pbraform20f_2014.htm - Generated by SEC Publisher for SEC Filing

As filed with the Securities and Exchange Commission on May 15, 2015

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, 2014

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)

Ivan de Souza Monteiro

Chief Financial Officer and Chief Investor Relations Officer
(55 21) 3224-2040 – ivanmonteiro@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
6.125% Global Notes due 2016, issued by PGF (successor to PifCo)	New York Stock Exchange
3.875% Global Notes due 2016, issued by PGF (successor to PifCo)	New York Stock Exchange
3.500% Global Notes due 2017, issued by PGF (successor to PifCo)	New York Stock Exchange
5.875% Global Notes due 2018, issued by PGF (successor to PifCo)	New York Stock Exchange
7.875% Global Notes due 2019, issued by PGF (successor to PifCo)	New York Stock Exchange
5.750% Global Notes due 2020, issued by PGF (successor to PifCo)	New York Stock Exchange
5.375% Global Notes due 2021, issued by PGF (successor to PifCo)	New York Stock Exchange
6.875% Global Notes due 2040, issued by PGF (successor to PifCo)	New York Stock Exchange
6.750% Global Notes due 2041, issued by PGF (successor to 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, 2014 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

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EXPLANATORY NOTE

The filing of this annual report for 2014 was delayed because we required additional time to complete disclosures in this annual report related to the write-off described below and to finalize disclosures in this annual report to describe material weaknesses in our internal control over financial reporting. Those material weaknesses are described in Item 15, Controls and Procedures.

In the third quarter of 2014, we wrote off U.S.$2,527 million of capitalized costs representing amounts that Petrobras overpaid for the acquisition of property, plant and equipment in prior years.

In 2009, the Brazilian federal police began an investigation called “Lava Jato” (Car Wash) aimed at criminal organizations engaged in money laundering in several Brazilian states. The Lava Jato investigation is extremely broad and involves numerous investigations into several criminal practices focusing on crimes committed by individuals in different parts of Brazil and sectors of the Brazilian economy.

Over the course of 2014, the Brazilian Federal Prosecutor’s Office focused part of its investigation on irregularities involving Petrobras’s contractors and suppliers and uncovered a broad payment scheme that involved a wide range of participants. According to testimony from Brazilian criminal investigations that became available beginning in October 2014, former senior Petrobras personnel conspired with contractors, suppliers and others from 2004 through April 2012 to establish and implement an illegal cartel that systematically overcharged Petrobras in connection with the acquisition of property, plant and equipment. Two former Petrobras executive officers (diretores) and one former executive manager were involved in this payment scheme, none of whom has been affiliated with us since April 2012; they are referred to in this annual report as the “former Petrobras personnel.” The overpayments were used to fund improper payments to political parties, elected officials or other public officials, individual contractor personnel, the former Petrobras personnel and other individuals involved in the payment scheme. We did not make the improper payments, which were made by the contractors and suppliers and by intermediaries acting on behalf of the contractors and suppliers.

We believe that under IAS 16, the amounts we overpaid pursuant to this payment scheme should not have been included in the historical costs of our property, plant and equipment. However, we cannot specifically identify either the individual contractual payments that include overcharges or the reporting periods in which overpayments occurred. As a result, we developed a methodology to estimate the aggregate amount that we overpaid under the payment scheme, in order to determine the amount of the write-off representing the overstatement of our property, plant and equipment resulting from overpayments used to fund improper payments. The circumstances and the methodology are described in this annual report.

The following sections of this annual report contain disclosures related to the Lava Jato investigation and the methodology adopted to address the overpayments:

· Item 3, Risk Factors, contains risks related to the estimation methodology used to determine the impact of the overpayments, the ongoing regulatory investigations, the pending civil litigation in the US, and material weaknesses in internal control over financial reporting;

· Item 4, Information on the Company, contains information regarding affected property, plant and equipment;

· Item 5, Operating and Financial Review and Prospects, contains a description of the charge for the overpayments, and a discussion of the estimation methodology in the Critical Accounting Estimates;

· Item 6, Directors, Senior Management and Employees, contains a description of the new board members, senior management, and the special committee serving as a reporting line for our internal investigations;

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FORWARD-LOOKING STATEMENTS

This annual report includes 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. The forward-looking statements contained in this annual report, which address our expected business and financial performance, among other matters, contain words such as “believe,” “expect,” “estimate,” “anticipate,” “intend,” “plan,” “aim,” “will,” “may,” “should,” “could,” “would,” “likely,” “potential” and similar expressions.

Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date on which they are made. There is no assurance that the expected events, trends or results will actually occur.

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 pricing strategy and development of additional revenue sources; and

· the impact, including cost, of acquisitions and divestments.

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 assumptions and factors. These factors include, but are not limited to, the following:

· 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;

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GLOSSARY OF PETROLEUM INDUSTRY TERMS

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

ANEEL	The Agência Nacional de Energia Elétrica (National Electrical Energy Agency), or ANEEL, is the federal agency that regulates the electricity industry in Brazil.
ANP	The Agência Nacional de Petróleo, Gás Natural e Biocombustíveis (National Petroleum, Natural Gas and Biofuels Agency), or ANP, is the federal agency that regulates the oil, natural gas and renewable fuels industry in Brazil.
API	Standard measure of oil density developed by the American Petroleum Institute.
Assignment Agreement	An agreement under which the Brazilian federal government assigned to us the right to explore and produce oil, natural gas and other fluid hydrocarbons in specified pre-salt areas in Brazil. See Item 10. “Additional Information—Material Contracts—Assignment Agreement.” Also referred to as the “Transfer of Rights Agreement.”
Barrels	Standard measure of crude oil volume.
BNDES	The Banco Nacional de Desenvolvimento Econômico e Social (the Brazilian Development Bank).
BSR	Buoyancy supported riser.
CGDU	The Controladoria Geral da União (General Federal Inspector’s Office), or CGDU, is an advisory body of the Brazilian Presidency, responsible for assisting in matters related to the protection of federal public property (patrimônio público) and the improvement of transparency in the Brazilian executive branch, through internal control activities, public audits, and the prevention and combat of corruption, among others.
Condensate	Light hydrocarbon substances produced with natural gas, which condense into liquid at normal temperature and pressure.
CMN	The Conselho Monetário Nacional (National Monetary Council), or CMN, is the highest authority of the Brazilian financial system, responsible for the formulation of the Brazilian currency and credit policy.
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 (Brazilian Securities and Exchange Commission), 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.

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DoJ	The U.S. Department of Justice.
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.
PGF	Petrobras Global Finance B.V.
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, 2014, 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.

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	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 for 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 reserve 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.
SPE	The Society of Petroleum Engineers.
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.
TCU	The Tribunal de Contas da União (Federal Auditor’s Office), or TCU, is an advisory body of the Brazilian Congress, responsible for assisting it in matters related to the supervision of the Brazilian executive branch with respect to accounting, finance, budget, operational and public property (patrimônio público) matters.
TLWP	Tension Leg Wellhead Platform.
Total depth	Total depth of a well, including vertical distance through water and below the mudline.
Ultra-deep water	Over 1,500 meters (4,921 feet) deep.

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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

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PRESENTATION OF FINANCIAL AND OTHER INFORMATION

This is the annual report of Petróleo Brasileiro S.A.—Petrobras, or Petrobras. Unless the context otherwise requires, the terms “Petrobras,” “we,” “us,” and “our” refer to Petróleo Brasileiro S.A.—Petrobras and its consolidated subsidiaries, 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 fully and unconditionally guarantee the notes issued by PGF. In the past, we used our former wholly-owned subsidiary, Petrobras International Finance Company S.A., or PifCo, as a vehicle to issue notes that we fully and unconditionally guaranteed. On December 29, 2014, PifCo merged into PGF, and PGF assumed PifCo’s obligations under all outstanding notes originally issued by PifCo (together with the notes issued by PGF, the “PGF notes”), which continue to benefit from our full and unconditional guarantee. PGF is not required to file periodic reports with the U.S. Securities and Exchange Commission, or SEC. See Note 36 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, 2014, 2013 and 2012 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:

· data contained in this annual report regarding capital expenditures, investments and other expenditures during the corresponding year that were not derived from the audited consolidated financial statements have been translated from reais at the average rates prevailing during such corresponding year;

· historical data contained in this annual report regarding balances of investments, commitments or other related costs that were not derived from the audited consolidated financial statements have been translated from reais at the period-end exchange rate; 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.

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Our management is currently working on our updated business and management plan, which we expect to release soon. Until we release our updated business and management plan, and for purposes of this annual report, all of our projections and forward-looking amounts have been projected on a constant basis and have been translated from reais using an average exchange rate for 2015 of R$3.10 to U.S.$1.00. In addition, future calculations involving an assumed price of crude oil have been calculated using a Brent crude oil price of U.S.$60 per barrel for 2015, adjusted for our quality and location differences, unless otherwise stated.

PRESENTATION OF INFORMATION CONCERNING RESERVES

We apply the SEC rules for estimating and disclosing oil and gas reserve quantities included in this annual report. In accordance with those rules, we estimate reserve volumes 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, except for reserves in certain fields for which volumes have been estimated using gas prices as set forth in our contractual arrangements for the sale of gas. Reserve volumes of non-traditional reserves, such as synthetic oil and gas, are also included in this annual report in accordance with SEC rules. In addition, the rules also utilize a reliable technology definition that permits reserves to be added based on field-tested technologies.

DeGolyer and MacNaughton (D&M) used our reserve estimates to conduct a reserves audit of 96.5% of our net proved crude oil, condensate and natural gas reserves as of December 31, 2014 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, 2014 from the properties we operate in Argentina. Furthermore, D&M used our reserve estimates to conduct a reserves audit of 100% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2014 in properties we operate in the United States. The reserve estimates were prepared in accordance with the reserves definitions in Rule 4-10(a) of Regulation S-X. All reserve 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 16, 2015, we filed proved reserve estimates for Brazil with the ANP, in accordance with Brazilian rules and regulations, totaling net volumes of 13.7 bnbbl of crude oil and condensate and 15.0 tcf of natural gas. The reserve estimates filed with the ANP were approximately 27.3% 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 SPE. The aggregate reserve estimates from our international operations, under SPE guidelines, amounted to 0.3 bnbbl of crude oil, condensate and NGL and 1.0 tcf of natural gas as of December 31, 2014, which is approximately 2.6% 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.

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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, 2014, 2013, 2012, 2011 and 2010, derived from our audited consolidated financial statements, which were audited by PricewaterhouseCoopers Auditores Independentes–PwC for the years ended December 31, 2014, 2013 and 2012 and KPMG Auditores Independentes for the years ended December 31, 2011 and 2010.

