20-F

 

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

 

TABLE OF CONTENTS

		Page
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

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TABLE OF CONTENTS (cont.)

		Page
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

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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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·Item 8, Financial Information, contains a description of the ongoing legal proceedings involving us, and a description of certain of our internal commissions established to evaluate past transactions;

·Item 15, Controls and Procedures, contains a discussion of the implications for effectiveness of internal control over financial reporting, and for effectiveness of disclosure controls and procedures; and

·Item 18, Financial Statements, Note 3, The Lava Jato (Car Wash) Operation, and its effects on the Company, contains a description of the Lava Jato investigation, a description of the estimation methodology, a tabular analysis of the impact of the overpayments and a description of related civil litigation.

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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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·changes in, or failure to comply with, laws or regulations, including with respect to fraudulent activity, corruption and bribery;

·receipt of governmental approvals and licenses;

·international and Brazilian political, economic and social developments;

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

·the cost and availability of adequate insurance coverage;

·the outcome of ongoing corruption investigations and any new facts or information that may arise in relation to the Lava Jato investigation;

·the effectiveness of our risk management policies and procedures, including operational risk; and

·litigation, such as class actions or enforcement or other proceedings brought by governmental and regulatory agencies.

For additional information on factors that could cause our actual results to differ from expectations reflected in forward-looking statements, see “Risk Factors” in this annual report.

All forward-looking statements attributed to us or a person acting on our behalf are qualified in their entirety by this cautionary statement.  We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information or future events or for any other reason.

The crude oil and natural gas reserve data presented or described in this annual report are only estimates, and our actual production, revenues and expenditures with respect to our reserves may materially differ from these estimates.

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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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CONVERSION TABLE

1 acre	=	43,560 square feet	=	0.004047 km2
1 barrel	=	42 U.S. gallons	=	Approximately 0.13 t of oil
1 boe	=	1 barrel of crude oil equivalent	=	6,000 cf of natural gas
1 m3 of natural gas	=	35.315 cf	=	0.0059 boe
1 km	=	0.6214 miles
1 meter	=	3.2808 feet
1 t of crude oil	=	1,000 kilograms of crude oil	=	Approximately 7.5 barrels of crude oil (assuming an atmospheric pressure index gravity of 37° API)

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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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Developments in the oil and gas industry and other factors have resulted, and may result, in substantial write-downs of the carrying amount of certain of our assets, which could adversely affect our operating results and financial condition.

We evaluate on an annual basis, or more frequently where the circumstances require, the carrying amount of our assets for possible impairment.  Our impairment tests are performed by a comparison of the carrying amount of an individual asset or a cash-generating unit with its recoverable amount. Whenever the recoverable amount of an individual asset or cash-generating unit is less than its carrying amount, an impairment loss is recognized to reduce the carrying amount to the recoverable amount.

Changes in the economic, regulatory, business or political environment in Brazil or other markets where we operate, such as the recent significant decline in international crude oil and gas prices, the devaluation of the real and lower projected economic growth in Brazil, among other factors, may result in the recognition of impairment charges in certain of our assets.  For example, in 2014, we recognized impairment charges of U.S.$16,823 million for certain of our property, plant and equipment, intangible assets and assets classified as held for sale.  See Item 5. “Operating and Financial Review and Prospects—Results of Operations-2014 compared to 2013”, Item 5. “Operating and Financial Review and Prospects—Critical Accounting Policies and Estimates” and Notes 5.2 and 14 to our audited consolidated financial statements for further information about the impairment of certain of our assets.

                Future developments in the economic environment, in the oil and gas industry and other factors could result in further substantial impairment charges, adversely affecting our operating results 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.

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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.

Risks Relating to Our Equity and Debt Securities

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

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

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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 2,034mbbl/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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The map below shows the location of the pre-salt reservoirs as well as the status of our exploratory activities there.

 

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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

___________________________

(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:

RecentlyDeveloped 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

___________________________
(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 90,000km² (22.24million acres), or a net exploratory acreage of 64,000km² (15.81million 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 29foreign and domestic companies and were party to a total of 82partnership 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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The following map shows our concession areas in Brazil as of December 2014.

 

Primary Basins in Which Petrobras Operates

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

Campos Basin

The Campos Basin, which covers approximately 115,000 km² (28.4 million acres), is the most prolific oil and gas basin in Brazil in terms of proved hydrocarbon reserves and annual production.  Since we began exploring this area in 1971, over 60 hydrocarbon accumulations have been discovered, including eight large oil fields in deep and ultra-deep waters.  The Campos Basin is our largest oil- and gas-producing area, with an average production of 1,526 mbbl/d of oil and 548.4 mmcf/d (14.5 mmm³/d) of associated natural gas from 43 producing fields in 2014.

During 2014, 71% of our total domestic production came from this basin. In 2014, the proved crude oil and natural gas reserves in the Campos Basin represented 66.4% and 41% of our total proved reserves in Brazil, respectively. In 2014, we operated 42 floating production systems and 14 fixed platforms in water depths from 80 to 1,886 meters (262 to 6,188 feet), delivering oil with an average API gravity of 21.3° and maximum basic sediment and water (a measurement of the water and sediment content of flowing crude oil) of 1%.

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

All of our production in the Campos Basin is under concession agreements.

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

We hold interests ranging from 24% to 100% in 20 of Brazil’s 27 local gas distribution companies.  We had approximately a 23.5% net equity interest in the combined 2,401.4 mmcf/d (68 mmm³/d) of natural gas distributed by Brazil’s local distribution companies in 2014.

According to our estimates, our three most significant holdings, CEG Rio, Bahiagás and Petrobras Distribuidora, are Brazil’s third, fifth and sixth largest gas distributors. These companies, together with independent distributors Comgás and CEG supply 64% of the Brazilian market.  

In October 2014, we sold our 40% equity interest in Gasmig, the local gas distribution company of the State of Minas Gerais, representing a 2% reduction in our net equity interest in natural gas distributed in Brazil compared to 2013.

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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

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

(2)               Brent price forecast based on our 2030 Strategic Plan, which is currently under review by our management.

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

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

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

Natural Gas Sales Contracts

We sell our gas primarily to local gas distribution companies and to gas fired plants generally based on standard take-or-pay, long-term supply contracts. This represents 70% of our total sale volumes, and the price formulas under these contracts are mainly indexed to an international fuel oil basket. In order to maintain the competitiveness of our natural gas in the Brazilian market, since 2011 we have applied a non-permanent discount to the prices we charge under some of our natural gas sales contracts. Additionally, we have a variety of sales contracts designed to create flexibility in matching customer demand with our gas supply capabilities.  These include flexible and interruptible long-term gas sales contracts, auction mechanisms for short-term contracts, weekly electronic auctions and a type of gas sales contract that consists of a seller delivery option that helps balance natural gas sales in case of low demand for natural gas from gas-fired power plants. In this circumstance, the excess natural gas volumes are offered to end consumers who ordinarily use energy sources other than natural gas.

In 2014, we continued to renegotiate some existing long-term natural gas sales contracts with local distribution companies of natural gas in order to promote adjustments tailored to specific market demands, encompassing term extensions for some contracts and prolonging our natural gas sales portfolio.

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The table below shows our future gas supply commitments from 2015 to 2019, including sales to both local gas distribution companies and gas-fired power plants:   

Future Commitments under Natural Gas Sales Contracts, mmm3/d	2015	2016	2017	2018	2019
To local gas distribution companies:
Related parties(1)	17.66	18.10	18.20	18.42	19.00
Third parties	20.34	20.65	20.81	21.27	21.27
To gas-fired power plants:
Related parties(1)	3.67	0.65	0.18	0.17	0.20
Third parties	11.63	11.44	11.53	11.42	11.48
Total(2)	53.31	50.85	50.71	51.28	51.96
Estimated amounts to be invoiced (U.S.$ billion)(3)(4)	6.6	6.4	6.3	6.3	6.3

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

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

(3)               Estimates are based on outside sales and do not include internal consumption or transfers.

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

Fertilizers

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

Our fertilizer plants in Bahia, Sergipe and Paraná produce ammonia and urea for the Brazilian market. The combined production capacity of these plants is 1,667,000 t/y of urea and 1,265,000 t/y of ammonia. Most of our ammonia production is used to produce urea, and the excess production is mainly sold in the Brazilian market. In 2014, we started the production of ammonium sulfate in Sergipe in a unit with a 300,000 t/y production capacity.

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

Ammonia and Urea (t/y)
	2014	2013	2012
Ammonia	234,339	205,029	229,575
Urea	1,046,004	1,071,827	848,000
Revenues (U.S.$ million)(1)	663	621	571

(1)                  Includes nitrogenous fertilizers sales revenues from the Fertilizer segment to other operating segments, services and other revenues from fertilizers companies.

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Our business context of lower projected economic growth ultimately led to the reduction in the pace of our capital expenditures.  As a result, our management decided to reevaluate the schedule for the construction of the following fertilizing facilities:

•     UFN III, with the capacity to produce 1.2 mmt/y of urea and 70 mt/y of ammonia from 2.2 mmm3/d of natural gas; and

•     UFN V, with the capacity to produce 519,000 t/y of ammonia from 1.3 mmm³/d of natural gas.

For further information, see Note 14 to our audited consolidated financial statements.

We have recognized impairment losses for the fiscal year ended December 31, 2014 of U.S.$116 million with respect to the Araucária fertilizer plant.  The impairment loss is mainly attributable to operational inputs that required higher capital expenditures during 2014.  See Note 14 to our audited consolidated financial statements.

Power

Brazilian electricity needs are mainly supplied by hydroelectric power plants (89,211 MW of installed capacity), which account for 67% of Brazil’s generation capacity.  Hydroelectric power plants are dependent on the annual level of rainfall; in the years where rainfall is abundant, Brazilian hydroelectric power plants will generate more electricity and consequently less generation from thermoelectric power plants will be demanded. The total installed capacity of the Brazilian National Interconnected Power Grid (Sistema Interligado Nacional—SIN) in 2014 was 133,713 MW. Of this total, 6,410 MW (or 4.8%) was available from 21 thermoelectric plants we operate.  These plants are designed to supplement power from the hydroelectric  power plants.  

In 2014, hydroelectric power plants in Brazil generated 44,815 MWavg, which corresponded to 69% of Brazil’s total electricity needs (64,728 MWavg). Hydroelectric generation capacity is supplemented by other sources of energy (wind, coal, nuclear, fuel oil, diesel oil, natural gas, and others).  Total electricity generated by these sources averaged 19,913 MW in 2014, of which our thermoelectric power plants contributed 4,761 MWavg, as compared to 4,043 MWavg in 2013 and 2,699 MWavg in 2012.  In 2014, we invested U.S.$299 million in our power business segment.

Electricity Sales and Commitments for Future Generation Capacity

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

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

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

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In 2014, the commercial capacity certified by MME for all thermoelectric power plants controlled by us was 4,222 MWavg, although our total generating capacity was 6,410 MWavg. Of the total 4,542 MWavg of commercial capacity available (capacidade comercial disponível or lastro) for sale in 2014, approximately 53% was sold as standby availability in public auctions in the regulated market (compared to 39% in 2013) and approximately 35% was committed under bilateral contracts and self-production (i.e. sales to related parties) (compared to 53% in 2013).

In 2014, public auctions on the regulated market were the main channel used by our thermoelectric generation business to sell energy that had not been previously contracted. Distribution companies must purchase, through a public auction process on the regulated market, their expected electricity requirements for their captive customers.  The public auction process is administered by ANEEL, either directly or through the Câmara de Comercialização de Energia Elétrica (Electric Energy Trading Chamber), or CCEE, under certain guidelines provided by the MME.

Existing power generators (such as our thermoelectric power plants) can hold auctions (i) in the year before the initial delivery date (“A-1 Auctions”), (ii) every year, for the delivery of energy for up to the following 15 years (“A Auctions”) and (iii) every year for the delivery of energy for up to the following 2 years (“Adjustment Auctions”).  Electricity auctions for new generation projects are held (i) in the fifth year before the initial delivery date of electricity (“A-5 Auctions”), and (ii) in the third year before the commencement of commercial operation (“A-3 Auctions”).

To benefit from attractive sale prices for energy that has not been previously contracted, for the delivery of energy starting in 2014, we sold some of our remaining certified commercial capacity as standby capacity under public auctions on the electricity regulated market as follows: (i) 10 MWavg per month in a A-1 Auction held on December 17, 2013 for the sale of energy between January 1, 2014 to December 31, 2014; (ii) 574 MWavg per month in an A Auction held on April 30, 2014 for the sale of energy between May 1, 2014 to December 31, 2019.  For the delivery of energy starting in 2015, we sold (i) 270 MWavg per month in an A-1 Auction held on December 5, 2014 for the sale of energy between January 1, 2015 to December 31, 2017 and (ii) 205 MWavg per month in the 18^th Adjustment Auction held on January 15, 2015 for the sale of energy between January 1^st to June 30, 2015.  With these sales, we can now better predict our revenues derived from the sale of electricity for the next 3 years.

Under the terms of standby availability contracts, we are paid a fixed amount whether or not we generate any power. Additionally, whenever we have to deliver energy under these contracts, we receive an additional payment for the energy delivered that is set on the auction date and is revised monthly or annually based on inflation-adjusted international fuel price indexes.   

Our future commitments under bilateral contracts and self-production are of 1,421 MWavg in 2015, 1,460 MWavg in 2016 and 1,520 MWavg in 2017.  The agreements expire gradually, with the last contract expiring in 2028.  As existing bilateral contracts expire, we will sell our remaining certified commercial capacity under contracts in new auctions to be conducted by MME or through the execution of new bilateral contracts.

