pbraform20f_2013.htm - Generated by SEC Publisher for SEC Filing

As filed with the Securities and Exchange Commission on April 30, 2014

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, 2013

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
2.000% Global Notes due 2016, issued by PGF	New York Stock Exchange
3.000% Global Notes due 2019, issued by PGF	New York Stock Exchange
4.375% Global Notes due 2023, issued by PGF	New York Stock Exchange
5.625% Global Notes due 2043, issued by PGF	New York Stock Exchange
Floating Rate Global Notes due 2016, issued by PGF	New York Stock Exchange
Floating Rate Global Notes due 2019, issued by PGF	New York Stock Exchange
3.250% Global Notes due 2017, issued by PGF	New York Stock Exchange
4.875% Global Notes due 2020, issued by PGF	New York Stock Exchange
6.250% Global Notes due 2024, issued by PGF	New York Stock Exchange
7.250% Global Notes due 2044, issued by PGF	New York Stock Exchange
Floating Rate Global Notes due 2017, issued by PGF	New York Stock Exchange
Floating Rate Global Notes due 2020, issued by PGF	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: None

The number of outstanding shares of each class of stock as of December 31, 2013 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 R No £

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

Yes £ No R

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes R No £

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

Yes R No £

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

Large accelerated filer R 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 R

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 oil, 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;

· our 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;

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	Standard measure of crude oil volume.
BNDES	The Banco Nacional de Desenvolvimento Econômico e Social (the Brazilian Development Bank)
BSR	Buoyancy supported riser.
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 assisting in the formulation of energy policies and guidelines.
CVM	The Comissão de Valores Mobiliários (Securities and Exchange Commission) of Brazil, or CVM.
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 Ministério de Minas e Energia (Ministry of Mines and Energy) of Brazil.
MPBM	The Ministério do Planejamento, Orçamento e Gestão (Ministry of Planning, Budget and Management) of Brazil.
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.
PLSV	Pipe laying support vessel.
Post-salt reservoir	A geological formation containing oil or natural gas deposits located above a salt layer.
Pre-salt reservoir	A geological formation containing oil or natural gas deposits located beneath a salt layer.
Proved reserves	Consistent with the definitions in Rule 4-10(a) of Regulation S-X, proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to December 31, 2013, 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	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	Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Proved undeveloped reserves do not include reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
SS	Semi-submersible unit.
Synthetic oil and synthetic gas	A mixture of hydrocarbons derived by upgrading (i.e., chemically altering) natural bitumen from oil sands, kerogen from oil shales, or processing of other substances such as natural gas or coal. Synthetic oil may contain sulfur or other non-hydrocarbon compounds and has many similarities to crude oil.
TLWP	Tension Leg Wellhead Platform.
Total depth	Total depth of a well, including vertical distance through water and below the mudline.
Ultra-deep water	Over 1,500 meters (4,921 feet) deep.

CONVERSION TABLE

1 acre	=	43,560 square feet	=	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 meter	=	3.2808 feet
1 t of crude oil	=	1,000 kilograms of crude oil	=	Approximately 7.5 barrels of crude oil (assuming an atmospheric pressure index gravity of 37° API)

ABBREVIATIONS

bbl	Barrels
bcf	Billion cubic feet
bn	Billion (thousand million)
bnbbl	Billion barrels
bncf	Billion cubic feet
bnm³	Billion cubic meters
boe	Barrels of oil equivalent
bnboe	Billion 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
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

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, joint operations and structured entities.

We currently issue notes in the international capital markets through our wholly-owned finance subsidiary Petrobras Global Finance B.V., or PGF, a private company with limited liability incorporated under the law of The Netherlands. We have also used our wholly-owned subsidiary Petrobras International Finance Company S.A., or PifCo, as a vehicle to issue notes. We fully and unconditionally guarantee the notes issued by PGF and PifCo, and neither of them is required to file periodic reports with the U.S. Securities and Exchange Commission, or SEC. See note 38 to our audited consolidated financial statements.

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 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.

Our audited consolidated financial statements as of and for each of the three years ended December 31, 2013, 2012 and 2011 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 CVM.

Our IFRS financial statements filed with the CVM are presented using reais, while the presentation currency of the audited consolidated financial statements included herein is the U.S. Dollar. The functional currency of Petrobras and all of its Brazilian subsidiaries is the real. The functional currency of Petrobras Argentina is the Argentine peso, and the functional currency of most of our other entities that operate internationally is the U.S. Dollar. As described more fully in Note 2.2 to our audited consolidated financial statements, the U.S. dollar amounts for the periods presented have been translated from the 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 corresponding year.

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 2030 Strategic Plan, approved on February 25, 2014, which covers the period from 2014 to 2030, and on our 2014-2018 Business and Management Plan (“2014-2018 Plan”), and have been projected on a constant basis and have been translated from reais at an estimated average exchange rate of R$2.23 to U.S.$1.00 in 2014, and the real strengthening against the U.S. dollar to R$1.92 in the long term, in accordance with our 2014-2018 Plan. In addition, in accordance with our 2014-2018 Plan, future calculations involving an assumed price of crude oil have been calculated using a Brent crude oil price of U.S.$105.00 per barrel for 2014, declining to U.S.$ 100.00 per barrel in 2017, and to U.S.$95.00 per barrel 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 applies the SEC rules for estimating and disclosing oil and gas reserve quantities included in this annual report. In accordance with those rules, first adopted by Petrobras at the end of 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.

DeGolyer and MacNaughton (D&M) used our reserves estimates to conduct a reserves audit of 96% of our net proved crude oil, condensate and natural gas reserves as of December 31, 2013 in 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, 2013 from the properties we operate in Argentina. Furthermore, D&M used our reserves estimates to conduct a reserves evaluation of 100% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2013 in certain properties we operate in the United States. The reserves estimates were prepared in accordance with the reserves definitions in Rule 4-10(a) of Regulation S-X. 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, 2014, we filed reserve estimates for Brazil with the ANP, in accordance with Brazilian rules and regulations, totaling net volumes of 13.5 bnbbl of crude oil and condensate and 14.8 trillion cubic feet of natural gas. The reserve estimates filed with the ANP were approximately 27.4% higher than those provided herein 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 future oil prices projected by Petrobras as opposed to the SEC requirement that the 12-month average price be used to determine the economic producibility of the reserves.

We also file reserve estimates from our international operations with various governmental agencies under the guidelines of the Society of Petroleum Engineers, or SPE. The aggregate reserve estimates from our international operations, under SPE guidelines, amounted to 0.4 bnbbl of crude oil, condensate and NGLs and 1.3 trillion cubic feet of natural gas as of December 31, 2013, which is approximately 2% higher than the reserve estimates calculated under Regulation S-X, as provided herein. This difference is due to different technical criteria for booking proved reserves, including the use of future oil prices projected by Petrobras as opposed to the SEC requirement that the 12-month average price be used to determine the economic producibility of the reserves.

PART I

Item 1. Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

Selected Financial Data

This section contains selected consolidated financial data presented in U.S. dollars and prepared in accordance with IFRS as of and for each of the five years ended December 31, 2013, 2012, 2011, 2010 and 2009, derived from our audited consolidated financial statements, which were audited by PricewaterhouseCoopers Auditores Independentes–PwC for the years ended December 31, 2013 and 2012 and KPMG Auditores Independentes for the three years ended December 31, 2011, 2010 and 2009.