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,
	2014	2013	2012	2011	2010
	(U.S.$ million)
Assets:
Cash and cash equivalents	16,655	15,868	13,520	19,057	17,655
Marketable securities	9,323	3,885	10,431	8,961	15,612
Trade and other receivables, net	7,969	9,670	11,099	11,756	10,845
Inventories	11,466	14,225	14,552	15,165	11,808
Assets classified as held for sale	5	2,407	143	−	−
Other current assets	5,414	6,600	8,049	9,653	7,639
Long-term receivables	18,863	18,782	18,856	18,962	22,637
Investments	5,753	6,666	6,106	6,530	6,957
Property, plant and equipment	218,730	227,901	204,901	182,918	168,104
Intangible assets	4,509	15,419	39,739	43,412	48,937
Total assets	298,687	321,423	327,396	316,414	310,194
Liabilities and shareholders’ equity:
Current liabilities	31,118	35,226	34,070	36,364	33,577
Non-current liabilities(1)	30,373	30,839	42,976	34,744	30,251
Non-current finance debt(2)	120,218	106,235	88,484	72,718	60,417
Total liabilities	181,709	172,300	165,530	143,826	124,245
Shareholders’ equity
Share capital (net of share issuance costs)	107,101	107,092	107,083	107,076	107,062
Reserves and other comprehensive income (deficit)(3)	9,171	41,435	53,631	64,240	77,048
Shareholders' equity attributable to the shareholders of Petrobras	116,272	148,527	160,714	171,316	184,110
Non-controlling interests	706	596	1,152	1,272	1,839
Total equity	116,978	149,123	161,866	172,588	185,949
Total liabilities and shareholders' equity	298,687	321,423	327,396	316,414	310,194
__________________ (1) Excludes non-current finance debt.
(2) Excludes current portion of finance debt.
(3) Change in interest in subsidiaries, profit reserve and accumulated other comprehensive income (deficit).

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INCOME STATEMENT DATA

IFRS Summary Financial Data

	For the Year Ended December 31,
	2014(1)	2013	2012	2011	2010
	(U.S.$ million, except for share and per share data)
Sales revenues	143,657	141,462	144,103	145,915	120,452
Net income (loss) before finance income (expense), share of earnings in equity-accounted investments, profit sharing and income taxes	(6,963)	16,214	16,900	27,285	26,372
Net income (loss) attributable to the shareholders of Petrobras	(7,367)	11,094	11,034	20,121	20,055
Weighted average number of shares outstanding:
Common	7,442,454,142	7,442,454,142	7,442,454,142	7,442,454,142	5,683,061,430
Preferred	5,602,042,788	5,602,042,788	5,602,042,788	5,602,042,788	4,189,764,635
Net income (loss) before financial results, profit sharing and income taxes per:
Common and Preferred shares	(0.53)	1.24	1.30	2.09	2.67
Common and Preferred ADS	(1.06)	2.48	2.60	4.18	5.34
Basic and diluted earnings (loss) per:
Common and Preferred shares	(0.56)	0.85	0.85	1.54	2.03
Common and Preferred ADS	(1.12)	1.70	1.70	3.08	4.06
Cash dividends per (2):
Common shares	−	0.22	0.24	0.53	0.70
Preferred shares	−	0.41	0.48	0.53	0.70
Common ADS	−	0.44	0.48	1.06	1.40
Preferred ADS	−	0.82	0.96	1.06	1.40
____________________ (1) In 2014, we wrote-off U.S.$2,527 million of incorrectly capitalized overpayments and recognized impairment losses of U.S.$16,823 million. See Notes 3 and 14 to our audited consolidated financial statements, respectively, for further information. (2) Pre-tax interest on capital and/or dividends proposed for the year. Amounts were translated from the original amounts in reais using the balance sheet date exchange rate.

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RISK FACTORS

Risks Relating to Our Operations

Maintaining 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 is highly dependent upon our ability to successfully develop our existing reserves and, in the long term, to obtain additional reserves. The development of the sizable reservoirs in deep and ultra-deep waters, including the pre-salt reservoirs that have been granted 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 granted 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 may 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.

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 depreciates in relation to the U.S. dollar, which could have a negative impact on our results of operations and financial condition.

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. For instance, on September 1, 2014, the Brent crude oil price per barrel was U.S.$101.37, while only five months later, on January 30, 2015, the Brent crude oil price per barrel was U.S.$50.77.

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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 Brazilian demand, increases in the price of crude oil and oil products 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.

From the fourth quarter of 2010 through the third quarter of 2014, we sold some of our oil products (such as diesel and gasoline) at prices below international prices. We may not be able to fully offset the losses in our Brazilian downstream operations during this 2010-2014 period if we are unable to benefit from the current spread between low international crude oil prices and high Brazilian domestic oil product prices for an extended period of time.

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 may also affect the value of our proved reserves.

We have substantial liabilities and are exposed to short-term liquidity constraints, which could make it difficult for us to obtain financing for our planned investments and adversely affect our financial condition and results of operations.

In order to finance the capital expenditures needed to meet our long-term growth objectives for oil production, we have incurred a substantial amount of debt. As our cash flow from operations in recent years has not been sufficient to fund our capital expenditures, debt service and payment of dividends, our debt has significantly increased since 2010. Our total debt (including accrued interest) increased by 16% to U.S.$132,086 million as of December 31, 2014 from U.S.$114,236 million as of December 31, 2013. Our debt, net of cash, cash equivalents and marketable securities, increased by 12% to U.S.$106,108 million as of December 31, 2014 compared to U.S.$94,483 million as of December 31, 2013. 27% of our existing debt (principal), or U.S.$34.8 billion, will mature in the next three years. In order to develop our oil and natural gas reserves, maintain our ability to supply the Brazilian domestic market and amortize scheduled debt maturities, we will need to raise significant amounts of debt capital from a broad range of funding sources.

To service our debt after meeting our capital expenditure targets, we have relied upon, and may continue to rely upon, a combination of cash flows provided by our operations, drawdowns under our available credit facilities, our cash and short-term financial investments balance and the incurrence of additional indebtedness. Credit rating agencies have recently expressed concerns regarding (i) liquidity pressures and our capacity to meet our principal and interest payment obligations maturing in the short- and medium-term, (ii) our negative free cash flow in the last few years primarily resulting from our significant capital expenditures, (iii) our ability to access any source of financing in the short-term; (iv) the total size of our debt, (v) the increase of our indebtedness over the last few years and (vi) the diversion of our management’s focus from our core business in order to manage issues related to the ongoing Lava Jato investigation. On February 24, 2015, we lost our Moody’s investment grade rating for all of our credit ratings.

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If, for any reason, we are faced with continued difficulties in accessing debt financing, this could hamper our ability to achieve our long-term production targets and could impair our ability to timely meet our principal and interest payment obligations with our creditors, as our cash flow from operations is currently insufficient to fund such both planned capital expenditures and all of our debt service obligations.

Additionally, any further lowering of our credit ratings may have adverse consequences on our ability to obtain financing or may impact our cost of financing, also making it more difficult or costly to refinance maturing obligations. Our inability to obtain financing on favorable terms could have an adverse effect on our results of operations and financial condition. A further downgrade in our credit ratings may result in a less liquid market for our debt and equity securities, because certain institutions would be unable to purchase our securities, therefore reducing our investor base.

As a result of the above, we may not be able to make the capital expenditures in the amounts needed to maintain our long-term growth objectives for oil production, which may adversely affect our results of operations and financial condition.

If such constraints occur at a time when our cash flow from operations are less than the resources needed to fund our capital expenditures or to meet our principal and interest payments obligations, in order to provide additional liquidity to our operations, we could be forced to further reduce our planned capital expenditures and increase the numbers of assets to be sold under our divestment program. A reduction in our capital expenditure program or the sale of strategic assets under our divestment program could significantly affect our results of operations and financial condition.

Despite the fact that the Brazilian federal government (as our controlling shareholder) is not responsible or liable for any of our liabilities – including those derived from the bonds we issue in the international capital markets – our credit rating is sensitive to any change in the Brazilian federal government credit rating. Any lowering of the Brazilian federal government credit ratings may have additional adverse consequences on our ability to obtain financing or our cost of financing, and consequently, on our results of operations and financial condition.

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, 2014, approximately 82% of our financial debt liabilities were 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 the U.S. dollar 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 this depreciation. Considering the average exchange rate of each year, from 2003 to 2011, the real appreciated against U.S. dollar each year (by an average of 7% per year), except for 2009 (when it depreciated by 9%). In 2014 the real depreciated 9.1% against the U.S. dollar, compared to depreciation of 10.4% in 2013 and depreciation of 16.7% in 2012. Throughout 2015, the real has continued to depreciate against the U.S. dollar. Through April 30, 2015, it has depreciated by 12.7% compared to December 31, 2014.

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 of the real, our cash generation relative to our capacity to service debt may decline, impacting our cash balance.

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As of December 31, 2014, approximately 50% of our total indebtedness consisted of floating rate debt. We generally do not enter into derivative contracts or similar financial instruments or make other arrangements with third parties to hedge against the risk of an increase in interest rates. Additionally, we have debt maturities that amount to U.S.$76.8 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. The cost of any new indebtedness may also be negatively affected by the February 2015 downgrade of our credit ratings below investment grade by Moody’s and possible further downgrades.

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 will affect the composition of our debt and may increase our debt service payments, which could have an adverse effect on our results of operations and financial condition.

We rely on key third-party suppliers and service providers to provide us with parts, components, services and critical resources that we need to operate our business and complete our major projects, which could be adversely affected by any failure or delay by such third parties in performing their obligations or any deterioration in the financial condition of such third parties.

Our ability to maintain our long-term growth objectives for oil production depends upon successful delivery of major exploration and production projects. Failure to successfully deliver such major projects, or delays in doing so, could adversely affect our results of operations and financial condition.

We rely upon various key third-party suppliers, vendors and service providers to provide us with parts, components, services and critical resources, which we need to operate and expand our business. If these key suppliers, vendors and service providers critically fail to deliver, or are delayed in delivering, equipment, service or critical resources to our major projects, we may not meet our operating targets in the time frame we expected. We may ultimately need to delay or suspend one or more of our major projects, which could have an adverse effect on our results of operations and financial condition.

We are susceptible to the risks of performance, product quality and financial condition of our key suppliers, vendors and service providers. For instance, their ability to adequately and timely provide us with parts, components, services and resources critical to our major projects may be affected if they are facing financial constrains or times of general financial stress and economic downturn. As a result of the ongoing Lava Jato investigation, a number of our Brazilian contractors and suppliers have been unable to secure financing and are currently facing liquidity and bankruptcy concerns that may affect their ability to continue as our key suppliers, vendors and service providers. Although we work closely with our key suppliers, vendors and service providers to avoid supply-related problems, there can be no assurance that we will not encounter supply disruptions in the future or that we will be able to timely replace such suppliers or service providers that are not able to meet our needs, which might adversely affect a timely and successful execution of our major projects, and consequently, our results of operations and financial condition. Currently, we are facing delays in the delivery of some key assets to meet our production targets and reach our long-term growth objectives for oil production. As a result, for instance, we have postponed the delivery of four FPSOs that had been scheduled to come on stream in 2016 (P-66, P-74, P-67 and P-65).

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In addition, we have imposed a temporary suspension on the ability of companies belonging to 24 corporate groups to participate as suppliers and contractors in future bids for new contracts and services, while we and the Brazilian authorities analyze the involvement and participation of these companies in alleged illegal conduct in connection with the Lava Jato investigation. See Note 3 to our audited consolidated financial statements for further information about the Lava Jato investigation. A number of these suppliers and contractors have historically acted as key suppliers, vendors and service providers for our major projects. There can be no assurance that these companies will be permitted to participate in our future major projects or that we will be able to replace such key suppliers, vendors and service providers with others that would be able to meet our needs, which could affect the successful and timely delivery of our major future projects, and consequently our results of operations and financial condition.

We are also subject to Brazilian local content requirements arising out of our concession agreements, the Assignment Agreement and the Libra’s Production Sharing Agreement. These requirements, along with the temporary suspension of many of our local suppliers described above, could cause delays in some of our major projects if we are unable to timely replace Brazilian suppliers or service providers that fail to perform their obligations under our contracts. Unless ANP exempts us from complying with local content requirements, as to which there is no assurance, we could face delays or fines in the execution of our current major exploration and production projects.