The table below shows the evolution of our installed thermoelectric power plants’ capacity, our purchases in the free market and the associated certificated commercial capacity.

	2015	2014	2013
Installed power capacity and utilization
Installed capacity (MW)	6,684	6,410	6,548
Certified commercial capacity (MWavg)	4,229	4,222	4,367
Purchases in the free market (MWavg)	250(1)	320	217
Commercial capacity available (Lastro) (MWavg)	4,479	4,542	4,584

(1)                  Includes 220 Mwavg already purchased in the free market and 30 Mwavg forecasted in our 2014-2018 Business Plan to be purchased in 2015.

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

Volumes of Electricity Sold (MWavg)
	2014	2013	2012
Total sale commitments	4,012	4,235	4,438
Bilateral contracts	1,183	2,021	2,318
Self-production	428	416	423
Public auctions to distribution companies	2,425	1,798	1,697
Generation volume	4,637	3,983	2,699
Revenues (U.S.$ million)(1)	7,693	5,173	3,755

(1)                  Includes electricity sales revenues from the Power segment to other operating segments, service and other revenues from electricity companies.

Renewable Energy

We have invested, alone and in partnership with other companies, in renewable power generation sources in Brazil including wind and small hydroelectric plants.  The power generation capacity we have (through the equity interest we hold on renewable energy companies) is equivalent to 25.4 MW of hydroelectric capacity, 1.1 MW of solar capacity and 105.8 MW of wind capacity.  We and our partners sell energy from these plants directly to the Brazilian federal government via the renewable energies incentive program (PROINFA) and the 2009 “reserve energy” auctions.

International

International Key Statistics
	2014	2013	2012
	(U.S.$ million)
International:
Sales revenues	13,912	16,302	17,929
Income (loss) before income taxes	(608)	2,035	1,933
Property, plant and equipment	6,058	7,971	10,882
Capital expenditures and investments	1,513	2,368	2,572

In addition to Brazil, we have operations in 16 countries, encompassing all phases of the energy business, with an emphasis on oil and gas exploration in Latin America, Africa and the United States.  The strategies of our international operations are:

·Investing in overseas exploration to discover and add to reserves, increasing our volumes of oil and gas;

·Developing and commercializing natural gas reserves overseas, supplementing our supply of natural gas in Brazil; and

·Maintaining the operational integrity and optimizing the management and efficiency of our refining and distribution assets abroad.

International Upstream Activities

Most of our international activities are in exploration and production of oil and gas.  We have long been active in Latin America.  In the Gulf of Mexico and West Africa, we focus on opportunities to leverage the deepwater expertise we have developed in Brazil.  From 2012 to 2014 we substantially reduced our international activities and production through the sale of assets to meet our announced divestment targets.

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In 2014, our net production outside Brazil averaged 115.9 mbbl/d of crude oil and NGLs and 560.3 mmcf/d (15.9 mmm³/d) of natural gas, representing 8.4% of our total production on a barrels of oil equivalent basis.  During 2014, our capital expenditures and investments for international exploration and production totaled U.S.$1.3 billion, representing 5.2% of our total exploration and production capital spending.

International Refining Activities

Our international crude distillation capacity as of December 31, 2014 was 230.2 mbbl/d and the utilization factor for our international consolidated refining plants was 69%.

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

Capacity and Average Throughput of Refineries
Name (Alternative Name)	Location	Crude Distillation Capacity at December 31, 2014	Average Throughput*
			2014	2013	2012
		(mbbl/d)	(mbbl/d)
PRSI (Pasadena Refining System Inc.)	Texas (USA)	100.0	100.3	101.8	97.9
NSS (Nansei Sekiyu Kabushiki Kaisha)	Okinawa (JP)	100.0	35.9	38.6	49.8
RBB (Ricardo Eliçabe Refinery)	Bahía Blanca (AR)	30.2	27.2	29.0	29.2
Total average crude oil throughput		230.2	158.9	160.8	161.8
Average external intermediate throughput			4.5	8.6	15.1
Total average throughput		‒	163.4	169.4	176.9

* Consider oil (fresh feedstock) and external processed intermediate oil products.

International Activities by Region and Country

In addition to exploring, producing and refining oil, our international activities include petrochemicals, distribution and gas and power activities. Information about our international presence, by region and country, is provided in the text that follows.  See the table at the end of this section for more information about our main international exploration and production assets in development.

South America

We are present in Argentina, Bolivia, Chile, Colombia, Venezuela, Paraguay and Uruguay.  In 2014, our average net production from South America (outside of Brazil) was 153.2 mboe/d, or 73% of our international production compared to 167.2 mboe/d, or 76% of our international production in 2013.  Reserves in the region represent 50.4% of our international reserves.  Our most significant natural gas production operations outside of Brazil are located in Argentina and Bolivia, where we produced an average 514.6 mmcf/d (14.6 mmm³/d) of natural gas in 2014, or 92% of our international production.

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Our largest operating region outside Brazil is Argentina, where we participate across the energy value chain, primarily through our 67.2% interest in Petrobras Argentina S.A., or PESA.  Our main oil production is concentrated in the Medanito, Entre Lomas and El Tordillo fields, and our main gas production is concentrated in the El Mangrullo, Río Neuquén fields in the Neuquén Basin and Santa Cruz I fields in the Austral Basin.  In January 2014, we announced the sale of the remaining 38.45% interest we held in the Puesto Hernandez field to YPF for U.S.$40.7 million and in March 2015, the sale of our assets in Austral Basin, which includes 26 exploration and production contracts and related infrastructure located in the Santa Cruz province, to Compañia General de Combustibles S.A. (CGC) for U.S.$101 million.  The conclusion of this transaction is subject to the approval of regulatory authorities in Argentina. Through our interest in PESA, we own the Bahia Blanca Refinery, with a capacity of 30.2 mbbl/d, and stakes in the Refinor refinery in Campo Duran and in two petrochemical plants in Puerto General San Martín and Zárate.  We also own 262 retail service stations, four electric power plants, Pichi Picún Leufú (hydrogeneration), Genelba (gas powered combined cycle), Genelba Plus (gas powered) and EcoEnergia (Cogeneration), and we hold an interest in two other electric power plants, Central Termelétrica José de San Martín S.A. and Central Termelétrica Manuel Belgrano S.A.  Through our interest in PESA, we also have stake in a natural gas transportation company called TGS (Transportadora Gas del Sur). Through Petrobras Participaciones SL (Spain), we have an interest in Mega Company, a natural gas separation facility.

In Bolivia, our oil and gas production comes principally from the San Alberto, San Antonio and Itaú fields.  Following enactment of the Bolivian government’s May 1, 2006 nationalization of hydrocarbons, we entered into new production-sharing contracts under which we continue to operate the fields, but are required to make all hydrocarbon sales to YPFB with the right to recover our costs and participate in profits.  On January 25, 2009, Bolivia adopted a new constitution that prohibits private ownership of the country’s oil and gas resources.  As a result, we were not able to include any of our Bolivian proved reserves in our consolidated proved reserves since year-end 2009.  We continue to report production from our operations in Bolivia under our existing contracts in that country.  Additionally, we operate gas fields that supply gas to Brazil and Bolivia.  We hold an 11% interest in GTB, owner of the Bolivian section of the Bolivia-to-Brazil (BTB) pipeline that transports natural gas we produce in Bolivia to the Brazilian market.  We also hold a 21% interest in the Rio Grande Compression Unit, where the Bolivia-Brasil Gas Pipeline starts. In August 2014, we sold our interest (44.5%) in Transierra S.A. to YPFB for U.S.$106.7 million. 

In Chile, our operations include 269 service stations, the distribution and sales of fuel at airports and a lubricant plant.

In Colombia, we concluded the sale of 100% of the shares of our subsidiary Petrobras Colombia Limited (PEC) to Perenco Colombia Ltda. in May 2014 for a total amount of U.S.$380 million. Our remaining upstream portfolio in Colombia includes offshore exploration blocks and one onshore exploration block. See Note 10 to our audited consolidated financial statements. Additionally, we also have 113 service stations and a lubricant plant.

In Paraguay, our operations include 176 service stations, the distribution and sales of fuel at three airports and an LPG refueling plant.

In Peru, we concluded the sale of 100% of the shares of our subsidiary Petrobras Energia Peru (PEP) to China National Petroleum Corporation (CNPC) in November 2014 for U.S.$2.6 billion and we closed our operations in the country.  See Note 10 to our audited consolidated financial statements.

In Venezuela, through PESA, we hold minority interests in four joint ventures with subsidiaries of Petróleos de Venezuela S.A., or PDVSA, which hold production rights.  PDVSA is the majority holder and operator.

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 In Uruguay, we concluded the sale of our interests in offshore exploration blocks 3 and 4, located in the Punta del Este Basin to Shell in May 2014 for U.S.$17 million.  We have no further upstream portfolio in the country.  We also have downstream operations in the country, including 87 service stations and gas segment assets.

North America

In the United States,we focus on deepwater fields in the Gulf of Mexico.  As of December 31, 2014, we held interests in 137 offshore blocks, 98 of which we operate.  Our production in the United States during 2014 originated mainly from the Cascade, Chinook and Cottonwood fields. The Cascade and Chinook fields began oil production in February 2012 and September 2012, respectively.  These projects are the first Gulf of Mexico operation to use an FPSO.  Other assets include the Saint Malo, which began oil production in December 2014, Lucius, which began oil production in January 2015, Hadrian South block, which began gas production in March 2015, and Tiber, among others, which are currently in the exploratory stage. In April 2014, we sold 50% of our 100% interest in the Urca field and transferred the operation to Murphy Oil Corporation, for U.S.$15 million. We also own 100% of the Pasadena Refining System Inc., or PRSI, and 100% of PRSI’s related trading company – PRSI Trading, LLC. 

We have recognized impairment losses for the fiscal year ended December 31, 2014 of U.S.$1.7 billion due to the impact of the recent decline in international crude oil prices in our exploration and production producing properties outside Brazil.  The impairment losses are mainly in the Cascade and Chinook fields, located in the United States (U.S.$1.6 billion).  For further information, see Note 14 to our audited consolidated financial statements.

We have held non-risk service contracts through our joint venture with PTD Servicios Multiplos SRL for the Cuervito and Fronterizo blocks in the Burgos Basin of Mexico since 2003.  Under these service contracts, we receive fees for our services, but any production is transferred to the Mexican national oil company Petróleos Mexicanos, or Pemex. 

Africa

In June 2013, we established a joint venture with BTG Pactual to jointly explore oil and gas opportunities in Africa. This joint venture, was formed upon the acquisition by BTG Pactual of 50% of the shares issued by Petrobras Oil & Gas B.V. (PO&G), an once wholly-owned subsidiary of Petrobras International Braspetro B.V. (PIBBV), for U.S.$1.5 billion.

PO&G is primarily involved in the exploration and production of oil and gas through its subsidiaries in Nigeria and branches in Benin, Gabon and Namibia. In May 2014, PO&G’s portfolio was further expanded when it obtained control over a Petrobras subsidiary in Tanzania and in June 2014, when it obtained control over a Petrobras branch in Angola.  During 2014, PO&G’s exploration resulted in four drilled wells considered dry and one considered a subcommercial discovery.

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The assets of our joint venture with BTG Pactual include:

In Angola, the Block 26 license, retained at the end of 2014, and which will expire in May 2015. During 2014, the licenses of 3 blocks expired: Block 2/85 in April and Blocks 6/06 and 18/06 in November. All of these blocks were in an exploratory phase;

In Benin,  Block 4, which is in an exploratory phase;

In Gabon, the Ntsina Marin and Mbeli Marin Blocks, which are in an exploratory phase;

In Namibia, we returned the Block 2714A license to the Namibian government in April 2014;

In Nigeria,  the Agbami and Akpo fields, which are both producing oil. We also have an interest in the Egina field project, currently in its development stage while the Preowei and Egina South fields are under appraisal; and

In Tanzania, two offshore exploration blocks, Blocks 6 and 8.

Asia

In Japan, we own the Nansei Sekiyu Kabushiki Kaisha (NSS) refinery in Okinawa, with a crude distillation capacity of 100 mbbl/d, which produces refined products such as gasoline, diesel, fuel oil and jet fuel.  In February 2015, we decided to begin winding down our operations of this refinery.  This plan involves continuing NSS’s activities in the maritime terminal in order to maintain the supply of fuel oil, gasoline and diesel to Okinawa Island until the completion of this process, which will be conducted in collaboration with the Ministry of Economy, Trade and Industry of the Japanese Government.  As a result of the plan, we have recognized impairment losses for the fiscal year ended December 31, 2014 of U.S.$129 million.  See Notes 14 and 35 to our audited consolidated financial statements.

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International Exploration and Production Assets in Development

The table below shows our main exploration and production projects being developed worldwide, as of December 31, 2014.