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,
	2013	*2012^()**	*2011^()**	*2010^()**	*2009^()**
	(U.S.$ million)
Assets:
Cash and cash equivalents	15,868	13,520	19,057	17,655	16,222
Marketable securities	3,885	10,431	8,961	15,612	77
Trade and other receivables, net	9,670	11,099	11,756	10,845	8,147
Inventories	14,225	14,552	15,165	11,808	11,103
Assets classified as held for sale	2,407	143	−	−	−
Other current assets	6,600	8,049	9,653	7,639	6,629
Long-term receivables	18,782	18,856	18,962	22,637	19,991
Investments	6,666	6,106	6,530	6,957	4,620
Property, plant and equipment	227,901	204,901	182,918	168,104	128,754
Intangible assets	15,419	39,739	43,412	48,937	3,899
Total assets	321,423	327,396	316,414	310,194	199,442
Liabilities and shareholders’ equity:
Total current liabilities	35,226	34,070	36,364	33,577	31,067
Non-current liabilities⁽¹⁾	30,839	42,976	34,744	30,251	23,809
Long-term debt⁽²⁾	106,235	88,484	72,718	60,417	48,963
Total liabilities	172,300	165,530	143,826	124,245	103,839
Shareholders’ equity
Share capital	107,371	107,362	107,355	107,341	33,790
Reserves and other comprehensive income	41,156	53,352	63,961	76,769	60,579
Shareholders' equity attributable to the shareholders of Petrobras	148,527	160,714	171,316	184,110	94,369
Non-controlling interests	596	1,152	1,272	1,839	1,234
Total shareholders' equity	149,123	161,866	172,588	185,949	95,603
Total liabilities and shareholders' equity	321,423	327,396	316,414	310,194	199,442

(1) Excludes long-term debt.

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

(*) Amounts restated, as set out in Note 2.3 to our audited consolidated financial statements. Amounts for 2010 and 2009 have not been restated, as the effects are not material.

INCOME STATEMENT DATA

IFRS Summary Financial Data

	For the Year Ended December 31,
	2013	2012	2011	2010	2009
	(U.S.$ million, except for share and per share data)
Sales revenues	141,462	144,103	145,915	120,452	91,146
Net income before financial results, profit sharing and income taxes	16,214	16,900	27,285	26,372	22,923
Net income attributable to the shareholders of Petrobras	11,094	11,034	20,121	20,055	15,308
Weighted average number of shares outstanding:
Common	7,442,454,142	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	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	1.24	1.30	2.09	2.67	2.61
Common and Preferred ADS	2.48	2.60	4.18	5.34	5.22
Basic and diluted earnings per:
Common and Preferred shares	0.85	0.85	1.54	2.03	1.74
Common and Preferred ADS	1.70	1.70	3.08	4.06	3.48
Cash dividends per⁽¹⁾:
Common shares	0.22	0.24	0.53	0.70	0.59
Preferred shares	0.41	0.48	0.53	0.70	0.59
Common ADS	0.44	0.48	1.06	1.40	1.18
Preferred ADS	0.82	0.96	1.06	1.40	1.18

(1) Pre-tax.

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 on platforms and in drilling operations and natural disasters. The occurrence of any of these events or other incidents could result in personal injuries, loss of life, severe environmental damage with the resulting containment, clean-up and repair expenses, equipment damage and liability in civil and administrative proceedings.

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

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

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 increase, 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 in Brazil of crude oil and oil products 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 and 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 product prices will not be at parity with international product prices (See “—Risks Relating to Our Relationship with the Brazilian Federal Government—The Brazilian federal government, as our controlling shareholder, may pursue certain macroeconomic and social objectives through us 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.

Our ability to maintain our long-term growth objectives for oil production depends on our ability to successfully develop our reserves.

Our ability to maintain our long-term growth objectives for oil production, including those defined in our 2014-2018 Plan and our 2030 Strategic 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 (i) securing the critical resources that are necessary to meet our production targets, (ii) allocating our resources to build the necessary equipment and deploy such equipment at considerable distances from the shore and (iii) 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 have been licensed and assigned to us, or that may be licensed 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.

It may be difficult for us to obtain financing for our planned investments, which may have a material adverse effect on us.

Under our 2014-2018 Plan, we intend to invest U.S.$220.6 billion from 2014 to 2018, U.S.$206.8 billion of which is for projects already being implemented or under a bidding process. The remaining U.S.$13.8 billion is for the portfolio under evaluation with projects that are still in the planning phase of development and subject to further approvals by our management. In addition, approximately 23.7% of our existing debt (principal), or U.S.$26.7 billion, will mature in the next three years.

Our debt, net of cash, cash equivalents and marketable securities, increased by 31% to U.S.$94,483 million as of December 31, 2013 compared to U.S.$72,012 million as of December 31, 2012, as our cash flow from operations has been less than the resources needed to fund our capital expenditures and payment of dividends. This is partly because we have not fully adjusted the prices for our products in Brazil to international levels.

In order to implement our 2014-2018 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, as well as to adjust our product pricing to international levels. We may not be able to obtain the necessary financing or to adjust our prices in order to implement our 2014-2018 Plan.

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

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

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

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

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 (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 any subsequent revision of the contract price and volume; and (5) the terms of the reallocation of volumes among the exploratory blocks assigned to us.

The Assignment Agreement includes provisions for a subsequent revision of the contract terms, including the price we paid for the rights we acquired. 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 assumptions regarding the timing of our oil and gas production, operating and investment costs, and the value of the crude oil at prevailing international prices 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 per barrel. Once the revision process is concluded pursuant to the terms of the Assignment Agreement, if 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.

In December 2013, we began negotiations for the revision process of the Assignment Agreement with the Brazilian government. See Item 4. “Exploration and Production-Santos Basin” and Item 10. “Material contracts—Assignment Agreement” for further information. During the term of the Assignment Agreement, novel issues may arise in the implementation of the revision process and other provisions that will require further negotiations.

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, ANEEL, Agência Nacional de Transportes Aquaviários (Brazilian Water Transportation Agency), or ANTAQ and 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 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 with evolving industry standards, and as new laws and regulations relating to climate change, including carbon controls, become applicable to us, 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, regulations and industry standards results in significant unplanned 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 31 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 prevent them from focusing on our core business. Depending on the outcome, certain litigation could result in restrictions on our operations and have a material adverse effect on certain of our businesses.

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

As of December 31, 2013, 80% of our financial debt liabilities are denominated in currencies other than the real. A substantial portion of our indebtedness is, and is expected to continue to be, denominated in or indexed to U.S. dollars and other foreign currencies. A depreciation of the real against these other currencies will increase our debt service, as the amount of reais necessary to pay principal and interest on foreign currency debt will increase with depreciation.

This foreign exchange variation will have an immediate impact on our reported income, except for a portion of our obligations denominated in U.S. dollars that are subject to our hedge accounting policy. Additionally, following a devaluation of the real, some of our operating expenses, capital expenditures, investments and import costs will increase. As most of our revenues are denominated in reais, unless we increase the prices of our products to reflect the depreciation, our cash generation relative to our capacity to service debt may decline.

As of December 31, 2013, 52% of our total indebtedness consisted of floating rate debt. Additionally, we have debt maturities that amount to U.S.$52.7 billion during the next five years, a portion of which may be refinanced by issuing new debt. To the extent that such floating rates rise, or the cost of debt increases when we refinance maturing obligations, we may incur additional expenses. 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 or to which it is indexed. Such changes may increase our financing expenses.

Furthermore, we decided not to enter into third-party derivative contracts or make other arrangements with third parties 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.

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 insurance 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 pursue certain of its macroeconomic and social objectives through us 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 that the Brazilian federal government 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.

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. 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. Prior to January 2002, prices for crude oil and oil products were regulated by the Brazilian federal government, occasionally set below prices prevailing in the world oil markets. We cannot assure you that price controls will not be reinstated in Brazil.

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

The Brazilian federal government maintains control over our investment budget and establishes limits on our investments and long-term debt. As a state-controlled entity, we must submit our proposed annual budgets to the MPBM, the MME and the Brazilian Congress for approval. Our approved budget may reduce our proposed investments and incurrence of new debt, and we may be unable to obtain financing that does not require Brazilian federal government approval. As a result, 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, which may adversely affect our operating results and financial condition.

