.

We are currently a party to numerous legal proceedings relating to civil, administrative, environmental, labor and tax claims filed against us. These claims involve substantial amounts of money and other remedies. Several individual disputes account for a significant part of the total amount of claims against us. See Item 8. “Financial Information—Legal Proceedings” and Note 28 to our audited consolidated financial statements included in this annual report for a description of the legal proceedings to which we are subject. In the event that claims involving a material amount and for which we have no provisions were to be decided against us, or in the event that the losses estimated turn out to be significantly higher than the provisions made, the aggregate cost of unfavorable decisions could have a material adverse effect on our financial condition and results of operations. We may also be subject to litigation and administrative proceedings in connection with our concessions and other government authorizations, which could result in the revocation of such concessions and government authorizations. In addition, our management may be required to direct its time and attention to defending these claims, which could preclude them from focusing on our core business. Depending on the outcome, certain litigation could result in restrictions on our operations and have a material adverse effect on certain of our businesses.

We are vulnerable to increased financing expenses resulting from increases in prevailing market interest rates and exchange rate fluctuation.

Fluctuations in exchange rates, especially a depreciation of the real in relation to the U.S. dollar rate, may increase our financing expenses as most of our revenues have been denominated in reais, while some of our operating expenses and capital expenditures and investments and a substantial portion of our indebtedness are, and are expected to continue to be, denominated in or indexed to U.S. dollars and other foreign currencies.

As of December 31, 2011, approximately 55.9% — U.S.$45,905 million of our total indebtedness — consisted of floating rate debt. In light of cost considerations and market analysis, we decided not to enter into derivative contracts or make other arrangements to hedge against the risk of an increase in interest rates. Accordingly, if market interest rates rise, our financing expenses will increase, which could have an adverse effect on our results of operations and financial condition. In addition, as we refinance our existing debt in the coming years, the mix of our indebtedness may change, specifically as it relates to the ratio of fixed to floating interest rates, the ratio of short-term to long-term debt, and the currencies in which our debt is denominated in or indexed to. We cannot assure you that such changes will not result in increased financing expenses borne by us.

We are not insured against business interruption for our Brazilian operations and most of our assets are not insured against war or sabotage.

We do not maintain coverage for business interruptions of any nature for our Brazilian operations, including business interruptions caused by labor action. If, for instance, our workers were to strike, the resulting work stoppages could have an adverse effect on us. In addition, we do not insure most of our assets against war or sabotage. Therefore, an attack or an operational incident causing an interruption of our business could have a material adverse effect on our financial condition or results of operations.

Our international operations are subject to substantial risks.

We operate in several countries, particularly in South America and West Africa. Political, economic and social instability in these countries can have a material adverse effect on us. The results of operations and financial condition of our subsidiaries in these countries may be adversely affected by fluctuations in their local economies, political instability and governmental actions relating to the economy, including:

· the imposition of price controls;

· the imposition of restrictions on hydrocarbon exports;

· the fluctuation of local currencies against the real;

· the nationalization of oil and gas reserves;

· increases in export tax and income tax rates for crude oil and oil products; and

· unilateral (governmental) institutional and contractual changes, including controls on investments and limitations on new projects.

If one or more of the risks described above were to materialize we may lose part or all of our reserves in the affected country and we may not achieve our strategic objectives in these countries or in our international operations as a whole, which may result in a material adverse effect on our results of operations and financial condition. For more information about our operations outside Brazil, see Item 4. “Information on the Company¾International.”

Risks Relating to PifCo

PifCo’s operations and debt servicing capabilities are dependent on us.

PifCo’s financial position and results of operations are directly affected by our decisions. PifCo is a direct, wholly-owned finance subsidiary of Petrobras incorporated in the Cayman Islands as an exempted company with limited liability. PifCo functions as a vehicle for us to raise capital for our operations through the issuance of debt securities in the international capital markets, among other means. PifCo’s ability to service and repay its indebtedness is consequently dependent on our own operations. Our support of PifCo’s debt obligations has been and will continue to be made through unconditional and irrevocable guaranties of payment. Our own financial condition and results of operations, as well as our financial support of PifCo, directly affect PifCo’s operational results and debt servicing capabilities. For a more detailed description of certain risks that may have a material adverse impact on our financial condition or results of operations and therefore affect PifCo’s ability to meet its debt obligations, see “Risks Relating to Our Operations.”

Risks Relating to Our Relationship with the Brazilian Federal Government

The Brazilian federal government, as our controlling shareholder, may cause us to pursue certain macroeconomic and social objectives that may have a material adverse effect on us.

As our controlling shareholder, the Brazilian federal government has pursued, and may pursue in the future, certain of its macroeconomic and social objectives through us, as permitted by law. Brazilian law requires the Brazilian federal government to own a majority of our voting stock, and so long as it does, the Brazilian federal government will have the power to elect a majority of the members of our board of directors and, through them, a majority of the executive officers who are responsible for our day-to-day management. As a result, we may engage in activities that give preference to the objectives of the Brazilian federal government rather than to our own economic and business objectives.

In particular, we continue to assist the Brazilian federal government to ensure that the supply and pricing of crude oil and oil products in Brazil meets Brazilian consumption requirements. Accordingly, we may make investments, incur costs and engage in sales on terms that may have an adverse effect on our results of operations and financial condition. Prior to January 2002, prices for crude oil and oil products were regulated by the Brazilian federal government, occasionally set below prices prevailing in the world oil markets. We cannot assure you that price controls will not be reinstated in Brazil.

Our investment budget is subject to approval by the Brazilian federal government, and failure to obtain approval of our planned investments could adversely affect our operating results and financial condition.

The Brazilian federal government maintains control over our investment budget and establishes limits on our investments and long-term debt. As a state-controlled entity, we must submit our proposed annual budgets to the Ministry of Planning, Budget and Management, the MME and the Brazilian Congress for approval. If our approved budget reduces our proposed investments and incurrence of new debt and we cannot obtain financing that does not require Brazilian federal government approval, we may not be able to make all the investments we envision, including those we have agreed to make to expand and develop our crude oil and natural gas fields. If we are unable to make these investments, our operating results and financial condition may be adversely affected.

Risks Relating to Brazil

Brazilian political and economic conditions have a direct impact on our business and may have a material adverse effect on us.

The Brazilian federal government’s economic policies may have important effects on Brazilian companies, including us, and on market conditions and prices of Brazilian securities. Our financial condition and results of operations may be adversely affected by the following factors and the Brazilian federal government’s response to these factors:

· devaluations and other exchange rate movements;

· inflation;

· exchange control policies;

· price instability;

· interest rates;

· liquidity of domestic capital and lending markets;

· tax policy;

· regulatory policy for the oil and gas industry, including pricing policy; and

· other political, diplomatic, social and economic developments in or affecting Brazil.

Uncertainty over whether the Brazilian federal government will implement changes in policy or regulations that may affect any of the factors mentioned above or other factors in the future may lead to economic uncertainty in Brazil and increase the volatility of the Brazilian securities market and securities issued abroad by Brazilian companies, which may have a material adverse effect on our results of operations and financial condition.

Risks Relating to Our Equity and Debt Securities

The size, volatility, liquidity and/or regulation of the Brazilian securities markets may curb the ability of holders of ADSs to sell the common or preferred shares underlying our ADSs.

Petrobras shares are among the most liquid in the São Paulo Stock Exchange (BM&FBOVESPA), but overall, the Brazilian securities markets are smaller, more volatile and less liquid than the major securities markets in the United States and other jurisdictions, and may be regulated differently from the way in which U.S. investors are accustomed. Factors that may specifically affect the Brazilian equity markets may limit the ability of holders of ADSs to sell the common or preferred shares underlying our ADSs at the price and time they desire.

The market for PifCo’s notes may not be liquid.

Some of PifCo’s notes are not listed on any securities exchange and are not quoted through an automated quotation system. We can make no assurance as to the liquidity of or trading markets for PifCo’s notes. We cannot guarantee that the holders of PifCo’s notes will be able to sell their notes in the future. If a market for PifCo’s notes does not develop, holders of PifCo’s notes may not be able to resell the notes for an extended period of time, if at all.

Holders of ADSs may be unable to exercise preemptive rights with respect to the common or preferred shares underlying the ADSs.

Holders of ADSs who are residents of the United States may not be able to exercise the preemptive rights relating to the common or preferred shares underlying our ADSs unless a registration statement under the Securities Act is effective with respect to those rights or an exemption from the registration requirements of the Securities Act is available. We are not obligated to file a registration statement with respect to the common or preferred shares relating to these preemptive rights, and therefore we may not file any such registration statement. If a registration statement is not filed and an exemption from registration does not exist, The Bank of New York Mellon, as depositary, will attempt to sell the preemptive rights, and holders of ADSs will be entitled to receive the proceeds of the sale. However, the preemptive rights will expire if the depositary cannot sell them. For a more complete description of preemptive rights with respect to the common or preferred shares, see Item 10. “Additional Information—Memorandum and Articles of Association of Petrobras—Preemptive Rights.”

If holders of our ADSs exchange their ADSs for common or preferred shares, they risk losing the ability to remit foreign currency abroad and forfeiting Brazilian tax advantages.

The Brazilian custodian for our common or preferred shares underlying our ADSs must obtain a certificate of registration from the Central Bank of Brazil to be entitled to remit U.S. dollars abroad for payments of dividends and other distributions relating to our preferred and common shares or upon the disposition of the common or preferred shares. If holders of ADSs decide to exchange their ADSs for the underlying common or preferred shares, they will be entitled to continue to rely, for five Brazilian business days from the date of exchange, on the custodian’s certificate of registration. After that period, such holders may not be able to obtain and remit U.S. dollars abroad upon the disposition of the common or preferred shares, or distributions relating to the common or preferred shares, unless they obtain their own certificate of registration or register under Resolution No. 2,689, of January 26, 2000, of the National Monetary Council (Conselho Monetário Nacional, or CMN), which entitles registered foreign investors to buy and sell on the BM&FBOVESPA. In addition, if such holders do not obtain a certificate of registration or register under Resolution No. 2,689, they may be subject to less favorable tax treatment on gains with respect to the common or preferred shares.

If such holders attempt to obtain their own certificate of registration, they may incur expenses or suffer delays in the application process, which could delay their ability to receive dividends or distributions relating to the common or preferred shares or the return of their capital in a timely manner. The custodian’s certificate of registration or any foreign capital registration obtained by such holders may be affected by future legislative or regulatory changes and we cannot assure such holders that additional restrictions applicable to them, the disposition of the underlying common or preferred shares, or the repatriation of the proceeds from the process will not be imposed in the future.

Holders of ADSs may face difficulties in protecting their interests.

