pbraform20f_2012.htm - Generated by SEC Publisher for SEC Filing

As filed with the Securities and Exchange Commission on April 26, 2013

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, 2012

Commission File Number 001-15106 Petróleo Brasileiro S.A.—Petrobras (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)

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)

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

3.25% Global Notes due 2019, issued by PGF

5.875% Global Notes due 2022, issued by PifCo

4.25% Global Notes due 2023, issued by PGF

6.250% Global Notes due 2026, issued by PifCo

5.375% Global Notes due 2029, issued by PGF

The number of outstanding shares of each class of stock as of December 31, 2012 was:

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

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

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

Yes þ 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 þ

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 þ 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 þ 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 þ Accelerated filer ¨ Non-accelerated filer ¨

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 þ

FORWARD-LOOKING STATEMENTS

Some of the information contained in this annual report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or 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 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;

· global economic conditions;

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

· 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;

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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.
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.
CVM	The Comissão de Valores Mobiliários (Securities and Exchange Commission) of Brazil.
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 productibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to December 31, 2012, 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.

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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)

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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
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
mm³/y	Thousand cubic meter per year
mmbbl	Million barrels
mmbbl/d	Million barrels per day
mmboe	Million barrels of oil equivalent
mmcf	Million cubic feet
mmcf/d	Million cubic feet per day
mmm³	Million cubic meters
mmm³/d	Million cubic meters per day
mmt	Million metric tons
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

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PRESENTATION OF FINANCIAL AND OTHER INFORMATION

This is the annual report of Petróleo Brasileiro S.A.—Petrobras, or Petrobras. Unless the context otherwise requires, the terms “Petrobras,” “we,” “us,” and “our” refer to Petróleo Brasileiro S.A.—Petrobras and its consolidated subsidiaries and special purpose entities.

We issue notes in the capital markets through our wholly-owned finance subsidiaries Petrobras International Finance Company, or PifCo, a Cayman Islands company, and Petrobras Global Finance B.V., or PGF, a Dutch company. We fully and unconditionally guarantee the notes issued by PGF and PifCo. PGF is not required to file periodic reports with the Securities and Exchange Commission, or SEC, and PifCo no longer has an obligation to file periodic reports with the SEC. See Note 35 to our audited consolidated financial statements. The last 20-F filed by PifCo with the SEC in connection with the year ended December 31, 2011 was filed on April 2, 2012, as amended on July 9, 2012.

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.

The audited consolidated financial statements of Petrobras and our consolidated subsidiaries as of and for each of the three years ended December 31, 2012, 2011 and 2010 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, or IFRS, issued by the International Accounting Standards Board, or IASB. See Item 5. “Operating and Financial Review and Prospects” and Note 2 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.

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. The functional currency of Petrobras and all Brazilian subsidiaries is the Brazilian real; the functional currency of PifCo, PGF and certain subsidiaries and special purpose entities that operate in the international economic environment is the U.S. dollar; and the functional currency of Petrobras Argentina is the Argentine peso. As described more fully in Note 2.3 to our audited consolidated financial statements, the U.S. dollar amounts for the periods presented have been translated from the Brazilian real amounts in accordance with the criteria set forth in IAS 21 – “The effects of changes in foreign exchange rates.” Based on IAS 21, we have translated all assets and liabilities into U.S. dollars at the exchange rate as of the date of the balance sheet and all accounts in the statement of income and statement of cash flows at the average rates prevailing during the year.

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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 2013-2017 Business and Management Plan, and have been projected on a constant basis and have been translated from reais at an estimated average exchange rate of R$2.00 to U.S.$1.00 in 2013, and the reais strengthening against the U.S. dollar to R$1.85 in the long term, in accordance with our 2013-2017 Business and Management Plan. In addition, in accordance with our 2013-2017 Business and Management Plan, future calculations involving an assumed price of crude oil have been calculated using a Brent crude oil price of U.S.$107.00 for 2013, declining to U.S.$100.00 in the long term, 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.

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, 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 93% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2012 from certain properties we own in Brazil. In addition, D&M used its own estimates of our reserves to conduct a reserves evaluation of 100% of the net proved crude oil, condensate, NGL and natural gas reserves as of December 31, 2012 from the properties we operate in Argentina. Furthermore, D&M used our reserves estimates to conduct a reserves audit of 98% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2012 from certain properties we operate in North and South America (other than Brazil and Argentina). 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 15, 2013, we filed reserve estimates for Brazil with the ANP, in accordance with Brazilian rules and regulations, totaling net volumes of 13.3 billion barrels of crude oil and condensate and 14.7 trillion cubic feet of natural gas. The reserve estimates filed with the ANP and those provided herein differ by approximately 22% 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.

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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

IFRS Summary Financial Data

	As of December 31,
	2012	2011	2010	2009
	(U.S.$ million)
Assets:
Cash and cash equivalents	13,520	19,057	17,655	16,222
Marketable securities	10,431	8,961	15,612	77
Trade and other receivables, net	11,099	11,756	10,845	8,147
Inventories	14,552	15,165	11,808	11,103
Other current assets	8,192	9,653	7,639	6,629
Long-term receivables	23,105	22,462	22,637	19,991
Investments	6,106	6,530	6,957	4,620
Property, plant and equipment	204,901	182,918	168,104	128,754
Intangible assets	39,739	43,412	48,937	3,899
Total assets	331,645	319,914	310,194	199,442
Liabilities and shareholders’ equity:
Total current liabilities	34,070	36,364	33,577	31,067
Non-current liabilities(1)	40,052	33,722	30,251	23,809
Long-term debt(2)	88,484	72,718	60,417	48,963
Total liabilities	162,606	142,804	124,245	103,839
Shareholders’ equity
Share capital	107,362	107,355	107,341	33,790
Reserves and other comprehensive income	60,525	68,483	76,769	60,579
Petrobras’ shareholders’ equity	167,887	175,838	184,110	94,369
Non-controlling interests	1,152	1,272	1,839	1,234
Total equity	169,039	177,110	185,949	95,603
Total liabilities and shareholders’ equity	331,645	319,914	310,194	199,442

(1) Excludes long-term debt.

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

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INCOME STATEMENT DATA

IFRS Summary Financial Data

	For the Year Ended December 31,
	2012	2011	2010	2009
	(U.S.$ million, except for share and per share data)
Sales revenues	144,103	145,915	120,452	91,146
Net income before financial results, profit sharing and income taxes	16,900	27,285	26,372	22,923
Net income attributable to the shareholders of Petrobras	11,034	20,121	20,055	15,308
Weighted average number of shares outstanding:
Common	7,442,454,142	7,442,454,142	5,683,061,430	5,073,347,344
Preferred	5,602,042,788	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	1.30	2.09	2.67	2.61
Common and Preferred ADS	2.60	4.18	5.34	5.22
Basic and diluted earnings per:
Common and Preferred Shares	0.85	1.54	2.03	1.74
Common and Preferred ADS	1.70	3.08	4.06	3.48
Cash dividends per:(1)
Common and Preferred shares	0.34	0.53	0.70	0.59
Common and Preferred ADS	0.68	1.06	1.40	1.18

(1) Represents dividends paid during the year.

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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 for oil and oil products are volatile, and have a significant effect on us. We may not adjust our prices for products sold in Brazil when the international prices of crude oil and oil products increases, or when the Real in relation to the U.S. Dollar depreciates, which could have a negative impact on our results of operations.

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 global and regional factors. Volatility and uncertainty in international prices for crude oil, oil products and natural gas may continue. 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.