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:

· exchange rate movements and volatility;

· inflation;

· financing of government current account deficit;

· price instability;

· interest rates;

· liquidity of domestic capital and lending markets;

· tax policy;

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

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

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

Risks Relating to Our Equity and Debt Securities

The size, volatility, liquidity 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 traded on 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 debt securities 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 listed both on the New York Stock Exchange and the Luxembourg Stock Exchange and trade on the NYSE Euronext and Euro MTF market, respectively. PGF can issue new notes that can be listed in markets other than the New York Stock Exchange and the Luxembourg Stock Exchange and traded in markets other than the NYSE Euronext and 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 our 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.

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 our 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 shareholders’ meetings. 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 Brazilian exchange controls, an obligation to pay amounts denominated in a currency other than reais, which is payable in Brazil pursuant to a decision of a Brazilian court, may be satisfied in reais at the rate of exchange, as determined by the Central Bank of Brazil, in effect on the date of payment.

A finding that we are subject to U.S. bankruptcy laws and that the guaranty executed by us were a fraudulent conveyance could result in PifCo noteholders 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 would 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 pursuant to the European Council Directive 2003/48/EC on the taxation of savings income.

Austria and Luxembourg have opted out of certain exchange of information provisions of the European Council Directive 2003/48/EC on the taxation of savings income (the Directive) and are instead, during a transitional period, applying a withholding tax on payments of interest, at a rate of up to 35%, made by a paying agent within those jurisdictions to, or collected by such a paying agent for, an individual beneficial owner resident in other member states of the European Union (EU Member States) or to certain limited types of entities established in other Member States unless the beneficial owner of the interest payments opts for exchange of information as required under the Directive. The Luxembourg government is currently in the process of electing Luxembourg out of the withholding system in favor of automatic exchange of information with effect from January 1, 2015. 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 EU Member State or another country or territory which has opted for a withholding system. For more information, see Item 10. “Additional Information—Taxation—Taxation Relating to PifCo’s and PGF’s Notes—European Union Savings Directive.” An investor should consult a tax adviser to determine the tax consequences of holding PifCo’s or PGF’s notes for such investor.

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 since then have been carrying out crude oil and natural gas production and refining activities in Brazil on behalf of the government. As of December 31, 2013, 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, the Brazilian government enacted Law No. 9,478/1997, 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. The law 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 government on September 3, 2010, the 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. On December 2, 2013, we executed our first agreement with the Brazilian government under a production sharing regime. See Item 10. “Material Contracts—Assignment Agreement” and Item 10. “Material Contracts – Production Sharing 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 deep and continuous commitment to find and develop oil fields in Brazil, our operations account for the majority of Brazil’s oil and gas production, and we hold a large base of proved reserves and a fully developed operational infrastructure. In 2013, our average domestic daily oil production was 1,931.4 mbbl/d, an estimated 90.9% of Brazil’s total oil production. Over 67.1% (8,419.4 mmboe) 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 45 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 areas.

As of December 31, 2013, we had proved developed oil and gas reserves of 7,605.8 mmboe and proved undeveloped reserves of 4,934.5 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 21 new FPSOs and planned 14 more for the period between 2014 and 2020, and are also making necessary investments in subsea equipment and infrastructure.

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 source of most of our crude oil in the Campos Basin. Our domestic crude distillation capacity of 2,102 mbbl/d and domestic refining throughput of 2,074 mbbl/d are currently below the levels required to meet strong and increasing domestic demand for transportation fuels, particularly gasoline, diesel and jet fuel. We are currently building two new refining facilities, but the resulting increase in our refining capacity may not fully address domestic demand. Until there is sufficient refinery capacity to meet such demand, we will continue to import oil and oil products and our planning to build additional refineries. 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 that 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 domestic 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 natural gas market.

Outside of Brazil, we operate in 17 countries. In South America, our operations extend from exploration and production to refining, marketing, retail services, natural gas and electricity power plants. 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 have oil and gas exploration in other countries while in Asia we have refining operations in Japan.

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

Our activities are organized into six business segments:

· Exploration and Production: crude oil, NGL and natural 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 and petrochemical investments in Brazil;

· Distribution: distribution of oil products, ethanol and vehicle natural gas to wholesalers and through our Petrobras Distribuidora S.A. (“Petrobras Distribuidora”) retail network in Brazil;

· Gas and Power: transportation and trading of natural gas and LNG, produced in or imported into Brazil, 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 electricity 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.

Additionally, we have a Corporate segment that has activities that are not 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.

The following table sets forth key information for each business segment in 2013:

	Key Information by Business Segment, 2013
	Exploration and Production	Refining, Transportation and Marketing	Gas and Power	Biofuel	Distribution	International	Corporate	Eliminations	Group Total
	(U.S.$ million)
Sales revenues	68,210	111,051	14,017	388	41,365	16,302	-	(109,871)	141,462
Income (loss) before income taxes	29,619	(12,417)	921	(168)	1,323	2,035	(7,818)	(85)	13,410
Total assets at December 31	152,707	92,107	27,703	1,196	7,681	18,123	28,540	(6,634)	321,423
Capital expenditures and investments	27,566	14,243	2,716	143	514	2,368	547	-	48,097

Exploration and Production

Exploration and Production Key Statistics
	2013	2012	2011
	(U.S.$ million)
Exploration and Production:
Sales revenues	68,210	74,714	74,117
Income (loss) before income taxes	29,619	35,465	36,809
Property, plant and equipment	126,716	102,779	90,633
Capital expenditures and investments	27,566	21,959	20,405

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 NGLs in Brazil in 1970 to 1,931.4 mbbl/d in 2013. 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 exploration and production 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 most promising offshore basin, 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. We have been active in these waters since 1971, when we started exploration in the Campos Basin, 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 deepwater drilling, where the discoveries are substantially larger and our technology and expertise create a competitive advantage.

Historically, our offshore exploration and production activities were focused on post-salt reservoirs, primarily in the Campos Basin. In recent years, we have made important discoveries in 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 22.2% (approximately 33,100 km²or 8.2 million acres) of the pre-salt areas, including the acreage assigned to us under the Concession Contracts and the Assignment Agreement. We are also part of the consortium that was granted a concession covering approximately 1,547.8 km²or 0.4 million acres of the Libra field under the Production Sharing Agreement.

In the southern part of the pre-salt province, within 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 (Lula, formerly Tupi), BM-S-9 (Lapa and Sapinhoá, formerly Carioca and Guará), in the Assignment Agreement area (Búzios and Sul de Lula, formerly Franco and Sul de Tupi) and in Libra, one of the most important discoveries made in the pre-salt area. In the northern part of the province, within the Campos Basin, 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. 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 March 31, 2014, we had 147 exploration agreements (covering 96 exploratory blocks and 51 evaluation plans currently underway), corresponding to a gross exploratory acreage of 103,597 km² (25.6 million acres), or a net exploratory acreage of 54,210 km² (13.4 million acres). We are exclusively responsible for conducting the exploration activities in 38 exploratory blocks and in 17 evaluation plans currently underway. As of March 31, 2014, we had exploration partnerships with 24 foreign and domestic companies. We conduct exploration activities under 62 of our 92 partnership agreements. We hold interests ranging from 20% to 100% in the exploration areas under concession or assigned to us.

In 2013, we invested a total of U.S.$7.8 billion in exploration activities in Brazil. We drilled a total of 76 exploratory wells in 2013, of which 31 were offshore and 45 onshore. Our 2014-2018 Plan, which was released on February 25, 2014, foresees capital expenditures and investments in exploration and production activities in Brazil of U.S.$153.9 billion from 2014 to 2018 (not including investments by our partners).

Throughout our history, we have 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. In 2013, offshore production accounted for 89% of our production and deep water production accounted for 77% of our production in Brazil. In 2013, we started production from 34 wells.