We are exposed to the credit risks of certain of our customers and associated risks of default. Any material nonpayment or nonperformance by some of our customers could adversely affect our cash flow, results of operations and financial condition.

Some of our customers may experience financial constrains or liquidity issues that could have a significant negative effect on their creditworthiness. Severe financial issues encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. For instance, as of December 31, 2014, certain subsidiaries of Centrais Elétricas Brasileiras S.A. – Eletrobras owed us U.S.$3.0 billion under energy supply agreements. In 2014, we recognized an allowance for impairment of trade receivables from the isolated electricity sector in the Northern region of Brazil (amounting to U.S.$1.9 billion), mostly to cover certain trade receivables due by Eletrobras’s subsidiaries. See Note 8.4 to our audited consolidated financial statements.

In addition, many of our customers finance their activities through their cash flows from operations, the incurrence of short and long term debt or the issuance of debt. Declining financial results and economic conditions in Brazil, and resulting decreased cash flows, combined with a lack of debt or equity financing for our customers may affect us, since many of our customers are Brazilian, and may have significantly reduced liquidity and limited ability to make payments or perform their obligations to us. As we have not obtained any other guarantees to minimize our customers’ credit risk, their financial problems could result in a decrease in our operating cash flows and may also reduce or curtail our customers’ future demand for our products and services, which may have an adverse effect on our results of operations and financial condition.

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. 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.

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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.

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 applicable agreements executed with the Brazilian federal government. We possess, as a concessionaire of certain oil and natural gas fields in Brazil, the exclusive right to develop the volumes of crude oil and natural gas included in our reserves pursuant to concession agreements, the Libra Production Sharing Agreement and the Assignment Agreement awarded to us by the Brazilian federal government, and except for the profit oil owed to the Brazilian federal government under the Libra Production Sharing Agreement, we own the hydrocarbons we produce under those contractual arrangements. 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, the Libra Production Sharing Agreement and the Assignment Agreement may be revoked if we do not comply with our obligations under such contractual arrangements.

The Assignment Agreement we entered into with the Brazilian federal government is a related party transaction subject to future price readjustment.

The transfer to us of oil and gas exploration and production rights related to specific pre-salt areas, subject to a maximum production of five billion boe, is governed by Law No. 12,276/2010 and 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.

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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 ongoing negotiations with the Brazilian federal government regarding the revision process of the Assignment Agreement. See Item 4. “Information on the Company—Exploration and Production-Santos Basin—Assignment Agreement” 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 could require further negotiations.

Beginning June 2014, CNPE Resolution No. 01/2014 authorized the Brazilian federal government to directly engage Petrobras, under production sharing agreements, to produce oil, natural gas and fluid hydrocarbons in the Assignment Agreement areas at a volume exceeding the five bnboe maximum production originally agreed to under the Assignment Agreement. However, we have not initiated negotiations of the terms of these production sharing agreements and do not have an estimate of when these agreements may be executed, nor can we assure that their terms would be favorable to us.

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 evolving industry standards and best practices, and 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. 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 significant costs 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), the various Brazilian state environmental agencies and the ANP, among others, routinely inspect our facilities, and may impose fines, restrictions on operations, or other sanctions in connection with their 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.

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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 possible 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, there could be 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 and financial condition.

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

We are currently a party to numerous legal proceedings relating to civil, administrative, tax, labor, environmental and corporate 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 30 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 results of operations and financial condition. 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, litigation could result in restrictions on our operations and have a material adverse effect on some of our businesses.

We are a defendant in a purported class action lawsuit and three individual actions by institutional investors, all in the United States District Court for the Southern District of New York (SDNY). See Item 8. “Financial Information—Legal Proceedings” for a description of the U.S. securities class action litigation. Because the actions are in their early stages, the possible loss or range of losses, if any, arising from the litigation cannot be estimated, and consequently we have made no provisions with respect to this litigation. In the event that this litigation is decided against us, or we enter into an agreement to settle such matters, we may be required to pay substantial amounts.

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 or those of our key third-party suppliers, vendors and service providers 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 results of operations and financial condition.

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Compliance and Control Risks

We are exposed to behaviors incompatible with our ethics and compliance standards, and failure to timely detect or remedy any such behavior may have a material adverse effect on our results of operations and financial condition.

Our business, including relationships with third parties, is guided by ethical principles. We have adopted a Code of Ethics and a number of internal policies designed to guide our management, employees and contractors and reinforce our principles and rules for ethical behavior and professional conduct. We offer a confidential hotline, managed through our Ombudsman, for employees, contractors and other third parties. See Item 6. “Directors, Senior Management and Employees—Ombudsman.”

We are subject to the risk that our employees, contractors or any person doing business with us may engage in fraudulent activity, corruption or bribery, circumvent or override our internal controls and procedures or misappropriate or manipulate our assets for their personal or business advantage to our detriment. This risk is heightened by the fact that we have a large number of complex, valuable contracts with local and foreign suppliers, as well as the geographic distribution of our operations and the wide variety of counterparties involved in our business. We have in place a number of systems for identifying, monitoring and mitigating these risks, but our systems may not be effective.

It is difficult for us to ensure that all of our employees and contractors, totaling over 371,000, will comply with our ethical principles. Any failure – real or perceived – to follow these principles or to comply with applicable governance or regulatory obligations could harm our reputation, limit our ability to obtain financing and otherwise have a material adverse effect on our results of operations and financial condition.

Our management has identified material weaknesses in our internal control over financial reporting, and has concluded that our internal control over financial reporting was not effective at December 31, 2014, which may have a material adverse result on our results of operation and financial condition.

Our management identified a number of material weaknesses in our internal control over financial reporting in 2014. For example, management overrides by certain former Petrobras personnel relating to our large investment projects in the Exploration and Production, Refining, and Gas and Power business segments did not comply with our existing internal controls over the process of contracting for services in these segments.

In addition, our management identified material weaknesses related to (i) internal controls over property, plant and equipment (specifically with respect to the evaluation of the financial condition of our contractors and suppliers, termination costs and write-downs of payments made in advance, among others), (ii) the review and approval of manual journal entries, and (iii) managing access to critical transactions in our systems and segregation of duties. As a result, our management concluded that our internal control over financial reporting was not effective at December 31, 2014. Although we have developed and implemented several measures to remedy these material weaknesses, we cannot be certain that there will be no other material weaknesses in our internal control over financial reporting in the future. For more information about these matters, see Item 15. “Controls and Procedures—Management’s Report on Internal Control over Financial Reporting.”

If our efforts to remediate the material weaknesses are not successful, we may be unable to report our results of operations for future periods accurately and in a timely manner and make our required filings with government authorities, including the SEC. There is also a risk that there could be accounting errors in our financial reporting, and we cannot be certain that in the future additional material weaknesses will not exist or otherwise be discovered. Any of these occurrences could adversely affect our business and operating results and could generate negative market reactions, potentially leading to a decline in the price of our shares, ADSs and debt securities.

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Ongoing SEC and DoJ investigations regarding the possibility of non-compliance with the U.S. Foreign Corrupt Practices Act could adversely affect us. Violations of this or other laws may require us to pay fines and expose us and our employees to criminal sanctions and civil suits.

In November 2014, we received a subpoena from the SEC requesting certain documents and information about us relating to, among other things, the Lava Jato investigation and any allegations regarding a violation of the U.S. Foreign Corrupt Practices Act. The DoJ is conducting a similar inquiry, and we are voluntarily cooperating with both investigations. The internal investigation and related government inquiries concerning these matters remain ongoing, and it is still not possible to estimate the duration, scope or results of the internal investigation or related inquiries by relevant authorities. While we are cooperating fully with both investigations, adverse developments in connection with these investigations, including any expansion of the scope of the investigations, could negatively impact us and could divert the efforts and attention of our management team from our ordinary business operations. In connection with any SEC or DoJ investigation, there can be no assurance that we will not be required to pay penalties or provide other financial relief, or consent to injunctions or orders on future conduct or suffer other penalties, any of which could have a material adverse effect on us. See “Item 8. – Financial Information—Legal Proceedings.”

Our methodology to estimate the incorrectly capitalized overpayments, uncovered in the context of the Lava Jato investigation, involves some degree of uncertainty. If substantive additional information comes to light in the future that would make our estimate for the overstatements of our assets appear, in retrospect, to have been materially underestimated or overestimated, this could require a restatement of our financial statements and may have a material adverse effect on our results of operations and financial condition and affect the market value of our securities.

As a result of the findings of the Lava Jato investigation, in the third quarter ended September 30, 2014, we wrote off U.S.$2,527 million of capitalized costs representing amounts that Petrobras overpaid for the acquisition of property, plant and equipment in prior years.

According to testimony from Brazilian criminal investigations that became available beginning October 2014, senior Petrobras personnel conspired with contractors, suppliers and others, from 2004 through April 2012, to establish and implement an illegal cartel that systematically overcharged us in connection with the acquisition of property, plant and equipment. In addition to the payment scheme, the investigations identified several specific instances of other contractors and suppliers that allegedly overcharged Petrobras and used the overpayment received from their contracts with us to fund improper payments, unrelated to the payment scheme, to certain Petrobras employees, including the former Petrobras personnel and a former Chief International Officer. See “Explanatory Note” and Note 3 to our audited consolidated financial statements for further information about the Lava Jato investigation, the overpayments charged by certain contractors and suppliers to Petrobras and our methodology to estimate the overstatement of our assets.

We concluded that a portion of our costs incurred to build property, plant and equipment that resulted from contractors and suppliers in the cartel overcharging us to make improper payments should not have been capitalized in our historical costs of property, plant and equipment. As it is impracticable to identify the specific periods and amounts for the overpayments made by us, we considered all the available information to determine the impact of the overpayments charged to us. As a result, to account for these overpayments, we developed a methodology to estimate the aggregate amount that we overpaid under the payment scheme, in order to determine the amount of the write-off representing the overstatement of our assets resulting from overpayments used to fund improper payments.

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The Lava Jato investigation is still ongoing and it could be a significant amount of time before the Brazilian federal prosecutors conclude their investigation. As a result of this investigation, substantive additional information might come to light in the future that would make our estimate for overpayments appear, in retrospect, to have been materially low or high, which may require us to restate our financial statements to further adjust the write-offs representing the overstatement of our assets recognized in our interim consolidated financial statements for the nine-month period ended September 30, 2014.

We believe that we have used the most appropriate methodology and assumptions to determine the amounts of overpayments incorrectly capitalized based on the information available to us, but our estimation methodology involves some degree of uncertainty. There can be no assurance that the write-offs representing the overstatement of our assets, determined using our estimation methodology, and recognized in our interim consolidated financial statements for the nine-month period ended September 30, 2014, are not underestimated or overestimated. In the event that we are required to write-off additional historical costs from our property, plant and equipment or to reverse write-offs previously recognized in our financial statements, this might impact the total value of our assets and we may be subject to negative publicity, credit rating downgrades, or other negative material events, which may have a material adverse effect on our results of operations and financial condition and affect the market value of our securities.

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 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 with parties or 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 in ensuring 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.

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Risks Relating to Brazil

Brazilian political and economic conditions and investor perception of these 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;

· allegations of corruption against political parties, elected officials or other public officials, including allegations made in relation to the Lava Jato investigation; 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.