Our pricing policy in Brazil seeks to align the price of oil products with international prices over the long term, however we do not necessarily adjust our prices for diesel, gasoline and other products to reflect oil price volatility in the international markets or short term movements in the value of the real. Based on the decisions of the Brazilian federal government as our controlling shareholder we have, and may continue to have, periods during which our products will not be at parity with international product prices (See Item 3. “Risk Factors—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 a result, when we are a net importer by volume of oil and oil products to meet the Brazilian demand, increases in the price of crude oil in the international markets may have a negative impact on our costs of sales and margins, since the cost to acquire such oil and oil products may exceed the price at which we are able to sell these products in Brazil. A similar effect occurs when the real depreciates 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 increases our cost of imported oil and oil products, without a corresponding increase in our revenues unless we are able to increase the price at which we sell products in Brazil.

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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 2013-2017 Business and Management 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. 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. 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 2013-2017 Business and Management Plan, we intend to invest U.S.$236.7 billion from 2013 to 2017, U.S.$207.1 billion of which is for projects already under implementation, while U.S.$29.6 billion is for projects that are still under evaluation and subject to final approval by our management. In addition, approximately 19% of our existing debt (principal), or U.S.$17.8 billion, will mature in the next three years. In order to implement our 2013-2017 Business and Management 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 and Management Plan and to roll-over our existing debt in a timely and advantageous manner in order to implement our 2013-2017 Business and Management 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.

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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 subject to future price readjustment.

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 assignment of rights, consisting of exploratory blocks; (2) the volume, on a barrel of oil equivalent basis, that we can extract from this area; (3) the price to be paid for the assignment of rights; (4) the terms of the subsequent revision of the contract price and volume under the Assignment Agreement; and (5) the terms of the reallocation of volumes among the exploratory blocks assigned to us.

This contract includes provisions for a subsequent revision of the contract terms, including the price we paid for the rights we acquired under the Assignment Agreement. The future negotiation with the Brazilian federal government will be conducted in accordance with the terms of the Assignment Agreement and will be based on a number of factors, including the international value of the crude oil at the time of the declaration of commerciality of the relevant pre-salt area. 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 approximately 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—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.

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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 Agência Nacional de Transportes Aquaviários (Brazilian Water Transportation Agency), or ANTAQ and the Agência Nacional de Transportes Terrestres (Brazilian Land Transportation Agency), or ANTT. 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 and delays resulting in decreased production. 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 27 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.

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We are vulnerable to increased financing expenses resulting from depreciation of the real in relation to the U.S. dollar and increases in prevailing market interest rates.

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. In addition, our net liability position in foreign currencies that are subject to monetary valuation has increased over time. As of December 31, 2012, our net liability position in foreign currency increased to approximately U.S.$49,513 million compared to U.S.$29,627 million as of December 31, 2011. In a year as 2012 during which the U.S. dollar appreciated 14.3% in relation to the real, this appreciation resulted in an additional U.S.$3,278 million in finance expense to us from foreign exchange variation of our debt.

As of December 31, 2012, approximately 50% — U.S.$47,889 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.

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.

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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.

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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, or 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 and PGF’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. PGF’s notes are currently only listed on the Luxembourg Stock Exchange and trade on the Euro MTF market. PGF can issue new notes which can be listed in markets other than the Luxembourg Stock Exchange and traded in markets other than the Euro MTF market. We can make no assurance as to the liquidity of or trading markets for PifCo’s notes or PGF’s notes. We cannot guarantee that the holders of PifCo’s notes or PGF’s notes will be able to sell their notes in the future. If a market for PifCo’s notes or PGF’s notes does not develop, holders of PifCo’s notes or PGF’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 Incorporation—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.

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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 do not have the same voting rights as our shareholders. In addition, holders of ADSs representing preferred shares generally do not have voting rights.

Holders of our ADSs do not have the same voting rights as holders of our shares. Holders of our ADSs are entitled to the contractual rights set forth for their benefit under the deposit agreements. ADS holders exercise voting rights by providing instructions to the depositary, as opposed to attending shareholders meetings or voting by other means available to shareholders. In practice, the ability of a holder of ADSs to instruct the depositary as to voting will depend on the timing and procedures for providing instructions to the depositary, either directly or through the holder’s custodian and clearing system.

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—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 or PGF’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 or PGF’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.

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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 or PGF noteholders losing their legal claim against us.

PifCo’s and PGF’s obligation to make payments on the PifCo notes and the PGF notes, respectively, 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 or PGF’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 or the PGF notes would not have a claim against us under the relevant guaranty and will solely have a claim against PifCo or PGF. We cannot assure you that, after providing for all prior claims, there will be sufficient assets to satisfy the claims of the PifCo noteholders or the PGF noteholders relating to any avoided portion of the guaranty.

Holders in some jurisdictions may not receive payment of gross-up amounts for withholding in compliance with the European Council Directive on taxation of savings income.

Austria and Luxembourg have opted out of certain provisions of the European Council Directive regarding taxation of savings income (Directive) and are instead, during a transitional period, applying a withholding tax on payments of interest, at a rate of up to 35%, unless the holder opts for exchange of information as required under the Directive. Neither we nor the paying agent (nor any other person) would be required to pay additional amounts in respect of the notes as a result of the imposition of withholding tax by any member state of the European Union (Member State) or another country or territory which has opted for a withholding system. For more information, see “Taxation—Taxation Relating to PifCo’s and PGF’s Notes—European Union Tax Considerations.” An investor should consult a tax adviser to determine the tax consequences of holding the notes for such investor.

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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, 2012, the Brazilian federal government owned 28.67% of our outstanding capital stock and 50.26% 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. 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. 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, or 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 bnbbl 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 2012, our average domestic daily oil production was 1,980 mbbl/d, an estimated 96.1% of Brazil’s total. Over 73.5% 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 44 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, 2012, we had proved developed oil and gas reserves of 7,543.3 mmboe and proved undeveloped reserves of 4,730.6 mmboe in Brazil. The exploration and development of this large reserve base and the new pre-salt areas granted to us by the Brazilian federal 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 28 drilling rigs and are also making necessary investments in infrastructure.

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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 2,018 mbbl/d is well balanced with our domestic refining throughput of 1,997 mbbl/d and sales of oil products to domestic markets of 2,285 mbbl/d. We are also involved in the production of petrochemicals. We distribute oil products through our own retail network 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 21 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, trading operations, oil products and crude oil exports and imports, as well as petrochemical sector in Brazil;

· Distribution: distribution of oil products, ethanol and vehicle natural gas 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 and the fertilizer business;

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

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

Our Corporate segment comprises activities that cannot be attributed to the other segments, notably those related to corporate financial management, corporate overhead and other expenses, including actuarial expenses related to the pension and medical benefits for retired employees and their dependents.

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The following table sets forth key information for each business segment in 2012:

	Key Information by Business Segment, 2012
	Exploration and Production	Refining, Transportation and Marketing	Gas and Power	Biofuel	Distribution	International	Corporate	Eliminations	Group Total
	(U.S.$ million)
Sales revenues	74,714	116,710	11,803	455	40,712	17,929	‒	(118,220)	144,103
Income (loss) before income taxes	35,465	(17,699)	1,277	(156)	1,386	1,933	(6,999)	(714)	14,493
Total assets at December 31	151,798	91,458	28,454	1,248	8,130	18,735	39,125	(7,303)	331,645
Capital expenditures and investments	21,959	14,745	2,113	147	666	2,572	747	‒	42,949

Exploration and Production

Exploration and Production Key Statistics
	2012	2011	2010
	(U.S.$ million)
Exploration and Production:
Sales revenues	74,714	74,117	54,273
Income (loss) before income taxes	35,465	36,809	25,439
Total assets at December 31	151,798	141,113	136,600
Capital expenditures and investments	21,959	20,405	18,621

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 1,980 mbbl/d in 2012. 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;

· 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;

· Employ new technologies for secondary recovery and increase production efficiency of our older offshore fields and production systems, as well as sustain and increase production from onshore and shallow fields through drilling and enhanced recovery operations;

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

· Develop associated and non-associated gas resources in the Santos Basin and elsewhere (including continued reductions in gas flaring) 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.