		Main International Exploration and Production Assets in Development
Countries		Main projects in development	Phase	Operated by	Petrobras interest (%)
South America
1	Argentina(1)	Sierra Chata El Tordillo Santa Cruz I Oeste(2) 25 de Mayo – Medanito Rio Neuquén Santa Cruz I(2) El Mangrullo Entre Lomas	Production Production Production Production Production Production Production Production	Petrobras Partner Petrobras Petrobras Petrobras Petrobras Petrobras Petrobras	46 36 50 100 100 71 100 77
2	Bolivia(3)	San Alberto San Antonio Itaú Colpa y Caranda (1)	Production Production Production Production	Petrobras Petrobras Petrobras Petrobras	35 35 30 100
3	Colombia	Tayrona Villarica Norte	ExplorationExploration	Petrobras Petrobras	4050
4	Venezuela(4)	Oritupano-Leona Acema La Concepción Mata	Production Production Production Production	Partner Partner Partner Partner	22 34 36 34
North America
5	Mexico(5)	Cuervito Fronterizo	Production Production	Petrobras Petrobras	45 45
6	U.S.A.	Cascade Chinook Cottonwood St. Malo Lucius Tiber Hadrian South	Production Production Production Production Production Exploration Development	Petrobras Petrobras Petrobras Partner Partner Partner Partner	100 66.67 100 25 11.5 20 23.33
Africa
7	Angola(6)	Block 26	Exploration	Petrobras	40
8	Benin(6)	Block 4	Exploration	Partner	35
9	Gabon(6)	Ntsina Marin Mbeli Marin	Exploration Exploration	Partner Partner	50 50
10	Nigeria(6)	Akpo Agbami Egina Egina South Preowei	Production Production Development Exploration Exploration	Partner Partner Partner Partner Partner	20 12.5 20 20 20
11	Tanzania(6)	Block 6 Block 8	Exploration Exploration	Petrobras Petrobras	38 50

(1)               All Argentine and Colpa Caranda exploration and production projects are held through our indirect 67.2% share in Petrobras Argentina S.A. (PESA).

(2)               Assets sold in March 2015 (Austral Basin) to third parties.  See Item 4. “Information on the Company—International—International Activities by Region and Country.”

(3)               Production-sharing contract, under which Petrobras’s expenditures are reimbursed only if exploration results in economically viable oil discoveries.

(4)               Joint venture through Petrobras Argentina S.A. (PESA).

(5)               Non-risk service contract, under which Petrobras’s expenditures are reimbursed regardless of whether exploration results in economically viable oil discoveries.

(6)               Since June 2013, our projects in Angola, Benin, Gabon, Namibia, Nigeria and Tanzania have been developed through a joint venture between Petrobras International Braspetro B.V. and BTG Pactual.

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Biofuels

Biofuels Key Statistics
	2014	2013	2012
	(U.S.$ million)
Biofuel:
Sales revenues	266	388	455
Income (loss) before income taxes	(166)	(168)	(156)
Property, plant and equipment	205	222	255
Capital expenditures	112	143	147

Brazil is a global leader in the use and production of biofuels.  In 2014,  88.2% of new light vehicles sold in Brazil had flexfuel capability, and service stations offered a choice of 100% ethanol and an ethanol/gasoline blend.  Starting in March 2015, the Brazilian federal government increased the anhydrous ethanol content requirement for the gasoline sold in Brazil from 25% to 27%.

Biodiesel

Since November 2014, all diesel fuel sold in Brazil is required to have at least 7% biodiesel.  In 2014, we supplied 17% of Brazil’s biodiesel (assuming 100% of BSBIOS Sul Brasil production) and we act as a market catalyst by securing and blending biodiesel supplies and furnishing these to smaller distributors as well as our own service stations.  We directly own three biodiesel plants and, through our 50% interest in BSBIOS Indústria e Comércio de Biodiesel Sul Brasil S.A. (BSBIOS Sul Brasil), we own two additional plants.  The biodiesel production capacity of these five plants totals 14.1 mbbl/d, ranking us amongst the five main biodiesel producers in Brazil.

Ethanol

Due to our ownership interest in Guarani S.A. (Guarani) (42.95%), Brazil’s fourth largest sugarcane processor, Nova Fronteira Bioenergia S.A. (Nova Fronteira) and Bambuí Bioenergia S.A. (Bambuí Bioenergia), we also have a presence in the whole ethanol and sugar production chain and we also sell the exceeding electricity generated from sugarcane bagasse burn. We have all the necessary infrastructure for the distribution and export of ethanol. 

Through our associated companies Bambuí Bioenergia, Nova Fronteira and Guarani, we own ethanol plants situated in the States of Minas Gerais, Goiás and São Paulo and in Mozambique, Africa. These associated  companies’ total milling in the 2014/2015 harvest amounted to 26.4 mmt of sugarcane, corresponding to an ethanol and sugar production of 21.3 mbbl/d and 1.6 mmt respectively compared to 18.2 mbbl/d and 1.6 mmt respectively in the 2013/2014 harvest. These associated entities sold 1,295 GWh of exceeding electricity generated during the 2014/2015 harvest. 

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Corporate

Corporate Key Statistics
	2014	2013	2012
	(U.S.$ million)
Corporate:
Income (loss) before income taxes	(7,714)	(7,818)	(6,999)
Property, plant and equipment	2,787	3,312	3,204
Capital expenditures and investments	446	547	747

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

Organizational Structure

As of December 31, 2014, we had 26 direct subsidiaries and two direct joint operations as listed below. Twenty-four are entities incorporated under the laws of Brazil and four are incorporated abroad.  We also have indirect subsidiaries (including Petrobras Argentina S.A. and PGF).  As described in Note 36 to our audited consolidated financial statements, on December 29, 2014, PifCo merged into PGF.  See Exhibit 8.1 for a complete list of our subsidiaries and joint operations, including their full names, jurisdictions of incorporation and our percentage of equity interest.

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PETROBRAS
BRAZIL	ABROAD
Petrobras Distribuidora S.A. - BR	Petrobras Netherlands B.V. - PNBV
Transportadora Associada de Gás S.A. - TAG	Petrobras International Braspetro - PIB BV
Petrobras Transporte S.A. - Transpetro	Braspetro Oil Services Company - Brasoil
Petrobras Logística de Exploração e Produção S.A. - PB-LOG	Cordoba Financial Services GmbH
Petrobras Gás S.A. - Gaspetro
Petrobras Biocombustível S.A.
Companhia Integrada Têxtil de Pernambuco S.A. - CITEPE
Liquigás Distribuidora S.A.
Termomacaé Ltda.
Companhia Petroquímica de Pernambuco S.A. - PetroquímicaSuape
Araucária Nitrogenados S.A.
Breitener Energética S.A.
Petrobras Comercializadora de Energia Ltda. - PBEN
Termobahia S.A.
Arembepe Energia S.A.
5283 Participações Ltda.
Baixada Santista Energia S.A.
Energética Camaçari Muricy I Ltda.
Fundo de Investimento Imobiliário RB Logística - FII
Termomacaé Comercializadora de Energia Ltda
Petrobras Negócios Eletrônicos S.A. - E-Petro
Downstream Participações Ltda.
Fábrica Carioca de Catalizadores S.A. - FCC (*)
Ibiritermo S.A. (*)
(*) Joint operations.

Property, Plant and Equipment

                Our most important tangible assets are wells, platforms, refining facilities, pipelines, vessels, other transportation assets, power plants as well as fertilizers and biodiesels plants. Most of these are located in Brazil.  We own and lease our facilities and some owned facilities are subject to liens, although the value of encumbered assets is not material.

                We have the right to exploit crude oil and gas reserves in Brazil under concession agreements, but the reserves themselves are the property of the government under Brazilian law. Item 4. “Information on the Company” includes a description of our reserves and sources of crude oil and natural gas, key tangible assets, and material plans to expand and improve our facilities.

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                As of December 31, 2014, our property, plant and equipment included U.S.$28,164 million (U.S.$21,510 million as of December 31, 2013) related to the Assignment Agreement (see Item 10. “Additional Information—Material Contracts—Assignment Agreement.”)  On December 29, 2014, we submitted the last declaration of commerciality of crude oil and natural gas accumulations, located in the Entorno de Iara block, to the ANP. During 2014, acquisition costs related to Florim (now Itapu field), Sul de Guará (now Sul de Sapinhoá field), Entorno de Iara (now Norte de Berbigão, Sul de Berbigão, Norte de Sururu, Sul de Sururu and Atapu fields) and Nordeste de Tupi (now Sepia field) were reclassified from intangible assets to property, plant and equipment as their commerciality was declared. During 2013, acquisition costs related to Franco (now Búzios field) and Sul de Tupi (now Sul de Lula field), had already been reclassified from intangible assets to property, plant and equipment.  See Note 12.3 to our audited consolidated financial statements.

                We have also recognized impairment charges of U.S.$16,823 million in 2014 for certain property, plant and equipment, intangible assets and assets classified as held for sale. Further information about impairment of our assets is provided in Note 14 to our audited consolidated financial statements.

Regulation of the Oil and Gas Industry in Brazil

Concession Regime for Oil and Gas

Under Brazilian law, the Brazilian federal government owns all crude oil and natural gas subsoil accumulations in Brazil.  The Brazilian federal government holds a monopoly over the exploration, production, refining and transportation of crude oil and oil products in Brazil and its continental shelf, with the exception that companies that were engaged in refining and distribution in 1953 were permitted to continue those activities.  Between 1953 and 1997, we were the Brazilian federal government’s exclusive agent for exploiting its monopoly, including the importation and exportation of crude oil and oil products.

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

Law No. 9,478/1997 established a concession-based regulatory framework and granted us the exclusive right to exploit crude oil reserves in each of our producing fields under the existing concession contracts for an initial term of 27 years from the date when they were declared commercially profitable.  These are known as the “Round Zero” concession contracts. This initial 27-year period for production can be extended at the request of the concessionaire and subject to approval from the ANP.  Law No. 9,478/1997 also established a procedural framework for us to claim exclusive exploratory rights for a period of up to three years, later extended to five years, to areas where we could demonstrate that we had made commercial discoveries or exploration investments prior to the enactment of the Law No. 9,478/1997.  In order to perfect our claim to explore and develop these areas, we had to demonstrate that we had the financial capacity to carry out these activities, either alone or through other cooperative arrangements.  Starting in 1999, all areas not already subject to concessions became available for public bidding conducted by the ANP.  All the concessions that we have obtained since then were obtained through participation in public bidding rounds.

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Taxation under Concession Regime for Oil and Gas

According to the Law No. 9,478/1997 and under our concession agreements for exploration and production activities with ANP, we are required to pay the government the following:

·Signing bonuses paid upon the execution of the concession agreement, which are based on the amount of the winning bid, subject to the minimum signing bonuses published in the relevant bidding guidelines (edital de licitação);

·Annual retention bonuses for the occupation or retention of areas available for exploration and production, at a rate established by the ANP in the relevant bidding guidelines based on the size, location and geological characteristics of the concession block;

·Special participation charges at a rate ranging from 0 to 40% of the net income derived from the production of fields that reach high production volumes or profitability, according to the criteria established in the applicable legislation. Net revenues are gross revenues less royalties paid, investments in exploration, operational costs and depreciation adjustments and applicable taxes.  The Special Participation Tax uses as a reference international oil prices converted to reais at the current exchange rate. In 2014, we paid this tax on 21 of our fields, namely Albacora, Albacora Leste, Baleia Azul, Baleia Franca, Barracuda, Baúna, Cachalote, Canto do Amaro, Caratinga, Carmópolis, Jubarte, Leste do Urucu, Lula, Manati, Marlim, Marlim Leste, Marlim Sul, Mexilhão, Rio Urucu, Roncador and Sapinhoá; and

·Royalties, to be established in the concession contracts at a rate ranging between 5% and 10% of gross revenues from production, based on reference prices for crude oil or natural gas established by Decree No. 2,705 and ANP regulatory acts.  In establishing royalty rates in the concession contracts, the ANP also takes into account the geological risks and expected productivity levels for each concession.  Virtually all of our crude oil production is currently taxed at the maximum royalty rate.

Law No. 9,478/1997 also requires concessionaires of onshore fields to pay to the owner of the land a participation fee that varies between 0.5% and 1.0% of the sales revenues derived from the production of the field.

Production-Sharing Contract Regime for Unlicensed Pre-Salt and Potentially Strategic Areas

Discoveries of large oil and natural gas reserves in the pre-salt areas of the Campos and Santos Basins prompted a change in the legislation regarding oil and gas exploration and production activities.

In 2010, three new laws were enacted to regulate exploration and production activities in pre-salt and other potentially strategic areas not subject to existing concessions:  Law No. 12,351, Law No. 12,304, and Law No. 12,276.  The enacted legislation does not impact the existing pre-salt concession contracts, which cover approximately 28% of the pre-salt areas.

Law No. 12,351/2010 regulates production-sharing contracts for oil and gas exploration and production in pre-salt areas not under concession and in potentially strategic areas to be defined by the CNPE.  Under the production-sharing regime, we will be the exclusive operator of all blocks.  The exploration and production rights for these blocks can either be granted to us on an exclusive basis or, in the case where they are not awarded to us on an exclusive basis, they will be offered under public bids.  If offered under public bids, we would still be required to participate as the operator, with a minimum interest to be established by the CNPE that would not be less than 30%, with the additional right, at our discretion, to participate in the bidding process to increase our interest in those areas.  Under the production-sharing regime, the winner of the bid will be the company that offers to the Brazilian federal government the highest percentage of “profit oil,” which is the production of a certain field after deduction of royalties and “cost oil,” which is the cost associated with oil production.  According to Law No. 12,351, we must accept the economic terms of the winning bid.

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Law No. 12,734 became partially effective on November 30, 2012, and amended Law 12,351, establishing a royalty rate of 15% applicable to the gross production of oil and natural gas under future production sharing contracts.

Law No. 12,304/2010, authorized the incorporation of a new state-run non-operating company that will represent the interests of the Brazilian federal government in the production-sharing contracts and will manage the commercialization contracts related to the Brazilian federal government’s share of the “profit oil.”  This new state-owned company was incorporated on August 1, 2013, named Pré-Sal Petróleo S.A. – PPSA, and will participate in operational committees, with a casting voteand veto powers, as defined in the contract, and will manage and control costs arising from production-sharing contracts.  Where production-sharing contracts are concerned, this new company will exercise its specific legal activities alongside the ANP, the independent regulatory agency that regulates and oversees oil and gas activities under all exploration and production regimes, and the CNPE, the entity that sets the guidelines to be applied to the oil and gas sector, including with respect to the new regulatory model.