Our corporate affairs are governed by our bylaws and Brazilian Corporate Law, which differ from the legal principles that would apply if we were incorporated in a jurisdiction in the United States or elsewhere outside Brazil. In addition, the rights of an ADS holder, which are derivative of the rights of holders of our common or preferred shares, as the case may be, to protect their interests against actions by our board of directors are different under Brazilian Corporate Law than under the laws of other jurisdictions. Rules against insider trading and self-dealing and the preservation of shareholder interests may also be different in Brazil than in the United States. In addition, shareholders in Brazilian companies ordinarily do not have standing to bring a class action.

We are a state-controlled company organized under the laws of Brazil and all of our directors and officers reside in Brazil. Substantially all of our assets and those of our directors and officers are located in Brazil. As a result, it may not be possible for holders of ADSs to effect service of process upon us or our directors and officers within the United States or other jurisdictions outside Brazil or to enforce against us or our directors and officers judgments obtained in the United States or other jurisdictions outside Brazil. Because judgments of U.S. courts for civil liabilities based upon the U.S. federal securities laws may only be enforced in Brazil if certain requirements are met, holders of ADSs may face greater difficulties in protecting their interest in actions against us or our directors and officers than would shareholders of a corporation incorporated in a state or other jurisdiction of the United States.

Holders of our ADSs may encounter difficulties in the exercise of voting rights and preferred shares and the ADSs representing preferred shares generally do not give holders of ADSs voting rights.

Holders of ADSs may encounter difficulties in the exercise of some of their rights as a shareholder if they hold our ADS rather than the underlying shares. For example, if we fail to provide the depositary with voting materials on a timely basis, holders of ADSs may not be able to vote by giving instructions to the depositary on how to vote for them.

In addition, a portion of our ADSs represents our preferred shares. Under Brazilian law and our bylaws, holders of preferred shares generally do not have the right to vote in meetings of our stockholders. This means, among other things, that holders of ADSs representing preferred shares are not entitled to vote on important corporate transactions or decisions. See Item 10. “Additional Information—Memorandum and Articles of Incorporation of Petrobras—Voting Rights” for a discussion of the limited voting rights of our preferred shares.

We would be required to pay judgments of Brazilian courts enforcing our obligations under the guaranty relating to PifCo’s notes only in reais.

If proceedings were brought in Brazil seeking to enforce our obligations in respect of the guaranty relating to PifCo’s notes, we would be required to discharge our obligations only in reais. Under the Brazilian exchange control rules, an obligation to pay amounts denominated in a currency other than reais, which is payable in Brazil pursuant to a decision of a Brazilian court, may be satisfied in reais at the rate of exchange, as determined by the Central Bank of Brazil, in effect on the date of payment.

A finding that we are subject to U.S. bankruptcy laws and that the guaranty executed by us were a fraudulent conveyance could result in PifCo noteholders losing their legal claim against us.

PifCo’s obligation to make payments on the PifCo notes is supported by our obligation under the corresponding guaranty. We have been advised by our external U.S. counsel that the guaranty is valid and enforceable in accordance with the laws of the State of New York and the United States. In addition, we have been advised by our general counsel that the laws of Brazil do not prevent the guaranty from being valid, binding and enforceable against us in accordance with its terms. In the event that U.S. federal fraudulent conveyance or similar laws are applied to the guaranty, and we, at the time we entered into the relevant guaranty:

· were or are insolvent or rendered insolvent by reason of our entry into such guaranty;

· were or are engaged in business or transactions for which the assets remaining with us constituted unreasonably small capital; or

· intended to incur or incurred, or believed or believe that we would incur, debts beyond our ability to pay such debts as they mature; and

· in each case, intended to receive or received less than reasonably equivalent value or fair consideration therefor,

then our obligations under the guaranty could be avoided, or claims with respect to that agreement could be subordinated to the claims of other creditors. Among other things, a legal challenge to the guaranty on fraudulent conveyance grounds may focus on the benefits, if any, realized by us as a result of PifCo’s issuance of these notes. To the extent that the guaranty is held to be a fraudulent conveyance or unenforceable for any other reason, the holders of the PifCo notes would not have a claim against us under the relevant guaranty and will solely have a claim against PifCo. We cannot assure you that, after providing for all prior claims, there will be sufficient assets to satisfy the claims of the PifCo noteholders relating to any avoided portion of the guaranty.

Concerns regarding the European credit crisis and market perceptions with respect to both the financial stability of Eurozone countries and the stability of the euro could adversely affect the value of our euro notes and the general availability and cost of financing.

There are persistent concerns regarding the debt burden of certain Eurozone countries and their ability to meet future financial obligations, the overall stability of the euro and the suitability of the euro to function as a single currency given the diverse economic and political circumstances in individual Eurozone countries. The risks and prevalent concerns about the credit crisis in Europe could have a detrimental impact on global economic recovery as well as on sovereign and non-sovereign debt in the Eurozone countries. There can be no assurance that the market disruptions in Europe will not spread, nor can there be any assurance that future assistance packages will be available or, even if provided, will be sufficient to stabilize affected countries and markets in Europe or elsewhere. These and other concerns could lead to the re-introduction of individual currencies in one or more Eurozone countries, or, in more extreme circumstances, the possible dissolution of the euro entirely.

Should the euro dissolve entirely, the legal and contractual consequences for holders of euro-denominated obligations would be determined by laws in effect at such time. It is difficult to predict the real impact of the European sovereign crisis; however, to the extent uncertainty regarding the economic recovery continues to negatively impact the global economy, concerns regarding the effect of this financial crisis globally could also have an adverse impact on the capital and financial markets generally. These potential developments, or market perceptions concerning these and related issues, could negatively impact the value of our euro notes and the general availability and cost of financing.

Item 4. Information on the Company

History and Development

Petróleo Brasileiro S.A.—Petrobras—was incorporated in 1953 to conduct the Brazilian federal government’s hydrocarbon activities. We began operations in 1954 and have been carrying out crude oil and natural gas production and refining activities in Brazil on behalf of the government. As of December 31, 2011, the Brazilian federal government owned 28.66% of our outstanding capital stock and 50.24% of our voting shares. Our common and preferred shares have been traded on the BM&FBOVESPA since 1968 and on the NYSE since 2000.

As part of a comprehensive reform of the oil and gas regulatory system, the Brazilian Congress amended the Brazilian Constitution in 1995 to authorize the Brazilian federal government to contract with any state or privately-owned company to carry out upstream, oil refining, cross-border commercialization and transportation activities in Brazil of oil, natural gas and their respective products. On August 6, 1997, Brazil enacted Law No. 9,478, which established a concession-based regulatory framework, ended our exclusive right to carry out oil and gas activities, and allowed competition in all aspects of the oil and gas industry in Brazil. Since that time, we have been operating in an increasingly deregulated and competitive environment. Law No. 9,478 also created an independent regulatory agency, the ANP, to regulate the oil, natural gas and renewable fuel industry in Brazil and to create a competitive environment in the oil and gas sector. Effective January 2, 2002, Brazil deregulated prices for crude oil, oil products and natural gas. See “Regulation of the Oil and Gas Industry in Brazil—Price Regulation.”

In 2010, new laws were enacted to regulate exploration and production activities in pre-salt areas not subject to existing concessions. Pursuant to this new legislation, we entered into an agreement with the Brazilian federal government on September 3, 2010 (Assignment Agreement), under which the government assigned to us the right to activities for the exploration and production of oil, natural gas and other fluid hydrocarbons in specified pre-salt areas, subject to a maximum production of five billion barrels of oil equivalent. The initial purchase price for our rights under the Assignment Agreement was R$74,807,616,407, which was equivalent to U.S.$42,533,327,500 as of September 1, 2010. On September 29, 2010, we issued new shares (including shares in the form of ADSs) in a global public offering consisting of a registered offering in Brazil and an international offering that included a registered offering in the United States. We applied part of the net proceeds from the global offering to pay the initial purchase price under the Assignment Agreement.

We operate through subsidiaries, joint ventures, and associated companies established in Brazil and many other countries. Our principal executive office is located at Avenida República do Chile 65, 20031-912 Rio de Janeiro, RJ, Brazil and our telephone number is (55-21) 3224-4477.

Overview of the Group

We are an integrated oil and gas company that is the largest corporation in Brazil and one of the largest companies in Latin America in terms of revenues. As a result of our legacy as Brazil’s former sole supplier of crude oil and oil products and our ongoing commitment to development and growth, we operate most of Brazil’s producing oil and gas fields and hold a large base of proved reserves and a fully developed operational infrastructure. In 2011, our average domestic daily oil production was 2,022.0 mbbl/d, an estimated 92% of Brazil’s total. Over 76% of our domestic proved reserves are in large, contiguous and highly productive fields in the offshore Campos Basin, which allows us to optimize our infrastructure and limit our costs of exploration, development and production. In 43 years of developing Brazil’s offshore basins we have developed special expertise in deepwater exploration and production, which we exploit both in Brazil and in other offshore oil provinces.

As of December 31, 2011, we had proved developed oil and gas reserves of 8,124 mmboe, including synthetic oil and synthetic gas from oil shale and proved undeveloped reserves of 4,143 mmboe in Brazil. The exploration and development of this large reserve based and the new pre-salt areas garanted to us by the Brazilian Government under the Assignment Agreement has demanded, and will continue to demand, significant investments and the rapid growth of our operations. To support this growth, we have ordered the construction of 22 new FPSOs and 33 drilling rigs and are also making necessary investments in infrastructure. We have planned capital expenditures and investments of U.S.$50.6 billion for 2012 and of U.S.$224.7 billion for the period from 2011 through 2015.

We operate substantially all of the refining capacity in Brazil. Most of our refineries are located in Southeastern Brazil, within the country’s most populated and industrialized markets and adjacent to the Campos Basin that provides most of our crude oil. Our domestic refining capacity of 2,013 mbbl/d is well balanced with our domestic refining throughput of 1,862 mbbl/d and sales of oil products to domestic markets of 2,131 mbbl/d. We are also involved in the production of petrochemicals. We distribute oil products through our own “BR” network of retailers and to wholesalers.

We participate in most aspects of the Brazilian natural gas market. We expect the percentage of natural gas in Brazil’s energy matrix to grow in the future as a result of the expansion of Brazil’s gas transportation infrastructure which began in 2005 and was largely completed in 2011 and as we expand our production of both associated and non-associated gas, mainly from offshore fields in the Campos, Espírito Santo and Santos Basins. We import natural gas from Bolivia and use LNG terminals to meet demand and diversify our supply. We also participate in the domestic power market primarily through our investments in gas-fired thermoelectric power plants. In addition, we participate in the fertilizer business, which is another important source of natural gas demand.