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. According to production data from PFC Energy, we operate more production (on a boe basis) from fields in deep and ultra-deep water than any other company. We focus much of our exploration effort on deep water drilling, where the discoveries are substantially larger and our technology and expertise create a competitive advantage.

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In 2012, offshore production accounted for 89% of our production and deep water production accounted for 78% of our production in Brazil. In 2012, we drilled 45 exploratory wells and operated 42 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, also known as the pre-salt province. Our existing contracts in this area cover 26.6% (approximately 39,615 km²or 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 km²or 1.5 million acres) is under concession to other oil companies for exploration. The remaining 69.4% (approximately 103,000 km²or 25.4 million acres) of the pre-salt area 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.

We hold interests ranging from 20% to 100% in the pre-salt exploration areas under concession to us. In the southern part of the Santos Basin, where the salt layer is thick and the hydrocarbons have been more perfectly preserved, we have made several particularly promising discoveries since 2006, including those made in Blocks BM-S-11 (Iara and Lula, formerly Tupi), BM-S-9 (Carioca and Sapinhoá, formerly Guará) and since 2011 in the Assignment Agreement area (Franco, Nordeste de Tupi). In the northern part of the region, we made significant discoveries in 2008 and early 2010 in the area known as Parque das Baleias and in the Barracuda, Albacora, Marlim and Caratinga fields, all of which are in the Campos Basin. As a result, we are committing substantial resources to develop these pre-salt discoveries, which are located in deep and ultra-deep waters and reservoirs at total depths of up to 7,000 meters (22,965 feet).

As of December 31, 2012, we had 117 exploration agreements covering 168 blocks, corresponding to a gross exploratory acreage of 90,708 km² (22 million acres), or a net exploratory acreage of 76,427 km² (19 million acres), and 52 evaluation plans. We are exclusively responsible for conducting the exploration activities in 31 of the 117 exploration agreements. As of December 31, 2012, we had exploration partnerships with 22 foreign and domestic companies. We conduct exploration activities under 47 of our 117 partnership agreements.

In 2012, we invested a total of U.S.$5.97 billion in exploration activities in Brazil. We drilled a total of 137 exploratory wells in 2012, of which 57 were offshore and 80 onshore. Our 2013-2017 Business and Management Plan, which was released on March 15, 2013, foresees capital expenditures and investments in exploration and production activities in Brazil of U.S.$147.5 billion from 2013 to 2017 (not including investments by our partners).

During 2012, our oil and gas production from Brazil averaged 2,205.5 mboe/d, of which 90% was oil and 10% was natural gas. On December 31, 2012, our estimated net proved crude oil and natural gas reserves in Brazil were 12.3 billion boe, of which 85.9% was crude oil and 14.1% was natural gas. Brazil provided 90.4% of our worldwide production in 2012 and accounted for 95.2% of our worldwide reserves at December 31, 2012 on a barrels of oil equivalent basis. Historically, approximately 85% of our total Brazilian production has been oil.

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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)
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
	Barracuda	100%	Deepwater	Intermediate Oil
	Cachalote	100%	Deepwater	Intermediate Oil
	Carapeba	100%	Shallow	Intermediate Oil
	Caratinga	100%	Deepwater	Intermediate Oil
	Cherne	100%	Shallow	Intermediate Oil
	Espadarte	100%	Deepwater	Intermediate Oil
	Jubarte	100%	Deepwater	Heavy Oil
	Marimbá	100%	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
	Pampo	100%	Shallow	Intermediate Oil
	Roncador	100%	Ultra-deepwater	Intermediate Oil
	Tartaruga Mestiça	100%	Shallow	Intermediate Oil
	Vermelho	100%	Shallow	Intermediate Oil
	Voador	100%	Deepwater	Heavy Oil
Espírito Santo	Fazenda Alegre Golfinho	100% 100%	Onshore Deepwater Ultra-deepwater	Heavy Oil Intermediate Oil Intermediate Oil
Potiguar	Canto do Amaro	100%	Onshore	Intermediate Oil/Natural Gas Heavy Oil/Natural Gas
	Estreito	100%	Onshore	Heavy Oil
Recôncavo	Aracas Buaracica	100% 100%	Onshore Onshore	Light Oil Light Oil
Santos	Baúna	100%	Shallow	Light Oil
	Mexilhão	100%	Shallow	Natural Gas
	Lula	65%	Ultra-deepwater	Intermediate Oil
	Piracaba	100%	Shallow	Light Oil
	Uruguá	100%	Deepwater	Intermediate Oil/Natural Gas
Sergipe/Alagoas	Carmópolis	100%	Onshore	Intermediate Oil
	Piranema	100%	Deepwater	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

Our domestic oil and gas exploration and production efforts are primarily focused on four major basins offshore in Brazil: Campos, Espírito Santo, Santos and Sergipe-Alagoas.

Campos Basin

The Campos Basin, which covers approximately 115,000 km² (28.4 million acres), is the most prolific oil and gas basin in Brazil as measured by proved hydrocarbon reserves and annual production. Since we began exploring this area in 1971, over 60 hydrocarbon accumulations have been discovered, including eight large oil fields in deep water and ultra-deep water.

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As of December 31, 2012, we held rights to 21 exploratory blocks (6 are evaluation plans) in the Campos Basin, comprising a total of 7,649 km² (1.89 million acres). During 2012, we have made important progress in the Campos Basin, where we have drilled a total of 17 wells (6 of them in the pre-salt reservoirs). 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 Campos Basin is our largest oil- and gas-producing region, producing an average 1,618.3 mbbl/d of oil and 498.5 mmcf/d (13.2 mmm³/d) of associated natural gas from 45 producing fields. During 2012, 77.0% of our total domestic production came from this Basin. The proved crude oil and natural gas reserves in the Campos Basin represented, in 2012, respectively, 77.8% and 47.5% of our total proved crude oil and natural gas reserves in Brazil.

We operated 41 floating production systems and 14 fixed platforms in water depths from 80 to 1,886 meters (262 to 6,188 feet), delivering oil with an average API gravity of 22.9° and a maximum basic sediment and water (a measurement of the water and sediment content of flowing crude oil) of 1%.

Production growth in the Campos Basin originates mainly from the installation of new platforms to develop our proved reserves in the region. The connection of new wells to previously installed platforms also contributed significantly to production increases in the Campos Basin. The interconnection of new wells in the P-48, P-56 and P-57 platforms and the FPSO-Cidade de Angra dos Reis added 174.8 mbbl/d to our average production in the Campos Basin in 2012.

While most of our production in the Campos Basis is from post-salt reservoirs, pre-salt reservoirs in the Campos Basin are a growing source of production. We first began producing pre-salt oil production in 2008 from the Jubarte field located in the region known as Parque das Baleias. We subsequently began producing from the Baleia Franca field in the second half of 2010. In September 2012, we started a pilot system exclusively dedicated to pre-salt appraisal and production in the Baleia Azul region using the FPSO Cidade de Anchieta, with a capacity to produce 100,000 bbl/d of oil and 123.6 mmcf/d (3.5 mmm³/d) of gas. As of the year end 2012, the Campos Basin pre-salt area was producing 82.7 mbbl/d, which is expected to increase due to additional discoveries that have been made in other existing concessions.

Campos Basin Projects

We are currently developing five major projects in the Campos Basin: Roncador Modules 3 and 4, Papa-Terra Modules 1 and 2, and Parque das Baleias (Baleia Azul, Jubarte, Cachalote, Baleia Anã and Baleia Franca).