Assignment Agreement (Cessão Onerosa)and Global Offering

Pursuant to Law No. 12,276/2010, we entered into an agreement with the Brazilian federal government on September 3, 2010 (Assignment Agreement), under which the government assigned to us the right to conduct activities for the exploration and production of oil, natural gas and other fluid hydrocarbons in specified pre-salt areas, subject to a maximum production of five bnboe. The initial contract price for our rights under the Assignment Agreement was R$74,807,616,407, which was equivalent to U.S.$42,533,327,500 as of September 1, 2010.  See Item 10. “Additional Information—Material Contracts—Assignment Agreement.” 

Natural Gas Law of 2009

In March 2009, the Brazilian Congress enacted Law No.11,909, or Gas Law, regulating activities in the gas industry, including transport, processing, storage, liquefaction, regasification and commercialization.  The Gas Law created a concession regime for the construction and operation of new pipelines to transport natural gas, while maintaining an authorization regime for pipelines subject to international agreements.  According to the Gas Law, after a certain exclusivity period, operators (transportadores) will be required to grant access to transport pipelines and maritime terminals, except LNG terminals, to third parties in order to maximize utilization of capacity.

The Gas Law authorized the ANP to regulate prices for the use of gas transport pipelines subject to the new concession regime, based on a procedure defined in the Gas Law as a “chamada pública,” and to approve prices submitted by carriers (carregadores), according to previously established criteria, for the use of new gas transport pipelines subject to the authorization regime.

Authorizations previously issued by the ANP for natural gas transport will remain valid for 30 years from the date of publication of the Gas Law, and initial carriers (carregadores iniciais) were granted exclusivity in these pipelines for 10 years. All pipelines that Petrobras’s subsidiaries currently own and operate in Brazil are subject to an authorization regime. The ANP will issue regulations governing third-party access and carrier compensation if no agreement is reached between the parties.

The Gas Law also authorized certain consumers, who can purchase natural gas on the open market or obtain their own supplies of natural gas, to construct facilities and pipelines for their own use in the event local gas distributors controlled by the states, which have monopoly over local gas distribution, do not meet their distribution needs.  These consumers are required to delegate the operation and maintenance of the facilities and pipelines to local gas distributors, but they are not required to sign gas supply agreements with the local gas distributors.

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In December 2010, Decree No. 7,382 was enacted in order to regulate Chapter I to VI and VIII of the Gas Law as it relates to activities in the gas industry, including transportation and commercialization. Since the publication of this decree, various administrative regulations were enacted by the ANP and the MME in order to regulate various issues in the Gas Law and Decree No. 7,382 that needed to be further clarified. Among those is ANP Resolution No. 51/2013, which prevents a carrier from holding any equity interest in concessionaires of gas transport pipelines. Resolution No. 51/2013 applies only to the concessions granted after its publication, not affecting, therefore, the transportation of Petrobras’s natural gas production through pipelines operated by its subsidiaries and subject to the previous authorization regime.

Price Regulation

Until the passage of Law No. 9,478 in 1997, the Brazilian federal government had the power to regulate all aspects of the pricing of crude oil, oil products, ethanol, natural gas, electric power and other energy sources.  In 2002, the government eliminated price controls for crude oil and oil products, although it retained regulation over certain natural gas sales contracts and electricity.  The Brazilian federal government has periodically adjusted taxes applicable to crude oil, oil and natural gas products as a tool to maintain price stability to end consumers and also to increase its tax revenues.

Environmental Regulations

All phases of the crude oil and natural gas business present environmental risks and hazards.  Our facilities in Brazil are subject to a wide range of federal, state and local laws, regulations and permit requirements relating to the protection of human health and the environment, and they fall under the regulatory authority of the Conselho Nacional doMeio Ambiente (National Council for the Environment, or CONAMA).

Our offshore activities are subject to the administrative authority of IBAMA, which issues operating and drilling licenses.  We are required to submit reports, including safety and pollution monitoring reports (IOPP) to IBAMA in order to maintain our licenses.

Most of the onshore environmental, health and safety conditions are controlled either at the federal or the state level depending on the localization of our facilities, the type of activity under development and other criteria to be set forth in regulation that is still pending. However, it is also possible for these conditions to be controlled on a local basis whenever the activities generate a local impact or are established in a county conservation unit. Under Brazilian law, there is strict and joint liability for environmental damage, mechanisms for enforcement of environmental standards and licensing requirements for polluting activities.

Individuals or entities whose conduct or activities cause harm to the environment are subject to criminal and administrative sanctions.  Government environmental protection agencies may also impose administrative sanctions for noncompliance with environmental laws and regulations, including:

·Fines;

·Partial or total suspension of activities;

·Requirements to fund reclamation and environmental projects;

·Forfeiture or restriction of tax incentives or benefits;

·Closing of establishments or operations; and

·Forfeiture or suspension of participation in credit lines with official credit establishments.

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We are subject to a number of administrative and legal proceedings relating to environmental matters.  For more information about these proceedings, see Item 8. “Financial Information—Legal Proceedings.” and Note 30 to our audited consolidated financial statements included in this annual report.

In 2014, we invested U.S.$1.4 billion in environmental projects, compared to U.S.$1.5 billion in 2013 and U.S.$1.5 billion in 2012.  These investments continued to be primarily directed at reducing emissions and wastes from industrial processes, managing water use and effluents, remedying impacted areas, implementing new environmental technologies, upgrading our pipelines and improving our ability to respond to emergencies.

Health, Safety and Environmental Initiatives

The protection of human health and the environment is one of our primary concerns, and is essential to our success as an integrated energy company.

We have a Health, Safety and Environmental (HSE) Committee (Comitê de Segurança, Meio Ambiente e Saúde) composed of three members of our board of directors who are responsible for assisting our board in the following matters:

·Definition of strategic goals in relation to HSE matters;

·Establishment of global policies related to the strategic management of HSE matters within Petrobras’s group of companies;

·Assessment of the conformity of Petrobras’s Strategic Plan to its global HSE policies, among others.

Our efforts to address health, safety and environmental concerns and ensure compliance with environmental regulations (which in 2014 totaled an investment of U.S.$2.4 billion) involve the management of environmental costs related to production and operations, pollution control equipment and systems, projects to rehabilitate degraded areas, safety procedures and initiatives for emergency prevention and control, health and safety programs as well as:  

·An HSE management system that seeks to minimize the impacts of operations and products on health, safety and the environment, reduce the use of natural resources and pollution and prevent accidents;

·ISO 14001 (environment) and OHSAS 18001 (health and safety) certification of our operating units.    All the oil refined in Brazil was processed by certified units. The Frota Nacionalde Petroleiros (National Fleet of Vessels) has been fully certified by the International Maritime Organization (IMO) International Management Code for Safe Operation of Ships and for Pollution Prevention (ISM Code) since December 1997;

·Regular and active engagement with the MME and IBAMA, in order to discuss environmental issues related to new oil and gas production and other transportation and logistical  aspects of our operations;

·A strategic goal to reduce the intensity of greenhouse gas emissions, along with a set of performance indicators with targets to monitor progress with respect to this goal; and 

·We evaluate each of our operational projects to identify risks and to ensure compliance with all of our HSE requirements and the adoption of the best HSE practices throughout a project’s life cycle.  In addition, we conduct more extensive environmental studies for new projects when required by applicable environmental legislation.

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In recent years, we have expanded our activities in almost all of our business segments, which consequently has led to an increase in our greenhouse gas emissions. In 2014, our emissions increased by 5% compared to 2013, mainly due to the higher energy generation of our thermoelectric power plants. Nevertheless, we are committed to reducing the intensity of greenhouse gas emissions from our processes and products.  We have been able to reduce greenhouse gas emissions through several different initiatives, including the modernization of our facilities, utilization of more efficient equipment and standardization of projects and operational practices, in furtherance of our ongoing investments in research and technology. 

Environmental Remediation Plans and Procedures

As part of our environmental plans, procedures and efforts, we maintain detailed response and remediation contingency plans to be implemented in the event of an oil spill or leak from our offshore operations.  In order to respond to these events, Petrobras has 36 dedicated oil spill recovery vessels (OSRVs) fully equipped for oil spill control and firefighting, 113 support boats and other vehicles, 270 additional support and recovery boats available to fight offshore oil spills and leaks, around 92 km of containment booms and 118 km of absorbent booms and around 113,000 liters of oil dispersants, among others. These resources are distributed in 12 environmental protection centers in strategic areas in which we operate throughout Brazil and in emergency response centers (distributed over 21 cities) in order to ensure rapid and coordinated response to onshore or offshore oil spills. Our regional facilities are supported by 11 local advanced bases dedicated to oil spill prevention, control and response.

We have more than 500 trained workers available to respond to oil spills 24 hours a day, seven days a week, and we can mobilize additional trained workers for shoreline cleanups on short notice from a large group of trained environmental agents in the country.  While these workers are located in Brazil, they are also available to respond to an offshore oil spill outside of Brazil.

Since 2012, Petrobras has been a participating member of the Oil Spill Response Limited – OSRL, an international organization that brings together over 160 corporations, including oil major, national/independent oil companies, energy related companies as well as other companies operating elsewhere in the oil supply chain. OSRL participates in the Global Response Network, an organization composed of several other companies dedicated to fighting oil spills. As a member of the OSRL, Petrobras has access to all resources available through that network, and we also subscribe to their Subsea Well Intervention Services (SWIS), which provides swift international deployment of response-ready capping and containment equipment.  The capping equipment is stored and maintained at bases worldwide, including Brazil.  An OSRL Brazilian base opened in March 2014 and is now operational.

In 2014, we conducted 22 emergency drills of regional scope with the Brazilian navy, the civil defense, firefighters, the military police, environmental organizations and local governmental and community entities.

We set up a Zero Spill Plan, aiming at optimizing management and reducing the risk of oil spills in our operations. This plan encompasses investments to improve the management of processes and to ensure the integrity of our equipment and installations.  Additionally, Petrobras has a model of communication, processing and recording of oil spills that permits the daily monitoring of these incidents, their impacts and mitigation measures.

The oil spill level in our upstream operations in 2014 was kept below 0.5 m³ per mmbbl produced. Data for 2012 compiled by the International Association of Oil & Gas Producers indicates that the industry average was 0.76 m³ of oil spilled per mmbbl produced. We continue to evaluate and develop initiatives to address HSE concerns and to reduce our exposure to HSE risks.  In 2014, we had oil spills totaling 437.1 barrels of crude oil, compared to 1,176 barrels of crude oil in 2013 (a 63% reduction) and 2,436 barrels of crude oil in 2012.

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Insurance

Our insurance programs focus principally on the evaluation of risks and the replacement value of assets, which is customary for our industry.  Under our risk management policy, risks associated with our principal assets, such as refineries, tankers and offshore production units and drilling rigs, are insured for their replacement value with third-party Brazilian insurers.  Although some policies are issued in Brazil, most of our policies are reinsured abroad with reinsurers rated A- or higher by Standard & Poor’s rating agency or B+ or higher by A.M. Best.  Part of our international operations are insured or reinsured by our Bermudian subsidiary BEAR following the same rating criteria.

Less valuable assets, including but not limited to small auxiliary boats, certain storage facilities, and some administrative installations, are self-insured.  We do not maintain coverage for business interruption, except for a minority of our international operations and a few specific assets in Brazil.  We generally do not maintain coverage for our wells for all of our Brazilian operations, except when required by a joint operating agreement.  Although we do not insure most of our pipelines, we have insurance against damage or loss to third parties resulting from specific incidents, such as unexpected seepage and oil pollution.  We also maintain coverage for risks associated with cargo, hull and machinery.  All projects and installations under construction that have an estimated maximum loss above U.S.$80 million are covered by a construction insurance policy.

We have operations in 16 countries outside Brazil and maintain varying levels of third-party liability insurance for our domestic and international operations as a result of a variety of factors, including our country risk assessments, whether we have onshore and offshore operations or legal requirements imposed by the particular country in which we operate.  We maintain insurance coverage for operational third-party liability with respect to our onshore and offshore activities, including losses to third parties resulting from environmental risks such as oil spills, in Brazil up to an aggregate policy limit of U.S.$250 million.  We also maintain additional protection and indemnity (P&I) marine insurance against third-party liability related to our domestic offshore operations up to an aggregate policy limit of up to U.S.$500 million for a period of 12 months.  In the event of an explosion or similar event at one of our offshore rigs in Brazil, these policies can provide combined third-party liability coverage of up to U.S.$750 million.

Our domestic and international operational third-party liability policies cover claims made against us by or on behalf of individuals who are not our employees in the event of property damage, personal injury or death, subject to the policy limits set forth above.  As a general rule, our service providers are required to indemnify us for a claim we pay directly to a third party as a result of a court decision holding us liable for the actions of that service provider. Our operational third-party liability policies also cover environmental damage from oil spills (including liability arising from an explosion or similar sudden and accidental event at one of our offshore rigs) as well as litigation and clean-up and remediation costs, but do not cover governmental fines or punitive damages.

We maintain separate “control-of-well” insurance policies at our international operations to cover liability arising from the uncontrolled eruption of oil, gas, water or drilling fluid, as well as to cover claims for environmental damage from well blow-outs and similar events as well as related clean-up costs, with aggregate policy limits up to U.S.$540 million for a period of 18 months depending on the country.  In the U.S. Gulf of Mexico, for example, we maintain third-party liability coverage up to an aggregate policy limit of U.S.$250 million, and control-of-well liability insurance up to U.S.$540 million.  Depending on the particular circumstances, either of these policies could apply in the event of an explosion or similar event at one of our offshore rigs in the U.S. Gulf of Mexico.