During 2013, our oil and gas production from Brazil averaged 2,165.7 mboe/d, of which 89.2% was oil and 10.8% was natural gas. On December 31, 2013, our estimated net proved crude oil and natural gas reserves in Brazil were 12.5 billion boe, of which 85% was crude oil and 15% was natural gas. Brazil provided 91% of our worldwide production in 2013 and accounted for 96% of our worldwide reserves at December 31, 2013 on a barrels of oil equivalent basis. Over the last five years, approximately 90% of our total Brazilian production has been oil.

In 2013, our production of crude oil, condensate and NGLs in Brazil averaged 1,931.4 mbbl/d, a 2.5% decline in comparison with the previous year. This production decrease is mainly attributable to:

· production delays caused by the need to rearrange the layout of certain subsea equipment for the P-63 platform (which operates in the Papa Terra field);

· delays in the delivery and installation of BSRs and the first steel catenary risers to be connected to the FPSOs Cidade de São Paulo and Cidade de Paraty, which delayed the production ramp-up from the Sapinhoá and Lula NE fields;

· delays in the delivery and first oil of some of the production units that began production in 2013; and

· the lack of sufficient PLSVs available to install the flowlines that connect subsea wells to our new production systems.

With the new production systems that came online in 2013 and the production systems expected to come online in 2014, we expect to achieve production growth of between 6.5% and 8.5% in 2014.

As of December 31, 2013 and December 31, 2012, our reserves and production in Brazil are summarized in the tables below.

	2013				2012
	Campos	Santos	Others	Total	Campos	Santos	Others	Total
Proved Reserves
Oil (mmbbl)	7,642.3	2,209.8	806.3	10,658.4	8,199.5	1,483.5	856.3	10,539.2
Gas (bcf)	4,662.4	3,935.4	2,693.9	11,291.7	4,911.8	2,552.0	2,880.7	10,344.6
Total (mmboe)	8,419.4	2,865.7	1,255.3	12,540.4	9,018.1	1,908.8	1,336.4	12,263.3
Production⁽¹⁾
Oil (mbb/d)	1,531.1	136.9	263.4	1,931.4	1,618.3	98.6	263.2	1,980.1
Gas (bcf/d)	0.6	0.3	0.6	1.5	0.5	0.3	0.6	1.4
Total (mboe/d)	1,623.4	183.7	358.6	2,165.7	1,701.4	148.0	356.1	2,205.5
Stationary production units	56	11	59	126	55	8	62	125

_____________________

(1) Includes synthetic oil and gas.

For the twenty-second consecutive year, we achieved a reserve replacement ratio higher than 100%, which means that we added more volume to our reserves than we produced throughout the year.

We have implemented a variety of programs designed to increase oil recovery from existing fields, reduce natural declines from producing fields and also reduce operational costs. During 2013, we continued to implement important programs: PROEF, which aims to increase operational efficiency within the Campos Basin, returning production efficiency to historical levels, and PROCOP to optimize operating costs and productivity. Additionally, in 2013 we implemented PRC Poço and PRC-Sub Programs, both focused on production growth and reduction of costs and time required to implement projects.

Our exploration and production activities outside Brazil are included in our International business segment. See “—International.”

We have historically conducted exploration, development and production activities in Brazil through concession agreements, which we have obtained through participation in bid rounds conducted by the ANP. Some of our existing concessions were granted by the ANP without an auction in 1998, as provided by Law No. 9,478/1997. These are known as the “Round Zero” concession agreements. Since that time, we have participated in all of the auction rounds conducted by ANP, including the first production-sharing regime auction round held on October 21, 2013. Currently, we operate under three different exploration and production regimes:

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

Main 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
		100%	Deepwater	Intermediate Oil
	Albacora Leste	90% 90%	Deepwater Ultra-deepwater	Intermediate Oil 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% 100%	Deepwater Ultra-deepwater	Intermediate Oil 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% 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	Aracás Buracica	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
	Sapinhoá	45%	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, Santos, Espírito Santo 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. The Campos Basin is our largest oil- and gas-producing region, producing an average 1,531.1 mbbl/d of oil and 553.8 mmcf/d (14.7 mmm³/d) of associated natural gas from 47 producing fields. During 2013, 75% of our total domestic production came from this basin. In 2013, the proved crude oil and natural gas reserves in the Campos Basin represented 71.7% and 41.3% of our total proved crude oil and natural gas reserves in Brazil, respectively. In 2013, we operated 42 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 21.9° and maximum basic sediment and water (a measurement of the water and sediment content of flowing crude oil) of 1%.

Our oil and gas activities in the Campos Basin are focused on increasing production by installing new production systems, tapping pre-salt reservoirs with both new and existing production units, and maintaining our production in relatively mature fields. We also have significant exploration plans in this area.

Expanding production through new production systems, including from pre-salt reservoirs

Campos Basin Projects

We are currently ramping up oil production from two major projects and starting to develop three other in the Campos Basin, as detailed in the table below:

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 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
Parque das Baleias (Baleia Azul, Jubarte, Cachalote, Baleia Anã & Baleia Franca)	FPSO	P-58	180,000	211.9	1,400	2014	Pre and post-salt
Papa-Terra–Module 1	TLWP	P-61	0	0	1,180	2014	Post-salt production processed by P-63

Roncador Modules 3 and 4 will develop the production of Roncador Field, located in the post-salt of Campos Basin, through two stationary production units: the SS P-55, which was installed in December 2013, and the FPSO P-62, which will be installed in 2014. The production capacity of each unit is 180,000 bbl/d of oil and 211.9 mmcf/d (6 mmm³/d) of natural gas. We own 100% of the oil produced from these units.

The FPSO 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 unit has an oil production capacity of 180,000 bbl/d and 211.9 mmcf/d (6 mmm³/d) of natural gas. We own 100% of the oil produced from this unit.

The Papa-Terra Modules 1 and 2 project aims to develop production of the Papa-Terra field located in the post-salt of Campos Basin. We started production at this field in November 2013, using P-63 (which is a FPSO), and in 2014 a second unit will be installed, P-61 (which is a TLWP). The joint production capacity of P-61 and P-63 is 140,000 bbl/d of oil and 35.3 mmcf/d (1 mmm³/d) of natural gas. The TLWP will be supported by a Tender Assisted Drilling (TAD) rig, and its output will be transferred to the FPSO. Our share of the oil produced from these units is 62.5%.

While most of our production in the Campos Basin is from post-salt reservoirs, pre-salt reservoirs in the basin are a growing source of production. We first began pre-salt oil production in 2008 in the Jubarte field located in the Parque das Baleias region. 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 evaluation 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. During 2013, this unit produced an average of almost 90,000 bbl/d. By the end of 2013, the Campos Basin pre-salt area was producing 165.2 mbbl/d, which represents an increase of almost 100% compared to 2012. Our share of oil from produced from Campos Basin pre-salt reservoirs is 100%.

Maintenance in mature fields

We seek to slow the natural decline in mature fields of the Campos Basin by improving the operational efficiency of our equipment and reservoirs through our PROEF program. Based on efficiency metrics set forth under the PROEF program, we increased the efficiency of Campos Basin operational units by 3.7 p.p., to 75.4% in 2013 from 71.7% in 2012, and of our Rio de Janeiro operational units by 0.7 p.p., to 92.4% in 2013 from 91.7% in 2012. As a result of our investments, production in 2013 from these areas was 63 mbbl/d greater than it otherwise would have been. To achieve these results, we conducted extensive campaigns and regular maintenance on our platforms, in addition to scheduled unit stoppages to improve performance. Furthermore, we have internal planning and resource management procedures, such as standardization of equipment to ease maintenance and the preparation of backup inventory for critical equipment, ensuring greater availability of those resources.

Exploration

As of December 31, 2013, we held rights to five exploratory blocks and seven exploration plans in the Campos Basin, comprising a total of 4,493 km² (1.1 million acres). During 2013, we have made important progress in the Campos Basin, where we have drilled a total of five exploratory wells (three of them in pre-salt reservoirs).