Main Campos Basin Development Projects
Field	Unit Type	Production Unit	Crude Oil Nominal Capacity (bbl/d)	Natural Gas Nominal Capacity (mmcf/d)	Water Depth (meters)	Start Up (year)	Notes

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	140,000	35.3	1,170	2013	Post-salt
Roncador–Module 3	SS	P-55	180,000	211.9	1,790	2013	Post-salt
Roncador–Module 4	FPSO	P-62	180,000	211.9	1,550	2014	Post-Salt
Baleia Azul, Jubarte, Cachalote, Baleia Anã & Baleia Franca	FPSO	P-58	180,000	211.9	1,400	2014	Pre-salt

The aim of Papa-Terra project is to develop the production of Papa-Terra field located in the post-salt of Campos Basin. Petrobras will install during 2013 two stationary production units, namely: P-61 (which is a TLWP) and P-63 (which is a FPSO). The joint production capacity of P-61 and P-63 is of 140,000 bbl/d of oil and 35.3 mmcf/d (1 mmm³/d) of natural gas. The TLWP will be supported by a TAD (Tender Assisted Drilling) rig and its production will be transferred to the FPSO.

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Roncador Module 3 and 4 will develop the production of Roncador Field, located in the post-salt of Campos Basin, through the installation of a stationary production unit (P-55, which is a SS) and a FPSO (P-62). The production capacity of each production unit is of 180,000 bbl/d of oil and 211.9 mmcf/d (6 mmm³/d) of natural gas.

The production unit P-58 will develop production in the Parque das Baleias area, which encompasses the following fields: Baleia Franca (pre and post-salt), Cachalote (post-salt), Jubarte (pre and post-salt), Baleia Azul (pre-salt) and Baleia Anã (post-salt). This FPSO has an oil production capacity of 180,000 bbl/d and 211.9 mmcf/d (6 mmm³/d) of natural gas.

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. As of December 31, 2012, we held exploration rights to 26 blocks in the Santos Basin, comprising 13,580 km2 (3.4 million acres).

The Santos Basin pre-salt was a central focus of E&P activities in 2012. In this period we have drilled 15 wells (13 in the pre salt area) in total. We continue to concentrate our efforts on gathering information about the pre-salt reserves through EWTs and testing drilling technologies to improve efficiency and to plan the definitive design of production platforms.

During 2012, we made several light oil discoveries within the areas of Franco, Carioca, Tupi NE, Bem-te-vi, BM-S-42, Iara, South of Guará and Júpiter NE. All of these discoveries were in the pre salt reservoir, with exception of Júpiter NE which was in the post salt.

In the Santos Basin in 2012, our share of average daily production of oil was 98.6 mbbl/d, of which 55.7 mbbl/d was produced in the pre-salt area and our average daily production of natural gas was 296.8 mmcf/d (7.9 mmm³/d), of which was 57 mmcf/d (1.5 mmm³/d) was produced in the pre-salt area. In the Santos Basin, we held proved crude oil and natural gas reserves representing, in 2012, respectively 14.1% and 24.7% of our total proved crude oil and natural gas reserves in Brazil.

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. During 2012, the FPSO produced near oil production capacity of 100 mbbl/d. We drilled two wells to be interconnected in 2013, one of which was the first horizontal well drilled in the complex geological conditions of the pre-salt. We currently have two systems performing EWT’s in the Santos Basin pre-salt, the FPSO Cidade de São Vicente and the FPSO Dynamic Producer.

Under the Assignment Agreement, we acquired six blocks and one contingent block which comprise our rights to explore, evaluate and produce up to five bnbbl of oil equivalent in the pre-salt area of the Santos Basin. We are developing these blocks in an integrated manner with the pre-salt areas we already have under concession. See Item 10. “Material Contracts—Assignment Agreement.”

In 2012, we concluded the drilling of four wells located in the Assignment Agreement area (Franco NW, Franco SW, Nordeste de Tupi and Sul de Guara). The FPSO Dynamic Producer will start operating Franco EWT, the first EWT under the Assignment Agreement area, which is planned to become effective in the second quarter of 2013. Over the next three years, we will proceed with our exploration program and are currently targeting the production of oil in the Franco area in 2016.

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Santos Basin Projects

The source of future production from the Santos Basin will be predominantly from deep and ultra-deep water oil fields. We will be developing, until 2016, 13 major projects in the Santos Basin. Of these, 2 are in the Assignment Agreement area (Franco 1 and Franco 2). These FPSOs are currently being constructed under contracts. The next phase, beginning in 2017, will include the application of improved technologies and engineering specifically designed for the pre-salt fields.

Field	Unit Type	Production Unit	Crude Oil Nominal Capacity (bbl/d)	Natural Gas Nominal Capacity (mmcf/d)	Water Depth (meters)	Start Up (year)	Notes
Bauna & Piracaba (BM-S-40)	FPSO	Cidade de Itajai	80,000	70.6	200	2013	Post-salt
Sapinhoá Pilot (Guará)	FPSO	Cidade de São Paulo	120,000	176.6	2,141	2013	Pre-salt
Lula (Northeast) Pilot	FPSO	Cidade de Paraty	120,000	176.6	2,200	2013	Pre-salt
Sapinhoá (North)	FPSO	Cidade de Ilha Bela	150,000	211.9	2,100	2014	Pre-salt
Iracema (South)	FPSO	Cidade de Mangaratiba	150,000	282.5	2,100	2014	Pre-salt
Iracema (North)	FPSO	Cidade de Itaguaí (Z1)	150,000	282.5	2,100	2015	Pre-salt
Lula (High)	FPSO	P-66	150,000	247.2	2,100	2016	Pre-salt
Lula (Central)	FPSO	P-67	150,000	176.6	2,100	2016	Pre-salt
Lula (South)	FPSO	P-68	150,000	221.9	2,100	2016	Pre-salt
Franco 1 Assignment Agreement	FPSO	P-74	150,000	247.2	2,100	2016	Assignment Agreement
Carioca	FPSO	No name (Z2)	80,000	152.4	2,100	2016	Pre-salt
Lula (North)	FPSO	P-69	150,000	211.9	2,100	2016	Pre-salt
Franco 2 Assignment Agreement	FPSO	P-75	150,000	247.2	2,100	2016	Assignment Agreement

Following Lula, the second field to begin development in the Santos pre-salt will be Sapinhoá (formerly known as Guará) which is one of the largest oil fields in Brazil, with a total estimated recoverable volume of 2.1 billion boe. Commercial production began in January 2013 through FPSO Cidade de Sao Paulo four years from discovery. The pilot system has a production capacity of 120,000 bbl/d of oil and natural gas processing of 176.6 mmcf/d (5 mmm³/d). The first well drilled by Cidade de Sao Paulo is capable of producing over 25,000 bbl/d of oil.

The Sapinhoá field Development Plan comprises two permanent systems. The next FPSO to be installed will be the FPSO Cidade de Ilhabela with a production capacity of 150,000 bbl/d of oil and 211.9 mmcf/d (6 mmm³/d) of gas. This FPSO is currently under construction and expected to begin operations during the second half of 2014.

The third pilot system for the Santos pre-salt will be Lula Northeast, through FPSO Cidade de Paraty. Production is scheduled to begin in May 2013. This FPSO has a capacity of 120,000 bbl/d of oil and 176.6mmcf/d (5 mmm³/d) of natural gas processing.

We are also developing post-salt fields in the Santos Basin. The FPSO Cidade de Itajaí in Baúna (formerly Tiro and Sidon) began operating in February, 2013. This FPSO has a capacity to process up to 80,000 bbl/d of oil and 70.6 mmcf/d (2 mmm³/d) of natural gas.

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. During 2012 we made two discoveries within the Golfinho area, both of them in the post-salt region. On December 31, 2012, we held exploration rights to 16 blocks (4 are evaluation plans) comprising a total of 3,861 km² (1.0 million acres).