We generally do not maintain control-of-well insurance for our domestic operations onshore and offshore Brazil, except when required by a joint operating agreement.  As a result, we would bear the costs of clean-up, decontamination and any proceedings arising out of a control-of-well incident.  Any loss of hydrocarbon containment from our domestic operations onshore and offshore that is not attributable to a control-of-well issue would be covered by either our Protection & Indemnity (P&I) insurance, with coverage of up to U.S.$500 million for our mobile offshore units, or our onshore-offshore liability policy, with coverage of up to U.S.$250 million.

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The premium for renewing our domestic property risk insurance policy for an 18-month period beginning December 2013 was U.S.$104.9 million.  This represented a nominal increase of 7.7% over the prior 18-month period.  The insured value of our assets, in the same period, increased by 11.3% to U.S.$168.2 billion. Since 2001, our risk retention for operational risks has been U.S.$20 million while for engineering risks it may reach U.S.$80 million in certain circumstances.

Additional Reserves and Production Information

During 2014, our oil and gas production in Brazil averaged 2,284 mboe/d, of which 89% was oil and 11% was natural gas.  The Campos Basin is one of Brazil’s main and most prolific oil and gas offshore basins, with over 60 hydrocarbon fields discovered, eight large oil fields and a total area of approximately 115,000 km² (28.4 million acres).  In 2014, the Campos Basin produced an average 1,526 mbbl/d of oil and 548.4 mmcf/d (14.5 mmm³/d) of associated natural gas, comprising 71% of our total production from Brazil. We also conduct limited oil shale mining operations in São Mateus do Sul, in the Paraná Basin of Brazil, and we use oil shale from these deposits to produce synthetic oil and gas. Our oil shale industrialization business unit does not utilize the fracking method or the hydraulic fracturing method for purposes of oil production given that they are not proper for this end.  We crush and subsequently heat in high temperatures all the shale we produce, obtaining a proper segregation of the products derived from such process. We do not inject any water or chemicals in the soil in connection with our oil shale mining operations.

On December 31, 2014, our estimated proved reserves of crude oil, condensate and natural gas in Brazil totaled 12.7 bnbbl of oil equivalent, including 10.9 bnbbl of crude oil and condensate and 296.0 bnm³ (11.2 tcf) of natural gas.  As of December 31, 2014, our domestic proved developed crude oil and condensate reserves represented 64.5% of our total domestic proved crude oil and condensate reserves, and our domestic proved developed natural gas reserves represented 59.6% of our total domestic proved natural gas reserves.  Total domestic proved crude oil and condensate reserves increased at an average annual rate of 1.8% in the last five years, and total natural gas proved reserves increased at an average annual rate of 2.7% over the same period. 

We calculate reserves based on forecasts of field production, which depend on a number of technical parameters, such as seismic interpretation, geological maps, well tests, reservoir engineering studies and economic data.  All reserve estimates involve some degree of uncertainty.  The uncertainty depends primarily on the amount of reliable geological and engineering data available at the time of the estimate and the interpretation of that data.  Our estimates are thus made using the most reliable data and technology at the time of the estimate, in accordance with the best practices in the oil and gas industry and regulations promulgated by the SEC.  

Internal Controls over Proved Reserves

The reserve estimation process begins with an initial evaluation of our assets by geophysicists, geologists and engineers.  Corporate Reserves Coordinators (Coordenadores de Reservas Corporativos, or CRCs) safeguard the integrity and objectivity of our reserve estimates by supervising and providing technical support to Regional Reserves Coordinators (Coordenadores de Reservas Regionais, or CRRs) who are responsible for preparing the reserve estimates.  Our CRRs and CRCs have degrees in geophysics, geology, petroleum engineering, accounting and economics and are trained internally and abroad in international reserve estimates seminars.  CRCs are responsible for compliance with SEC rules and regulations, consolidating and auditing the reserve estimation process. The technical person primarily responsible for overseeing the preparation of our domestic reserves is a member of the SPE, with 26 years of experience in the field and has been with Petrobras for over 31 years.  The technical person primarily responsible for overseeing the preparation of our international reserves has 25 years of experience in the field and has been with Petrobras for 32 years. Our reserve estimates are approved by our board of executive officers, which then informs our board of directors of its approval.

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DeGolyer and MacNaughton (D&M) used our reserve estimates to conduct a reserve audit of 96.5% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2014 from certain properties we own in Brazil. In addition, D&M used its own estimates of our reserves to conduct a reserves evaluation of 100% of the net proved crude oil, condensate, NGL and natural gas reserves as of December 31, 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 of Rule 4-10(a) of Regulation S-X of the SEC. For further information about our proved reserves, see “Supplementary Information on Oil and Gas Exploration and Production” beginning on page F-96. For disclosure describing the qualification of D&M’s technical person primarily responsible for overseeing our reserves audit and reserves evaluation, see Exhibit 99.1.

Changes in Proved Reserves

During 2014, we added 1,096.7 mmboe to our proved reserves, excluding synthetic oil and synthetic gas, while we (i) relinquished to the ANP eleven fields in Brazil (four with proved reserves) and (ii) we divested from fields in which we had interests in Peru, Colombia, Argentina and United States, representing aggregate proved reserves of 192.5 mmboe.  The net result of these additions and dispositions was an increase of 904.1 mmboe to our proved reserves in 2014. Considering a production of 896.2 mmboe in 2014, our net increase of proved reserves was 7.9 mmboe. This volume production does not take into account the production of Extended Well Tests (EWTs) in exploratory blocks in Brazil, production of synthetic oil and synthetic gas and production in Bolivia, since the Bolivian Constitution prohibits the disclosure and registration of its reserves.

At year‐end 2014 compared to year‐end 2013, our proved undeveloped reserves company‐wide decreased by a net total of 493.8 mmboe. Thus, we had a total of 4,773.2 mmboe of proved undeveloped reserves company‐wide at December 31, 2014, compared to 5,267.0 mmboe of proved undeveloped reserves company-wide at December 31, 2013.

In Brazil, the net decrease in our proved undeveloped reserves in 2014 compared to 2013 is mostly derived from the conversion of some of our proved undeveloped reserves to proved developed reserves, attributable to the start-up of new production units in the Campos and Santos Basins, and the drilling of wells in existing production fields, amounting to 1,222.6 mmboe. In addition, our proved undeveloped reserves in Brazil were reduced by 29.3 mmboe due to the relinquishment of four fields with proved reserves to the ANP. This net decrease was partially offset by the 632.8 mmboe increase of proved undeveloped reserves derived from revisions to previous estimates and a 284.3 mmboe increase from extensions and discoveries mainly in the pre-salt areas of Santos and Campos Basins.

 All reserve volumes described above are “net” to the extent that they only include Petrobras’s proportional participation in reserve volumes and exclude reserves attributed to our partners.

                In 2014, we invested a total of U.S.$19.8 billion in development projects, of which 92% (U.S.$18.2 billion) was invested in Brazil, and converted a total of 1,299.5 mmboe of proved undeveloped reserves to proved developed reserves, approximately 94% (1,222.6 mmboe) of which were Brazilian reserves.

Most of our investments relate to long-term development projects which are developed in phases due to the large volumes and extensions involved, the deep and ultra-deep water infrastructure and the production resources complexity. In these cases, the full development of the reserves related to these investments can exceed five years.

We had a total of 4,773.2 mmboe of proved undeveloped reserves company-wide at year‐end 2014, approximately 2.1% (100.4 mmboe) of which have remained undeveloped for five years or more as a result of several factors affecting development and production, including the inherent complexity of ultra‐deepwater development projects, particularly in Brazil, and constraints in the capacity of our existing infrastructure.

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The majority of the 100.4 mmboe of our proved undeveloped reserves that have remained undeveloped for five years or more consist of reserves in the Campos Basin, in which we are making investments to develop necessary infrastructure.

The following tables set forth our production of crude oil, natural gas, synthetic oil and synthetic gas by geographic area in 2014, 2013 and 2012: 

	Hydrocarbon Production by Geographic Area
	2014						2013					2012
	Oil (mbbl/d) (5)	Synthetic Oil (mbbl/d) (4)	Nat. Gas (mmcf/d) (1)	Synthetic Gas (mmcf/d) (1)(4)	Total (mboe/d)	Oil (mbbl/d) (5)	Synthetic Oil (mbbl/d) (4)	Nat. Gas (mmcf/d) (1)	Synthetic Gas (mmcf/d) (1)(4)	Total (mboe/d)	Oil (mbbl/d)	Synthetic Oil (mbbl/d) (4)	Nat. Gas (mmcf/d)(1)	Synthetic Gas (mmcf/d) (1)(4)	Total (mboe/d)
Brazil:
Roncador field(2)	276.0	‒	121.6	‒	296.3	268.2	‒	105.3	‒	285.8	262.8	‒	101.4	‒	279.7
Other	1,755.5	2.9	1,377.8	1.0	1,988.2	1,660.5	2.7	1,299.7	0.9	1,879.9	1,714.3	3.0	1,249.8	1.1	1,925.8
Total Brazil	2,031.5	2.9	1,499.4	1.0	2,284.4	1,928.7	2.7	1,404.9	0.9	2,165.7	1,977.1	3.0	1,351.3	1.1	2,205.5
International:
South America (outside of Brazil)	57.3	‒	545.9	‒	148.3	70.2	‒	546.7	‒	161.4	76.4	‒	629.9	‒	181.4
North America	27.3	‒	12.8	‒	29.5	11.8	‒	11.9	‒	13.8	9.0	‒	18.8	‒	12.1
Africa	‒	‒	‒	‒	‒	25.9	‒	0.0	‒	25.9	51.8	‒	‒	‒	51.8
Total International	84.7	‒	558.7	‒	177.8	107.9	‒	558.7	‒	201.1	137.3	‒	648.7	‒	245.4
Total consolidated production	2,116.2	‒	2,058.1	‒	2,462.2	2,036.6	2.7	1,963.6	0.9	2,366.7	2,114.4	3.0	2,000.0	1.1	2,450.9
Equity and non-consolidated affiliates(3):
South America (outside of Brazil)	4.6	‒	1.6	‒	4.9	5.5	‒	1.7	‒	5.8	6.4	‒	2.4	‒	6.8
Africa	26.6	‒	‒	‒	26.6	13.8	‒	0.0	‒	13.8	‒	‒	‒	‒	‒
Worldwide production	2,147.4	2.9	2,059.7	1.0	2,493.7	2,055.9	2.7	1,965.3	0.9	2,386.4	2,120.8	3.0	2,002.4	1.1	2,457.7

(1)      Natural gas production figures are the production volumes of natural gas available for sale, excluding flared and reinjected gas and gas consumed in operations.

(2)      Roncador field is separately included as it contains more than 15% of our total proved reserves.

(3)      Equity-accounted investees.

(4)      We produce synthetic oil and synthetic gas from oil shale deposits in São Mateus do Sul, in the Paraná Basin of Brazil.

(5)      Oil production includes LNG and production from extended well tests.

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The following table sets forth our estimated net proved developed and undeveloped reserves of crude oil and natural gas by region as of December 31, 2014. 

Estimated Net Proved Developed and Undeveloped Reserves
Reserves category	Reserves
	Oil (mmbbl)	Natural gas (bncf)	Total oil and natural gas (mmboe)	Synthetic oil (mmbbl)(1)	Synthetic gas (bncf)(1)	Total synthetic oil and synthetic gas (mmboe)	Total oil and gas products (mmboe)
Proved developed:
Brazil	7,002.7	6,661.0	8,112.8	7.9	10.6	9.6	8,122.5
International
South America (outside of Brazil)	52.0	358.2	111.7	0.0	0.0	0.0	111.7
North America	63.6	146.2	88.0	0.0	0.0	0.0	88.0
Total International	115.6	504.3	199.7	0.0	0.0	0.0	199.7
Total consolidated proved developed reserves	7,118.3	7,165.4	8,312.5	7.9	10.6	9.6	8,322.2
Equity and non-consolidated affiliates
South America (outside of Brazil)	9.4	15.7	12.0	0.0	0.0	0.0	12.0
Africa	30.8	14.4	33.2	0.0	0.0	0.0	33.2
Total non-consolidated proved developed reserves	40.2	30.2	45.2	0.0	0.0	0.0	45.2
Total proved developed reserves	7,158.5	7,195.6	8,357.8	7.9	10.6	9.6	8,367.4
Proved undeveloped:
Brazil	3,848.2	4,509.2	4,599.7	0.0	0.0	0.0	4,599.7
International
South America (outside of Brazil)	14.6	372.5	76.7	0.0	0.0	0.0	76.7
North America	56.4	33.8	62.1	0.0	0.0	0.0	62.1
Total International	71.1	406.3	138.8	0.0	0.0	0.0	138.8
Total consolidated proved undeveloped reserves	3,919.2	4,915.6	4,738.5	0.0	0.0	0.0	4,738.5
Equity and non-consolidated affiliates
South America (outside of Brazil)	8.6	11.9	10.5	0.0	0.0	0.0	10.5
Africa	23.3	4.9	24.1	0.0	0.0	0.0	24.1
Total non-consolidated proved undeveloped reserves	31.9	16.8	34.7	0.0	0.0	0.0	34.7
Total proved undeveloped reserves	3,951.1	4,932.3	4,773.2	0.0	0.0	0.0	4,773.2
Total proved reserves (developed and undeveloped)	11,109.6	12,127.9	13,130.9	7.9	10.6	9.6	13,140.6

_____________

(1)               Volumes of synthetic oil and synthetic gas from oil shale deposits in the Paraná Basin in Brazil have been included in our proved reserves in accordance with the SEC rules for estimating and disclosing reserve quantities.