Outside of Brazil, we operate in 24 countries. In South America, our operations extend from exploration and production to refining, marketing, retail services and natural gas pipelines. In North America, we produce oil and gas and have refining operations in the United States. In Africa, we produce oil in Angola and Nigeria, and in Asia, we have refining operations in Japan. In other countries, we are engaged mainly in oil and gas exploration.

Comprehensive information and tables on reserves and production is presented at the end of Item 4. See “—Additional Reserves and Production Information.”

Our activities comprise six business segments:

· Exploration and Production: oil and gas exploration, development and production in Brazil;

· Refining, Transportation and Marketing: includes refining, logistics, transportation, oil products and crude oil exports and imports, as well as petrochemical sector in Brazil;

· Distribution: distribution of oil products to wholesalers and through our “BR” retail network in Brazil;

· Gas and Power: transportation and trading of natural gas and LNG , as well as, generation and trading of electric power;

· Biofuel: production of biodiesel and its co-products and ethanol activities, through equity investments, production and marketing of ethanol, sugar and the excess electric power generated from sugarcane bagasse; and

· International: exploration and production, refining, transportation and marketing, distribution and gas and power operations outside of Brazil.

Our Corporate segment comprises our financing activities not attributable to other segments, including corporate financial management, central administrative overhead and actuarial expenses related to our pension and health care plans for inactive participants. As of 2011, the results of our Biofuels segment have been presented separately from our Corporate segment. The 2010 and 2009 financial information related to our Corporate and Biofuel segments were reclassified accordingly.

The following table sets forth key information for each business segment in 2011:

	Key Information by Business Segment, 2011
	Exploration and Production	Refining, Transportation and Marketing	Gas and Power	Biofuel	Distribution	International	Corporate	Eliminations	Group Total
	(U.S.$ million)
Sales revenues	74,117	118,630	9,738	320	44,001	16,956	–	(117,847)	145,915
Income (loss) before income taxes	36,809	(8,753)	2,725	(151)	1,134	2,117	(5,003)	(2,154)	26,724
Total assets at December 31	141,113	84,330	27,645	1,289	7,885	19,427	45,326	(7,605)	319,410
Capital expenditures and investments	20,405	16,133	2,293	294	679	2,631	729	–	43,164

Exploration and Production

Exploration and Production Key Statistics
	2011	2010	2009
	(U.S.$ million)
Exploration and Production:
Sales revenues	74,117	54,273	38,759
Income (loss) before income taxes	36,809	25,439	14,707
Total assets at December 31	141,113	136,600	75,908
Capital expenditures and investments	20,405	18,621	16,162

Oil and gas exploration and production activities in Brazil are the largest component of our portfolio. We have gradually increased production over the past four decades, from 164 mbbl/d of crude oil, condensate and natural gas liquids in Brazil in 1970 to 2,022 mbbl/d in 2011. We aim to grow oil and gas reserves and production sustainably and be recognized for excellence in Exploration and Production operations.

The primary focus of our E&P segment is to:

· Continue to explore and develop the Campos Basin, leveraging the current infrastructure to drill in deeper horizons in existing concessions, including pre-salt reservoirs, and using new technologies for secondary recovery in producing fields;

· Explore and develop Brazil’s two other most promising offshore basins, Espírito Santo (light oil, heavy oil and gas) and Santos (gas and light oil), with a particular focus on pre-salt development;

· Explore light oil and natural gas in new frontiers, including Brazil’s equatorial margin and eastern and northeastern regions;

· Develop associated and non-associated gas resources in the Santos Basin and elsewhere to meet Brazil’s growing demand for gas and to increase the contribution of Brazilian gas production as a proportion of total domestic gas supply; and

· Sustain and increase production from onshore and shallow fields through drilling and enhanced recovery operations.

During 2011, our oil and gas production from Brazil averaged 2,220.5 mboe/d, of which 91% was oil and 9% was natural gas. On December 31, 2011, our estimated net proved crude oil and natural gas reserves in Brazil were 12.26 billion boe, of which 85% was crude oil and 15% was natural gas. Brazil provided 90.7% of our worldwide production in 2011 and accounted for 95% of our worldwide reserves at December 31, 2011 on a barrels of oil equivalent basis. Historically, approximately 85% of our total Brazilian production has been oil. In connection with the development of the pre-salt, the contribution of natural gas to total hydrocarbon production is expected to grow. In 2011, we drilled a total of 398 development wells, of which 84 were offshore and 314 were onshore.

As of December 31, 2011, we had 132 exploration agreements covering 194 blocks, corresponding to a gross exploratory acreage of 119,132 km² (29.4 million acres), or a net exploratory acreage of 95,672.2 km²(23.6 million acres), and 51 evaluation plans. We are exclusively responsible for conducting the exploration activities in 98 of the 132 exploration agreements. As of December 31, 2011, we had exploration partnerships with 20 foreign and domestic companies. We conduct exploration activities under 111 of our 132 partnership agreements.

We focus much of our exploration effort on deepwater drilling, where the discoveries are substantially larger and our technology and expertise create a competitive advantage. In 2011, we invested a total of U.S.$5.3 billion in exploration activities in Brazil. We drilled a total of 123 exploratory wells in 2011, of which 47 were offshore and 76 onshore.

Brazil’s richest oil fields are located offshore, most of them in deep waters. Since 1971, when we started exploration in the Campos Basin, we have been active in these waters and we have become globally recognized as innovators in the technology required to explore and produce hydrocarbons in deep and ultra-deep water. We operate more production (on a boe basis) from fields in deep and ultra-deep water than any other company. In 2011, offshore production accounted for 89% of our production and deepwater production accounted for 77% of our production in Brazil. In 2011, we operated 226 wells in water deeper than 1,000 meters (3,281 feet), and we drilled around 26 exploratory wells in water deeper than 1,000 meters (3,281 feet).

Offshore exploration, development and production costs are generally higher than those onshore, but we have been able to offset these higher costs by higher drilling success ratios, larger discoveries and greater production volumes. We have historically been successful in finding and developing significant oil reservoirs offshore, which has allowed us to achieve economies of scale by spreading the total costs of exploration, development and production over a large base. By focusing on opportunities that are close to existing production infrastructure, we limit the incremental capital requirements of new field development.

Historically, our offshore exploration and production activities were focused on post-salt reservoirs. In recent years, we have focused our offshore exploration efforts on pre-salt reservoirs located in a region of approximately 149,000 km² (36.8 million acres) stretching from the Campos to the Santos Basins. Our existing contracts in this area cover 26.6% (approximately 39,615 km² or 9.8 million acres) of the pre-salt areas, including the pre-salt areas assigned to us under Concession Contracts and the Assignment Agreement. An additional 4% (approximately 6,000 km² or 1.5 million acres) is under concession to other oil companies for exploration. The remaining 69.4% (approximately 103,000 km² or 25.4 million acres) of the pre-salt region is open acreage area, not licensed yet, and the licensing of new pre-salt areas will be made under a production-sharing regime under Law No. 12,351, enacted on December 22, 2010.

Information about our principal oil and gas producing fields in Brazil is summarized in the table below.

Principal Oil and Gas Producing Fields in Brazil
Basin	Fields	Petrobras %	Type	Fluid(1)
Alagoas	Pilar	100%	Onshore	Light Oil/Natural Gas

Camamu	Manati	35%	Shallow	Natural Gas

Campos	Albacora	100%	Shallow	Intermediate Oil
			Deepwater	Intermediate Oil
	Albacora Leste	90%	Deepwater Ultra-deepwater	Intermediate Oil
	Baleia Azul	100%	Deepwater	Intermediate Oil
	Baleia Franca	100%	Deepwater	Intermediate Oil
	Barracuda	100%	Deepwater	Intermediate Oil
	Bijupirá/Salema	22.4%(2)	Deepwater	Intermediate Oil
	Cachalote	100%	Deepwater	Intermediate Oil
	Caratinga	100%	Deepwater	Intermediate Oil
	Espadarte	100%	Deepwater	Intermediate Oil
	Jubarte	100%	Deepwater	Heavy Oil
	Maromba	62.5%	Deepwater	Heavy Oil
	Marlim	100%	Deepwater	Heavy Oil
	Marlim Leste	100%	Deepwater	Intermediate Oil
	Marlim Sul	100%	Deepwater Ultra-deepwater	Intermediate Oil
	Namorado	100%	Shallow	Intermediate Oil
	Ostra	35%(2)	Deepwater	Heavy Oil
	Pampo	100%	Shallow	Intermediate Oil
	Pargo	100%	Shallow	Intermediate Oil
	Roncador	100%	Ultra-deepwater	Intermediate Oil
	Voador	100%	Deepwater	Heavy Oil
Espírito Santo	Fazenda Alegre Peroá Golfinho	100% 100% 100%	Onshore Shallow Deepwater Ultra-deepwater	Heavy Oil Light Oil Intermediate Oil Intermediate Oil
	Canapu	100%	Deepwater	Natural Gas
	Camarupim	76%	Deepwater	Natural Gas
Potiguar	Canto do Amaro	100%	Onshore	Intermediate Oil/Natural Gas Heavy Oil/Natural Gas

Recôncavo	Jandaia Miranga	100% 100%	Onshore Onshore	Light Oil Light Oil/Natural Gas
Santos	Merluza	100%	Shallow	Natural Gas
	Mexilhão	100%	Shallow	Natural Gas
	Uruguá	100%	Deepwater	Intermediate Oil/Natural Gas
	Tambaú	100%	Deepwater	Natural Gas
	Lula	65%	Ultra-deepwater	Intermediate Oil
	Sapinhoá	45%	Ultra-deepwater	Intermediate Oil
Sergipe	Carmópolis	100%	Onshore	Intermediate Oil
	Sirirízinho	100%	Onshore	Intermediate Oil
Solimões	Leste do Urucu	100%	Onshore	Light Oil/Natural Gas
	Rio Urucu	100%	Onshore	Light Oil/Natural Gas

(1) Heavy oil = up to 22° API; intermediate oil = 22° API to 31° API; light oil = greater than 31° API

We have historically conducted exploration, development and production activities in Brazil through concession contracts, which we have obtained through participation in bid rounds conducted by the ANP. Some of our existing concessions were granted by the ANP without an auction in 1998, as provided by Law No. 9,478. These are known as the “Round Zero” concession contracts. Since such time, we have participated in all of the auction rounds, most recently in December 2008.

Production growth in the Campos Basin originates mainly from the installation of new platforms to develop our proved reserves in the region. In 2011, the start-up of operations at the P-56 platform located in the Marlim Sul field in the offshore Campos Basin added a capacity of 100 mbbl/d of oil and 6.0 mmm³/d of natural gas. The connection of new wells to previously installed platforms is also a significant contributor to production increases in the Campos Basin. The interconnection of new wells in the P-48 and P-57 platforms and the FPSO Capixaba added 68.9 mbbl/d to our average production in the Campos Basin in 2011.