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At December 31, 2012, we were producing from 46 producing fields oil at an average rate of 43.8 mbbl/d and our average daily production of natural gas was of 215.1 mmcf/d (5.7 mmm³/d). At December 31, 2012, we held proved crude oil and natural gas reserves representing respectively, 0.7% and 4.8% of our total proved oil and 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 247.2 mmcf/d (7 mmm³/d). The pipeline, which runs from the Parque das Baleias area to the Cacimbas gas treatment unit, came online in November 2012.

Sergipe/Alagoas Basin

The Sergipe-Alagoas Basin is one of our new frontier offshore regions. During 2012, we made 5 new discoveries in the areas informally denominated as Muriú, Moita Bonita, Farfan, Cumbe and Barra-1. All of them are in ultra-deep water, in a distance of almost 100 km from Aracaju. As of December 31, 2012, we held exploration rights to 11 blocks in the Sergipe-Alagoas Basin, comprising 3,297 km2 (0.81 million acres). Our aggregate production level in Sergipe–Alagoas Basin was of 48.9 mbbl/d of oil and 66.4 mmcf/d (1.8 mmm³/d) of natural gas. In the Sergipe/Alagoas Basin, we held proved crude oil and natural gas reserves representing, in 2012, respectively 1.84% and 2.48% of our total proved crude oil and natural gas reserves in Brazil.

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 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. In 2012, these other basins production was of 167.5 mbbl/d of oil and 282 mmcf/d (7.5 mmm³/d) of natural gas.

Critical Resources in Exploration and Production

We seek to develop and retain the critical resources that are necessary to meet our production targets. Drilling rigs are an important resource for our E&P operations and substantial lead time is required when fleet expansion is needed. When we discovered the pre-salt, in 2007 our activities were constrained by the availability of rigs, but our subsequent efforts to contract additional rigs has eliminated this constraint. Whereas in 2008 we only had three rigs capable of drilling in water depths greater than 2000 meters (6,560 feet), we had 40 as of December 31, 2012. We believe that we now have sufficient rigs to meet our long term production targets, although we will continue to evaluate our drilling requirements and will adjust our fleet size as needed.

In addition to contracting the additional rigs that are now operating in Brazil, all of which were built internationally, we have been working since 2008 to develop the capacity to construct drilling rigs in Brazil. We have awarded contracts for 28 additional rigs to be built in Brazil to meet our long-term needs and satisfy Brazilian local content requirements arising out of the Assignment Agreement and concession agreements obtained in later Brazilian exploration bid rounds. We expect these rigs to be delivered from 2015 through 2020 and they will replace or supplement the existing fleet in Brazil. The contracts to build the 28 rigs was awarded to Sete Brasil S.A. (Sete BR), a Brazilian company in which Petrobras holds a 10% interest.

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Drilling Units in Use by Exploration and Production on December 31 of Each Year
	2012		2011		2010
	Leased	Owned	Leased	Owned	Leased	Owned
Onshore	24	11	17	11	22	12
Offshore, by water depth (WD)	65	9	54	8	44	8
Jack-up rigs	0	5	1	4	1	4
Floating rigs:	65	4	53	4	43	4
500 to 1000 meters WD	6	2	8	2	11	2
1001 to 2000 meters WD	19	2	26	2	19	2
2001 to 3000 meters WD	40	0	19	0	13	0

Refining, Transportation and Marketing

Refining, Transportation and Marketing Key Statistics
	2012	2011	2010
	(U.S.$ million)
Refining, Transportation and Marketing:
Sales revenues	116,710	118,630	97,936
Income (loss) before income taxes	(17,699)	(8,753)	3,141
Total assets at December 31	91,458	84,330	70,515
Capital expenditures and investments	14,745	16,133	16,198

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 2,018 mbbl/d, and are one of the world’s largest refiners. As of December 31, 2012, 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 the economic growth and rising real incomes. Since 2010, we have met this incremental growth in demand primarily by increasing imports as our refining capacity was not sufficient to meet the increased demand. This growth in imports has increased our cost of sales, contributing to declining margins when we have not passed on the higher import costs of our domestic product prices. See Item 5. “Operating and Financial Review and Prospects.” Additional refining capacity currently under construction will help to reduce our import needs, but we will continue to require product imports for the foreseeable future.

Our Refining, Transportation and Marketing segment also includes (i) petrochemical operations that add value to the hydrocarbons we produce and meet the needs of the growing Brazilian economy and (ii) extraction and processing of shale.

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, 2012, was 2,018 mbbl/d and our average throughput during 2012 was 1,944 mbbl/d.

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The following table shows the installed capacity of our Brazilian refineries as of December 31, 2012, and the average daily throughputs of our refineries in Brazil in 2012, 2011 and 2010.

Capacity and Average Throughput of Refineries
Name (Alternative Name)	Location	Crude Distillation Capacity at December 31, 2012	Average Throughput
Name (Alternative Name)	Location	Crude Distillation Capacity at December 31, 2012	2012	2011	2010
		(mbbl/d)	(mbbl/d)
LUBNOR	Fortaleza (CE)	8	8	7	8
RECAP (Capuava)	Capuava (SP)	53	53	43	36
REDUC (Duque de Caxias)	Rio de Janeiro (RJ)	239	263	254	256
REFAP (Alberto Pasqualini)	Canoas (RS)	189	154	148	145
REGAP (Gabriel Passos)	Betim (MG)	151	145	129	143
REMAN (Isaac Sabbá)	Manaus (AM)	46	38	42	42
REPAR (Presidente Getúlio Vargas)	Araucária (PR)	195	199	193	170
REPLAN (Paulínia)	Paulinia (SP)	396	387	373	316
REVAP (Henrique Lage)	São Jose dos Campos (SP)	252	248	240	238
RLAM (Landulpho Alves)	Mataripe (BA)	281	239	233	250
RPBC (Presidente Bernardes)	Cubatão (SP)	172	172	166	160
RPCC (Potiguar Clara Camarão)	Guamaré (RN)	36	37	34	33
Total		2,018	1,944	1,862	1,798

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 2012, we invested a total of U.S.$3,435 million in our refineries, of which U.S.$2,581 million was invested for hydrotreating units to improve the quality of our diesel and gasoline and U.S.$419 million for coking units to convert heavy oil into lighter products.

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

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

· Gasoline quality upgrades at REPLAN and RLAM.

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

· Diesel quality upgrades at REDUC; and

· Upgrades to receive, process and deliver LPG and natural gas produced in the processing plant located in Caraguatatuba in the State of São Paulo.

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By the end of 2013, all of our refineries will be capable of producing a maximum sulfur content for diesel of 500 ppm, and six of our refineries (RLAM, REGAP, REPLAN, RECAP, REVAP and REPAR) are expected to have capacity to produce 10 ppm sulfur diesel. By 2014, we will also 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 highest rates of demand growth in the world 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 two 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 2015; and

· 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 2014.