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The table below summarizes information about the changes in total proved reserves of our consolidated entities for 2014, 2013 and 2012:  

Total Proved Developed and Undeveloped Reserves (consolidated entities only) (1)
	Oil (mmbbl)	Natural gas (bncf)	Total oil and natural gas (mmboe)	Synthetic oil (mmbbl)	Synthetic gas (bncf)	Total synthetic oil and synthetic gas (mmboe)	Total oil and gas products (mmboe)
Reserves quantity information for the year ended December 31, 2014
January 1, 2014	10,947.7	12,483.2	13,028.3	8.8	11.8	10.7	13,039.0
Revisions of previous estimates	631.4	539.6	721.4	0.2	0.1	0.2	721.6
Improved recovery	0.5	10.8	2.3	0.0	0.0	0.0	2.3
Purchases of minerals in situ	22.9	47.1	30.8	0.0	0.0	0.0	30.8
Extensions and discoveries	272.3	264.0	316.3	0.0	0.0	0.0	316.3
Production	(732.9)	(911.8)	(884.8)	(1.1)	(1.4)	(1.3)	(886.1)
Sales of minerals in situ	(104.5)	(351.9)	(163.1)	0.0	0.0	0.0	(163.1)
December 31, 2014	11,037.5	12,081.0	13,051.0	7.9	10.6	9.6	13,060.7
Reserves quantity information for the year ended December 31, 2013
January 1, 2013	10,928.5	11,541.2	12,852.1	8.3	13.3	10.6	12,862.6
Transfer/Disposal of assets with loss of control(2)	(65.0)	(22.5)	(68.8)	‒	‒	‒	(68.8)
Revisions of previous estimates	(74.7)	(213.3)	(110.2)	1.3	(0.1)	1.2	(109.0)
Improved recovery	124.2	916.0	276.8	‒	‒	‒	276.8
Purchases of minerals in situ	0.0	0.4	0.1	‒	‒	‒	0.1
Extensions and discoveries	851.4	1,193.5	1,050.3	‒	‒	‒	1,050.3
Production	(707.5)	(878.5)	(853.9)	(0.8)	(1.4)	(1.1)	(855.0)
Sales of minerals in situ	(109.2)	(53.5)	(118.1)	‒	‒	‒	(118.1)
December 31, 2013	10,947.7	12,483.2	13,028.3	8.8	11.8	10.7	13,039.0
Reserves quantity information for the year ended December 31, 2012
January 1, 2012	10,774.2	12,367.8	12,835.5	8.6	13.4	10.8	12,846.3
Revisions of previous estimates	112.8	363.8	173.5	0.7	1.8	1.0	174.5
Improved recovery	343.8	(623.5)	239.9	‒	‒	‒	239.9
Purchases of minerals in situ	‒	‒	‒	‒	‒	‒	‒
Extensions and discoveries	435.8	295.3	485.0	‒	‒	‒	485.0
Production	(738.1)	(862.2)	(881.8)	(1.0)	(1.9)	(1.3)	(883.1)
Sales of minerals in situ	‒	‒	‒	‒	‒	‒	‒
December 31, 2012	10,928.5	11,541.2	12,852.1	8.3	13.3	10.6	12,862.6

____________

(1)    Natural gas production volumes used in this table are the net volumes withdrawn from Petrobras’s proved reserves, including flared gas consumed in operations and excluding reinjected gas.  Oil production volumes used in this table are net volumes withdrawn from Petrobras’s proved reserves and exclude LNG and production from extended well tests.  As a result, the oil and natural gas production volumes in this table are different from those shown in the production table above, which shows the production volumes of natural gas available for sale.

(2)    This line represents the amount of proved reserves excluded from our consolidated total proved reserves due to the implementation of our joint venture with BTG Pactual to jointly explore oil and gas opportunities in Africa. Since July 2013, we no longer hold the corporate control of the entities incorporated in Nigeria directly responsible for our operations in such country. As such, we no longer consolidate the Nigeria reserves held by Brasoil Oil Services Company (Nigeria) Ltd., Petroleo Brasileiro Nigeria Ltd into our consolidated reserves.

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We do not have any material acreage expiring before 2025. 

The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage in which Petrobras had interests as of December 31, 2014.   

Gross and Net Productive Wells and Gross and Net Developed and Undeveloped Acreage
	As of December 31, 2014
	Oil		Natural gas		Synthetic oil		Synthetic gas
Gross and net productive wells(1):	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Consolidated subsidiaries
Brazil	8,275	8,263	227	219	‒	‒	‒	‒
International
South America (outside of Brazil)	2,362	1,737	406	305	‒	‒	‒	‒
North America	8	5.8	4	2.3	‒	‒	‒	‒
Total international	2,370	1,743	410	307.3	‒	‒	‒	‒
Total consolidated	10,645	10,006	637	526.3	‒	‒	‒	‒
Equity and non-consolidated affiliates:
South America (outside of Brazil)	130	37.5	3	1.1	‒	‒	‒	‒
Africa	40	3.4	‒	‒	‒	‒	‒	‒
Total gross and net productive wells	10,815	10,047	640	527	‒	‒	‒	‒

	As of December 31, 2014
	Oil		Natural gas		Synthetic oil		Synthetic gas
	(in acres)
Gross and net developed acreage:	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Brazil	4,214,376.3	3,914,470.8	408,031.7	391,053.3	1,346.0	1,346.0	‒	‒
International
South America (outside of Brazil)	1,328,531.1	1,030,824.9	2,331,174.6	1,629,335.5	‒	‒	‒	‒
North America	12,776.3	7,220.1	6,194.1	1,764.4	‒	‒	‒	‒
Total international	1,341,307.4	1,038,045.0	2,337,368.7	1,631,099.9	‒	‒	‒	‒
Total consolidated	5,555,683.7	4,952,515.8	2,745,400.5	2,022,153.2	1,346.0	1,346.0	‒	‒
Equity and non-consolidated affiliates:
South America (outside of Brazil)	250,346.7	61,750.1	12,195.0	4,031.3	‒	‒	‒	‒
Africa	312,368.3	23,771.2	‒	‒	‒	‒	‒	‒
Total non-consolidated	562,715.0	85,521.3	12,195.0	4,031.3	‒	‒	‒	‒
Total gross and net developed acreage	6,118,398.7	5,038,037.1	2,757,595.4	2,026,184.5	1,346.0	1,346.0	‒	‒

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	As of December 31, 2014
	Oil		Natural gas		Synthetic oil		Synthetic gas
	(in acres)
Gross and net undeveloped acreage:	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Brazil	1,298,072.5	1,156,821.2	255,516.2	248,728.1	‒	‒	‒	‒
International
South America (outside of Brazil)	224,401.9	150,499.4	719,218.6	500,523.4	‒	‒	‒	‒
North America	10,921.9	7,113.2	1,690.2	1,376.9	‒	‒	‒	‒
Total international	235,323.7	157,612.6	720,908.8	501,900.3	‒	‒	‒	‒
Total consolidated	1,533,396.3	1,314,433.8	976,425.0	750,628.3	‒	‒	‒	‒
Equity and non-consolidated affiliates:
South America (outside of Brazil)	289,377.7	73,915.4	22,689.6	7,596.8	‒	‒	‒	‒
Africa	332,206.1	27,904.1	‒	‒	‒	‒	‒	‒
Total non-consolidated	621,583.8	101,819.5	22,689.6	7,596.8	‒	‒	‒	‒
Total gross and net undeveloped acreage	2,154,980.1	1,416,253.4	999,114.6	758,225.2	‒	‒	‒	‒

_____________

(1)              A “gross” well or acre is a well or acre in which a working interest is owned, while the number of “net” wells or acres is the sum of fractional working interests in gross wells or acres.

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The following table sets forth the number of net productive and dry exploratory and development wells drilled for the last three years.  

Net Productive and Dry Exploratory and Development Wells
	2014	2013	2012
Net productive exploratory wells drilled:
Consolidated subsidiaries:
Brazil	48.3	67.55	44.7
South America (outside of Brazil)	4.7	3.5	4.0
North America	0.4	‒	1.1
Africa	‒	‒	‒
Other	‒	‒	‒
Total consolidated subsidiaries	53.4	71.05	49.8
Equity and non-consolidated affiliates:
South America (outside of Brazil)	‒	‒	0.4
Africa	‒	‒	‒
Total productive exploratory wells drilled	53.4	71.05	50.2
Net dry exploratory wells drilled:
Consolidated subsidiaries:
Brazil	19.15	16.75	42.2
South America (outside of Brazil)	1.1	0.8	3.0
North America	‒	0.9	0.5
Africa	‒	‒	0.7
Other	‒	‒	‒
Total consolidated subsidiaries	20.25	18.45	46.4
Equity and non-consolidated affiliates:
South America (outside of Brazil)	‒	0.5	‒
Africa	0.9	‒	‒
Total dry exploratory wells drilled	21.15	18.95	46.4
Total number of net exploratory wells drilled	74.55	90.0	96.6
Net productive development wells drilled:
Consolidated subsidiaries:
Brazil	397.97	399.73	355.1
South America (outside of Brazil)	41.8	57.7	239.9
North America	‒	2.5	1.8
Africa	‒	‒	0.6
Other	‒	‒	‒
Total consolidated subsidiaries	439.77	459.93	597.4
Equity and non-consolidated affiliates:
South America (outside of Brazil)	0.4	1.5	2.4
Africa	0.7	0.6	‒
Total productive development wells drilled	440.87	462.03	599.8
Net dry development wells drilled:
Consolidated subsidiaries:
Brazil	12.65	6	1
South America (outside of Brazil)	‒	‒	‒
North America	‒	‒	‒
Africa	‒	‒	‒
Other	‒	‒	‒
Total consolidated subsidiaries	12.65	6.0	1
Equity and non-consolidated affiliates:
South America (outside of Brazil)	‒	‒	‒
Africa	0.1	‒	‒
Total dry development wells drilled	12.75	6.0	1
Total number of net development wells drilled	453.62	468.03	600.8

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The following table summarizes the number of wells in the process of being drilled as of December 31, 2014.  For more information about our ongoing exploration and production activities in Brazil, see “—Exploration and Production.”  Our present exploration and production activities outside of Brazil are described in “—International.”

Number of Wells Being Drilled as of December 31, 2014
	Year-end 2014
	Gross	Net
Wells Drilling
Consolidated Subsidiaries:
Brazil	45	39.05
International:
South America (outside of Brazil)	8	4.6
North America	3	1.4
Africa	‒	‒
Others	‒	‒
Total International	11	6
Total consolidated production	56	45.05
Equity and non-consolidated affiliates:
South America (outside of Brazil)	3	0.9
Africa	3	0.3
Total wells drilling	62	46.25

The following table sets forth our average sales prices and average production costs by geographic area and by product type for the last three years.

	Brazil	South America (outside of Brazil)	North America	Africa	Total	Equity and non-consolidated affiliates(2)
	(U.S.$)
During 2014
Average sales prices
Oil, per barrel	87.84	79.28	90.31	‒	87.64	100.62
Natural gas, per thousand cubic feet(1)	7.99	3.50	4.77	‒	7.45	‒
Synthetic oil, per barrel	92.63	‒	‒	‒	92.63	‒
Synthetic gas, per thousand cubic feet	9.68	‒	‒	‒	9.68	‒
Average production costs, per barrel – total	16.89	12.32	6.23	‒	16.49	32.45
During 2013
Average sales prices
Oil, per barrel	98.19	82.82	99.29	107.88	97.72	108.75
Natural gas, per thousand cubic feet(1)	7.95	3.88	3.97	‒	7.40	‒
Synthetic oil, per barrel	99.54	‒	‒	‒	99.54	‒
Synthetic gas, per thousand cubic feet	8.24	‒	‒	‒	8.24	‒
Average production costs, per barrel – total	15.26	17.29	30.79	6.93	15.40	9.40
During 2012
Average sales prices
Oil, per barrel	104.60	81.53	100.56	112.15	103.90	89.73
Natural gas, per thousand cubic feet(1)	8.08	3.37	3.17	‒	7.75	‒
Synthetic oil, per barrel	99.13	‒	‒	‒	99.13	‒
Synthetic gas, per thousand cubic feet	7.33	‒	‒	‒	7.33	‒
Average production costs, per barrel – total	13.75	13.71	6.69	9.39	13.62	22.80

(1)               The volumes of natural gas used in the calculation of this table are the production volumes of natural gas available for sale and are also shown in the production table above.  Natural gas amounts were converted from bbl to cubic feet in accordance with the following scale: 1 bbl = 6 cubic feet.

(2)               Operations in Venezuela and in Africa-PO&G (2014 and 2013).

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Item 4A.   Unresolved Staff Comments

None.

Item 5.  Operating and Financial Review and Prospects

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The information derived from our financial statements as of and for the years ended December 31, 2014,  2013 and 2012 has been prepared in accordance with IFRS issued by the IASB. For more information, see “Presentation of Financial and Other Information” and Notes 2, 4 and 5 to our audited consolidated financial statements.

You should read the following discussion of our financial condition and results of operations together with our audited consolidated financial statements and the accompanying notes beginning on page F-4 of this annual report.

Overview

We earn income from:

·domestic sales, which consist of sales of oil products (including diesel, gasoline, jet fuel, naphtha, fuel oil and liquefied petroleum gas), natural gas, ethanol, electricity and petrochemical products;

·export sales, which consist primarily of sales of crude oil and oil products;

·international sales (excluding export sales), which consist of sales of crude oil, natural gas and oil products that are purchased, produced and refined abroad; and

·other sources, including services, interest income from investments, share of earnings in equity-accounted investees, foreign exchange variation gains and inflation indexation gains on financial instruments.