Historically, the country’s political scenario has influenced the performance of the Brazilian economy and political crises have affected the confidence of investors and the general public, which resulted in economic deceleration and heightened volatility in the securities issued abroad by Brazilian companies. Currently, Brazilian markets are experiencing heightened volatility due to the uncertainties derived from the ongoing Lava Jato investigation and its impacts on the Brazilian economy and political environment. Although Brazilian authorities have publicly described Petrobras as a victim of the alleged illegal conduct identified during the Lava Jato investigation, at this stage of the investigation, any developments in the Lava Jato investigation (foreseeable and unforeseeable) could have a material adverse effect on the Brazilian economy and on our results of operations and financial condition.

Additionally, since 2011, Brazil has been experiencing an economic slowdown. Gross Domestic Product, or GDP, growth rates were 0.1% in 2014, 2.7% in 2013, 1.8% in 2012 and 3.9% in 2011, compared to a GDP growth of 7.5% in 2010. Our results of operations and financial condition have been, and will continue to be, affected by the growth rate of GDP in Brazil because a substantial portion of our oil products are sold in Brazil. We cannot assure that GDP will increase or remain stable in the future. Future developments in the Brazilian economy may affect Brazil’s growth rates and, consequently, the consumption of our oil products. As a result, these developments could impair our results of operations and financial condition.

Allegations of political corruption against the Brazilian federal government and the Brazilian legislative branch could create economic and political instability.

In the past, members of the federal government and the Brazilian legislative branch have faced allegations of political corruption. As a result, a number of politicians, including senior federal officials and congressman, resigned or have been arrested. Currently, elected officials and other public officials in Brazil are being investigated for allegations of unethical and illegal conduct identified during the Lava Jato investigation being conducted by the Office of the Brazilian Federal Prosecutor. The potential outcome of these investigations is unknown, but they have already had an adverse impact on the image and reputation of the implicated companies (including Petrobras), in addition to the adverse impact on general market perception of the Brazilian economy. These proceedings, their conclusions or further allegations of illicit conduct could have additional adverse effects on the Brazilian economy. We cannot predict whether such allegations will lead to further instability or whether new allegations against Brazilian government officials will arise in the future. In addition, we cannot predict the outcome of any such allegations nor their effect on the Brazilian economy.

Inflation, and the Brazilian government’s measures to combat inflation, may contribute significantly to economic uncertainty in Brazil, and may materially adversely affect us.

Brazil has historically experienced high rates of inflation, particularly prior to 1995. Inflation, as well as government efforts to combat inflation, had significant negative effects on the Brazilian economy. More recently, inflation rates were 6.41% in 2014, 5.91% in 2013 and 5.84% in 2012, as measured by the IPCA, the National Consumer Price Index, compiled by IBGE (Brazilian Institute of Geography and Statistics).

Brazil may experience high levels of inflation in the future. The Brazilian government may introduce policies to reduce inflationary pressures, which could have the effect of reducing the overall performance of the Brazilian economy. Some of these policies may have an effect on our ability to access foreign capital or reduce our ability to execute our future business and management plans, particularly for those projects that rely on foreign partners.

The Brazilian government’s measures to control inflation have often included maintaining a tight monetary policy with high real interest rates. These policies have contributed to limiting the size and attractiveness of the local debt markets, requiring borrowers like us to seek foreign currency funding in the international capital markets. To the extent that there is economic uncertainty in Brazil, which weakens our ability to obtain external financing on favorable terms, the local Brazilian market may be insufficient to meet our financing needs, which in turn may materially adversely affect us.

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.

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The market for PGF’s debt securities may not be liquid.

Some of PGF’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 PGF’s notes. We cannot guarantee that the holders of PGF’s notes will be able to sell their notes in the future. If a market for PGF’s notes does not develop, holders of 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 timely 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. Such remittances under an ADR program are subject to a specific tax treatment in Brazil that may be more favorable to a foreign investor if compared to remitting gains originated from securities directly acquired by the investor in the Brazilian regulated stock markets. Therefore, an investor who opts to exchange ADSs for the underlying common or preferred share may be subject to less favorable tax treatment on gains with respect to these investments.

The exchange of ADSs for the underlying common or preferred shares is governed by CMN Resolution No. 4,373 and foreign investors who intend to do so are required to appoint a representative in Brazil for the purposes of Annex I of CMN Resolution No. 4,373, who will be in charge for keeping and updating the investors’ certificates of registrations with the Central Bank of Brazil, which entitles registered foreign investors to buy and sell directly on the BM&FBOVESPA. Such arrangements may require additional expenses from the foreign investor. Moreover, if such representatives fail to obtain or update the relevant certificates of registration, investors may incur in additional expenses or be subject to operational delays which could affect 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 directly 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.

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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, and under Petrobras’s by-laws must, generally with respect to disputes concerning rules regarding the operation of the capital markets, arbitrate any such claims. See Item 10. “Additional Information—Memorandum and Articles of Incorporation—Dispute Resolution.”

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 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 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.

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

If proceedings were brought in Brazil seeking to enforce our obligations in respect of the guaranty relating to 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.

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

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

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

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

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

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

then our obligations under the guaranty could be avoided, or claims with respect to that agreement could be subordinated to the claims of other creditors. Among other things, a legal challenge to the guaranty on fraudulent conveyance grounds may focus on the benefits, if any, realized by us as a result of the issuance of the PGF notes. To the extent that the guaranty is held to be a fraudulent conveyance or unenforceable for any other reason, the holders of the PGF notes would not have a claim against us under the relevant guaranty and would solely have a claim against PGF. We cannot assure you that, after providing for all prior claims, there will be sufficient assets to satisfy the claims of 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 has 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 is 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. 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 Relating to PGF’s Notes—European Union Savings Directive.” An investor should consult a tax adviser to determine the tax consequences of holding PGF’s notes for such investor.

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Item 4. Information on the Company

History and Development

Petróleo Brasileiro S.A.—Petrobras was incorporated in 1953 to conduct the Brazilian federal government’s hydrocarbon activities. We began operations in 1954 and 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, 2014, the Brazilian federal government owned 28.67% of our outstanding capital stock and 50.26% of our voting shares. See Item 7. “Major Shareholders and Related Party Transactions—Major Shareholders.” Our common and preferred shares have been traded on the BM&FBOVESPA since 1968 and on the NYSE in the form of ADSs 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 federal 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 Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Price Regulation.”

In 2010, new laws were enacted to regulate exploration and production activities in pre-salt areas not subject to existing concessions. Pursuant to this new legislation, we entered into an agreement with the Brazilian federal government on September 3, 2010, the Assignment Agreement, under which the government assigned to us the right to explore and produce oil, natural gas and other fluid hydrocarbons in specified pre-salt areas in Brazil. On December 2, 2013, we executed our first agreement with the Brazilian federal government under a production sharing regime. See Item 10. “Additional Information—Material Contracts—Assignment Agreement” and Item 10. “Additional Information—Material Contracts – Production Sharing Agreement.”

We operate through subsidiaries, joint ventures, joint operations 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 one of the largest companies in Latin America in terms of revenue. As a result of our legacy as Brazil’s former sole supplier of crude oil and oil products and our strong 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 2014, our average domestic daily oil production was 2,034 mbbl/d, which represents more than 90% of Brazil’s total oil production. Over 62.7% (7,965.9 mmboe) of our domestic proved reserves are located in our most developed area - the offshore Campos Basin - which allows us to optimize our infrastructure and limit our costs of exploration, development and production. The contribution of our most promising deepwater fields, located in the offshore Santos Basin (southeast Brazil), to our proved reserves and oil production is continuously growing. Our production process in the Santos Basin has benefited from the expertise we cultivated through similar production experiences in the Campos Basin.

Over 46 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.

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As of December 31, 2014, we had proved developed oil and gas reserves of 8,112.8 mmboe and proved undeveloped reserves of 4,599.7 mmboe in Brazil. The development of this large reserve base and the exploration of pre-salt areas has demanded, and will continue to demand, significant investments and the growth of our operations. To support this growth we have ordered the construction of 16 new FPSOs and planned 15 more for the period between 2015 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 2,176 mbbl/d and domestic refining throughput of 2,106 mbbl/d are currently below the levels required to meet domestic demand for transportation fuels, particularly gasoline, diesel and jet fuel. We are in the process of expanding and upgrading our refining capacity to meet growing demand in Brazil, but our current capacity is not sufficient to process the oil produced in Brazil necessary to satisfy such demand. Consequently, and for the foreseeable future, we will continue to import oil and oil products. 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, including the logistics and processing of natural gas. To meet our domestic demand, we process natural gas derived from our onshore and offshore (mainly from fields in the Campos, Espírito Santo and Santos Basins) production, import natural gas from Bolivia, and to the extent necessary, import LNG through our regasification terminals. We also participate in the domestic power market primarily through our investments in gas-fired thermoelectric power plants and in renewable energy. In addition, we participate in the fertilizer business, which is another important natural gas market.

Outside of Brazil, we operate in 16 countries. In Latin 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, through a joint venture, we produce oil in 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 “Information on the Company—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, biodiesel and 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.

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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 2014:

	Key Information by Business Segment, 2014
	Exploration and Production	Refining, Transportation and Marketing	Gas and Power	Biofuel	Distribution	International	Corporate	Eliminations	Group Total
	(U.S.$ million)
Sales revenues	65,616	112,320	17,882	266	41,729	13,912	−	(108,068)	143,657
Income (loss) before income taxes	21,764	(22,983)	(553)	(166)	760	(608)	(7,714)	676	(8,824)
Total assets at December 31	151,524	70,038	28,367	1,109	7,221	13,009	32,385	(4,966)	298,687
Capital expenditures and investments	24,164	7,778	2,545	112	446	1,513	446	−	37,004

Exploration and Production

Exploration and Production Key Statistics
	2014	2013	2012
	(U.S.$ million)
Exploration and Production:
Sales revenues	65,616	68,210	74,714
Income (loss) before income taxes	21,764	29,619	35,465
Property, plant and equipment	135,671	126,716	102,779
Capital expenditures and investments	24,164	27,566	21,959

Oil and gas exploration and production activities in Brazil are the largest components of our portfolio. We have gradually increased production over the past four decades, from 164 mbbl/d of crude oil, condensate and NGL in Brazil in 1970 to 2,034 mbbl/d in 2014. We aim to grow oil and gas reserves and production sustainably and be recognized for excellence in exploration and production operations.

The major target of our exploration and production segment is to produce (in Brazil and abroad), on average, 4,000 mbbl/d of crude oil, condensate and NGL during the 2020-2030 period. We expect to meet this target by:

• Finding and acquiring hydrocarbon reserves in Brazil, maintaining a minimum 12-year ratio (under SPE guidelines) between our reserves and production;

• Developing oil production in the pre-salt province in Brazil;

• Maximizing the oil and gas recovery in our production areas that have largely been developed;

• Exploring the Brazilian basins in a selective manner and sharing related risks with partners; and

• Exploring the Brazilian basins for natural gas.

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In supporting these objectives, we have implemented a variety of programs designed to manage our capital and operational expenditures: PROEF – which aims to increase operational efficiency; PROCOP – which aims to reduce the operational expenditures of our exploration and production segment; PRC-Poço – focused on reducing capital expenditures in the construction of our wells; PRC-SUB – focused on reducing capital expenditures in the installation of our subsea systems; and INFRALOG – which seeks to optimize our logistics infrastructure.

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 waters. Our exploration success has been in the deepwater, where the reservoirs in which we have made discoveries are substantially larger and where our technology and expertise have created a competitive advantage for us. In 2014, offshore production accounted for 90% of our production and deep water production accounted for 78% of our production in Brazil. 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.