We are also in the evaluation stage for two new refineries in Northeastern Brazil:

· Premium I in the State of Maranhão is designed to process 20° API heavy crude oil, maximize production of low sulfur diesel, and produce LPG, naphtha, low sulfur kerosene, bunker fuel and petroleum coke. This refinery will be built in two phases of 300 mbbl/d each; and

· 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)
	2012	2011	2010
Diesel	782	745	716
Gasoline	438	395	351
Fuel oil	238	234	243
Naphtha	106	109	133
LPG	143	137	132
Jet fuel	93	93	80
Other	196	183	177
Total domestic output of oil products	1,997	1,896	1,832
Installed capacity	2,018	2,013	2,007
Utilization (%)	96	92	90
Domestic crude oil as % of total feedstock processed	82	82	82

(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

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Domestic Sales Volumes, mbbl/d
	2012	2011	2010
Diesel	937	880	809
Gasoline	570	489	394
Fuel oil	84	82	100
Naphtha	165	167	167
LPG	224	224	218
Jet fuel	106	101	90
Other	199	188	180
Total oil products	2,285	2,131	1,958
Ethanol and other products	83	86	99
Natural gas	357	304	312
Total domestic market	2,725	2,521	2,369
Exports	554	633	698
International sales and other operations	506	563	581
Total international market	1,060	1,196	1,279
Total sales volumes	3,785	3,717	3,648

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 260 mbbl/d in 2013. We believe our domestic proved reserves will be sufficient to allow us to continue to deliver all contracted volumes. For 2013, approximately 84% of our exported crude oil will be committed to meeting our contractual delivery commitments to third parties.

Imports and Exports

Much of the crude oil we produce in Brazil is heavy or intermediate. We must 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 we don’t have the capacity to process. We use exports and imports of crude oil to balance our domestic production and refinery capacity with market needs, while optimizing our refining margins.

Our imports and exports of oil products depend on our refinery output and Brazilian demand levels. We import oil products to balance any shortfall between production from our Brazilian refineries and the market demand for each product. We export oil product that our refineries produce in excess of Brazilian market demand, which is largely fuel oil. The table below shows our exports and imports of crude oil and oil products in 2012, 2011 and 2010:

Exports and Imports of Crude Oil and Oil Products, mbbl/d
	2012	2011	2010
Exports
Crude oil	364	428	497
Fuel oil (including bunker fuel)	153	160	153
Gasoline	1	5	14
Other	30	38	33
Total exports	548	631	697
Imports
Crude oil	346	362	316
Diesel and other distillates	190	199	177
LPG	53	61	58
Gasoline	87	43	9
Naphtha	58	64	42
Other	45	20	13
Total imports	779	749	615

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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, 2012, our onshore and offshore, crude oil and oil products pipelines extended 16,333 km (10,151 miles). We operate 28 marine storage terminals and 20 other tank farms with nominal aggregate storage capacity of 65 mmbbl. Our marine terminals handle an average 10,820 tankers and oil barges annually. We are working in partnership with other companies to develop and expand Brazil’s ethanol pipeline and logistics 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, 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.

Two new oil tankers were delivered to Transpetro on May 14, 2012 and June 18, 2012. The remaining orders for 46 vessels are scheduled to be delivered between 2013 and 2020, all of which will be built in Brazilian shipyards. In addition, Transpetro has contracted 20 convoys (each composed of four barges and one pushboat) for ethanol transportation on the Tietê-Paraná river waterway.

The table below shows our operating fleet and vessels under contract as of December 31, 2012.

Owned and Chartered Vessels in Operation and Under Construction Contracts at December 31, 2012
	In Operation		Under Contract/Construction
	Number	Tons Deadweight Capacity	Number	Tons Deadweight Capacity
Owned fleet:
Tankers	51	3,735,438	38	3,642,330
LPG tankers	6	40,171	8	42,000
Anchor Handling Tug Supply (AHTS)	1	2,163	‒	‒
Floating, Storage and Offloading (FSO)	1	28,903	‒	‒
Layed-up vessel	1	91,902	‒	‒
Total	60	3,898,577	46	3,684,330
Chartered vessels:
Tankers	166	15,552,167	‒	‒
LPG tankers	11	232,014	‒	‒
Total	177	15,784,181	‒	‒

Petrochemicals

Our petrochemicals operations provide an outlet for our growing production volumes of gas and other refined products, which increase their value and provides substitute for products that are otherwise 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.

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We engage in our petrochemicals operations through the following subsidiaries, controlled entities and affiliated companies:

	mmt/y	Petrobras interest (%)
Braskem (1):
Ethylene	3.95	36.20
Polyethylene	3.03
Polypropylene	3.95
PVC	0.71
DETEN Química S.A.:
LAB(1)	0.22	27.88
LABSA(1)	0.08	27.88
METANOR S.A./COPENOR S.A.:
Methanol	0.08	34.54
Formaldehyde	0.09
Hexamine	0.01
FCC Fábrica Carioca de Catalisadores S.A.:
Catalysts	0.04	50.00
Additives	0.01	50.00
INNOVA S.A.:
Ethylbenzene	0.54	100.00
Styrene	0.26
Polystyrene	0.16
PETROCOQUE S.A.:
Calcined petroleum coke	0.50	50.00
________________________

(1) Feedstock for the production of biodegradable detergents.

Our investments in petrochemical companies amount to U.S.$2,856 million and the most significant investment is in Braskem S.A. (Braskem), Brazil’s largest petrochemical company.

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

	·	Complexo Petroquímico do Rio de Janeiro—Comperj: designed to meet the Brazilian demand for thermoplastic resins. The petrochemical plants are in the planning stage and are scheduled to start up in 2018;
	·	PetroquímicaSuape Complex in Pernambuco: to produce purified terephthalic acid (PTA) with a capacity of 0.7 million t/y (already in operation), polyethylene terephthalate (PET) resin with a capacity of 0.45 million t/y, and polymer and polyester filament textiles with a capacity of 0.24 million t/y; 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
	2012	2011	2010
	(U.S.$ million)
Distribution:
Sales revenues	40,712	44,001	37,282
Income (loss) before income taxes	1,386	1,134	1,081
Total assets at December 31	8,130	7,938	7,384
Capital expenditures and investments	666	679	515

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, or RTM, and works to expand the domestic market for these oil products and for other fuels, including LPG, ethanol and biodiesel.

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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 38.1% 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 2012, BR sold the equivalent of 885 mbbl/d of oil products and other fuels to wholesale and retail customers, of which the largest portion (43.6%) was diesel.

At December 31, 2012, our BR branded service station network was Brazil’s leading retail marketer, with 7,641 service stations, or 19.5% of the stations in Brazil. BR-owned and franchised stations make up 30.6% 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 743 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 54.9% of the total Brazilian wholesale market. Our customers include aviation, transportation and industrial companies, as well as utilities and government entities.

Our LPG distribution business, Liquigas Distribuidora, held a 22.6% market share and ranked second in LPG sales in Brazil in 2012, according to the ANP.

Oil products sales in Brazil increased 6.5% in 2012 compared to 2011. 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
	2012	2011	2010
	(U.S.$ million)
Gas and Power:
Sales revenues	11,803	9,738	8,492
Income (loss) before income taxes	1,277	2,725	990
Total assets at December 31	28,454	27,645	30,109
Capital expenditures and investments	2,113	2,293	3,964

Our Gas and Power segment comprises gas transmission and distribution, LNG regasification, the manufacture of nitrogen-based fertilizers, gas-fired and flex-fuel power generation, and power generation from renewable sources, including solar, wind and small-scale hydroelectric.

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The primary focus of 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.

As a result of our efforts to develop the market, natural gas in the year of 2011 supplied 10.2% of Brazil’s total energy needs, compared to 3.7% in 1998, and is projected to supply 15.5% of Brazil’s total energy needs by 2021, according to Empresa de Pesquisa Energética, a branch of the MME.

Natural Gas

We have three principal markets for natural gas:

· Industrial, commercial and retail customers;

· Thermoelectric generation; and

· Consumption by our refineries and fertilizer plants.

Natural gas consumption in Brazil by industrial, commercial and retail customers decreased 0.5% in 2012 compared to 2011. This decrease was due mainly to Brazil’s low economic growth. Natural gas consumption in the power generation industry increased 105% from 2011 to 2012 due to unfavorable rainfall, which reduced the reservoir storage levels of Brazilian hydroelectric power plants. Natural gas consumption by refineries and fertilizer plants increased 13%.