Our expenses include:

·costs of sales (comprised of direct labor costs, operating costs and purchases of crude oil and oil products); property, plant and equipment maintenance and repairs; depreciation, depletion and amortization of property, plant and equipment, oil fields and signing bonuses (acquisition costs); and oil and gas exploration costs;

·selling (which include expenses for transportation and distribution of our products), general and administrative expenses;

·research and development;

·impairment of assets and other operating expenses; and

·interest expense, inflation indexation and foreign exchange variation losses on debt and other financial instruments.

Fluctuations in our financial condition and results of operations are driven by a combination of factors, including:

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·the volume of crude oil, oil products and natural gas we produce and sell;

·changes in international prices of crude oil and oil products (denominated in U.S. dollars);

·changes in the domestic prices of crude oil and oil products (denominated in reais);

·the demand for oil products in Brazil and the amount of imports required to meet the domestic demand;

·the recoverable amounts of assets for impairment testing purposes;

·fluctuations in the real vs. U.S. dollar exchange rates and, to a lesser degree, other currencies, as set out in Note 33.2(c) to our audited consolidated financial statements; and

·the amount of production taxes from our operations that we are required to pay.

Sales Volumes and Prices

The profitability of our operations in any particular accounting period is related to the sales volume and prices of the crude oil, oil products, natural gas and biofuels that we sell and the relationship of these prices to international prices.  Our consolidated net sales in 2014 totaled 1,447,912 mboe, representing U.S.$143,657 million in sales revenues, compared to 1,384,616 mboe, representing U.S.$141,462 million in sales revenues, in 2013, and 1,385,917 mboe, representing U.S.$144,103 million in sales revenues, in 2012.

                As a vertically integrated company, we process most of our crude oil production in our refineries and sell the refined oil products primarily in the Brazilian domestic market.  Therefore, the price of oil products in Brazil has a more significant impact on our financial results than crude oil prices.  International oil product prices vary over time as the result of many factors, including the price of crude oil.  Over the long term, we intend to sell our products in Brazil at parity with international product prices. However, because we do not adjust our prices for gasoline, diesel and certain other oil products to reflect short-term volatility in the international markets, our downstream margins may be significantly different than those of other integrated international oil companies within a given financial reporting period due to significant rapid or sustained increases or decreases in the international prices of crude oil and oil products, or in the real vs. U.S. dollar exchange rate.

                The average price of Brent crude, an international benchmark oil, was U.S.$98.99 per barrel in 2014, U.S.$108.66 per barrel in 2013 and U.S.$111.58 per barrel in 2012.  In December 2014, Brent crude oil prices averaged U.S.$62.53 per barrel. Due to the devaluation of the real throughout 2014, the average price of the Brent crude, when expressed in reais, decreased to R$231.30 per barrel during 2014 from R$234.52 per barrel during 2013.

In 2012, we announced price increases at the refinery gate (the wholesale price we sell to distributors), totaling 7.8% for gasoline and 10.2% for diesel compared to December 31, 2011 prices, to partially adjust to higher international oil product prices. In 2013, we announced further price increases at the refinery gate, totaling 10.9% for gasoline and 19.6% for diesel compared to December 31, 2012 prices, and in November 2014 we announced further price increases at the refinery gate totaling 3% for gasoline and 5% for diesel compared to December 31, 2013 prices. 

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                Since November 2013, our diesel and gasoline pricing policy has been based on the following principles and objectives:

•     Achieving, in a reasonable time period, an alignment of Brazilian and international diesel and gasoline prices; and

•      Preventing the transfer of volatility in diesel and gasoline international prices to the domestic consumer.

During 2014, 77.7% of our sales revenues were derived from sales of oil products, natural gas and other products in Brazil, compared to 75.3% in 2013 and 69.7% in 2012.

	For the Year Ended December 31,
	2014			2013			2012
	Volume	Net Average Price	Sales Revenues	Volume	Net Average Price	Sales Revenues	Volume	Net Average Price	Sales Revenues
	(mbbl, except as otherwise noted)	(U.S.$)(1)	(U.S.$ million)	(mbbl, except as otherwise noted)	(U.S.$)(1)	(U.S.$ million)	(mbbl, except as otherwise noted)	(U.S.$)(1)	(U.S.$ million)
Diesel	365,510	116.50	42,586	359,266	115.30	41,435	343,063	112.39	38,558
Automotive gasoline	226,230	104.80	23,702	215,419	109.00	23,470	208,695	111.54	23,277
Fuel oil (including bunker fuel)	43,494	100.20	4,357	35,588	97.30	3,464	30,896	92.71	2,864
Naphtha	59,443	94.60	5,622	62,520	94.10	5,885	60,331	95.23	5,745
Liquefied petroleum gas	85,723	43.50	3,729	84,281	47.00	3,960	81,992	50.32	4,126
Jet fuel	40,285	138.10	5,562	38,751	143.30	5,553	38,896	150.72	5,862
Other oil products	76,567	75.40	5,771	74,068	77.80	5,760	72,969	81.67	5,958
Subtotal oil products	897,252	101.80	91,329	869,893	102.90	89,527	836,842	103.20	86,392
Natural gas (boe)	162,633	49.40	8,035	149,277	49.40	7,376	130,544	50.41	6,580
Ethanol, nitrogen products, renewables and other non-oil products	36,181	106.70	3,862	33,346	146.00	4,868	30,369	132.60	4,027
Electricity, services and others	−	−	8,384	−	−	4,693	‒	‒	3,498
Total domestic market	1,096,066	−	111,610	1,052,516	−	106,464	997,755	‒	100,497
Exports	143,423	97.10	13,930	144,111	105.30	15,172	203,234	109.99	22,353
International sales	208,423	86.90	18,117	187,989	105.50	19,826	184,928	114.92	21,253
Total international market	351,846	−	32,047	332,100	−	34,998	388,162	‒	43,606
Consolidated sales revenues	1,447,912	−	143,657	1,384,616	−	141,462	1,385,917	‒	144,103

(1)                  Net average price calculated by dividing sales revenues by the volume for the year.

Effect of Taxes on Our Income

In addition to taxes paid on behalf of consumers to federal, state and municipal governments, such as the Domestic Value-Added Tax (Imposto sobre Circulação de Mercadorias eServiços, or ICMS), we are required to pay three main charges on our oil production activities in Brazil: royalties, special participation and retention bonuses.  See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Taxation under Concession Regime for Oil and Gas” and Item 3. “Key Information—Risk Factors—Risks Relating to Brazil.”

These charges imposed by the Brazilian federal government are included in our cost of goods sold. In addition, we are subject to tax on our income at an effective rate of 34%, including 25% of corporate income tax and a social contribution tax at an effective rate of 9%, the standard corporate tax rates in Brazil. 

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For further information about income taxes, other taxes payable, deferred income taxes and a reconciliation of income taxes calculated by applying a statutory tax rate and our tax expense, see Note 21 to our audited consolidated financial statements.

Inflation and Exchange Rate Variation

Inflation

Since the introduction of the real as the Brazilian currency in July 1994, inflation in Brazil has remained relatively stable.  Inflation was 6.41% in 2014, 5.91% in 2013 and 5.84% in 2012 as measured by IPCA, the National Consumer Price Index.  Inflation has had, and may continue to have, effects on our financial condition and results of operations.  See Item 3. “Key Information—Risk Factors—Inflation, and the Brazilian government’s measures to combat inflation, may contribute significantly to economic uncertainty in Brazil, and may materially adversely affect us.”

Exchange Rate Variation  

                Our functional currency is the Brazilian real and our presentation currency is the U.S. dollar. Therefore, we maintain our financial records in reais, and translate our financial statements into U.S. dollars for presentation purposes based on the average exchange rates prevailing during the period or at the balance sheet date, pursuant to the criteria set out in IAS 21 - “The effects of changes in foreign exchange rates”.

                When the real appreciates relative to the U.S. dollar, the effect is to generally increase both revenues and expenses when expressed in U.S. dollars.  When the real depreciates relative to the U.S. dollar, the effect is to generally decrease revenues and expenses when expressed in U.S. dollars. 

                From 2003 to 2011, considering the average exchange rates of each year, 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.               

                Fluctuations in exchange rate have multiple effects on our results of operations in reais. The relative pace at which our total revenues and expenses in reais increase or decrease with the exchange rate, and its impact on our margins, is affected by our pricing policy in Brazil.  Absent changes in the international prices for crude oil, oil products and natural gas, when the real appreciates against the U.S. dollar and we do not adjust our prices in Brazil, our margins generally improve. Absent changes in the international prices for crude oil, oil products and natural gas, when the real depreciates against the U.S. dollar and we do not adjust our prices in Brazil, margins generally decline.

                The depreciation of the real against the U.S. dollar also increases our debt service in reais, as the amount of reais necessary to pay principal and interest on foreign currency debt increases with the depreciation of the real.  A devaluation of the real also increases our costs to import oil and oil products, imported goods and services necessary for our operations and our production taxes.  Unless the depreciation of the real is offset by higher prices for our products sold in Brazil, a devaluation increases our debt service relative to our cash flows while also reducing our operating margins.

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The foreign exchange variations on foreign-denominated assets and liabilities of entities for which the real is the functional currency are recorded in profit or loss, while the foreign exchange variations on the translation of foreign subsidiaries are recognized in other comprehensive income in shareholders’ equity. As our net debt denominated in other currencies increases, the negative impact of a depreciation of the real on our results and net income when expressed in reais also increases, thereby reducing the earnings available for distribution. Note 33.2(c) to our audited consolidated financial statements provides further information about our foreign exchange exposure related to assets and liabilities. 

                Since mid-May 2013 we have designated cash flow hedging relationships in which (a) the hedged items are portions of our highly probable future monthly export revenues in U.S. dollars, (b) the hedging instruments are portions of our long-term debt obligations denominated in U.S. dollars, and (c) the risk hedged is the effect of changes in exchange rates between the U.S. dollar and our functional currency, the Brazilian real. Both long-term debt obligations (hedging instruments) and future exports (hedged items) are exposed to the real/U.S. dollar foreign currency risks at their respective spot exchange rate. Cash flow hedge accounting allows gains and losses arising from the effect of changes in the foreign currency exchange rate on the hedging instruments to be recognized in other comprehensive income in shareholders’ equity and then reclassified from equity to profit or loss in the periods during which the hedged transactions occur, rather than being immediately recognized as profits or losses.  See Notes 4.3.6 and 33.2(a) to our audited consolidated financial statements for further information about our cash flow hedge.

Exchange rate variation also affects the amount of retained earnings available for distribution by us when expressed in U.S. dollars.  Amounts reported as available for distribution in our statutory accounting records are calculated in reais and prepared in accordance with the IFRS and they may increase or decrease when expressed in U.S. dollars as the real appreciates or depreciates against the U.S. dollar.

Results of Operations

                The differences in our operating results from year to year occur as a result of a combination of factors, including primarily: the volume of crude oil, oil products and natural gas we produce and sell; the price at which we sell our crude oil, oil products and natural gas and the relationship of those prices to the international prices; the level and cost of imports and exports needed to satisfy our demand; production taxes; and the differential between Brazilian and international inflation rates, adjusted by the depreciation or appreciation of the real against the U.S. dollar.

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The table below shows the amount by which each of these variables has changed during the last three years.  Production volumes presented in this table are prepared in accordance with SPE criteria, which are the criteria we apply to analyze our operating results:

	2014	2013	2012
Crude oil and NGL production (mbbl/d):
Brazil	2,034	1,931	1,980
International	85	109	139
Non-consolidated international production(1)	31	19	7
Total crude oil and NGL production	2,150	2,059	2,126
Change in crude oil and NGL production	4.4%	(3.2)%	(2.0)%
Average sales price for crude (U.S.$/barrel):
Brazil	87.84	98.19	104.60
International	82.93	89.86	94.37
Natural gas production (mmcf/d)(2):
Brazil	2,556	2,334	2,250
International	558	546	582
Total natural gas production	3,114	2,880	2,832
Change in natural gas production (sold only)	8.1%	1.7%	4.4%
Average sales price for natural gas (U.S.$/mcf)(2):
Brazil	7.99	7.95	8.08
International	3.53	3.51	3.00
Year-end exchange rate (reais/U.S.$)	2.66	2.34	2.04
Appreciation (depreciation) during the year(3)	(13.4)%	(14.6)%	(8.9)%
Average exchange rate for the year (reais/U.S.$)	2.35	2.16	1.96
Appreciation (depreciation) during the year(4)	(9.1)%	(10.4)%	(16.7)%
Inflation rate (IPCA)	6.41%	5.91%	5.84%

(1)                  Non-consolidated companies in Venezuela and in Africa.

(2)                  Amounts were converted from bbl to cubic feet in accordance with the following scale: 1 bbl = 6 cubic feet. They do not include LNG but include reinjected gas.

(3)                  Based on year-end exchange rate (R$/U.S.$.)

(4)                  Based on average exchange rate for the year (R$/U.S.$.)

Virtually all of our revenues and expenses for our Brazilian operations are denominated and payable in reais. When the U.S. dollar strengthens relative to the real, as it did in 2014 and 2013 (with an appreciation of 9.1% and 10.4%, respectively), revenues and expenses decrease when translated into U.S. dollars. The appreciation of the U.S. dollar against the real affects the line items discussed below in different ways. As a consequence, the following comparison between our results of operations in 2014 and in 2013, and between our results of operations in 2013 and 2012, are impacted by the depreciation of the real against the U.S. dollar during that period. See Note 2 of our audited consolidated financial statements for the year ended December 31, 2014 for more information about the translation of real amounts into U.S. dollars.