Santos Basin

The Santos Basin, which covers approximately 348,900 km² (86 million acres located adjacent to and southwest of Campos Basin), is one of the most promising offshore exploration and production areas in the world. We are currently exploring and developing the Santos Basin pre-salt region under the Concession, Assignment, and Production Sharing Agreements.

Concession Agreements

In 2000 and 2001, we and our partners acquired through public auction under concession agreements eight blocks in what is now known as the Santos Basin pre-salt. In November 2007, we announced the discovery of this important new province, and we began producing oil in May 2009, with an EWT in block BMS -11 (formerly Tupi, now Lula).

In November 2010, we replaced the EWT with a long-term production system, the FPSO Cidade de Angra dos Reis. During 2013, this FPSO produced near its full oil production capacity of 100 mbbl/d.

Following Lula, the second field in development in the Santos Basin pre-salt is Sapinhoá (formerly known as Guará) with a total estimated recoverable volume of 2.1 billion boe. Commercial production began in January 2013 through FPSO Cidade de Sao Paulo. This 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 production well has been producing over 25,000 bbl/d of oil. The second well began production in February 2014, with initial production of 36 mbbl/d. This well was the first to produce through a pioneering connecting system, the BSR. The well is located at a water depth of 2,118 meters.

The third pilot system for the Santos pre-salt is FPSO Cidade de Paraty, located in the Lula field, which started production in June 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 currently have two systems performing EWTs in the Santos Basin pre-salt area, the FPSO Cidade de São Vicente and the FPSO Dynamic Producer.

During 2014, two additional systems will be installed: 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 to be located in the Sapinhoá field. This FPSO is currently in Brazil on the shipyard Brasa for modules integration and is expected to start operating during the second half of 2014. The second FPSO to be installed is Cidade de Mangaratiba, with a production capacity of 150,000 bbl/d of oil and 282.5 mmcf/d (8 mmm³/d) of gas to be located in Iracema. This FPSO is currently undergoing a module integration at the Brasfels shipyard, in Brazil.

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.

As of December 31, 2013, we held exploration rights to seven blocks in the Santos Basin and 11 exploration plans, comprising 10,404 km² (3.6 million acres). Our share of average daily production of oil was 136.9 mbbl/d, of which 83.0 mbbl/d was produced in the pre-salt area, and our average daily production of natural gas was 280.9 mmcf/d (7.4 mmm³/d), of which 262.3 mmcf/d (6.9 mmm³/d) was produced in the pre-salt area. As of December 31, 2013, 20.7% and 34.9% of our total proved crude oil and natural gas reserves in Brazil, respectively, were in the Santos Basin.

The Santos Basin pre-salt was a central focus of exploration and production activities in 2013. In this period, we drilled 12 exploratory wells (11 in the pre-salt area) in total. In 2013, we made several oil discoveries in the areas of Franco, Florim, BM-S-42 (Sagitário), Entorno de Iara, Sul de Tupi and Júpiter and we also declared the commerciality of a new exploratory field named Lapa (formerly known as Carioca), with estimated recoverable volume of 459 million barrels of petroleum. Lapa is operated by Petrobras (45%) in partnership with BG E&P Brasil (30%) and Repsol Sinopec Brasil (25%) and its first oil is planned for 2016.

Assignment Agreement (Contrato de Cessão Onerosa)

Under the Assignment Agreement, we acquired six blocks and one contingent block which comprise our rights to explore, evaluate and produce up to five billion boe in the pre-salt area of the Santos Basin, of which we have already declared as commercial 3.18 billion boe from the Buzios and Sul de Lula blocks. We are developing these blocks in an integrated manner with the pre-salt areas we already have under concession. Following the declaration of commerciality for these blocks, we have initiated the revision process of the Assignment Agreement with the Brazilian government and for the remaining blocks we must either declare commerciality or relinquish them by September 2014. See Item 10. “Material Contracts—Assignment Agreement.”

In 2013, we concluded the drilling of nine wells located in the Assignment Agreement area. Over the next three years, we intend to proceed with our exploration program and are currently targeting the production of oil in the Búzios field in 2016.

Production Sharing Agreement (Contrato de Partilha de Produção)

In October 2013, a consortium including Petrobras (40% interest), Shell (20% interest), Total (20% interest), Petrochina (10% interest) and CNOOC (10% interest) was awarded the rights and obligations to operate and explore the Libra field in the ultra-deep waters of the Santos Basin in the first production-sharing regime auction ever held in Brazil. Through the Production Sharing Agreement, the consortium was granted rights to explore and produce in an area comprising 1,547.76 km² (0.4 million acres) with estimated recoverable volumes from 8 to 12 billion boe according to the ANP. The exploration phase of the block will have a term of four years counted from the agreement’s execution date on December 2, 2013. The minimum exploratory program, to be carried out during this period, includes 3D seismic acquisition for the whole block, two exploratory wells and one extended well test. See Item 10. “Material Contracts – Production Sharing Agreement.”

Santos Basin Projects

The primary source of our expected future production growth will be from the Santos Basin pre-salt. We currently have under construction through 2018, 19 major projects that will be installed in this area. Of these, six are in the Assignment Agreement area (Búzios 1, Búzios 2, Búzios 3, Búzios 4, Nordeste de Tupi and Entorno de Iara). The following FPSOs are currently being constructed under contracts.

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 Norte	FPSO	Cidade de Ilha Bela	150,000	211.9	2,100	2014	Pre-salt Concession
Iracema Sul	FPSO	Cidade de Mangaratiba	150,000	282.5	2,100	2014	Pre-salt Concession
Iracema Norte	FPSO	Cidade de Itaguaí (Z1)	150,000	282.5	2,100	2015	Pre-salt Concession
Lula Alto	FPSO	Cidade de Maricá	150,000	211.9	2,100	2016	Pre-salt Concession
Lula Central	FPSO	Cidade de Saquarema	150,000	211.9	2,100	2016	Pre-salt Concession
Lula Sul	FPSO	P-66	150,000	211.9	2,100	2016	Pre-salt Concession
Búzios 1	FPSO	P-74	150,000	247.2	2,100	2016	Assignment Agreement
Lapa	FPSO	Cidade de Caraguatatuba	100,000	176.6	2,100	2016	Pre-salt Concession
Lula Norte	FPSO	P-67	150,000	211.9	2,100	2016	Pre-salt Concession
Búzios 2	FPSO	P-75	150,000	247.2	2,100	2016	Assignment Agreement
Lula Extremo Sul	FPSO	P-68	150,000	211.9	2,100	2017	Pre-salt Concession
Lula Oeste	FPSO	P-69	150,000	211.9	2,100	2017	Pre-salt Concession
Búzios 3	FPSO	P-76	150,000	247.2	2,100	2017	Assignment Agreement
Iara Horst	FPSO	P-70	150,000	211.9	2,100	2017	Pre-salt Concession
Búzios 4	FPSO	P-77	150,000	247.2	2,100	2017	Assignment Agreement
NE Tupi	FPSO	P-72	150,000	211.9	2,100	2018	Pre-salt Concession
Iara NW	FPSO	P-71	150,000	211.9	2,100	2018	Pre-salt Concession
Carcará	FPSO	TBD	150,000	282.5	2,100	2018	Pre-salt Concession
Entorno de Iara	FPSO	P-73	150,000	211.9	2,100	2018	Assignment Agreement

On February 27, 2014, our total pre-salt production reached 412 mboe/d, representing a new production record. This was accomplished with only 21 wells, highlighting the relatively high level of productivity of pre-salt fields that have been discovered. Ten of these wells are located in Santos Basin and were responsible for 59% of production (240 mboe/d). In addition, we have reduced the time required to drill and complete production wells in the Santos Basin pre-salt cluster. In January 2014, we drilled and completed SPH-5, located in Sapinhoá field, with a final depth of 2,126 meters in 109 days: 60 days for drilling and 49 days for well completion.