As a result of a multi-year infrastructure development program, including investments of approximately U.S.$13 billion (R$25.48 billion) in the last five years, we now have an integrated system centered around two main, interlinked pipeline networks that allow us to deliver natural gas from our main offshore natural gas producing fields in the Santos, Campos and Espírito Santo Basins, as well as from three LNG terminals, one of which is under construction, and a gas pipeline connection with Bolivia.

Currently, our natural gas pipeline network has a total extension of 9,190 km. In 2012, we invested U.S.$1,243.2 million in our natural gas infrastructure, and in 2013, we plan to invest an additional U.S.$1,003.7 million for enhancements to our gas transportation system primarily directed to expanding the Cabiúnas Terminal natural gas processing capacity in order to receive up to 459 mmcf/d (13 mmm³/d) in expectation of increasing associated natural gas production from the pre-salt reservoirs in the Santos Basin. This project is scheduled to be fully operational by August 2014.

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Principal Natural Gas Local Distribution Holdings
Name	State	Group Interest %	Average Gas Sales in 2012 (mmm³/d)	Customers

CEG RIO	Rio de Janeiro	37.41	6.6	33,333
BAHIAGAS	Bahia	41.50	3.7	14,335
GASMIG	Minas Gerais	40.00	3.6	406
PETROBRAS DISTRIBUIDORA	Espírito Santo	100.00	3.0	25,828

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
	2012	2011	2010
Sources of natural gas supply
Domestic production	39.5	34.1	28.6
Imported from Bolivia	27.0	27.1	27.1
LNG	8.4	1.6	7.6
Total natural gas supply	74.9	62.8	63.3
Sales of natural gas
Sales to local gas distribution companies(1)	39.3	39.8	37.2
Sales to gas-fired power plants	16.6	8.2	12.2
Total sales of natural gas	55.9	48.0	49.4
Internal consumption (refineries, fertilizer and gas-fired power plants)(2)	18.5	14.8	13.9
Revenues (U.S.$ billion)(3)	8.1	5.9	4.7
________________________

(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 construction of the Bolivia-Brazil pipeline in 1996, we entered into a long-term Gas Supply Agreement, or GSA, with the Bolivian state-owned company Yacimientos Petrolíferos Fiscales Bolivianos, or 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, 19, 2009, Petrobras and YPFB signed the fourth amendment to the GSA, which provides for annual additional payments to YPFB for liquids contained in the natural gas purchased by Petrobras through the GSA. As of February 2010, Petrobras has paid all obligations owed for 2007, but YPFB did not meet the condition precedent necessary to receive additional payments for the subsequent years (after 2007). Petrobras and YPFB are currently discussing several aspects of the GSA, including payments for liquids contained in the natural gas purchased in the subsequent years (after 2007). As a result of this negotiation, Petrobras may agree to make additional payments in exchange for certain compensations to be agreed by YPFB, but it is currently not possible to provide any specific payment estimates for subsequent years. As a result, we have not considered them in our contractual GSA obligations forecast.

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Our volume obligations under the ship-or-pay arrangements entered into with Gás Transboliviano (GTB) and Transportadora Brasileira Gasoduto Bolivia-Brasil (TBG) were generally designed to match our gas purchase obligations under the GSA through 2019. The tables below show our contractual commitments under these agreements for the five-year period from 2013 through 2017.

Commitments to Purchase and Transport Natural Gas in Connection with Bolivia-Brazil Pipeline
	2013	2014	2015	2016	2017
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.$)(2)	107.16	104.73	100.00	100.00	100.00
Estimated payments (U.S.$ million)(3)	2,844.30	2,701.10	2,575.70	2,589.40	2,604.00
Ship-or-pay contract with GTB
Volume commitment (mmm³/d)	30.08	30.08	30.08	30.08	30.08
Volume commitment (mmcf/d)	1,062.26	1,062.26	1,062.26	1,062.26	1,062.26
Estimated payments (U.S.$ million)(5)	138.46	139.14	139.82	140.51	141.21
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)	529.44	508.87	516.38	521.50	524.01

(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

We sell our gas primarily to local gas distribution companies and to gas fired plants generally based on standard take-or-pay long term supply contracts. This represents 72% of our total sale volumes and the price formula under these contracts are indexed to an international fuel oil basket.

Additionally, we have 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, weekly electronic auctions and a new gas sale contract introduced in 2011, which consists of a seller delivery option aiming to help balance natural gas supply and demand in case of a low dispatch of natural gas from gas-fired power plants.

In 2012, we renegotiated some existing long-term natural gas sales contracts with local distribution company of natural gas in order to promote adjustments tailored to specific market demands, encompassing term extensions for some contracts, prolonging our natural gas procurement portfolio. We continued offering contracts for short-term volumes through electronic auctions.

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The table below shows our future gas supply commitments from 2013 to 2017, including sales to both local gas distribution companies and gas-fired power plants.

Future Commitments under Natural Gas Sales Contracts, mmm³/d
	2013	2014	2015	2016	2017
To local gas distribution companies:
Related parties(1)	19.16	21.07	20.51	21.24	21.65
Third parties	16.84	16.90	16.93	16.93	16.93
To gas-fired power plants:
Related parties(1)	6.79	4.66	2.52	2.54	2.59
Third parties	6.55	7.93	8.27	8.32	8.60
Total(2)	49.34	50.56	48.23	49.03	49.77
Estimated contract revenues (U.S.$ billion)(3)(4)	6.4	6.9	7.0	7.1	7.4

(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 Sales

In 2009, we contributed to the development of a short-term market for natural gas sales, focusing on the industrial market. Sales under these short-term contracts were accomplished by an electronic auction system. These auctions commercialized natural gas volumes reserved for but not otherwise utilized by local gas distributors, and allowed us to offer to end users more competitive prices.

Since October 2012 we have revised the auction so that one short-term contract will regulate all operations of sales during an one-year period. On average, 4.4 mmm³/d of natural gas were sold under short-term contracts in 2009, with volumes reaching 7.8 mmm³/d in 2010 and 6.7 mmm³/d in 2011. In 2012, the average volumes of natural gas delivered under this new agreement was 6.6 mmm³/d, with a delivery record of 7.3 mmm³/d in October 2012.

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 the growing production of our associated natural gas.

Our fertilizer plants in Bahia and Sergipe produce ammonia and urea for the Brazilian market.

The table below shows our ammonia and urea sales, and revenues for each of the past three years:

Ammonia and Urea (ton)
	2012	2011	2010
Ammonia	229,575	240,665	235,729
Urea	848,000	831,462	772,059
Revenues (U.S.$ million)	571	605	421

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We are currently building four additional facilities:

• 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;

• UFN III, with the ability to sell 1.2 million t/y of urea and 70 thousand t/y of ammonia from 2.2 mmm3/d of natural gas, expected to start up in September 2014;

• 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 November 2016; and

• 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 July 2018. 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.

Power

Brazilian electricity needs are mainly supplied by hydroelectric power plants (84,463 MW of installed capacity) which corresponds to 69% of Brazil’s generation capacity. Hydroelectric power plants are dependent on the annual level of rainfall, i.e., in the years where rainfall is abundant, the Brazilian hydroelectric power plants will generate more electricity and consequently less generation from thermoelectric power plants will be demanded. In 2012, hydroelectric power plants in Brazil generated 50,225 MWavg, which corresponded to 86% of Brazil’s total electricity needs (58,401 MWavg).

The total installed capacity of the Brazilian National Interconnected Power Grid (Sistema Interligado Nacional—SIN) in 2012 was of 122,561 MW. Of this total, 6,235 MW (or 5%) was available from 19 thermoelectric plants which we control. These plants are designed to supplement power from the hydroelectric power plants. In 2012, we invested U.S.$387.8 million (R$760.0 million) in our power business segment.