Historically, we focused our offshore exploration and production activities on sandstone turbidite reservoirs, located primarily in the Campos Basin. In 2006, we were successful in drilling through a massive salt layer off the Brazilian coast that stretches from the Campos to the Santos Basins. The oil under the salt layer has in many areas been well-preserved in large reservoirs, leading to a number of important discoveries. This province, identified by the salt layer, occupies an area of approximately 149,000 km2 (36.8 million acres), of which we have rights to produce from 17.8% of the total area (approximately 26,430 km2 or 6.5 million acres), through acreage assigned to us under Concession Agreements and the Assignment Agreement. We are also part of the consortium that was granted a concession covering approximately 1,547.8 km2 (0.4 million acres), in the Libra area, under a Production Sharing Agreement.

The pre-salt reservoirs we have discovered are located in deep and ultra-deep waters at total depths of up to 7,000 meters (22,965 feet). The southern part of the pre-salt province consists of the Santos Basin, where the salt layer is approximately two kilometers thick. We have made significant discoveries in that area, including:

· BM-S-11: Lula, formerly Tupi, and the area of Berbigão, Sururu and Oeste de Atapu, formerly lara;

· BM-S-9: Lapa and Sapinhoá, formerly Carioca and Guará;

· BM-S-8: Carcará;

· BM-S-24: Júpiter;

· Assignment Agreement area: Búzios, Sul de Lula, Sul de Sapinhoá, Sépia and Itapu, formerly Franco, Sul de Tupi, Sul de Guará, Nordeste de Tupi and Florim, and the area of Norte de Berbigão, Sul de Berbigão, Norte de Sururu, Sul de Sururu and Atapu, formerly Entorno de Iara; and

· Libra.

In the northern part of the pre-salt province, the salt is thinner and much of the oil has migrated through the salt to the post-salt sandstone reservoirs of the Campos Basin. While some of the oil that formed has migrated, we still have made important discoveries in pre-salt reservoirs in the Campos Basin, as we drilled through the salt layers. Most of our current and future capital will be committed to developing the oil found in the pre-salt province, with an emphasis on the Santos Basin, given the size of its reservoirs and its potential.

In December 2014, the monthly average production in the pre-salt area (Campos and Santos Basins) was 666 mbbl/d, an increase of 93% compared to December 2013. Wells in the pre-salt province are highly productive. Total pre-salt production reached 800 mbbl/d on April 11, 2015 (a new daily production record) with only 39 producing wells. Twenty of these wells are located in the Santos Basin and were responsible for 64% of that production (511 mbbl/d).

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Production

During 2014, our oil and gas production in Brazil averaged 2,284 mboe/d, of which 89% was oil and 11% was natural gas. On December 31, 2014, our estimated net proved crude oil and natural gas reserves in Brazil were 12.7 bnboe, of which 85.4% was crude oil and 14.6% was natural gas. Brazil represented 92% of our worldwide production in 2014 and accounted for 97% of our worldwide reserves on December 31, 2014 on a barrels of oil equivalent basis. Over the last five years, approximately 90% of our total Brazilian production has been oil.

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 Baleia Franca	100% 100%	Deepwater Deepwater	Intermediate Oil 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
	Papa-Terra Pampo	62.5% 100%	Deepwater Shallow	Heavy Oil Intermediate Oil
	Roncador	100%	Ultra-deepwater	Intermediate Oil
	Vermelho	100%	Shallow	Intermediate 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	Araçás 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	Light 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

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Our average production per basin in Brazil as of December 31, 2014, December 31, 2013 and December 31, 2012 is summarized in the table below:

	2014				2013				2012
	Campos	Santos	Others	Total	Campos	Santos	Others	Total	Campos	Santos	Others	Total
Production(1)
Oil (mbb/d)	1,525.8	246.7	261.9	2,034.4	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	0.4	0.5	1.5	0.6	0.3	0.6	1.5	0.5	0.3	0.6	1.4
Total (mboe/d)	1,617.2	315.5	351.7	2,284.4	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	55	122	56	11	59	126	55	8	62	125

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(1) Includes synthetic oil and gas.

We offset the natural decline from our reservoirs and increase our total production of oil and gas by installing additional units in our deepwater fields. In 2014, our production of crude oil, condensate and NGL in Brazil averaged 2,034 mbbl/d, a 5.3% increase compared to the previous year. This increase was mainly attributable to the production from a number of recently received FPSOs that came online in 2013 and 2014 with a total oil processing capacity of 1,300 mbbl/d.

Information about our systems that came online in 2013 and 2014 is summarized in the table below:

Recently Developed Projects
Basin	Field	Unit Type	Production Unit	Crude Oil Nominal Capacity (bbl/d)	Natural Gas Nominal Capacity (mmcf/d)	Water Depth (meters)	Start Up (year)	Notes
Campos	Papa-Terra–Module 2	FPSO	P-63	140,000	35.3	1,200	2013	Post-salt
Campos	Roncador–Module 3	SS	P-55	180,000	211.9	1,795	2013	Post-salt
Campos	Roncador–Module 4	FPSO	P-62	180,000	211.9	1,600	2014	Post-Salt
Campos	Parque das Baleias (Baleia Azul, Jubarte, Cachalote, Baleia Anã & Baleia Franca)	FPSO	P-58	180,000	211.9	1,399	2014	Pre and post-salt
Campos	Papa-Terra–Module 1(1)	TLWP	P-61	‒	‒	1,180	2015	Post-salt production processed by P-63
Santos	Sapinhoá Pilot	FPSO	Cidade de São Paulo	120,000	176.6	2,140	2013	Pre-salt
Santos	Lula Northeastern area	FPSO	Cidade de Paraty	120,000	176.6	2,140	2013	Pre-salt
Santos	Baúna	FPSO	Cidade de Itajaí	80,000	70.6	275	2013	Post-salt
Santos	Lula-Iracema Southern area	FPSO	Cidade de Mangaratiba	150,000	282.5	2,220	2014	Pre-salt
Santos	Sapinhoá – Northern area	FPSO	Cidade de Ilhabela	150,000	211.9	2,140	2014	Pre-salt

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(1) Production from the P-61 platform is processed by the P-63 platform.

In 2014, we were able to connect and start producing from 57 new wells. Due to the new production systems that came online in 2014 and those that are planned to go online in 2015, we expect to increase our oil production in Brazil in 2015 by between 3.5% and 5.5% above our 2014 average.

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We recognized impairment losses for the fiscal year ended December 31, 2014 of U.S.$1.6 billion due to the impact of the recent decline in international crude oil prices on the price assumptions for certain of our oil and gas producing properties located in Brazil, including Frade, Pirapitanga, Tambuatá, Carapicu and Piracucá. We have also recognized impairment losses for the fiscal year ended December 31, 2014 of U.S.$536 million with respect to oil and gas production and drilling equipment, unrelated to oil and gas producing properties. These impairment losses are mainly related to the idle capacity of two drilling rigs in the future and to the demobilization of two oil platforms, which were not deployed in any oil and gas property as of December 31, 2014. For further information, see Note 14 to our audited consolidated financial statements.

Our exploration and production activities outside Brazil are included in our International business segment. See “Item 4. Information on the Company—International.”

Exploration

As of December 31, 2014, we had 133 exploration agreements covering a total of 158 exploratory blocks, corresponding to a total gross exploratory acreage of 90,000 km² (22.24 million acres), or a net exploratory acreage of 64,000 km² (15.81 million acres). We also had 56 evaluation plans underway, including 40 in exploratory areas and 16 in ring fence areas. We are exclusively responsible for conducting exploration activities under 68 exploratory agreements.

As of December 31, 2014, we had exploration partnerships with 29 foreign and domestic companies and were party to a total of 82 partnership exploratory agreements, in 58 of which we are the operator. We hold interests ranging from 40% to 100% in the exploration areas under concession or assigned to us.

In 2014, we invested a total of U.S.$4.5 billion in exploration activities in Brazil. We drilled a total of 74 exploratory wells in 2014, of which 37 were offshore and 37 onshore.

Reserves

Our reserves in Brazil as of December 31, 2014, December 31, 2013 and December 31, 2012 are summarized in the table below:

	2014				2013				2012
	Campos	Santos	Others	Total	Campos	Santos	Others	Total	Campos	Santos	Others	Total
Proved Reserves
Oil (mmbbl)	7,202.8	2,917.4	730.7	10,850.9	7,642.3	2,209.8	806.3	10,658.4	8,199.5	1,483.5	856.3	10,539.2
Gas (bcf)	4,578.4	4,339.7	2,252.2	11,170.3	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)	7,965.9	3,640.7	1,106.1	12,712.6	8,419.4	2,865.7	1,255.3	12,540.4	9,081.1	1,908.8	1,336.4	12,263.3

For the twenty-third consecutive year, we achieved a reserve replacement ratio higher than 100% under ANP and SPE guidelines, which means that we added more volume to our reserves than we produced throughout the year. Under SEC rules for estimating and disclosing oil and gas reserve quantities, our reserve replacement ratio in 2014 was 121%.

Exploration and Production Regimes Applicable to Petrobras in Brazil

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 then, we have participated in all of the auction rounds conducted by the ANP, including the first production-sharing regime auction round held on October 21, 2013. Currently, we operate under three different exploration and production regimes:

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· Concession Agreements: ANP grants rights, from time to time, through public auctions open to qualified operators, to explore and produce crude oil and gas reserves in Brazil under concession agreements for the blocks offered in each auction. We have participated in all of the concession auction rounds conducted by the ANP, including the 11th Round, held on May 14, 2013, in which we acquired 34 blocks located in multiple basins, and the 12^th Round, held on November 28, 2013, in which we acquired, directly and in partnership with other companies, 49 blocks located in multiple basins. These concession agreements have a term of 27 years following the declaration of commerciality, with the possibility of extension by the ANP.

· Assignment Agreement (Contrato de Cessão Onerosa): On September 3, 2010, we entered into an agreement with the Brazilian federal government, under which it assigned to us the right to conduct activities for the exploration and production of oil, natural gas and other fluid hydrocarbons in specified pre-salt areas. The agreement is subject to a maximum production of five bnboe over 40 years (extendable for five additional years), and we have already declared commerciality for this entire volume in the areas of Franco (Búzios), Sul de Tupi (Sul de Lula), Florim (Itapu), Nordeste de Tupi (Sépia), Sul de Guará (Sul de Sapinhoá) and Entorno de Iara (Norte de Berbigão, Sul de Berbigão, Norte de Sururu, Sul de Sururu and Atapu). See Item 10. “Additional Information—Material Contracts—Assignment Agreement.”

· Production Sharing Agreement (Contrato de Partilha de Produção): Under this regime, exploration and production licenses are awarded through a public auction to the consortium that offers the highest share of profit oil to the government. At a public auction held on October 21, 2013, a consortium including Petrobras was awarded the rights and obligations to operate and explore a strategic pre-salt area (known as Libra – which has an estimated recoverable volume of between 8 and 12 bnboe according to the ANP) located in the Santos Basin. On December 2, 2013, we executed the first agreement under this regime. We have a 40% interest in the Libra block and are its exclusive operator. This agreement has a term of 35 years. In June 2014, the CNPE enacted Resolution No. 1, which established that Petrobras could be directly engaged by the Brazilian federal government under a production sharing regime to produce the volume of oil, natural gas and fluid hydrocarbons from the Assignment Agreement areas that exceeds the five bnboe maximum production originally agreed under the Assignment Agreement or that may be negotiated during the revision process of the Assignment Agreement.