We are also developing post-salt fields in the Santos Basin. The FPSO Cidade de Itajaí in Baúna (formerly Tiro and Sidon) started 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

From 2000 to 2007, we made important discoveries in the Golfinho, Camurupim and Camurupim Norte fields. More recently we have made additional discoveries, still under evaluation, in the Parque dos Doces, Parque dos Deuses and Parque dos Cachorros fields.

During 2013, we produced oil from 45 fields at an average rate of 48.8 mbbl/d, and our average daily production of natural gas was of 182.2 mmcf/d (4.8 mmm³/d). The proved crude oil and natural gas reserves in the Espírito Santo Basin represented 0.6% and 3.7% in 2013 of our total proved crude oil and natural gas reserves in Brazil, respectively.

As of December 31, 2013, we held exploration rights to 16 blocks (10 onshore and 6 offshore) and 10 exploration plans offshore, comprising a total of 9,910 Km² (2.4 million acres) in the Espírito Santo Basin. In 2013, we made two discoveries in its post-salt area, known as prospects São Bernardo and Arjuna.

Sergipe-Alagoas Basin

The Sergipe-Alagoas Basin is one of our new frontiers in offshore regions. In 2013, we held proved crude oil and natural gas reserves in the Sergipe-Alagoas Basin representing 1.7% and 2.3% of our total proved crude oil and natural gas reserves in Brazil, respectively. Our aggregate production level in Sergipe–Alagoas Basin was 46.9 mbbl/d of oil and 72.7 mmcf/d (1.9 mmm³/d) of natural gas.

During 2013, we continued to confirm the existence of oil and gas resources through our exploration plans, and we have made new discoveries made in the areas informally denominated as Muriú, Moita Bonita, Farfan, Cumbe and Barra-1. All of them are in ultra-deep water, almost 100 km from the coast of Aracaju. As of December 31, 2013, we held exploration rights to one block and seven exploration plans in the Sergipe-Alagoas Basin, comprising 5,917 km2 (1.4 million acres).

Other Basins

We produce hydrocarbons and hold exploration acreage in 20 other basins in Brazil. 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 2013, production from these other basins amounted to 167.7 mbbl/d of oil and 316.2 mmcf/d (8.4 mmm³/d) of natural gas.

The most significant potential for exploratory success within our other basins are the equatorial margin and the south of Bahia offshore.

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 exploration and production operations and substantial lead time is required when fleet expansion is needed. When we discovered the pre-salt, in 2006, our activities were constrained by the availability of rigs, but our subsequent efforts to lease additional rigs have eliminated this constraint. Whereas in 2008 we only had three rigs capable of drilling in water deeper than 2,000 meters (6,560 feet), we had 40 as of December 31, 2013. 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 leasing 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 were awarded to Sete Brasil S.A. (Sete BR), a Brazilian company in which Petrobras holds a 10% interest.

Drilling Units in Use by Exploration and Production on December 31 of Each Year
	2013		2012		2011
	Leased	Owned	Leased	Owned	Leased	Owned
Onshore	12	10	24	11	17	11
Offshore, by water depth (WD)	61	7	65	9	54	8
Jack-up rigs	-	3	-	5	1	4
Floating rigs:	61	4	65	4	53	4
500 to 999 meters WD	4	2	6	2	8	2
1000 to 1999 meters WD	17	2	19	2	26	2
2000 to 3200 meters WD	40	-	40	-	19	-

In order to advance our exploration and production plans, we also need to secure a number of specialized vessels to connect wells and the FPSOs and for subsea construction. In particular, we seek to increase the fleet of PLSVs available to us. We currently have 11 leased PSLVs, and we expect an additional eight leased PLSVs to arrive in Brazil during 2014 and another 11 through 2017 to help us meet our production targets.

Refining, Transportation and Marketing

Refining, Transportation and Marketing Key Statistics
	2013	2012	2011
	(U.S.$ million)
Refining, Transportation and Marketing:
Sales revenues	111,051	116,710	118,630
Income (loss) before income taxes	(12,417)	(17,699)	(8,753)
Property, plant and equipment	66,200	63,463	54,629
Capital expenditures and investments	14,243	14,745	16,133

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 2,102 mbbl/d, and are one of the world’s largest refiners. As of December 31, 2013, 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, 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.

The Brazilian market has been characterized since 2010 by very high rates of growth in consumption of oil products, driven primarily by economic growth, rising real incomes and the decline of domestic ethanol production. Because domestic oil consumption has grown faster than our oil production, we have shifted from being a net exporter of oil and oil products to being a net importer.

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 crude distillation capacity in Brazil as of December 31, 2013, was 2,102 mbbl/d and our average throughput during 2013 was 2,074 mbbl/d.

The following table shows the installed capacity of our Brazilian refineries as of December 31, 2013, and the average daily throughputs of our refineries in Brazil in 2013, 2012 and 2011.

Capacity and Average Throughput of Refineries
Name (Alternative Name)	Location	Crude Distillation Capacity at December 31, 2013	Average Throughput*
Name (Alternative Name)	Location	Crude Distillation Capacity at December 31, 2013	2013	2012	2011
		(mbbl/d)	(mbbl/d)
LUBNOR	Fortaleza (CE)	8	8	8	7
RECAP (Capuava)	Capuava (SP)	53	53	53	43
REDUC (Duque de Caxias)	Rio de Janeiro (RJ)	239	282	263	254
REFAP (Alberto Pasqualini)	Canoas (RS)	201	197	154	148
REGAP (Gabriel Passos)	Betim (MG)	157	150	145	129
REMAN (Isaac Sabbá)	Manaus (AM)	46	42	38	42
REPAR (Presidente Getúlio Vargas)	Araucária (PR)	208	194	199	193
REPLAN (Paulínia)	Paulinia (SP)	415	421	387	373
REVAP (Henrique Lage)	São Jose dos Campos (SP)	252	234	248	240
RLAM (Landulpho Alves)	Mataripe (BA)	306	279	239	233
RPBC (Presidente Bernardes)	Cubatão (SP)	178	177	172	166
RPCC (Potiguar Clara Camarão)	Guamaré (RN)	38	37	37	34
Average Crude Oil Throughput		2,102	2,029	1,898	1,815
Average NGL Throughput		‒	45	46	47
Average Throughput		‒	2,074	1,944	1,862

* Consider oil and NGLs processing (fresh feedstock)

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 residue conversion; and

· Reduce the environmental impact of our refining operations.

In 2013, we invested a total of U.S.$3,162 million in our refineries, of which U.S.$2,512 million was invested in hydrotreating units necessary to improve the quality of our diesel oil and gasoline and U.S.$174 million in coking units necessary to convert heavy oil into lighter products.

Our modernization efforts to meet stricter standards and improve facilities for our existing refineries began in 2005 and have been largely completed. By the end of 2013, all of our refineries were capable of producing a maximum sulfur content for diesel of 500 ppm, and seven of our refineries (RLAM, REGAP, REPLAN, RECAP, REVAP, REDUC and REPAR) to produce 10 ppm sulfur diesel.

REGAP completed its Diesel quality upgrade in January 2014 and increased its capacity of producing Diesel S-10. During 2014, the principal projects that will be under construction are the hydrotreating units at RPBC and REFAP, which will result in the capacity to produce 10 ppm sulfur diesel as well.

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 2016, and as of December 31, 2013, we have completed approximately 66.3% of construction and invested U.S.$7.6 billion; and

· Abreu e Lima - RNEST, 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 the last quarter of 2014, and as of December 31, 2013, we have completed approximately 84.3% of construction and invested U.S.$14.8 billion.

We also include within our 2014-2018 Plan two new refineries in northeastern Brazil that will be bid for construction. We expect to initiate bidding to construct the following refineries in 2014:

· Premium I in the State of Maranhão is being designed to process 24° 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 our domestic output of oil products and consolidated sales by product for the last three years.