Hydroelectric generation capacity is supplement by other sources of energy (biomass, wind, coal, nuclear and natural gas). Total electricity generated by these sources averaged 8,176 MW in 2012, of which Petrobras’ thermoelectric power plants contributed 2,699 MWavg, as compared to 653 MWavg in 2011. Most of our generation occurred in the fourth quarter when we averaged 5,279 MWavg of generation due to reduced rainfall affecting hydroelectric generation in this period.

Electricity Sales and Commitments for Future Generation Capacity

Under Brazil’s power pricing regime, a power plant may sell only electricity that is certified by the MME and which corresponds to a fraction of its installed capacity. This certificate is granted to ensure a constant sale of commercial capacity over the course of years to each power plant, given its role within Brazil’s system to supplement hydroelectricity power during periods of unfavorable rainfall. The amount of certified capacity for each power plant is determined by its expected capacity to generate energy over time.

The totality of the capacity certified by the MME (garantia física) may be sold through long term contracts in auctions to power distribution companies (standby availability), long term bilateral contracts executed with free customers and to attend the energy needs of our own facilities.

In exchange for selling this certified capacity, the thermoelectric power plants shall produce energy whenever requested by the national operator (ONS). In addition to a capacity payment, thermoelectric power plants also receive from the Electric Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica, or “CCEE”) reimbursement for its variable costs (previously declared to MME to calculate its commercial certified capacity) incurred whenever they are called to generate electricity.

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For the year of 2012, the commercial capacity certified by MME for all thermoelectric power plants controlled by us was of 4,146 MWavg, although our total generating capacity was 6,235 MWavg in 2012. Of the total 4,438 MWavg of commercial capacity available (capacidade comercial disponível or lastro) for sale in 2012, approximately 38% was sold as standby availability in auctions and approximately 62% was committed under bilateral contracts and self-production.

Under the terms of standby availability contracts, we are compensated a fixed amount whether or not we generate any power. Additionally, whenever we have to deliver energy under such standby availability contracts, we receive an additional compensation for the energy delivered that is set on the date of the auction and is annually revised based on an inflation-adjusted fuel oil basket.

In addition, in the new energy auction (Leilão de Energia Nova) held on August 17, 2011, we committed to sell 416.4 MWavg from our Baixada Fluminense plant for the period of March 2014 through December 2033. In 2012, we acquired the Camaçari Polo de Apoio I (Arembepe) and Camaçari Muricy I (Muricy) oil-fired thermoelectric power plants. In the new energy auction held on June 26, 2006, each of them committed to sell 101 MWavg for the period of January 2009 through December 2023.

Our future commitments under bilateral contracts and self-production are of 2,753 MWavg in 2013, 2,420 MWavg in 2014 and 2,407 MWavg in 2015. 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 commercial capacity under short and medium-term bilateral contracts, in new auctions to be conducted by MME or in the spot market.

The table below shows the evolution of our thermoelectric power plants installed capacity and the associated certificated commercial capacity.

Installed Power Capacity, Certified Commercial Capacity
	2010	2011	2012	2013	2014	2015
Installed power capacity and utilization
Installed capacity (MW)	5,277	5,806	6,235	6,323	6,379	6,379
Certified commercial capacity (MWavg)	3,619	3,777	4,146	4,342	4,266	4,421
Purchases (MWavg)	234	214	292	209	203	200
Commercial capacity available (Lastro) (MWavg)	3,853	3,991	4,438	4,551	4,469	4,621

The table below shows the allocation of our sales volume between our customers and our revenues for each of the past three years:

Volumes of Electricity Sold (MWavg)
	2012	2011	2010
Total sale commitments	4,438	3,991	3,853
Bilateral contracts	2,318	2,000	2,024
Self-production	423	395	438
Auctions to distribution companies	1,697	1,596	1,391
Generation volume	2,699	653	1,837
Revenues (U.S.$ million)	3,755	2,366	2,752

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 the renewable energies incentive program (PROINFA) and the 2009 “reserve energy” auctions.


TABLE OF CONTENTS (cont.)
		Page

Item 8.	Financial Information	109
Consolidated Statements and Other Financial Information		109
Legal Proceedings		109
Dividend Distribution		109
Item 9.	The Offer and Listing	110
Item 10.	Additional Information	111
Memorandum and Articles of Incorporation		111
Restrictions on Non-Brazilian Holders		120
Transfer of Control		121
Disclosure of Shareholder Ownership		121
Material Contracts		121
Exchange Controls		128
Taxation Relating to Our ADSs and Common and Preferred Shares		129
Taxation Relating to PifCo’s and PGF’s Notes		137
Documents on Display		144
Item 11.	Qualitative and Quantitative Disclosures about Market Risk	144
Item 12.	Description of Securities other than Equity Securities	147
American Depositary Shares		147
PART II		148
Item 13.	Defaults, Dividend Arrearages and Delinquencies	148
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	148
Item 15.	Controls and Procedures	149
Evaluation of Disclosure Controls and Procedures		149
Management’s Report on Internal Control over Financial Reporting		149
Changes in Internal Controls		149
Item 16A.	Audit Committee Financial Expert	150
Item 16B.	Code of Ethics	150
Item 16C.	Principal Accountant Fees and Services	150
Audit and Non-Audit Fees		150
Audit Committee Approval Policies and Procedures		150
Item 16D.	Exemptions from the Listing Standards for Audit Committees	151
Audit Committee Approval Policies and Procedures		151
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	151
Item 16F.	Change in Registrant’s Certifying Accountant	151
Item 16G.	Corporate Governance	152
PART III		155
Item 17.	Financial Statements	155
Item 18.	Financial Statements	155
Item 19.	Exhibits	155
Signatures		159
Index to Audited Consolidated Financial Statements		160


TABLE OF CONTENTS
		Page

Forward-Looking Statements		3
Glossary of Petroleum Industry Terms		5
Conversion Table		7
Abbreviations		8
Presentation of Financial and Other Information		9
Presentation of Information Concerning Reserves		10
PART I		11
Item 1.	Identity of Directors, Senior Management and Advisers	11
Item 2.	Offer Statistics and Expected Timetable	11
Item 3.	Key Information	11
Selected Financial Data		11
Risk Factors		14
Item 4.	Information on the Company	23
History and Development		23
Overview of the Group		23
Exploration and Production		25
Refining, Transportation and Marketing		34
Distribution		39
Gas and Power		40
International		48
Biofuels		53
Corporate		54
Organizational Structure		54
Property, Plants and Equipment		55
Regulation of the Oil and Gas Industry in Brazil		55
Health, Safety and Environmental Initiatives		59
Insurance		62
Additional Reserves and Production Information		63
Item 4A.	Unresolved Staff Comments	71
Item 5.	Operating and Financial Review and Prospects	71
Management’s Discussion and Analysis of Financial Condition and Results of Operations		71
Overview		72
Sales Volumes and Prices		72
Effect of Taxes on Our Income		74
Inflation and Exchange Rate Variation		74
Results of Operations		75
Additional Business Segment Information		85
Liquidity and Capital Resources		86
Contractual Obligations		90
Critical Accounting Policies and Estimates		90
Research and Development		93
Trends		95
Item 6.	Directors, Senior Management and Employees	96
Directors and Senior Management		96
Compensation		102
Share Ownership		103
Fiscal Council		103
Audit Committee		103
Other Advisory Committees		104
Ombudsman		104
Employees and Labor Relations		105
Item 7.	Major Shareholders and Related Party Transactions	107
Major Shareholders		107
i

International Key Statistics
	2012	2011	2010
	(U.S.$ million)
International:
Sales revenues	17,929	16,956	13,519
Income (loss) before income taxes	1,933	2,117	1,053
Total assets at December 31	18,735	19,427	16,958