We expect that the source of future production from the Campos Basin will be predominantly from deepwater oil fields. We are currently developing nine major projects in the Campos Basin: Marlim Sul Module 3, Roncador Modules 3 and 4, Papa-Terra Modules 1 and 2, Aruanã (BM-C-36) - EWT, Jubarte Phase II, Parque das Baleias and the pre-salt reservoirs of Baleia Azul.

Principal Campos Basin Development Projects
Field	Unit Type	Production Unit	Crude Oil Nominal Capacity (bbl/d)	Natural Gas Nominal Capacity (mcf/d)	Water Depth (meters)	Start Up (year)	Notes
Baleia Azul & Pirambu	FPSO	Anchieta	100,000	88,285	1,220	2012	Post-salt; existing FPSO chartered from SBM; Post-salt
Roncador–Module 3	SS	P-55	180,000	211,884	1,790	2013	Post-salt
Papa-Terra–Module 1	TLWP	P-61	0	0	1,180	2013	Production by P-63 Post-salt
Papa-Terra–Module 2	FPSO	P-63	150,000	31,783	1,170	2013	Post-salt
Baleia Azul, Jubarte, Cachalote, Baleia Anã & Baleia Franca	FPSO	P-58	180,000	211,884	1,400	2013	Pre-salt
Roncador–Module 4	FPSO	P-62	180,000	211,884	1,550	2013	Post-Salt

We have also made important progress in the pre-salt reservoirs of the Campos Basin, where we have drilled a total of 30 wells. Of particular note are the discoveries in the Parque das Baleias area, in the northern part of Campos Basin off the coast of the State of Espírito Santo. The first pre-salt oil production in Parque das Baleias was at the Jubarte field in 2008. We started producing from the Baleia Franca field in the second half of 2010 using the existing FPSO Capixaba. In 2012, we expect to start up a pilot system exclusively dedicated to pre-salt exploration in the Baleia Azul region using the FPSO Cidade de Anchieta, with a capacity to produce 100,000 bpd of oil and 3.5 mmm³/d of gas. We have also made promising discoveries near existing infrastructure in our Campos Basin concessions. Specifically, we have discovered pre-salt reserves of Brava, Carimbe and Tracaja in the pre-salt layers of the Marlim, Caratinga and Marlim Leste concessions. These discoveries represent opportunities to increase pre-salt production in the Campos Basin in the coming years while taking advantage of the existing infrastructure in the area.

Santos Basin

The Santos Basin, which covers approximately 348,900 km² (86 million acres) off the city of Santos, in the State of São Paulo, is one of the most promising exploration and production areas offshore Brazil. In the Santos Basin in 2011, we produced oil at an average rate of 66.9 mbbl/d and natural gas at an average rate of 4.1 mmm³/d (156.4 mmcf/d). In the Santos Basin, we held proved crude oil reserves representing 10% of our total proved crude oil reserves in Brazil and held natural gas reserves representing 29% of our total proved natural gas reserves in Brazil. On December 31, 2011, we held exploration rights to 38 blocks in the Santos Basin, comprising 23,625.4 km² (5,835.5 million acres).

The Santos Basin pre-salt was a central focus of E&P activities in 2011. We continue to concentrate our efforts on gathering information about the pre-salt reserves through extended well tests (EWTs) and testing drilling technologies to improve efficiency and to plan the definitive design of production platforms. Throughout the year, we drilled 14 new wells, increasing to 37 the number of wells in the Santos Basin pre-salt. In addition, we expect to drill up to 21 new wells in this region in 2012.

We currently have two platforms, the FPSO Cidade de São Vicente and the FPSO Dynamic Producer, that are dedicated to perform EWTs in the Santos Basin pre-salt. Since 2009, two EWTs have been performed in the Lula and Guará areas. We are currently performing EWTs in the Iracema and Carioca Northeast areas, and have three additional EWTs in other areas planned for 2012. From 2013 through 2017, we plan to install at least 17 FPSOs in the Santos Basin pre-salt to develop the production in the region. These FPSOs are currently being designed or constructed. The subsequent phase, beginning in 2017, will include the application of improved technologies and engineering specifically designed for the pre-salt fields.

The first productive field in the Santos Basin pre-salt was Lula (formerly Tupi), which began producing oil in May 2009 following an 18-month EWT. In November 2010, we replaced the EWT with a long-term production system, the FPSO Cidade de Angra dos Reis, which has a production capacity of 100 mbbl/d. By the end of 2011, we had drilled and connected three production wells to this FPSO, which was producing 65 mbbl/d of oil. A gas injection well was also drilled in the Lula area and was the first injection well to be tested in the pre-salt reservoirs. In 2012, we plan to drill two additional production wells and one injector in the Lula system.

In December 2011, the Declaration of Commerciality for the Guará area was submitted to the ANP for approval. Located in the Santos Basin pre-salt area called Sapinhoá Pilot, the FPSO Cidade de São Paulo has an expected capacity of 120,000 mbbl/d of oil and 5 mmm³/d of gas and is expected to come online in 2012.

Under the Assignment Agreement, we have six blocks and one contingent block which comprise our rights to explore, evaluate and produce up to five billion barrels of oil equivalent in the pre-salt area of the Santos Basin. We are developing these blocks in an integrated manner with the areas we already have under concession. In 2011, we drilled our first exploratory well under the Assignment Agreement in the Franco area and we have an EWT planned for that area in 2012. With a view to further develop these blocks, we have acquired four tanker hulls that will be converted into FPSOs. Over the next four years, we will proceed with our exploration program and are currently targeting the production of oil in the Franco area in 2015.

Principal Santos Basin Development Projects
Field	Unit Type	Production Unit	Crude Oil Nominal Capacity (bbl/d)	Natural Gas Nominal Capacity (mcf/d)	Water Depth (meters)	Start Up (year)	Notes
Bauna & Piracaba (BM-S-40)	FPSO	Cidade de Itajai	80,000	70,628	200	2012	Chartered from Teekay
Sapinhoá Pilot (Guará)	FPSO	Cidade de São Paulo	120,000	176,573	2,141	2012	Chartered from Schahin/Modec
Lula (Nordeste) Pilot	FPSO	Cidade de Paraty	120,000	176,573	2,200	2013	Chartered from Queiroz Galvão/SBM
Sapinhoá (Norte) – Module 2	FPSO	Cidade de Ilha Bela	150,000	211,884	2,100	2014	Chartered from Queiroz Galvão/SBM
Lula Iracema Area	FPSO	Cidade de Mangaratiba	150,000	282,520	2,100	2014	Chartered from Schahin/Modec
Franco 1 Transfer of Rights	FPSO	P-74	150,000	247,205	2,100	2015	Owned
Lula (Central)	FPSO	P-66	150,000	247,205	2,100	2015	Owned
Lula (High)	FPSO	P-67	150,000	176,575	2,100	2015	Owned

Santos is also the focus of our plans to develop domestic natural gas. Our average natural gas production in this basin in 2011 was 4.1 mmm³/d (156.4 mmcf/d) and our proved natural gas reserves in the Santos Basin represented 29% of our total proved natural gas reserves in Brazil.

In recent years we have been carrying out plans to increase our gas production and build supporting infrastructure in the Santos and Espírito Santo Basins. These plans are now reaching fruition, and we expect that they will increase our average gas production capacity in the Santos Basin from 5.8 mmm³/d (204.8 mmcf/d) in 2011 to 17.8 mmm³/d (628.6 mmcf/d) by the end of 2012. In 2010, we started up post-salt operations at the FPSO Cidade de Santos platform located in the Uruguá field, which produced 0.8 mmm³/d (28.3 mmcf/d) of gas in 2011 and is expected to produce 6.8 mmm³/d (240.1 mmcf/d) by the end of 2012, when the Tambaú field will start production using the same platform. Mexilhão, located in shallow waters in the Santos Basin Block BS-400, started its production in March 2011, and produced 1.7 mmm³/d (60.0 mmcf/d). This production may increase to 8.6 mmm³/d (303.7 mmcf/d) in 2012 in light of the potential production from new wells.

In addition to the foregoing activities, we have made light oil discoveries in shallow water post-salt reservoirs in the BM-S-40 block, called Tiro and Sidon. In 2010, we commenced an EWT in these fields using the SS-11 Atlantic Zephyr platform. We are using the results of that EWT to develop a long-term production system for this block, including a plan to install the FPSO Cidade de Itajaí, with an expected capacity of 80 mbbl/d of oil and 2 mmm³/d of gas. The FPSO Cidade de Itajaí is expected to come online in 2012. In February, 2012 we submitted to the ANP the Declaration of Commerciality for Tiro and Sidon, which were renamed Bauna and Piracaba, respectively.

Espírito Santo Basin

We have made several discoveries of light oil and natural gas in the Espírito Santo Basin, which covers approximately 75,000 km² (18.5 million acres) offshore and 14,000 km² (3.5 million acres) onshore. At December 31, 2011, we were producing oil at an average rate of 54.4 mbbl/d from 46 fields and held proved crude oil reserves representing 1% of our total proved crude oil reserves in Brazil. At December 31, 2011, we were producing natural gas at an average rate of 6.9 mmm³/d (261.2 mmcf/d) and held proved natural gas reserves representing 4% of our total proved natural gas reserves in Brazil.

In addition to developing new production projects, we are also optimizing existing resources in the Espírito Santo area by constructing the Sul Norte Capixaba gas pipeline with capacity to transport 7 mmm³/d (247.2 mmcf/d). The pipeline, which runs from the Parque das Baleias area to the Cacimbas gas treatment unit, is expected to come online in 2012.

On December 31, 2011, we held exploration rights to 20 blocks, one onshore and 19 offshore (five of which are evaluation areas), comprising a total of 8,217.5 km² (2,029.7 million acres).

Other Basins

We produce hydrocarbons and hold exploration acreage in 19 other basins in Brazil. Of these, the most significant are the shallow offshore Camamu Basin and the onshore Potiguar, Recôncavo, Sergipe, Alagoas and Solimões Basins. While our onshore production is primarily in mature fields, we plan to sustain and slightly increase production from these fields in the future by using enhanced recovery methods.

We had a total of 297 production agreements as of December 31, 2011, and were the 100% owner in 256 of them. We are operators under 12 of our 27 partnership agreements.

Critical Resources in Exploration and Production

We have sought to ensure that critical service sector resources are sufficient to permit us to move ahead with our E&P plans. Because offshore Brazil is geographically isolated from other offshore drilling areas, and because we often drill in unusually deep waters, we plan carefully for our future drilling rig needs. By using a combination of our own rigs and units that we contract for periods of three years or longer, we have historically ensured the availability of drilling units to meet our needs, and paid lower average daily rates than if we had contracted the units on a spot basis. We continually evaluate our need for rigs, renew our drilling contracts, contract ahead for rigs as needed, and stimulate new rig construction by signing long-term operating leases with drilling contractors for rigs that are not yet built.