Domestic Output of Oil Products: Refining and marketing operations, mbbl/d⁽¹⁾
	2013	2012	2011
Diesel	850	782	745
Gasoline	491	438	395
Fuel oil	255	238	234
Naphtha	90	106	109
LPG	137	143	137
Jet fuel	96	93	93
Other	206	196	183
Total domestic output of oil products	2,124	1,997	1,896
Installed capacity	2,102	2,018	2,013
Crude Distillation Utilization (%)	97	94	90
Domestic crude oil as % of total feedstock processed	82	82	82

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

Consolidated Sales Volumes, mbbl/d
	2013	2012	2011
Diesel	984	937	880
Gasoline	590	570	489
Fuel oil	98	84	82
Naphtha	171	165	167
LPG	231	224	224
Jet fuel	106	106	101
Other	203	199	188
Total oil products	2,383	2,285	2,131
Ethanol, nitrogen fertilizers, renewables and other products	91	83	86
Natural gas	409	357	304
Total domestic market	2,883	2,725	2,521
Exports	395	554	633
International sales	514	506	563
Total international market	909	1,060	1,196
Total sales volumes	3,792	3,785	3,717

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 240 mbbl/d in 2014. We believe our domestic proved reserves will be sufficient to allow us to continue to deliver all contracted volumes. For 2014, approximately 75% of our exported crude oil will be committed to meeting our contractual delivery commitments to third parties.

Imports and Exports

Our imports and exports of oil products depend on our refinery output and Brazilian demand levels. Much of the crude oil we produce in Brazil is heavy or intermediate. We must therefore import some light crude to balance the slate for our refineries, and export heavier crude that we do not have the capacity to process. We also import oil products to balance any shortfall between production from our Brazilian refineries and the market demand for each product.

The demand for oil products in Brazil increased rapidly between 2010 and 2012, at an average of 7.9% per year. From 2010 to 2012, we met this incremental growth in demand primarily by increasing imports, as our refining capacity was insufficient to meet the increasing demand.

In 2013, due to the positive results from modernization investments, our Brazilian refineries expanded output by 6% while consumption increased by 4.1%. This led to a decrease in oil product imports compared to 2012. The increase in refining output was met by processing higher volumes of both our domestic oil as well as imported oil. The result was a decrease in our product imports, but also an increase in our oil imports and a decline in our oil exports.

We export oil products that our refineries produce in excess of Brazilian market demand, which is largely fuel oil. Additional refining capacity currently under construction will help to reduce our import needs for products, but we will continue to require product imports for the foreseeable future.

The table below shows our exports and imports of crude oil and oil products in 2013, 2012 and 2011:

Exports and Imports of Crude Oil and Oil Products, mbbl/d
	2013	2012	2011
Exports
Crude oil	207	364	428
Fuel oil (including bunker fuel)	151	153	160
Gasoline	0	1	5
Other	35	30	38
Total exports	393	548	631
Imports
Crude oil	404	346	362
Diesel	174	190	199
LPG	63	53	61
Gasoline	32	87	43
Naphtha	83	58	64
Other	37	45	20
Total imports	793	779	749

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, 2013, our onshore and offshore, crude oil and oil products pipelines extended 19,313 km (9,525 miles). We operate 27 marine storage terminals and 21 other tank farms with nominal aggregate storage capacity of 64 mmbbl. Our marine terminals handle an average 10,019 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 Brazil 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.

Three new oil tankers were delivered to Transpetro in 2013. Another 39 vessels are scheduled to be delivered between 2014 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 biofuel transportation on the Tietê-Paraná waterway.

The table below shows our operating fleet and vessels under contract as of December 31, 2013.

Owned and Chartered Vessels in Operation and Under Construction Contracts at December 31, 2013
	In Operation		Under Contract/Construction
	Number	Tons Deadweight Capacity	Number	Tons Deadweight Capacity
Owned fleet:
Tankers	49	3,957,389	31	3,200,000
LPG tankers	6	40,171	8	42,000
Anchor Handling Tug Supply (AHTS)	1	2,163	0	0
Floating, Storage and Offloading (FSO)	0	0	0	0
Layed-up vessel	1	28,903	0	0
Total	57	4,028,626	39	3,242,000
Chartered vessels:
Tankers	203	18,383,200	-	-
LPG tankers	12	249,547	-	-
Total	215	18,632,747	-	-

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 operate in an integrated manner with the other businesses of Petrobras, preferably through partnerships with other companies.

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

	mmt/y (nominal capacity)	Petrobras interest (%)
Braskem⁽¹⁾:
Ethylene	3.95	36.20
Polyethylene	3.03
Polypropylene	3.95
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
PETROQUÍMICASUAPE COMPLEX⁽²⁾:
Purified Terephthalic Acid - PTA	0.70	100.00
Polyethylene Terephthalate - PET	0.45
Polymer and Polyester filament textiles	0.24
PETROCOQUE S.A.:
Calcined petroleum coke	0.50	50.00
________________________

(1) Feedstock for the production of biodegradable detergents.

(2) The PTA unit started operations in January 2013 and the PET operations are expected to begin in the second quarter of 2014.

Our investments in petrochemical companies amount to U.S.$2,285 million and the largest investment is in Braskem S.A. (Braskem), Brazil’s largest petrochemical company.

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

· 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; and

· Complexo Petroquímico do Rio de Janeiro—Comperj: The scope of this project has not yet been determined. This petrochemical facility will use Petrobras’ natural gas as raw material and its project will be undertaken by Braskem.

On September 2013 Petrobras executed an agreement to sell 100% of its equity interest in Petroquímica Innova S.A. to Videolar S.A. and its majority shareholder for R$870 million (approximately U.S.$372 million), including the assumption by the buyers of approximately R$23 million in debt. The conclusion of this transaction is subject to certain conditions precedent, including approval by the Brazilian Antitrust Authority – CADE.

Distribution

Distribution Key Statistics
	2013	2012	2011
	(U.S.$ million)
Distribution:
Sales revenues	41,365	40,712	44,001
Income (loss) before income taxes	1,323	1,386	1,134
Property, plant and equipment	2,672	2,733	2,510
Capital expenditures and investments	514	666	679

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.

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 , which accounts for 37.5% of the total Brazilian retail and wholesale distribution market. Petrobras Distribuidora distributes oil products, ethanol and biodiesel, and vehicular natural gas to retail, commercial and industrial customers. In 2013, Petrobras Distribuidora sold the equivalent of 925.2 mbbl/d of oil products and other fuels to wholesale and retail customers, of which the largest portion (42.7%) was diesel.

At December 31, 2013, our Petrobras Distribuidora branded service station network was Brazil’s leading retail marketer, with 7,710 service stations, or 19.7% of the stations in Brazil. Petrobras Distribuidora owned and franchised stations make up 29.9% of Brazil’s retail sales of diesel, gasoline, ethanol, vehicular natural gas and lubricants.

Most Petrobras Distribuidora stations are owned by franchisees that use the Petrobras Distribuidora brand name under license and purchase exclusively from us; we also provide franchisees with technical support, training and advertising. We own 632 of the Petrobras Distribuidora 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 Petrobras Distribuidora 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 Petrobras Distribuidora brand to commercial and industrial customers accounts for 55% 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 22.7% market share and ranked second in LPG sales in Brazil in 2013, according to the ANP.

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
	2013	2012	2011
	(U.S.$ million)
Gas and Power:
Sales revenues	14,017	11,803	9,738
Income (loss) before income taxes	921	1,277	2,725
Property, plant and equipment	20,882	21,585	21,968
Capital expenditures and investments	2,716	2,113	2,293

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.

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 supply of natural gas;

· Consolidate our electric energy business, exploring synergies between our natural gas supply and power generation capacities, along with the expansion of our electric energy commercialization activities; and

· Add value to natural gas by chemically processing it, prioritizing nitrogen fertilizers and other value- added products.