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Campos Basin Production

In 2013 and 2014, we installed several major systems in the Campos Basin. The largest systems were P-55 and P-62, FPSOs with individual capacities of 180 mbbl/d of oil and 211.9 mmcf/d (6 mmm³/d) of natural gas located in modules 3 and 4 of our largest field in the Campos Basin, Roncador. Another major project was P-58, an FPSO with 180 mmbl/d of oil and 211.9 mmcf/d (6 mmm³/d) of natural gas capacity located in the Parque das Baleias field. The last major project being developed in the Campos Basin is the Papa Terra development, consisting of two units with a combined capacity of 140 mbbl/d of oil and 35.3 mmcf/d (1 mmm³/d) of natural gas. Our projects in Roncador and Parque das Baleias are owned and operated 100% by Petrobras, while in Papa Terra we operate and have a 62.5% interest.

Most of our production in the Campos Basin is from post-salt reservoirs, but 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. In December 2014, the Campos Basin pre-salt area monthly average production was 260 mbbl/d, which represents an increase of 60% compared to December 2013. Our share of oil produced from the Campos Basin pre-salt reservoirs is 100%.

With the installation of these units, we expect that major new development projects for the Campos Basin have been completed, and most of our future development projects will focus on the pre-salt projects of the Santos Basin.

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. Over the past few years, based on efficiency metrics set forth under the PROEF program, we increased the efficiency of the Campos Basin Operational Unit from 75.4% in 2013 to 79.7% in 2014, and the efficiency of our Rio de Janeiro Operational Unit increased from 92.4% in 2013 to 95.4% in 2014. As a result of our investments to increase efficiency, production in 2014 from these areas was 104 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, 2014, we held rights to ten exploratory blocks and two exploration plans in the Campos Basin, comprising a total of 3,398 km² (0.84 million acres). During 2014, we drilled a total of ten exploratory wells (six of them in pre-salt reservoirs).

Santos Basin

The Santos Basin, which covers approximately 348,900 km² (86 million acres) and is located adjacent to and southwest of Campos Basin, is one of the most promising offshore exploration and production areas in the world. Since discovery in 2006, and with first production only in 2009, we have increased monthly oil production from the Santos Basin pre-salt area to 406,000 bbl/d by year-end 2014 (which represents an increase of 122% compared to December 2013). As of December 31, 2014, 26.9% and 38.9% of our total proved crude oil and natural gas reserves in Brazil, respectively, came from the Santos Basin.

Santos Basin Production

We are currently exploring and developing the Santos Basin pre-salt area under the Concessions, Assignment Agreement and Libra Production Sharing Agreement.

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Concession Agreements

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

In October 2010, we replaced the EWT with a long-term production system, the FPSO Cidade de Angra dos Reis. In 2012, this FPSO reached its maximum capacity of 100 mbbl/d with four production wells connected.

In 2013 we continued our development of the Santos Basin pre-salt with two additional units: FPSO Cidade de São Paulo in the Sapinhoá field (formerly known as Guará), with a production capacity of 120,000 bbl/d of oil and 176.6 mmcf/d (5 mmm³/d) of natural gas and FPSO Cidade de Paraty, in the Lula field at Lula Nordeste area, with the same production capacity as FPSO Cidade de São Paulo. Both units reached their maximum capacity in 2014, each having only four production wells connected.

In 2014, two additional systems were installed: FPSO Cidade de Mangaratiba in the Lula field at Iracema Norte, with a production capacity of 150,000 bbl/d of oil and 282.5 mmcf/d (8 mmm³/d) of natural gas and FPSO Cidade de Ilhabela, in the northern area of Sapinhoá field, with a production capacity of 150,000 bbl/d of oil and 211.9 mmcf/d (6 mmm³/d) of natural gas. By January 2015, this first unit was producing 66,000 bbl/d with only two wells connected and the second unit was producing 30,000 bbl/d of oil through one well that has been connected since November 2014.

We continue to concentrate our efforts on gathering information about the pre-salt reserves through EWTs and pilots. We currently have two units that can perform EWTs in the Santos Basin pre-salt area, the FPSO Dynamic Producer and Cidade de São Vicente. In 2014, EWTs were performed in Lula Central, Lula Sul and Iara Oeste.

We are also testing drilling technologies to improve efficiency and to optimize the definitive design of production platforms.

We have reduced the time required to drill and complete production wells in the Santos Basin pre-salt. In 2014, we drilled and completed a well in the Lula/Iracema Sul area with a final depth of 5,450 meters in 92 days.

As of December 31, 2014, we held exploration rights to one block and six exploration plans in the Santos Basin, comprising 4,774 km² (1.6 million acres), through Concession Agreements.

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 bnboe in the pre-salt area of the Santos Basin, and we have already declared commerciality for this entire volume from all six 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 six blocks, we have initiated the revision process of the Assignment Agreement with the Brazilian federal government, and we have returned the contingent block to the Brazilian federal government. See Item 10. “Additional Information—Material Contracts—Assignment Agreement.”

In 2014, we drilled nine wells located in the Assignment Agreement area. Over the next three years, we intend to proceed with our exploration program, and we have been performing an EWT in the Búzios field since March 2015. In the coming years, we intend to continue with our drilling program to acquire reservoir data and develop the fields in the Assignment Agreement area.

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In June 2014, the CNPE enacted Resolution No. 1, which established that Petrobras could be directly engaged by the Brazilian federal government under a production sharing agreement to produce the volume of oil, natural gas and fluid hydrocarbons from the Assignment Agreement areas that exceeds the five bnboe maximum production originally agreed under the Assignment Agreement or that may be negotiated during the revision process. This excess production would be extracted from the following areas regulated by the Assignment Agreement: (i) Búzios, (ii) Entorno de Iara; (iii) Florim and (iv) Nordeste de Tupi. See Item 10. “Additional Information—Material Contracts—Assignment Agreement–Additional Production in the Assignment Agreement Areas.”

Production Sharing Agreement (Contrato de Partilha de Produção)

In October 2013, a consortium led by Petrobras (holding a 40% interest and acting as exclusive operator of the area), Shell (20% interest), Total (20% interest), CNPC (10% interest) and CNOOC (10% interest) was awarded the rights and obligations to operate the Libra block in the ultra-deep waters of the Santos Basin in the first production-sharing regime auction ever held in Brazil. Through this 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 ranging from 8 to 12 bnboe, according to the ANP. The exploration phase of the block will continue until December 2, 2017, and the minimum exploratory program to be carried out during this period includes 3D seismic acquisition for the entire block, two exploratory wells and one extended well test. In February 2015, the consortium concluded drilling and testing the first appraisal well. This well is situated four kilometers away from the pioneer well. The drilling results confirmed the presence of an approximately 290-meter oil column and carbonate reservoirs that show high porosity and permeability. The two production tests, performed in two different zones, confirmed strong productivity and oil quality of these reservoirs. See Item 10. “Additional Information—Material Contracts—Production Sharing Agreement.”

Exploration

We continue to explore the Santos Basin pre-salt area. In 2014, we drilled eight exploratory wells, including seven in the pre-salt area, and we made several oil discoveries in the areas of Florim 2, Entorno de Iara 2 and 3, Júpiter Apollonia and NW1 LIBRA. We also declared the commerciality of the new exploratory fields Sul de Sapinhoá, Sépia, Itapu, Norte de Berbigão, Sul de Berbigão, Berbigão, Norte de Sururu, Sul de Sururu, Sururu, Oeste de Atapu, and Atapu, with total estimated recoverable volume of more than 6.2 billion barrels of oil.

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Santos Basin Projects

The primary source of our expected future production growth will be from the Santos Basin pre-salt area. We currently have 16 major projects contracted that are expected to be installed in this area in the coming years. Of these, six are in the Assignment Agreement area (Búzios 1, Búzios 2, Búzios 3, Búzios 4, Sépia and Entorno de Iara). The following FPSOs are currently being constructed:

Field	Unit Type	Production Unit	Crude Oil Nominal Capacity (bbl/d)	Natural Gas Nominal Capacity (mmcf/d)	Water Depth (meters)
Iracema Norte	FPSO	Cidade de Itaguaí	150,000	282.5	2,100
Lula Alto	FPSO	Cidade de Maricá	150,000	211.9	2,100
Lula Central	FPSO	Cidade de Saquarema	150,000	211.9	2,100
Lula Sul	FPSO	P-66	150,000	211.9	2,100
Búzios 1	FPSO	P-74	150,000	247.2	2,100
Lapa	FPSO	Cidade de Caraguatatuba	100,000	176.6	2,100
Lula Norte	FPSO	P-67	150,000	211.9	2,100
Búzios 2	FPSO	P-75	150,000	247.2	2,100
Lula Extremo Sul	FPSO	P-68	150,000	211.9	2,100
Atapu Norte	FPSO	P-69	150,000	211.9	2,100
Búzios 3	FPSO	P-76	150,000	247.2	2,100
Atapu Sul	FPSO	P-70	150,000	211.9	2,100
Búzios 4	FPSO	P-77	150,000	247.2	2,100
Itapu	FPSO	P-72	150,000	211.9	2,100
Berbigão	FPSO	P-71	150,000	211.9	2,100
Búzios 6	FPSO	P-73	150,000	211.9	2,100

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, Camarupim and Camarupim Norte fields. In 2014, we have made additional discoveries in the post-salt area of the Espírito Santo basin, including in Tanganika, Brigadeiro and Lontra.

In 2014, we produced oil from 42 fields at an average rate of 51.6 mbbl/d, and our average daily production of natural gas was of 154.1 mmcf/d (4.1 mmm³/d). The proved crude oil and natural gas reserves in the Espírito Santo Basin represented 0.6% and 3.3% in 2014 of our total proved reserves in Brazil, respectively.

As of December 31, 2014, we held exploration rights to 17 blocks (6 onshore and 11 offshore), and 6 exploration plans (1 onshore and 5 offshore), comprising a total of 6,334.51 Km² (1.53 million acres) in the Espírito Santo Basin.

In 2014, our PROEF program was implemented in the Espírito Santo Basin to improve our operational efficiency. We increased the efficiency of the offshore units of the Espírito Santo Basin operational unit to 92.9% in 2014 (compared to an efficiency target of 88.3%). As a result of our effort, production in 2014 from this area was 52 mbbl/d greater than it otherwise would have been.

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Sergipe-Alagoas Basin

The Sergipe-Alagoas Basin is one of our oldest onshore and shallow water producing basins and one of our new frontiers for offshore exploration. In 2014, we had proved crude oil and natural gas reserves in the Sergipe-Alagoas Basin representing 1.4% and 2.0% of our total proved reserves in Brazil, respectively. Our aggregate production level in the Sergipe–Alagoas Basin was 49.4 mbbl/d of oil and 73.8 mmcf/d (2.0 mmm³/d) of natural gas, largely from onshore fields.

Our exploration efforts in ultra-deep waters in the Sergipe-Alagoas Basin have led to a series of new discoveries. During 2014, we made discoveries of oil and gas resources in the areas informally known as Muriú, Moita Bonita, Farfan, Cumbe and Barra-1, all approximately 100 km from the coast of Aracaju. As of December 31, 2014, we held exploration rights to one block and seven exploration plans in this 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 2014, production from these other basins amounted to 160.9 mbbl/d of oil and 311.2 mmcf/d (8.2 mmm³/d) of natural gas.