In the last three years we have successfully eased pressures related to a limited supply of deepwater rigs. Whereas in 2008 we only had three rigs capable of drilling in water depths greater than 2000 meters (6,560 feet), we had 19 as of December 31, 2011, and we expect to have 33 by 2013.

More specifically, we have entered into long-term contracts for 16 drilling rigs to engage in deepwater exploration and production development of our offshore fields in Brazil in 2012 and 2013. Of these 16 rigs, one will be capable of operating in water depths of up to 1,500 meters (4,621 feet), and 15 will be capable of drilling in water deeper than 2,000 meters (6,562 feet). All of these rigs will be chartered by us and have been built or are being built in shipyards outside of Brazil. Of the 19 drilling rigs that we had capable of drilling in water depths greater than 2,000 meters (6,562 feet) as of December 31, 2011, two have contracts that expire by 2013.

In addition to these 16 new drilling rigs, we have also announced plans for 33 rigs to be built in Brazil to meet our long-term needs, including satisfying Brazilian local content requirements arising out of the Assignment Agreement and existing concession agreements. To this end, we have awarded contracts for seven drilling rigs to be built by Sete Brasil S.A. (Sete BR), a Brazilian company in which we hold a 10% interest. We are currently negotiating contracts for an additional 21 drilling rigs to be built by Sete BR and five drilling rigs to be built by Ocean Rig UDW Inc. (Ocean Rig). We expect to fulfill our future drilling requirements with a combination of rigs built in Brazil, supplemented when needed by the international fleet of deepwater rigs.

Drilling Units in Use by Exploration and Production on December 31 of Each Year
	2011		2010		2009
	Leased	Owned	Leased	Owned	Leased	Owned
Onshore	17	11	22	12	31	13
Offshore, by water depth (WD)	54	8	44	8	36	8
Jack-up rigs	1	4	1	4	2	4
Floating rigs:	53	4	43	4	34	4
500 to 1000 meters WD	8	2	11	2	9	2
1001 to 2000 meters WD	26	2	19	2	20	2
2001 to 3000 meters WD	19	0	13	0	5	0

Refining, Transportation and Marketing

Refining, Transportation and Marketing Key Statistics
	2011	2010	2009
	(U.S.$ million)
Refining, Transportation and Marketing:
Sales revenues	118,630	97,936	74,381
Income (loss) before income taxes	(8,753)	3,141	10,239
Total assets at December 31	84,330	70,515	50,920
Capital expenditures and investments	16,133	16,198	9,694

We are an integrated company with a dominant market share in our home market. We own and operate 12 refineries in Brazil, with a total net distillation capacity of 2,013 mbbl/d, and are one of the world’s largest refiners. As of December 31, 2011, we operated substantially all of Brazil’s total refining capacity. We supplied almost all of the refined product needs of third-party wholesalers, exporters and petrochemical companies, in addition to the needs of our Distribution segment. We operate a large and complex infrastructure of pipelines and terminals and a shipping fleet to transport oil products and crude oil to domestic and export markets. Most of our refineries are located near our crude oil pipelines, storage facilities, refined product pipelines and major petrochemical facilities, facilitating access to crude oil supplies and end-users.

We also import and export crude oil and oil products. The demand for oil products in Brazil is increasing rapidly, driven primarily by economic growth. Particularly in 2011, we met this incremental growth in demand by increasing imports as our refining capacity was not sufficient to meet the increased demand. This increase in imports increased our cost of sales and decreased our margins in 2011. See Item 5. “Operating and Financial Review and Prospects.” We expect the need for imports to decline in the future as we build additional refining capacity and upgrade our refineries to facilitate the processing of domestically produced crudes.

Our Refining, Transportation and Marketing segment also includes petrochemical operations that add value to the hydrocarbons we produce and meet the needs of the growing Brazilian economy.

We participate in refining, transportation and marketing operations outside of Brazil through our International business segment. See “—International.”

Refining

Our refining capacity in Brazil as of December 31, 2011, was 2,013 mbbl/d and our average throughput during 2011 was 1,862 mbbl/d.

The following table shows the installed capacity of our Brazilian refineries as of December 31, 2011, and the average daily throughputs of our refineries in Brazil and production volumes of principal oil products in 2011, 2010 and 2009.

Capacity and Average Throughput of Refineries
		Crude Distillation Capacity at December 31, 2011	Average Throughput
Name (Alternative Name)	Location	Crude Distillation Capacity at December 31, 2011	2011	2010	2009
		(mbbl/d)	(mbbl/d)
LUBNOR	Fortaleza (CE)	8	7	8	7
RECAP (Capuava)	Capuava (SP)	49	43	36	44
REDUC (Duque de Caxias)	Rio de Janeiro (RJ)	239	254	256	238
REFAP (Alberto Pasqualini)	Canoas (RS)	189	148	145	169
REGAP (Gabriel Passos)	Betim (MG)	151	129	143	140
REMAN (Isaac Sabbá)	Manaus (AM)	46	42	42	41
REPAR (Presidente Getúlio Vargas)	Araucária (PR)	195	193	170	185
REPLAN (Paulínia)	Paulinia (SP)	396	373	316	341
REVAP (Henrique Lage)	São Jose dos Campos (SP)	252	240	238	241
RLAM (Landulpho Alves)	Mataripe (BA)	281	233	250	220
RPBC (Presidente Bernardes)	Cubatão (SP)	172	166	160	165
RPCC (Potiguar Clara Camarão)	Guamaré (RN)	35	34	33
Total		2,013	1,862	1,798	1,791

In recent years, we have made substantial investments in our refinery system for the following purposes:

· Improve gasoline and diesel quality to comply with stricter environmental regulations;

· Increase crude slate flexibility to process more Brazilian crude, taking advantage of light/heavy crude price differentials;

· Increase residuum conversion; and

· Reduce the environmental impact of our refining operations.

In 2011, we invested a total of U.S.$5,613.75 million in our refineries, of which U.S.$2,108.89 million was invested for hydrotreating units to improve the quality of our diesel and gasoline and U.S.$1,039.19 million for coking units to convert heavy oil into lighter products. In 2011, as a result of investments that allowed for more flexibility in our refineries, we reduced the need for additional imports of middle distillates by 23 million barrels (or 63 mbbl/d).

During 2012, we expect to complete the following investment projects at our refineries:

· Diesel quality upgrades at REPAR, REGAP and RLAM;

· Gasoline quality upgrades at REPAR, REPLAN, REFAP, RPBC, REVAP, RLAM and RECAP; and

· Delayed coking units at REPAR.

The following refinery upgrades are underway for expected completion between 2013 and 2014:

· Diesel quality upgrades at REGAP, REDUC, REPLAN and RPBC;

· Gasoline quality upgrades at REPLAN; and

· Delayed coking units at REPAR.

The following refinery upgrade projects are scheduled for completion after 2014:

· Diesel quality upgrades at REDUC; and

· Mild thermal cracking units to improve diesel and quality upgrades for diesel and gasoline at REMAN.

By the end of 2013, we will reduce the maximum sulfur content of the diesel produced in our refineries from 1800 ppm to 500 ppm, and nine of our refineries (RLAM, REGAP, REDUC, REPLAN, RPBC, RECAP, REVAP, REPAR, RNEST) are expected to be able to produce 10 ppm sulfur diesel. By the beginning of 2014, we will reduce the maximum sulfur content of the gasoline produced in our refineries from 1,000 ppm to 50 ppm.

Major Refinery Projects

Brazil has one of the world’s most dynamic economies with above average rates of demand growth for transportation fuels, particularly gasoline, diesel and jet fuel. We are planning capacity expansions to meet the needs of this growing market and add value to our growing volumes of crude oil production in Brazil. We are currently building three new refining facilities:

· Complexo Petroquímico do Rio de Janeiro—Comperj, an integrated refining and petrochemical complex. We broke ground in 2008, and began construction in 2010. The 165 mbbl/d refining operation is scheduled to start up in 2014. A second phase, scheduled for 2018, will increase capacity to 330 mbbl/d and add petrochemicals production.

· Abreu e Lima, a refinery in Northeastern Brazil is designed to process 230 mbbl/d of crude oil to produce 162 mbbl/d of low sulfur diesel (10 ppm) as well as LPG, naphtha, bunker fuel and petroleum coke. We expect operations to come on stream in 2013,in a proposed partnership with Petróleos de Venezuela S.A. (PDVSA), the Venezuelan state oil company.

· Premium I in the State of Maranhão is designed to process 20° API heavy crude oil, maximize production of low sulfur diesel, and also produce LPG, naphtha, low sulfur kerosene, bunker fuel and petroleum coke. This refinery will be built in two phases of 300 mbbl/d each. We broke ground in 2011 and expect operations to come on stream in 2016 (Phase I) and 2019 (Phase II).

We are also in the planning stage for another new refinery in Northeastern Brazil:

· Premium II in the State of Ceará will have a processing capacity of 300 mbbl/d and will follow the same specifications as Premium I. The Premium facilities will be able to reduce costs and achieve efficiencies through simplification and standardization of the projects.

The following tables summarize output of oil products and sales by product in Brazil for the last three years.

Domestic Output of Oil Products: Refining and marketing operations, mbbl/d(3)
	2011	2010	2009
Diesel	745	716	737
Gasoline	395	351	331
Fuel oil	234	243	243
Naphtha	109	133	143
LPG	137	132	135
Jet fuel	93	80	74
Other	183	177	160
Total domestic output of oil products	1,896	1,832	1,823
Installed capacity	2,013	2,007	1,942
Utilization (%)	92	90	92
Domestic crude oil as % of total feedstock processed	82	82	79

(1) Unaudited.

(2) As registered by the ANP.

(3) Output volumes are larger than throughput volumes as a result of gains during the refining process

Domestic Sales Volumes, mbbl/d
	2011	2010	2009
Diesel	880	809	740
Gasoline	489	394	338
Fuel oil	82	100	101
Naphtha	167	167	164
LPG	224	218	210
Jet fuel	101	90	77
Other	188	180	140
Total oil products	2,131	1,958	1,770
Ethanol and other products	86	99	96
Natural gas	304	312	240
Total domestic market	2,521	2,369	2,106
Exports	655	698	707
International sales and other operations	540	581	541
Total international market	1,195	1,279	1,248
Total sales volumes	3,716	3,648	3,354

Delivery Commitments

We sell crude oil through long-term and spot-market contracts. Our long-term contracts specify the delivery of fixed and determinable quantities, subject to a price negotiation with third parties on a delivery-by-delivery basis. We are committed through long-term contracts to deliver a total of approximately 350 mbbl/d in 2012. We believe our domestic proved reserves will be sufficient to allow us to continue to deliver all contracted volumes. For 2012, approximately 68% of our exported crude oil will be committed to meeting our contractual delivery commitments to third parties.