As a result of our efforts to develop the market, natural gas in 2012 supplied 11.5% of Brazil’s total energy needs, compared to 3.7% in 1998, and is projected to supply 16% of Brazil’s total energy needs by 2022, 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 in 2013 was 40.9 mmm³/d, representing a decrease of only 0.4% compared to 2012. This small decrease is attributable mainly to Brazil’s low economic growth. Natural gas consumption in the power generation industry increased 73% from 2012 to 2013 due to unfavorable rainfall, which reduced the reservoir storage levels of Brazilian hydroelectric power plants. Natural gas consumption by refineries and fertilizer plants increased by 3%.

As a result of a multi-year infrastructure development program in pipelines network that was completed in 2011, 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, and a gas pipeline connection with Bolivia.

Currently, our natural gas pipeline network has a total extension of 9,190 km. In 2013, we invested U.S.$987.67 million in our natural gas infrastructure, and in 2014, we plan to invest an additional U.S.$1,227.7 million for (i) enhancements to our gas transmission system primarily directed to expanding the Cabiúnas Terminal natural gas processing capacity in order to receive up to 459 mmcf/d (13 mmm³/d) with the expectation of increasing associated natural gas production from the pre-salt reservoirs in the Santos Basin, (ii) the development of the processing plant of Comperj’s petrochemical complex for the processing of 742 mmcf/d (21 mmm³/d) of natural gas, also associated with the pre-salt reservoirs in the Santos Basin and (iii) the construction of two gas pipelines connecting our pre-salt natural gas producing fields to the Cabiúnas Terminal and Comperj’s processing plant. The Cabiúnas Terminal expansion is scheduled to be fully operational by October 2015 and the Comperj is scheduled to begin operations by October 2016.

We also own and operate three LNG flexible terminals using three FSRUs (Floating Storage and Regasification Units), one in Guanabara Bay (State of Rio de Janeiro) with a send-out capacity of 706 mmcf/d (20 mmm³/d), another in Pecém (State of Ceará) in Northeastern Brazil with a send-out capacity of 247 mmcf/d (7 mmm³/d) and the last one located in the Todos os Santos Bay (State of Bahia), with a send-out capacity of 494 mmcf/d (14 mmm³/d).

In 2013, we conducted 88 cargo purchase operations, 77 of which were received in Brazil (including one cargo later exported) and 11 directly resold abroad.

We also own and operate four natural gas processing plants.

The map below shows our gas pipeline networks, LNG terminals and natural gas processing plants.

We hold interests ranging from 24% to 100% in 21 of Brazil’s 27 local gas distribution companies. We had approximately a 25% net equity interest in the combined 2,207mmcf/d (62.5 mmm³/d) of natural gas distributed by Brazil’s local distribution companies in 2013.

According to our estimates, our three most significant holdings, CEG Rio, Bahiagás and Gasmig, are Brazil’s third, fourth and fifth largest gas distributors. These companies, together with independent distributors Comgás and CEG supply 68% of the Brazilian market.

Principal Natural Gas Local Distribution Holdings
Name	State	Group Interest %	Average Gas Sales in 2013 (mmm³/d)	Customers⁽¹⁾

CEG RIO	Rio de Janeiro	37.41	9.1	38,888
BAHIAGAS	Bahia	41.50	4.5	23,354
GASMIG	Minas Gerais	40.00	4.1	1,484
PETROBRAS DISTRIBUIDORA	Espírito Santo	100.00	3.0	27,386
___________________________

(1) Units of households and industries attended by local gas distribution companies.

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
	2013	2012	2011
Sources of natural gas supply
Domestic production	40.8	39.5	34.1
Imported from Bolivia	30.5	27.0	27.1
LNG	14.5	8.4	1.6
Total natural gas supply	85.9	74.9	62.8
Sales of natural gas
Sales to local gas distribution companies⁽¹⁾	38.6	39.3	39.8
Sales to gas-fired power plants	26.0	16.6	8.2
Total sales of natural gas	64.6	55.9	48.0
Internal consumption (refineries, fertilizer and gas-fired power plants)⁽²⁾	20.8	18.5	14.8
Revenues (U.S.$ billion)⁽³⁾	9.0	8.1	5.9
________________________

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

(2) Includes gas used in the transport system.

(3) Includes natural gas sales revenues from the Natural Gas segment to other operating segments, service and other revenues from natural gas companies.

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 have been negotiating 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 ongoing 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.

Item 8.	Financial Information	112
Consolidated Statements and Other Financial Information		112
Legal Proceedings		112
Internal Commissions		112
Dividend Distribution		113
Item 9.	The Offer and Listing	113
Item 10.	Additional Information	115
Memorandum and Articles of Incorporation		115
Restrictions on Non-Brazilian Holders		124
Transfer of Control		124
Disclosure of Shareholder Ownership		125
Material Contracts		125
Exchange Controls		135
Taxation Relating to Our ADSs and Common and Preferred Shares		136
Taxation Relating to PifCo’s and PGF’s Notes		145
Documents on Display		152
Item 11.	Qualitative and Quantitative Disclosures about Market Risk	152
Item 12.	Description of Securities other than Equity Securities	154
American Depositary Shares		154
PART II		155
Item 13.	Defaults, Dividend Arrearages and Delinquencies	155
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	155
Item 15.	Controls and Procedures	155
Evaluation of Disclosure Controls and Procedures		155
Management’s Report on Internal Control over Financial Reporting		155
Changes in Internal Controls		156
Item 16A.	Audit Committee Financial Expert	156
Item 16B.	Code of Ethics	156
Item 16C.	Principal Accountant Fees and Services	157
Audit and Non-Audit Fees		157
Audit Committee Approval Policies and Procedures		157
Item 16D.	Exemptions from the Listing Standards for Audit Committees	157
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	158
Item 16F.	Change in Registrant’s Certifying Accountant	158
Item 16G.	Corporate Governance	158
PART III		161
Item 17.	Financial Statements	161
Item 18.	Financial Statements	161
Item 19.	Exhibits	161
Signatures		167

	2014	2015	2016	2017	2018
Purchase commitments to YPFB
Volume obligation (mmm³/d)⁽¹⁾	24.06	24.06	24.06	24.06	24.6
Volume obligation (mmcf/d)⁽¹⁾	850.00	850.00	850.00

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		10
Item 1.	Identity of Directors, Senior Management and Advisers	10
Item 2.	Offer Statistics and Expected Timetable	10
Item 3.	Key Information	11
Selected Financial Data		11
Risk Factors		13
Item 4.	Information on the Company	22
History and Development		22
Overview of the Group		22
Exploration and Production		24
Refining, Transportation and Marketing		36
Distribution		42
Gas and Power		43
International		50
Biofuels		55
Corporate		56
Organizational Structure		56
Property, Plants and Equipment		58
Regulation of the Oil and Gas Industry in Brazil		58
Health, Safety and Environmental Initiatives		62
Insurance		64
Additional Reserves and Production Information		65
Item 4A.	Unresolved Staff Comments	74
Item 5.	Operating and Financial Review and Prospects	74
Management’s Discussion and Analysis of Financial Condition and Results of Operations		74
Overview		75
Sales Volumes and Prices		76
Effect of Taxes on Our Income		77
Inflation and Exchange Rate Variation		78
Results of Operations		79
Additional Business Segment Information		87
Liquidity and Capital Resources		88
Contractual Obligations		92
Critical Accounting Policies and Estimates		93
Research and Development		95
Trends		97
Item 6.	Directors, Senior Management and Employees	98
Directors and Senior Management		98
Compensation		105
Share Ownership		105
Fiscal Council		106
Audit Committee		106
Other Advisory Committees		107
Ombudsman		107
Employees and Labor Relations		108
Item 7.	Major Shareholders and Related Party Transactions	110
Major Shareholders		110