The most significant potential for exploratory success within our other basins is 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 as operators were constrained by a lack 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 waters with depth greater than 2,000 meters (6,560 feet), we had 39 as of December 31, 2014. In addition to those rigs, we hired three others to begin operating in the first half of 2015, including two in the Libra area. We now have sufficient rigs to meet our long-term production targets, and 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 on developing the capacity to construct drilling rigs in Brazil. We have awarded contracts for additional rigs to be built in Brazil to meet our long-term needs and satisfy Brazilian local content requirements, under the expected terms of Production Sharing Agreements, the Assignment Agreement and concession agreements obtained in later Brazilian exploration bid rounds. The contracts for the locally built rigs were awarded to Sete Brasil S.A. (Sete BR), a Brazilian company in which Petrobras holds a 5% interest.

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Drilling Units in Use by Exploration and Production on December 31 of Each Year
	2014		2013		2012
	Leased	Owned	Leased	Owned	Leased	Owned
Onshore	16	10	12	10	24	11
Offshore, by water depth (WD)	55	6	61	7	65	9
Jack-up rigs	–	2	–	3	–	5
Floating rigs:	55	4	61	4	65	4
500 to 999 meters WD	2	2	4	2	6	2
1000 to 1999 meters WD	14	2	17	2	19	2
2000 to 3200 meters WD	39	–	40	–	40	–

In order to advance our exploration and production plans, we also need to secure a number of specialized vessels to connect wells to the FPSOs and for subsea construction. In the past we have experienced shortages of PLSVs, but we now have enough capacity of specialized vessels to meet our needs.

Refining, Transportation and Marketing

Refining, Transportation and Marketing Key Statistics
	2014	2013	2012
	(U.S.$ million)
Refining, Transportation and Marketing:
Sales revenues	112,320	111,665	116,826
Income (loss) before income taxes	(22,983)	(12,401)	(17,700)
Property, plant and equipment	49,662	66,552	63,822
Capital expenditures and investments	7,778	14,243	14,745

We are an integrated company with a dominant market share in our home market. We own and operate 13 refineries in Brazil (including Abreu e Lima – RNEST, which became operational in December 2014), with a total net distillation capacity of 2,176 mbbl/d, and are one of the world’s largest refiners. As of December 31, 2014, 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.

From 2010 to 2012, the Brazilian market was characterized 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. Since 2013, the domestic growth rate of consumption of oil products has diminished, particularly diesel, as a result of the Brazilian economic slowdown. The 21% growth rate during this period for fuel oil sales was an exception resulting mainly from increased thermoelectric consumption.

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, 2014, was 2,176 mbbl/d and our average throughput during 2014 was 2,106 mbbl/d.

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The following table shows the installed capacity of our Brazilian refineries as of December 31, 2014, and the average daily throughputs of our refineries in Brazil in 2014, 2013 and 2012.

Capacity and Average Throughput of Refineries
Name (Alternative Name)	Location	Crude Distillation Capacity at December 31, 2014	Average Throughput*
Name (Alternative Name)	Location	Crude Distillation Capacity at December 31, 2014	2014	2013	2012
		(mbbl/d)	(mbbl/d)
LUBNOR	Fortaleza (CE)	8	9	8	8
RECAP (Capuava)	Capuava (SP)	53	54	53	53
REDUC (Duque de Caxias)	Duque de Caxias (RJ)	239	271	282	263
REFAP (Alberto Pasqualini)	Canoas (RS)	201	192	197	154
REGAP (Gabriel Passos)	Betim (MG)	157	158	150	145
REMAN (Isaac Sabbá)	Manaus (AM)	46	44	42	38
REPAR (Presidente Getúlio Vargas)	Araucária (PR)	208	204	194	199
REPLAN (Paulínia)	Paulinia (SP)	415	408	421	387
REVAP (Henrique Lage)	São Jose dos Campos (SP)	252	262	234	248
RLAM (Landulpho Alves)	Mataripe (BA)	315	287	279	239
RPBC (Presidente Bernardes)	Cubatão (SP)	170	177	177	172
RPCC (Potiguar Clara Camarão)	Guamaré (RN)	38	38	37	37
RNEST (Abreu e Lima)	Ipojuca (PE)	74	3	–	–
Average crude oil throughput		2,176	2,065	2,029	1,898
Average NGL throughput		–	41	45	46
Average throughput		–	2,106	2,074	1,944

* Consider oil and NGLs processing (fresh feedstock)

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

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

· Increasing crude slate flexibility to process more Brazilian crude, especially from the pre-salt areas, taking advantage of light/heavy crude price differentials;

· Increasing residue conversion; and

· Reducing the environmental impact of our refining operations.

In 2014, we invested a total of U.S.$1.5 billion in our refineries (excluding RNEST), of which U.S.$712 million was invested in hydrotreating units necessary to improve the quality of our diesel oil and gasoline.

Our modernization efforts to meet stricter standards (such as diesel S-10 and gasoline S-50) and improve facilities for our existing refineries began in 2005 and have been largely completed. In 2015, we expect to finalize the construction of the diesel hydrotreating unit at RPBC.

Major Refinery Projects

In December 2014, the first refining unit of Abreu e Lima – RNEST refinery in northeastern Brazil, which is designed to process 115 mbbl/d of crude oil, to produce low sulfur diesel (10 ppm) as well as LPG, naphtha, bunker fuel and petroleum coke, started fuel production with a partial capacity of 74 mbbl/d.

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Suspended Major Refinery Projects

Recent changes in our business context and the impact of the Lava Jato investigation prompted a review of our future prospects and ultimately led to the reduction in the pace of our capital expenditures. As a result, our management postponed for an extended period of time the completion of the following refining projects: (i) Petrochemical Complex of Rio de Janeiro (Complexo Petroquímico do Rio de Janeiro - Comperj); and (ii) the second refining unit of RNEST. We have recognized impairment losses for the fiscal year ended December 31, 2014 of U.S.$11.7 billion. For further information, see Notes 3.3 and 14 to our audited consolidated financial statements.

In addition, in January 2015, our board of directors decided not to move forward with the construction of two new refineries in northeastern Brazil (Premium I and Premium II), because the assumptions and conditions in our 2014-2018 Plan were not met. We have written off from our financial statements for the fiscal year ended December 31, 2014 U.S.$1.24 billion due to the cancellation of these projects. See Note 12.4 to our audited consolidated financial statements.

Domestic Output of Oil Products and Consolidated Sales Volumes

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)
	2014	2013	2012
Diesel	853	850	782
Gasoline	494	491	438
Fuel oil	286	255	238
Naphtha	85	90	106
LPG	130	137	143
Jet fuel	105	96	93
Other	217	206	196
Total domestic output of oil products	2,170	2,124	1,997
Installed capacity(2)	2,176	2,102	2,018
Crude distillation utilization (%)(3)	98	97	94
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.

(2) Installed capacity as of December 31, 2014, 2013 and 2012.

(3) Crude distillation utilization considers average installed capacity as of December 31, 2014, 2013 and 2012.

Consolidated Sales Volumes, mbbl/d
	2014	2013	2012
Diesel	1,001	984	937
Gasoline	620	590	570
Fuel oil	119	98	84
Naphtha	163	171	165
LPG	235	231	224
Jet fuel	110	106	106
Other	210	203	199
Total oil products	2,458	2,383	2,285
Ethanol, nitrogen fertilizers, renewables and other products	99	91	83
Natural gas	446	409	357
Total domestic market	3,003	2,883	2,725
Exports	393	395	554
International sales	571	514	506
Total international market	964	909	1,060
Total sales volumes	3,967	3,792	3,785

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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 200 mbbl/d of crude oil in 2015. We believe our domestic proved reserves will be sufficient to allow us to continue to deliver all contracted volumes. For 2015, approximately 40% of our exported crude oil will be committed to meeting our contractual delivery commitments to third parties.

Imports and Exports

Our import and export 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 import some light crude to balance the slate for our refineries, and export heavier crude oil from our production in Brazil. 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. Despite the slower rates of growth in consumption of oil products in 2013 and 2014, we are still a net importer of oil products.

In 2014, due to the positive results from modernization investments, our Brazilian refineries expanded output by 2.1%, while consumption increased by 2.7%. This led to an increase in oil product imports compared to 2013.

We export oil products that our refineries produce in excess of Brazilian market demand, which is largely fuel oil.

The table below shows our exports and imports of crude oil and oil products in 2014, 2013 and 2012:

Exports and Imports of Crude Oil and Oil Products, mbbl/d
	2014	2013	2012
Exports
Crude oil	232	207	364
Fuel oil (including bunker fuel)	128	151	153
Gasoline	0	0	1
Other	30	35	30
Total exports	390	393	548
Imports
Crude oil	392	404	346
Diesel	185	174	190
LPG	70	63	53
Gasoline	41	32	87
Naphtha	88	83	58
Other	29	37	45
Total imports	805	793	779

Logistics and Infrastructure for Oil and Oil Products

We own and operate an extensive network of crude oil and oil product pipelines in Brazil that connect our terminals, refineries and other primary distribution points. On December 31, 2014, our onshore and offshore, crude oil and oil products pipelines extended over 20,913 km (12,998 miles). We operate 28 marine storage terminals and 21 other tank farms with nominal aggregate storage capacity of 64 mmbbl. Our marine terminals handle an average 10,595 tankers and oil barges annually.

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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 and decrease our dependency on chartered vessels. Upgrades will include replacing single-hulled tankers with double-hulled vessels and replacing vessels nearing the end of their 25-year useful life. Our long-term strategy continues to focus on the flexibility afforded by operating a combination of owned and chartered vessels.

Two new oil tankers were delivered to Transpetro in 2014. We plan to have another 37 vessels delivered to us in the future, all of which will be built in Brazilian shipyards.

The table below shows our operating fleet and vessels under contract as of December 31, 2014.

Owned and Chartered Vessels in Operation and Under Construction Contracts at December 31, 2014
	In Operation		Under Contract/Construction
	Number	Tons Deadweight Capacity	Number	Tons Deadweight Capacity
Owned fleet:
Tankers	48	4,034,223	29	2,928,135
LPG tankers	5	35,653	8	42,000
Anchor Handling Tug Supply (AHTS)	1	1,920	–	–
Total	54	4,071,796	37	2,970,135
Chartered vessels:
Tankers	171	17,352,452	–	–
LPG tankers	32	656,029	–	–
Total	203	18,008,481	–	–

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Petrochemicals

Our petrochemicals operations provide an outlet for our growing production volumes of gas and other refined products, which increase their value and provide 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, joint ventures, joint operations and associated companies:

	mmt/y (nominal capacity)	Petrobras interest (%)
Braskem(1):
Ethylene	3.95	36.20
Polyethylene	3.03
Polypropylene	3.99
DETEN Química S.A.:
LAB(1)	0.22	27.88
LABSA(1)	0.12	27.88
METANOR S.A./COPENOR S.A.(2):
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(3):
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) Copernor S.A. is a Metanor S.A. subsidiary.

(3) The PTA unit started operations in January 2013 and the PET unit started operations in August 2014.

Our investments in petrochemical companies amount to U.S.$1.8 billion and the largest investment is in Braskem S.A. (Braskem), Brazil’s largest petrochemical company.

We also recognized impairment losses for the fiscal year ended December 31, 2014 of U.S.$1.1 billion with respect to the Suape Petrochemical complex, mainly attributable to changes in market assumptions and forecasts resulting from a decrease in economic activity, a reduction in the spread for petrochemical products in the international market and modifications in tax regulations. For further information, see Note 14 to our audited consolidated financial statements.