Imports and Exports

We use exports and imports of crude oil and oil products to balance our domestic production and refinery capacity with market needs and optimize our refining margins. Much of the crude oil we produce in Brazil is heavy or intermediate, and we import some light crude to balance the slate for our refineries, which were originally designed to run on lighter imported crude, and export heavier crude that is surplus to our needs.

We import oil products, for which there is insufficient production capacity in our Brazilian refineries. Our imports and exports of oil products depend on production capacity, demand levels and relative pricing in the Brazilian market. The table below shows our exports and imports of crude oil and oil products in 2011, 2010 and 2009:


Exports and Imports of Crude Oil and Oil Products, mbbl/d
	2011	2010	2009
Exports(1)
Crude oil	435	497	478
Fuel oil (including bunker fuel)	173	153	150
Gasoline	3	14	38
Other	41	33	39
Total exports	652	697	705
Imports
Crude oil	362	316	396
Diesel and other distillates	199	177	78
LPG	61	58	45
Gasoline	43	9	0
Naphtha	64	42	25
Other	20	13	3
Total imports	749	615	547

(1) Includes sales made by PifCo to unaffiliated third parties, including sales of oil and oil products purchased internationally.

Logistics and Infrastructure for oil and oil products

We own and operate an extensive network of crude oil and oil products pipelines in Brazil that connect our terminals, refineries and other primary distribution points. On December 31, 2011, our onshore and offshore, crude oil and oil products pipelines extended 15,436 km (9,593 miles). We operate 28 marine storage terminals and 20 other tank farms with nominal aggregate storage capacity of 65 million barrels. Our marine terminals handle an average 10,643 tankers annually. We are working in partnership with other companies to develop and expand Brazil’s ethanol pipeline and logistics network.

Until 1998, we held the monopoly on oil and natural gas pipelines in Brazil and shipping oil products to and from Brazil. The deregulation of the Brazilian oil sector in that year provided for open competition in the construction and operation of pipeline facilities and gave the ANP the power to authorize entities other than Petrobras to transport crude oil, natural gas and oil products. In accordance with this deregulation, we transferred our transportation and storage network and fleet to a separate wholly owned subsidiary, Petrobras Transporte S.A.—Transpetro, to allow third parties to access our excess capacity on a non-discriminatory basis. We enjoy preferred access to the Transpetro network based on our historical usage levels and, in practice, third parties make very limited use of this network.

We operate a fleet of owned and chartered vessels. These provide shuttle services between our producing basins offshore Brazil and the Brazilian mainland, and shipping to other parts of South America and internationally. The fleet includes double-hulled vessels, which operate internationally where required by law, and single-hulled vessels, which operate in South America and Africa only. We are increasing our fleet of owned vessels to replace older vessels, decrease our dependency on chartered vessels and exposure to charter rates tied to the U.S. dollar, and accommodate growing production volumes. Upgrades will include replacing single-hulled tankers with double-hulled vessels and replacing vessels nearing the end of their 25-year useful life. Our long-term strategy continues to focus on the flexibility afforded by operating a combination of owned and chartered vessels.

We plan to take delivery of another 48 new vessels by 2016, all to be built in Brazilian shipyards. We have ongoing contracts with five shipyards for delivery of 40 large oil tankers, bunkering vessels and LPG carriers between 2011 and 2016. We expect to contract an additional eight product tankers in the beginning of 2012. The first product vessel, the MV Celso Furtado, was delivered on November 25, 2011.

The table below shows our operating fleet and vessels under contract as of December 31, 2011.

Owned and Chartered Vessels in Operation and Under Construction Contracts at December 31, 2011
	In Operation		Under Contract/Construction
	Number	Tons Deadweight Capacity	Number	Tons Deadweight Capacity
Owned fleet:
Tankers	44	2,815,719	32	3,440,450
LPG tankers	6	40,171	8	38,600
Anchor Handling Tug Supply (AHTS)	1	2,163	0	0
Floating, Storage and Offloading (FSO)	1	28,903	0	0
Layed-up vessel	3	129,623	0	0
Total	55	3,016,579	40	3,479,050
Chartered vessels:
Tankers	174	16,260,464	0	0
LPG tankers	12	225,744	0	0
Total	186	16,486,208	0	0

Petrochemicals

Our petrochemicals operations provide an outlet for our growing production volumes of gas and other refined products, which increases our value added and provides domestic sources for products that would otherwise be imported. Our strategy is to increase domestic production of basic petrochemicals and engage in second generation and biopolymer activities through investments in companies in Brazil and abroad, capturing synergies within all our businesses.

In the past, the Brazilian petrochemicals industry was fragmented, with a large number of small companies that were not internationally competitive. We participated in consolidating and restructuring the Brazilian petrochemicals industry in a series of mergers and capital subscriptions, creating Brazil’s largest petrochemicals company – Braskem S.A. (Braskem) – a publically traded company in which we hold a 36.1% interest. Braskem operates 35 petrochemical plants, produces basic petrochemical and plastics and conducts related distribution and waste processing operations.

The table below sets forth the primary production capacities of Braskem as of December 31, 2011:

Braskem: Nominal Capacity by Petrochemical Type
	(mmt/y)
Braskem
Ethylene	3.95
Propylene	1.54
Polyethylene	3.24
Polypropylene	3.97
PVC	0.51
Cumene	0.32

On April 1, 2011, we announced the acquisition of Innova S.A., which produces, among other products, styrene, polystyrene and ethylbenzene.

We have three new petrochemical projects under construction or in various stages of engineering or design:

· Complexo Petroquímico do Rio de Janeiro—Comperj: In the second phase of Comperj, scheduled for 2018, we have plans to develop a petrochemicals complex to be integrated with the Comperj refinery to produce materials for the plastics industry;

· PetroquímicaSuape Complex in Pernambuco: to produce purified terephthalic acid (PTA), polyethylene terephthalate (PET) resin, and polymer and polyester filament textiles; and

· Companhia de Coque Calcinado de Petróleo—Coquepar: calcined petroleum coke plant in the State of Paraná, with a capacity of 0.35 million t/y.

Distribution

Distribution Key Statistics
	2011	2010	2009
	(U.S.$ million)
Distribution:
Sales revenues	44,001	37,282	29,652
Income (loss) before income taxes	1,134	1,081	914
Total assets at December 31	7,885	7,384	6,304
Capital expenditures and investments	679	515	331

We are Brazil’s leading oil products distributor, operating through our own retail network, through our own wholesale channels, and by supplying other fuel wholesalers and retailers. Our Distribution segment sells oil products that are primarily produced by our Refining, Transportation and Marketing segment (RTM), and works to expand the domestic market for these oil products and for other fuels, including LPG, ethanol and biodiesel.

The primary focus of our Distribution segment is to:

· Lead the market in the domestic distribution of oil products and biofuels, increasing our market share and profit through an integrated supply chain; and

· Be the preferred brand of our consumers while upholding and promoting social and environmental responsibility.

We supply and operate Petrobras Distribuidora S.A.—BR, which accounts for 39.2% of the total Brazilian retail and wholesale distribution market. BR distributes oil products, ethanol and biodiesel, and vehicular natural gas to retail, commercial and industrial customers. In 2011, BR sold the equivalent of 846.1 mbbl/d of oil products and other fuels to wholesale and retail customers, of which the largest portion (44.1%) was diesel.

At December 31, 2011, our BR branded service station network was Brazil’s leading retail marketer, with 7,485 service stations, or 19.2% of the stations in Brazil. BR-owned and franchised stations make up 31.9% of Brazil’s retail sales of diesel, gasoline, ethanol, vehicular natural gas and lubricants.

Most BR stations are owned by franchisees that use the BR brand name under license and purchase exclusively from us; we also provide franchisees with technical support, training and advertising. We own 723 of the BR stations and are required by law to subcontract the operation of these owned stations to third parties. We believe that our market share position is supported by a strong BR brand image and by the remodeling of service stations and addition of lubrication centers and convenience stores.

Our wholesale distribution of oil products and biofuels under the BR brand to commercial and industrial customers accounts for 55.4% of the total Brazilian wholesale market. Our customers include aviation, transportation and industrial companies, as well as utilities and government entities.

We also sell oil products produced by RTM to other retailers and to wholesalers.

Our LPG distribution business, Liquigas Distribuidora, held a 22.8% market share and ranked second in LPG sales in Brazil in 2011, according to the ANP.

Oil products sales in Brazil increased 3.4% in 2011 compared to 2010. This increase was due mainly to Brazil’s economic growth and its corresponding growth in household income and consumer credit.

We participate in the retail sector in other South American countries through our International business segment. See “—International.”

Gas and Power

Gas and Power Key Statistics
	2011	2010	2009
	(U.S.$ million)
Gas and Power:
Sales revenues	9,738	8,492	4,923
Income (loss) before income taxes	2,725	990	738
Total assets at December 31	27,645	30,109	24,926
Capital expenditures and investments	2,293	3,964	5,398

For more than two decades, we have been working actively to simultaneously develop Brazil’s natural gas reserves, production, infrastructure and markets. As a result of our efforts, natural gas in 2010 supplied 10.3% of Brazil’s total energy needs, compared to 3.7% in 1998, and is projected to supply 14.2% of Brazil’s total energy needs by 2020, according to Empresa de Pesquisa Energética, a branch of the MME.

In 2011, we supplied, through our own production and imports, 62.8 mmm³/d (2,218.2 mmcf/d). This volume is directed to the market and our refineries, fertilizer operations and gas-fired power plants. The development plans for our Exploration and Production operations are expected to result in substantial increases in gas production from the Espírito Santo and Santos Basins off the Brazilian coast, including from pre-salt reservoirs. We expect domestic gas production to play an increasingly important role in the supply mix, but we will continue to import gas from Bolivia and use LNG imports selectively to provide supplemental supplies, particularly to meet surges in demand from the power sector.

Our Gas and Power segment is responsible for monetizing and delivering the gas produced by our Exploration and Production segment, and gas purchased from other sources, including imported LNG. The segment comprises gas transmission and distribution, LNG regasification, the manufacture of nitrogen-based fertilizers, gas-fired power generation, and power generation from renewable sources, including solar, wind and small-scale hydroelectric.

The primary focus on our Gas and Power segment is to:

· Add value by monetizing Petrobras’ natural gas resources;

· Assure flexibility and reliability in the commercialization of natural gas;

· Expand the use of LNG to meet Brazilian gas demand and diversify our supply of natural gas;

· Optimize our thermoelectric power plant portfolio and supplement it with power generation from renewables; and

· Create an additional flexible means of monetizing our natural gas resources by investing in capacity to manufacture nitrogen fertilizers.