Our management also decided that we will not participate in the construction of petrochemical projects that were under evaluation or various stages of engineering or design: (i) Aromatics, MDI and Policarbonates, all projects located in the Complexo Petroquímico do Rio de Janeiro—Comperj and (ii) Companhia de Coque Calcinado de Petróleo—Coquepar.

In August 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 U.S.$369 million. This transaction closed in October 2014, after approval by the Brazilian Antitrust Authority – CADE.

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Distribution

Distribution Key Statistics
	2014	2013	2012
	(U.S.$ million)
Distribution:
Sales revenues	41,729	40,023	40,596
Income (loss) before income taxes	760	1,306	1,387
Property, plant and equipment	2,284	2,350	2,374
Capital expenditures and investments	446	514	666

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 37.9% of the total Brazilian retail and wholesale distribution market. Petrobras Distribuidora distributes oil products, ethanol, biodiesel and natural gas to retail, commercial and industrial customers. In 2014, Petrobras Distribuidora sold the equivalent of 988.9 mbbl/d of oil products and other fuels to wholesale and retail customers, of which the largest portion (41.1%) was diesel.

At December 31, 2014, our Petrobras Distribuidora branded service station network was Brazil’s leading retail marketer, with 7,931 service stations, or 20% of the stations in Brazil. Petrobras Distribuidora owned and franchised stations that represented 29.7% of Brazil’s retail sales of diesel, gasoline, ethanol, vehicular natural gas and lubricants in 2014.

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 1,060 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 57.1% 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 22.5% market share and ranked second in LPG sales in Brazil in 2014, according to the ANP.

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

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Gas and Power

Gas and Power Key Statistics
	2014	2013	2012
	(U.S.$ million)
Gas and Power:
Sales revenues	17,882	14,017	11,803
Income (loss) before income taxes	(553)	921	1,277
Property, plant and equipment	22,126	20,882	21,585
Capital expenditures and investments	2,545	2,716	2,113

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 sources.

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

· Add value by monetizing Petrobras’s 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 2013 supplied 12.8% of Brazil’s total energy needs, compared to 3.7% in 1998, and is expected to supply 14.2% of Brazil’s total energy needs by 2023, 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.

Our volume of natural gas sales to industrial, gas-fired electric power generation, commercial and retail customers in 2014 was 70.5 mmm³/d, representing an increase of 10% compared to 2013. This increase is attributable to the increase in consumption by the power generation industry by 20% from 2013 to 2014 due to low rainfall, which reduced the reservoir storage levels of Brazilian hydroelectric power plants. Natural gas consumption by refineries and fertilizer plants increased by 12%.

As a result of a multi-year infrastructure development program in pipeline networks 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.

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Currently, our natural gas pipeline network extends over 9,190 km. In 2014, we invested U.S.$207 million in our natural gas infrastructure, and in 2015, we plan to invest in (i) the construction of two gas transfer pipelines connecting our pre-salt natural gas producing fields to the Cabiúnas Terminal and Comperj’s processing plant; (ii) the expansion of the natural gas processing capacity of the Cabiúnas Terminal in order to receive up to 459 mmcf/d (13 mmm³/d) with the expectation of increasing the associated natural gas production from the pre-salt reservoirs in the Santos Basin, and (iii) the development of a natural gas processing plant with a capacity of 742 mmcf/d (21 mmm³/d), located at Comperj’s petrochemical complex, also associated with the pre-salt reservoirs in the Santos Basin. The Cabiúnas Terminal expansion is expected to be fully operational by January 2016 and Comperj’s natural gas processing plant (which is a specific project that has not been subject to any impairment) is scheduled to begin operations by October 2017.

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 2014, we conducted 114 cargo purchase operations, 99 of which were received in Brazil (including two cargo later exported) and 15 directly resold abroad.

We also own and operate four natural gas processing facilities. Two of them, Sul Capixaba and Cacimbas, located in the State of Espírito Santo, have the capacity to process 2.5 mmm³/d and 16 mmm³/d of natural gas, respectively, and are designated to process natural gas from the Campos Basin. Caraguatatuba plant, located in the State of São Paulo, has the capacity to process 20 mmm³/d of natural gas, and is designated to process natural gas from the Santos Basin post-salt and pre-salt areas. The TECAB plant, located in State of Rio de Janeiro, has the capacity to process 24 mmm³/d of natural gas from the Campos Basin and the Santos Basin pre-salt.

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Principal Natural Gas Local Distribution Holdings
Name	State	Group Interest %	Average Gas Sales in 2014 (mmm³/d)	Customers(1)

CEG RIO	Rio de Janeiro	37.41	10.5	46,053
BAHIAGAS	Bahia	41.50	3.8	31,555
PETROBRAS DISTRIBUIDORA	Espírito Santo	100.00	3.5	31,251
COPERGAS	Pernambuco	41.50	3.2	16,225

___________________________

(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
	2014	2013	2012
Sources of natural gas supply
Domestic production	43.2	40.8	39.5
Imported from Bolivia	32.9	30.5	27.0
LNG	20.0	14.5	8.4
Total natural gas supply	96.1	85.9	74.9
Sales of natural gas
Sales to local gas distribution companies(1)	38.9	38.6	39.3
Sales to gas-fired power plants	31.6	26.0	16.6
Total sales of natural gas	70.5	64.6	55.9
Internal consumption (refineries, fertilizer and gas-fired power plants)(2)	25.6	20.8	18.5
Revenues (U.S.$ billion)(3)	9.8	9.0	8.1

________________________

(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 Petroliferos 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. Until August 18, 2014, Petrobras had paid all obligations owed for 2007, but YPFB had not then met the condition precedent necessary to receive additional payments for the years after 2007.

After more than two years of negotiations, on August 18, 2014, Petrobras and YPFB reached an agreement and settled contractual disputes regarding several aspects of the GSA, including those related to payment for the liquids contained in the natural gas provided by YPFB under the GSA’s fourth amendment, which was formally terminated as of January 1, 2014. As a result of this agreement, Petrobras has agreed to pay YPFB a net lump sum of U.S.$438 million, primarily for the liquids contained in the natural gas purchased by Petrobras from 2008 to 2013. The net economic effect of this arrangement with YPFB has generated a net positive cash flow for us of U.S.$319.78 million as of February 28, 2015, and we will generate an expected net present value of U.S.$566.15 million by December 2016. We also reached an agreement that provides for the supply of natural gas for the Cuiabá power plant (UTE Cuiabá), currently being leased by us, to facilitate operations through December 31, 2016.

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Our agreement with YPFB also provides that with respect to natural gas we find in the gas fields we operate in Bolivia, we will have the right to sell such natural gas to the Brazilian market after confirming that Bolivian market needs have been met.

Our volume obligations under the ship-or-pay arrangements entered into with Gas Transboliviano S.A. (GTB) and Transportadora Brasileira Gasoduto Bolívia-Brasil S.A. (TBG) were generally designed to match our gas purchase obligations under the GSA through 2019. The tables below show our contractual commitments under these agreements for the five-year period from 2015 through 2019.

	2015	2016	2017	2018	2019
Purchase commitments to YPFB
Volume obligation (mmm³/d)(1)	24.06	24.06	24.06	24.06	24.06
Volume obligation (mmcf/d)(1)	850.00	850.00	850.00	850.00	850.00
Brent crude oil projection (U.S.$)(2)	58.00	70.20	70.00	70.00	70.00
Estimated payments (U.S.$ million)(3)	1,785.80	1,571.70	1,691.30	1,690.60	1,687.40
Ship-or-pay contract with GTB
Volume commitment (mmm³/d)	30.08	30.08	30.08	30.08	30.08
Volume commitment (mmcf/d)	1,062.26	1,062.26	1,062.26	1,062.26	1,062.26
Estimated payments (U.S.$ million)(5)	139.97	141.04	141.37	142.06	142.78
Ship-or-pay contract with TBG
Volume commitment (mmm³/d)(4)	35.28	35.28	35.28	35.28	35.28
Volume commitment (mmcf/d)	1,246.09	1,246.09	1,246.09	1,246.09	1,246.09
Estimated payments (U.S.$ million)(5)	518.19	522.86	527.00	529.29	531.97

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Major Shareholders		130
Related Party Transactions		130
Item 8.	Financial Information	131
Consolidated Statements and Other Financial Information		131
Legal Proceedings		131
Internal Commissions		132
Dividend Distribution		134
Item 9.	The Offer and Listing	134
Item 10.	Additional Information	136
Memorandum and Articles of Incorporation		136
Restrictions on Non-Brazilian Holders		145
Transfer of Control		145
Disclosure of Shareholder Ownership		145
Material Contracts		146
Exchange Controls		156
Taxation Relating to Our ADSs and Common and Preferred Shares		157
Taxation Relating PGF’s Notes		164
Documents on Display		171
Item 11.	Qualitative and Quantitative Disclosures about Market Risk	171
Item 12.	Description of Securities other than Equity Securities	173
American Depositary Shares		173
PART II		174
Item 13.	Defaults, Dividend Arrearages and Delinquencies	174
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	174
Item 15.	Controls and Procedures	174
Disclosure Controls and Procedures		174
Management’s Report on Internal Control over Financial Reporting		174
Changes in Internal Control Over Financial Reporting		179
Item 16A.	Audit Committee Financial Expert	179
Item 16B.	Code of Ethics	179
Item 16C.	Principal Accountant Fees and Services	180
Audit and Non-Audit Fees		180
Audit Committee Approval Policies and Procedures		181
Item 16D.	Exemptions from the Listing Standards for Audit Committees	181
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	181
Item 16F.	Change in Registrant’s Certifying Accountant	181
Item 16G.	Corporate Governance	181
PART III		184
Item 17.	Financial Statements	184
Item 18.	Financial Statements	184
Item 19.	Exhibits	184
Signatures.		190

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)

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EXPLANATORY NOTE		3
Forward-Looking Statements		5
Glossary of Petroleum Industry Terms		7
Conversion Table		10
Abbreviations		11
Presentation of Financial and Other Information		12
Presentation of Information Concerning Reserves		13
PART I		14
Item 1.	Identity of Directors, Senior Management and Advisers	14
Item 2.	Offer Statistics and Expected Timetable	14
Item 3.	Key Information	14
Selected Financial Data		14
Risk Factors		16
Item 4.	Information on the Company	33
History and Development		33
Overview of the Group		33
Exploration and Production		35
Refining, Transportation and Marketing		48
Distribution		54
Gas and Power		55
International		63
Biofuels		69
Corporate		70
Organizational Structure		70
Property, Plants and Equipment		71
Regulation of the Oil and Gas Industry in Brazil		72
Health, Safety and Environmental Initiatives		76
Insurance		78
Additional Reserves and Production Information		79
Item 4A.	Unresolved Staff Comments	88
Item 5.	Operating and Financial Review and Prospects	88
Management’s Discussion and Analysis of Financial Condition and Results of Operations		88
Overview		88
Sales Volumes and Prices		89
Effect of Taxes on Our Income		90
Inflation and Exchange Rate Variation		91
Results of Operations		92
Additional Business Segment Information		103
Liquidity and Capital Resources		104
Contractual Obligations		109
Critical Accounting Policies and Estimates		109
Research and Development		114
Trends		116
Item 6.	Directors, Senior Management and Employees	117
Directors and Senior Management		117
Compensation		123
Share Ownership		123
Fiscal Council		124
Audit Committee		124
Other Committees		125
Ombudsman		126
Employees and Labor Relations		127
Item 7.	Major Shareholders and Related Party Transactions	130