Natural Gas

Natural gas consumption in Brazil by industrial, commercial and retail customers increased 7% in 2011 compared to 2010. This increase was due mainly to Brazil’s economic growth and more flexible contractual forms. Natural gas consumption in the power generation industry decreased 34% from 2010 to 2011 due to favorable rainfall, which improved the reservoir storage levels of Brazilian hydroelectric power plants. Natural gas consumption by refineries and fertilizer plants increased 18%.

We hold interests ranging from 24% to 100% in 21 of Brazil’s 27 local gas distribution companies. In particular, we acquired a 100% interest in Gas Brasiliano Distribuidora S.A., granting us access to São Paulo, the largest natural gas market in Brazil. We had approximately a 25% net equity interest in the combined 47.6 mmm³/d (1,682 mmcf/d) of natural gas distributed by Brazil’s local distribution companies in 2011.

According to our estimates, our two most significant holdings, CEG Rio and Bahiagás, are Brazil’s third and fourth largest gas distributors. These companies, together with independent distributors Comgás and CEG supply 59% of the Brazilian market.

Principal Natural Gas Local Distribution Holdings
Name	State	Group Share %	Average Gas Sales in 2011 (mmm³/d)	Customers

CEG RIO	Rio de Janeiro	37.41	4,307	28,082
BAHIAGAS	Bahia	41.50	3,843	8,571
PETROBRAS DISTRIBUIDORA	Espírito Santo	100.0	2,942	24,295
GASMIG	Minas Gerais	40.00	2,919	405

The table below shows the sources of our natural gas supply, our sales and internal consumption of natural gas, and revenues in our local gas distribution operations for each of the past three years.

Supply and Sales of Natural Gas in Brazil, mmm³/d
	2011	2010	2009
Sources of natural gas supply
Domestic production	34.1	28.6	23.0
Imported from Bolivia	27.1	27.1	22.4
LNG	1.6	7.6	0.7
Total natural gas supply	62.8	63.3	46.1
Sales of natural gas
Sales to local gas distribution companies(1)	39.8	37.2	32.4
Sales to gas-fired power plants	8.2	12.2	4.1
Total sales of natural gas	48.0	49.4	36.5
Internal consumption (refineries, fertilizer and gas-fired power plants)(2)	14.8	13.9	9.6
Revenues (U.S.$ billion)(3)	5.9	4.7	3.5

________________________

(1) Includes sales to local gas distribution companies in which we have an equity interest.

(2) Includes gas used in the transport system.

(3) Excludes internal consumption.

Long-Term Natural Gas Commitments

When we began investment in the Bolivia-Brazil pipeline in 1996, we entered into long-term contracts with three companies:

· Gas Supply Agreement (GSA) with the Bolivian state-owned company Yacimientos Petrolíferos Fiscales Bolivianos (YPFB), to purchase certain minimum volumes of natural gas at prices linked to the international fuel oil price through 2019, after which the agreement may be extended until all contracted volume has been delivered. On December 18, 2009, Petrobras and YPFB signed the fourth amendment to the GSA, which provides for additional payments to YPFB for liquids contained in the natural gas purchased by Petrobras through the GSA, of between U.S.$100 million and U.S.$180 million per year, retroactive to May 2007. As of February 2010, Petrobras has paid all obligations owed for 2007. Additional payments for subsequent years will only be paid with the fulfillment by YPFB of conditions precedent established in the amendment. For the remaining contractual period of the GSA, Petrobras considers that the fulfillment of such conditions precedent is unachievable. Accordingly, such payment obligations have not been considered in our contractual GSA obligations forecast;

· Ship-or-Pay agreement with Gás Transboliviano (GTB), owner and operator of the Bolivian portion of the pipeline to transport certain minimum volumes of natural gas through 2019; and

· Ship-or-Pay agreement with Transportadora Brasileira Gasoduto Bolivia-Brasil (TBG), owner and operator of the Brazilian portion of the pipeline to transport certain minimum volumes of natural gas through 2019.

Our volume obligations under the ship-or-pay arrangements were generally designed to match our gas purchase obligations under the GSA. The tables below show our contractual commitments under these agreements for the five-year period from 2012 through 2016.

Commitments to Purchase and Transport Natural Gas in Connection with Bolivia-Brazil Pipeline
	2012	2013	2014	2015	2016
Purchase commitments to YPFB
Volume obligation (mmm³/d)(1)	24.06	24.06	24.06	24.06	24.06
Volume obligation (mmcf/d)(1)	850.00	850.00	850.00	850.00	850.00
Brent crude oil projection (U.S.$)(2)	80.0	80.0	80.0	80.0	75.0
Estimated payments (U.S.$ million)(3)	2,391.9	2,012.3	1,981.9	1,975.1	1,906.3
Ship-or-pay contract with GTB
Volume commitment (mmm³/d)	30.00	30.00	30.00	30.00	30.00
Volume commitment (mmcf/d)	1,059.00	1,059.00	1,059.00	1,059.00	1,059.00
Estimated payments (U.S.$ million)(5)	137.78	138.46	139.14	139.82	140.51
Ship-or-pay contract with TBG
Volume commitment (mmm³/d)(4)	35.28	35.28	35.28	35.28	35.28
Volume commitment (mmcf/d)	1,246.09	1,246.09	1,246.09	1,246.09	1,246.09
Estimated payments (U.S.$ million)(5)	501.32	510.42	526.34	526.87	527.40

(1) 25.3% of contracted volume supplied by Petrobras Bolivia.

(2) Brent price forecast based on our 2020 Strategic Plan.

(3) Estimated payments are calculated using gas prices expected for each year based on our Brent price forecast. Gas prices may be adjusted in the future based on contract clauses and amounts of natural gas purchased by Petrobras may vary annually.

(4) Includes ship-or-pay contracts relating to TBG’s capacity increase.

(5) Amounts calculated based on current prices defined in natural gas transport contracts.

Gas Sales Contracts

In recent years, we introduced a variety of supply contracts designed to create flexibility in matching customer demand with our gas supply capabilities. These include flexible and interruptible long-term gas supply contracts, auction mechanisms for short-term contracts and weekly electronic auctions.

In 2011, a new gas sale contract – a seller delivery option aiming to help balance natural gas supply and demand – was introduced by us. Whenever there is a low dispatch of natural gas from gas-fired power plants, the excess natural gas volumes are offered to end consumers who ordinarily use energy sources other than natural gas. In this context, prices of gas are a function of the alternative energy source that is being replaced. Existing long-term natural gas sales contracts were also renegotiated in 2011 with local distribution company (LDCs) of natural gas in order to promote adjustments tailored to specific market demands. These negotiations encompassed term extensions for some contracts, prolonging our natural gas procurement portfolio. We continued offering contracts for short-term volumes (for both weekly and four-month periods) through electronic auctions.

The table below shows our future gas supply commitments from 2012 to 2016, including sales to both local gas distribution companies and gas-fired power plants.

Future Commitments under Natural Gas Sales Contracts, mmm³/d
	2012	2013	2014	2015	2016
To local gas distribution companies:
Related parties(1)	19.68	20.86	21.88	21.02	21.54
Third parties	17.32	17.05	16.83	16.83	16.83
To gas-fired power plants:
Related parties(1)	4.46	3.27	3.15	3.13	3.12
Third parties	5.93	7.30	8.06	7.92	7.78
Total(2)	47.39	48.48	49.92	48.90	49.27
Estimated contract revenues (U.S.$ billion)(3)(4)	6.3	6.5	6.6	6.5	6.5

(1) For purposes of this table, “related parties” include all local gas distribution companies and power generation plants in which we have an equity interest and “third parties” refer to those in which we do not have an equity interest.

(2) Estimated volumes are based on “take or pay” agreements in our contracts, expected volumes and contracts under negotiation (including renewals of existing contracts), not maximum sales.

(3) Figures show revenues net of taxes. Estimates are based on outside sales and do not include internal consumption or transfers.

(4) Prices may be adjusted in the future and actual amounts may vary.

Short-Term Natural Gas Commitments

In 2009, we contributed to the development of a short-term market for natural gas sales, focusing on the industrial market as an alternative to the market for power generation when the power plants are not being dispatched. Sales under these short-term contracts were accomplished by an electronic auction system conducted by means of the Internet. These auctions commercialized natural gas volumes reserved for but not otherwise utilized by local gas distributors, and allowed us to offer end users more competitive prices. On average, 4.4 mmm³/d of natural gas were sold under these short-term contracts in 2009, with volumes reaching 7.8 mmm³/d in 2010 and 6.7 mmm³/d in 2011. The last auction resulted in a sales record of 8.8 mmm³/d for a four-month delivery period.

In April 2010, we implemented a new method for selling short-term natural gas. On a weekly basis, we offer for sale to the non-thermoelectric market volumes of natural gas that had been originally reserved for gas-fired power plants but that were not dispatched. Under this method, weekly sales begin with orders from gas distribution companies for deliveries to be made within the subsequent four-week period. Depending on the availability and cost of natural gas during that period, we have the option of either accepting or rejecting the orders. This new method allowed us to sell an average of 348,000 m³/d of natural gas in 2010 and 70,000 m³/d of natural gas in 2011, with a sales record of 500,000 m³/d in December 2011.

Fertilizers

We are expanding production of nitrogenous fertilizers in order to meet the growing needs of Brazilian agriculture, to substitute for imports, and to expand the market for natural gas.

Our fertilizer plants in Bahia and Sergipe produce ammonia and urea for the Brazilian market. In 2011, these plants sold a combined 240,665 t of ammonia and 831,642 t of urea.

Nitrogenous Sales (ton)
	2010	2011	%
Ammonia	235,739	240,665	+2.1
Urea	772,059	831,642	+7.7

We are also expanding production of nitrogenous fertilizers. To this end, we are conducting feasibility studies for four additional facilities:

• UFN III, with the ability to sell 1.22 million t/y of urea and 70 million t/y of ammonia from 2.2 mmm³/d of natural gas, expected to start up in September 2014;

• UFN IV, with the ability to sell 755,000 t/y of urea and 721,000 t/y of methanol from 3.5 mmm³/d of natural gas, expected to start up in June 2017. 42,000 t/y of melamine will be produced from the foregoing quantity of urea, and 211,000 t/y of acetic acid and 26,000 t/y of formic acid will be produced from the foregoing quantity of methanol;

• UFN V, with the ability to sell 519,000 t/y of ammonia from 1.3 mmm³/d of natural gas, expected to start up in September 2015; and

• Sergipe, with the ability to sell 303,000 t/y of ammonium sulfate from 226 t/d of ammonia, expected to start up in May 2013.

These facilities would reduce Brazil’s deficit in these fertilizers while increasing the demand for our natural gas produced offshore.

Power

To further our goal of developing natural gas demand in Brazil, we have invested in power plants and the associated system of gas supply contracts. These plants are designed to supplement power from the hydroelectric stations that supply an average of 90% of the country’s electric power needs in a given year. Gas-fired power is particularly needed during times of peak demand, high economic growth, and drought.

We own interests in 28 thermoelectric power plants with a combined installed capacity at year-end 2011 of 6,385 MW, equivalent to 73% of Brazil’s total thermoelectric gas capacity. Of this total, 6,009 MW was in thermoelectric plants controlled by us and 97% (or 5,806 MW) was in the Sistema Interligado Nacional—SIN (National Interconnected Power Grid).

Under Brazil’s power pricing regime, we may sell only power-generating capacity that is certified by the MME. At year-end 2011, due to gas supply constraints, the MME certified 3,776 MWavg of commercial capacity, or 65% of the installed capacity controlled by us in the SIN.

In 2011, the Brazilian hydroelectric system generated 51,397 MWavg of electricity, or 90% of the country’s needs. The SIN was called upon to supplement this power with an average 4,971 MW, of which we generated an average 653 MW of electricity in 2011, compared to 1,837 MW in 2010.

We also export energy to neighboring countries. In 2011, we exported 113 MWavg to Argentina and Uruguay compared to 110.2 MWavg in 2010.

Commitments for Future Generation Capacity and Electricity Sales

Under a 2007 agreement with the ANEEL, we are committed to increasing our ability to supply power to the grid by increasing natural gas supplies, including LNG, converting some existing power plants to dual-fuel operation and leasing backup oil-fired power plants. By 2012, we are committed to supply up to 5,938 MW of installed capacity and expect to have an average 3,970 MW certified capacity available for sale, exclusive of our own power requirements.

The table below shows the installed capacity and commercial capacity of the thermoelectric power plants controlled by us for 2011 through 2014 under our agreement with the ANEEL:

Installed Power Capacity and Utilization
	2011	2012(2)	2013	2014
Gross installed capacity (MW)	5,609	5,938	5,537	5,855
Certified commercial capacity(1) (MWavg)	3,776	3,970	3,826	4,084

(1) Weighted average of certified commercial capacity for the year.

(2) Our installed and commercial capacity will be reduced in 2013 due to the termination of our lease of the Araucaria thermoelectric power plant.

In 2011, we invested U.S.$359.9 million (R$599.9 million) in thermoelectric generation.

We sell our power output under long-term contracts for “standby availability” and long-term bilateral contracts, primarily with power distribution companies. Of the total 4,172 MWavg of power available for sale in 2012 (including the certified commercial capacity of our plants and 202 MWavg of power purchased from third parties), approximately 46% has already been sold as standby availability in the 2005 and 2006 auctions, and approximately 54% has been committed under bilateral contracts. We also have the option to fulfill our contractual commitments by purchasing power from third parties.

In the 2005 and 2006 auctions, we sold standby availability of 1,391 and 205 MWavg, respectively, on 15-year contracts beginning in 2008 to 2011. This represented most of our capacity that is eligible to be sold through the auction system. Under the terms of these contracts, we will be compensated a fixed amount whether or not we generate any power. Additionally, we receive an extra amount for the energy we actually generate at a price that is set on the date of the auction and revised annually based on an inflation-adjusted fuel oil basket. We have been compensated for the standby availability from the 2005 and 2006 auctions since 2008, with the capacity compensation stepping up through 2011, at which time it stabilizes.

In addition, in the new energy auction (Leilão de Energia Nova) held on August 17, 2011, we committed to selling 416.4 MWavg from our Baixada Fluminense plant for the period of March 2014 through December 2033.

Our future commitments under bilateral contracts are 1,899 MWavg in 2012, 1,590 MWavg in 2013 and 1,604 MWavg in 2014. The agreements will run off gradually, with the last contract expiring in 2028. As existing bilateral contracts run-off, we will sell our remaining certified power-generation capacity under short- and medium-term bilateral contracts and auctions conducted by us and by the MME.

The following table summarizes our commitments under standby availability and bilateral contracts, power purchased from third parties, and the power we expect to be available for sale.

Power Available for Sale and Power Commitments
	2010	2011	2012	2013	2014
	(MWavg)
Total available for sale:
Commercial capacity (MW)(1)	3,619	3,776	3,970	3,826	4,084
Purchased from third parties	234	214	202	200	200
Commitments:
Standby availability auctions	1,391	1,596	1,596	1,596	1,847
Bilateral contracts	2,442	2,394	1,899	1,590	1,604
Remaining available for sale (1)(2)	20	0	677	840	833

(1) Projections based on existing capacity and expected supply of gas.

(2) Represents the remaining commercial capacity available for sale beginning in 2011.

Renewable Energy

We have invested, alone and in partnership with other companies, in renewable power generation sources in Brazil including wind and small hydroelectric plants. Our net interests are equivalent to 316.5 MW of hydroelectric capacity and 105.8 MW of wind capacity. We and our partners sell energy from these plants directly to the Brazilian federal government via “reserve energy” auctions.

International

International Key Statistics
	2011	2010	2009
	(U.S.$ million)
International:
Sales revenues	16,956	13,519	10,239
Income (loss) before income taxes	2,117	1,053	207
Total assets at December 31	19,427	16,958	15,293
Capital expenditures and investments	2,631	2,712	3,436

We have operations in 24 countries outside of Brazil, encompassing all phases of the energy business. The primary focus of our international operations is to:

· Use our technical expertise in deepwater exploration and production to participate in high-potential and frontier offshore regions; and

· Integrate international downstream operations aligned with our domestic activities.

International Upstream Activities

Most of our international activities are in exploration and production of oil and gas. We have long been active in Latin America. In the Gulf of Mexico and West Africa, we focus on opportunities to leverage the deepwater expertise we have developed in Brazil. We have preliminary exploratory efforts underway in other regions.

In 2011, our net production outside Brazil averaged 144.88 mbbl/d of crude oil and NGLs and 16.54 mmm³/d (584.01 mmcf/d) of natural gas, representing 9.8% of our total production on a barrels of oil equivalent basis.


TABLE OF CONTENTS (cont.)
		Page

Fiscal Council		121
Petrobras Audit Committee		122
Other Advisory Committees		122
Petrobras Ombudsman		122
PifCo Advisory Committees		123
Employees and Labor Relations		123
Item 7.	Major Shareholders and Related Party Transactions	125
Major Shareholders		125
PifCo Related Party Transactions		127
Item 8.	Financial Information	129
Petrobras Consolidated Statements and Other Financial Information		129
PifCo Consolidated Statements and Other Financial Information		129
Legal Proceedings		129
Dividend Distribution		129
Item 9.	The Offer and Listing	130
Petrobras		130
PifCo		131
Item 10.	Additional Information	132
Memorandum and Articles of Incorporation of Petrobras		132
Restrictions on Non-Brazilian Holders		141
Transfer of Control		141
Disclosure of Shareholder Ownership		141
Memorandum and Articles of Association of PifCo		141
Material Contracts		145
Petrobras Exchange Controls		152
Taxation Relating to Our ADSs and Common and Preferred Shares		154
Taxation Relating to PifCo’s Notes		162
Documents on Display		166
Item 11.	Qualitative and Quantitative Disclosures about Market Risk	166
Petrobras		166
PifCo		169
Item 12.	Description of Securities other than Equity Securities	171
American Depositary Shares		171
PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies	172
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	172
Item 15.	Controls and Procedures	172
Evaluation of Disclosure Controls and Procedures		172
Management’s Report on Internal Control over Financial Reporting		173
Changes in Internal Controls		173
Item 16A.	Audit Committee Financial Expert	173
Item 16B.	Code of Ethics	174
Item 16C.	Principal Accountant Fees and Services	174
Audit and Non-Audit Fees		174
Audit Committee Approval Policies and Procedures		175
Item 16D.	Exemptions from the Listing Standards for Audit Committees	176
Audit Committee Approval Policies and Procedures		176
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	176
Item 16F.	Change in Registrant’s Certifying Accountant	176
Item 16G.	Corporate Governance	176
PART III
Item 17.	Financial Statements	179
Item 18.	Financial Statements	179


TABLE OF CONTENTS (cont.)
	Page

Item 19. Exhibits	179
Signatures	185
Index to Audited Consolidated Financial Statements Petróleo Brasileiro S.A.—Petrobras	187
Index to Audited Consolidated Financial Statements Petrobras International Finance Company	187

Countries		Main International Exploration and Production Assets in Development
Countries		Main projects in development	Phase	Operated by	Petrobras interest (%)
South America
1	Argentina(1)	Sierra Chata El Tordillo Santa Cruz I Oeste 25 de Mayo – Medanito Rio Neuquen Santa Cruz I El Mangrullo<


TABLE OF CONTENTS
		Page

Forward-Looking Statements		4
Glossary of Petroleum Industry Terms		6
Conversion Table		8
Abbreviations		9
Presentation of Financial Information		10
Petrobras		10
PifCo		11
Presentation of Information Concerning Reserves		11
PART I
Item 1.	Identity of Directors, Senior Management and Advisers	12
Item 2.	Offer Statistics and Expected Timetable	12
Item 3.	Key Information	12
Selected Financial Data		12
Risk Factors		16
Item 4.	Information on the Company	26
History and Development		26
Overview of the Group		26
Exploration and Production		28
Refining, Transportation and Marketing		37
Distribution		43
Gas and Power		44
International		51
Biofuels		56
Corporate		57
Information on PifCo		57
Organizational Structure		58
Property, Plants and Equipment		60
Regulation of the Oil and Gas Industry in Brazil		60
Health, Safety and Environmental Initiatives		64
Insurance		67
Additional Reserves and Production Information		68
Item 4A.	Unresolved Staff Comments	77
Item 5.	Operating and Financial Review and Prospects	77
Management’s Discussion and Analysis of Petrobras’ Financial Condition and Results of Operations		77
Overview		79
Sales Volumes and Prices		80
Effect of Taxes on Our Income		81
Inflation and Exchange Rate Variation		82
Results of Operations		83
Additional Business Segment Information		95
Management’s Discussion and Analysis of PifCo’s Financial Condition and Results of Operations		96
Liquidity and Capital Resources		99
Petrobras		99
PifCo		103
Contractual Obligations		106
Petrobras		106
PifCo		106
Critical Accounting Policies and Estimates		107
Research and Development		109
Trends		111
Item 6.	Directors, Senior Management and Employees	112
Directors and Senior Management		112
Compensation		120
Share Ownership		121