Results of Operations—2014 compared to 2013

Sales Revenues

Sales revenues increased by 2% to U.S.$143,657 million in 2014 from U.S.$141,462 million in 2013, primarily driven by:

•     Higher oil product prices in the domestic market, due to diesel and gasoline price increases applied in 2013 and 2014, and to the impact of the appreciation of the U.S. dollar against the real (9%) on the price (in reais) of oil products that are adjusted to reflect international prices (such as jet fuel and naphtha), as well as higher electricity and natural gas prices;

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•     A 3% increase in the domestic demand for oil products, mainly diesel (2%), gasoline (5%) and fuel oil (21%), and an increase in crude oil export volumes (12%), partially offset by a decrease in oil product export volumes (15%); and

•     Foreign currency translation effects (appreciation of the U.S. dollar against the real), which reduced the increase of sales revenues in U.S. dollars. Excluding those effects, sales revenues increased by 11% when expressed in reais.

Cost of Sales

Cost of sales increased by 1% to U.S.$109,477 million in 2014 from U.S.$108,834 million in 2013, mainly due to:

•    Higher import costs and production taxes attributable to the depreciation of the real;

•    Increased domestic oil products sales volumes (3%) and increased LNG import volumes to meet the demand; and

•    Higher electricity costs as a result of increased electricity prices in the spot market.

Excluding the impact of foreign currency translation effects (appreciation of the U.S. dollar against the real), cost of sales increased by 9% when expressed in reais.

Selling Expenses

Selling expenses increased by 39% to U.S.$6,827 million in 2014 from U.S.$4,904 million in 2013, mainly due to an allowance for impairment of trade receivables from the isolated electricity sector in the Northern region of Brazil (amounting to U.S.$1,948 million) primarily to cover certain trade receivables due by Eletrobras’s subsidiaries.  See Note 8.4 to our audited consolidated financial statements.

General and Administrative Expenses

General and administrative expenses decreased by 5% to U.S.$4,756 million in 2014 from U.S.$4,982 million in 2013 mainly due to foreign currency translation effects. Excluding those effects, general and administrative expenses increased by 4% when expressed in reais, mainly as a result of higher employee compensation expenses arising from the 2013 and 2014 collective bargaining agreements.  See Item 6. “Directors, Senior Management and Employees—Employees and Labor Relations.”

Exploration Costs

Exploration costs increased by 3% to U.S.$3,058 million in 2014 from U.S.$2,959 million in 2013, primarily due to an increase in write-offs of dry or sub-commercial wells. A breakdown of exploration costs by category is set out in Note 15 to our audited consolidated financial statements.

Research and Development Expenses

Research and development expenses decreased by 3% to U.S.$1,099 million in 2014 from U.S.$1,132 million in 2013, mainly due to foreign currency translation effects. Excluding those effects, research and development expenses were 7% higher when expressed in reais.  That increase was due to an increase in gross revenues from high productivity oil fields in Brazil, since the ANP requires that we invest at least 1% of our gross revenues originating from those fields in research and development projects, and also a result of higher expenditures in research and development for projects in Brazil. See Item 5. ”Operating and Financial Review and Prospects” for further details about our research and development activities.

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Impairment of Assets

We recognized impairment charges of U.S.$16,823 million in 2014, mainly related to the following assets:

·Domestic refineries (U.S.$11,662 million): These charges resulted from individualized impairment testing of the second refining unit of Refinaria Abreu e Lima (RNEST) and Complexo Petroquímico do Rio de Janeiro (Comperj) conducted due to the postponement of each of these projects for an extended period of time.  Those postponements were implemented as part of our measures to preserve cash and in response to the difficulties created for our suppliers by the “Lava Jato” investigation. The impairment charges are mainly attributable to project planning deficiencies, the use of a higher discount rate (reflecting a specific risk premium for the postponed projects), a delay in expected cash inflows resulting from postponing these projects and lower projected economic growth in Brazil;

·Domestic and international assets related to exploration and production of crude oil and natural gas (U.S.$3,766 million): these charges mainly result from lower international crude oil prices; and

·Petrochemical assets (U.S.$1,121 million): these charges are mainly attributable to changes in market assumptions and forecasts resulting from a decrease in economic activity, lower margins in the international market and modifications in tax regulations.

See Notes 4.10, 5.2 and 14 to our audited consolidated financial statements for more information about the impairment of these assets.

Write-Offs of Overpayments Incorrectly Capitalized

In the 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 resulting from a payment scheme uncovered by the Brazilian Federal Prosecutor’s Office in connection with the Lava Jato investigation. See Note 3 to our audited consolidated financial statements for a detailed description of this investigation, the overpayments charged by certain contractors and suppliers to Petrobras and our response to it, sources of information available to us, our methodology to estimate the overstatement of our assets and the impact of these overpayments on our financial statements. 

Other Expenses, Net

Other expenses, net increased by 376% to U.S.$5,293 million in 2014 from U.S.$1,113 million in 2013. This U.S.$4,180 million increase primarily relates to:

·The write-off of the capitalized costs of Premium I and Premium II refineries due to our decision to abandon these projects (U.S.$1,236 million).  See Note 12.4 to our audited consolidated financial statements;

·The impact of our Voluntary Separation Incentive Plan – PIDV (U.S.$1,035 million).  See Note 22.8 to our audited consolidated financial statements;

·Higher decommissioning costs related to returned and abandoned areas (U.S.$501 million);

·The write-off of exploration and production areas returned to ANP and cancelled exploration and production projects (U.S.$249 million); and

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·Higher actuarial expenses related to retirees due to the review of our pension and medical benefit obligations (U.S.$130 million).

Other expenses were also higher in 2014 when compared to 2013, primarily because we recognized gains from the disposal of 50% of our interest in assets in Africa and of block BC-10 in Brazil in 2013 (which did not occur in 2014). Those effects were partially offset by a gain on disposal of our interest in Petrobras Energia Peru S.A. in 2014.

Net Finance Income (Expense)

Net finance expense was U.S.$1,635 million in 2014, a U.S.$1,156 million decrease compared to 2013 (U.S.$2,791 million) resulting from:

•     A decrease in foreign exchange variation charges, because a smaller portion of our liabilities in U.S. dollars was exposed to exchange rate variation due to the extension of our cash flow hedge accounting policy to highly probable future exports, beginning in May 2013.  For further information about our cash flow hedge accounting, see Notes 4.3.6 and 33.2(a) to our audited consolidated financial statements;

•     Foreign exchange gains attributable to the appreciation of the U.S. dollar against other currencies, mainly the Euro;

•     Inflation indexation gains on a contingent asset related to undue finance income – PIS and COFINS taxes paid by us from February 1999 to December 2002; and

•     Inflation indexation gains on debt acknowledgement agreements with respect to trade receivables due by Eletrobras’s subsidiaries.

Finance expenses were also lower in 2014 when compared to 2013, mainly because in 2013 we recognized the effects of the settlement of certain of our tax debts and disputes through our participation in a federal tax refinancing/settlement program (REFIS), which increased our finance expense significantly in 2013 and was not recurring in 2014.

Those effects were partially offset by higher interest expenses resulting from an increase in our debt.

Income Taxes

We reported a loss for the fiscal year ended December 31, 2014, and consequently recognized tax loss carry-forwards for that period. See Note 21.3 to our audited consolidated financial statements for a reconciliation of statutory tax rates and our tax expense.

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Net Income (Loss) by Business Segment

We measure performance at the business segment level based on net income.  The following is a discussion of the net income of our six business segments for 2014, compared to 2013. See Item 4. “Information on the Company” and Notes 4.2 and 29 to our audited consolidated financial statements for more information about our business segments.

	Year Ended December 31,
	2014(1)	2013(1)	Percentage Change
	(U.S.$ million)
Exploration and Production	14,133	19,523	(28)%
Refining, Transportation and Marketing	(15,405)	(8,150)	89%
Gas and Power	(410)	631	(165)%
Biofuel	(127)	(117)	9%
Distribution	499	863	(42)%
International	(1,145)	1,729	(166)%
Corporate(2)	(5,359)	(3,331)	61%
Eliminations	447	(54)	(928)%
Net income	(7,367)	11,094	(166)%
_________________
(1)            Excluding non-controlling interests.
(2)            Our Corporate segment comprises our financing activities not attributable to other segments, including corporate financial management, central administrative overhead and actuarial expenses related to our pension and medical benefits for retirees.

Exploration and Production

Net income in our Exploration and Production segment decreased by 28% to U.S.$14,133 million in 2014 compared to U.S.$19,523 million in 2013, mainly due to (i) impairment charges recognized in 2014 (U.S.$2,133 million - see Note 14 to our audited consolidated financial statements); (ii) write-offs of overpayments incorrectly capitalized (U.S.$804 million – see Note 3 to our audited consolidated financial statements); (iii) the impact of our voluntary separation incentive plan (PIDV) (U.S.$415 million); (iv) higher decommissioning costs on returned and abandoned areas (U.S.$501 million); (v) write-offs of exploration and production areas returned to the ANP (U.S.$249 million) and (vi) higher operating costs, such as equipment depreciation, equipment maintenance, interventions on wells, oil platform chartering, materials and increased employee compensation costs.

These effects were partially offset by higher crude oil and NGL production (5%) and, when compared to 2013, by the fact that in 2013 we recognized a gain on the disposal of Parque das Conchas offshore project (BC-10).

The spread between the average domestic oil price (sale/transfer) and the average Brent price increased from U.S.$10.47/bbl in 2013 to U.S.$11.15/bbl in 2014.

See Item 4. “Information on the Company—Overview of the Group—Changes in Proved Reserves” for information on changes in our proved reserves.

Refining, Transportation and Marketing

Net losses in our Refining, Transportation and Marketing segment increased by 89% to U.S.$15,405 million in 2014 compared to U.S.$8,150 million in 2013, as a result of: (i) impairment charges recognized in 2014 (U.S.$12,782 million – see Note 14 to our audited consolidated financial statements); (ii) write-offs of overpayments incorrectly capitalized (U.S.$1,398 million – see Note 3 to our audited consolidated financial statements); (iii) the write-off of capitalized costs in Premium I and Premium II refineries (U.S.$1,236 million – see Note 12.4 to our audited consolidated financial statements); and (iv) the impact of our voluntary separation incentive plan (PIDV). Those effects were partially offset by higher average oil product selling prices attributable to diesel and gasoline price increases in 2013 and 2014, and by an increase in oil product production (2%).

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Gas and Power

Our Gas and Power segment reported a loss of U.S.$410 million in 2014 compared to a net income of U.S.$631 million in 2013, resulting from:

·Higher LNG and natural gas import costs to meet thermoelectric demand in Brazil;

·The impact of an agreement with YPFB to settle contractual disputes regarding several aspects of the GSA.  See Item 4. “Information on the Company—Overview of the Group—Gas and Power—Long-Term Natural Gas Commitments” and Note 31 to our audited consolidated financial statements;

·An allowance for impairment of trade receivables from companies that operate in the isolated electricity sector in the Northern region of Brazil (see Note 8.4 to our audited consolidated financial statements);

·Write-offs of overpayments incorrectly capitalized; and

·The impact of our voluntary separation incentive plan (PIDV).

These effects were partially offset by higher average electricity prices in the spot market, as a result of lower water reservoir levels in Brazil, and by a U.S.$274 million gain from the disposal of 100% of our interest in Brasil PCH S.A.

Biofuel

Biofuel segment net losses increased by 9% to U.S.$127 million in 2014 compared to U.S.$117 million in 2013, mainly due to the higher share of losses from biodiesel investees and to the impact of our voluntary separation incentive plan (PIDV). These effects were partially offset by lower losses on biodiesel operations and by a decrease in inventory write-downs to net realizable value (market value).

Distribution

Net income in our Distribution segment decreased by 42% to U.S.$499 million in 2014 compared to U.S.$863 million in 2013, mainly due to higher selling expenses attributable to an allowance for impairment of trade receivables from companies that operate in the isolated electricity sector in the Northern region of Brazil (see Note 8.4 to our audited consolidated financial statements) and to the impact of our voluntary separation incentive plan (PIDV), partially offset by an increase in sales volumes and higher average margins in fuel trading.

International

Our International segment reported a loss of U.S.$1,145 million in 2014 compared to a net income of U.S.$1,729 million in 2013, mainly attributable to:

·Impairment charges recognized on exploration and production activities, mostly in the United States and on our Japanese refinery, mainly resulting from a decrease in international crude oil and oil product prices.  See Note 14 to our audited consolidated financial statements;

·An allowance for losses on net investments in exploration and production operations in Venezuela, Ecuador and Africa;

·Higher inventory write-downs to net realizable value (market value) in Japan; and

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·Lower gross profit, mainly in international exploration and production operations, due to assets disposed of in 2014 and 2013 and to a decrease in international crude oil and oil product prices.

These effects were partially offset by gains on the disposal of our interest in Peruvian operations and of onshore assets in Colombia in 2014, compared to the gain we recognized in 2013 on the disposal of 50% of the Company’s assets in Africa.

See Note 29 to our audited consolidated financial statements for further information regarding our business segments.

Results of Operations—2013 compared to 2012

Sales Revenues

Sales revenues decreased by 2% to U.S.$141,462 million from U.S.$144,103 million in 2012, driven primarily by foreign currency translation effects (the appreciation of the U.S. dollar against the real). Excluding foreign currency exchange effects, local currency sales revenues increased by 8%, primarily driven by:

·Higher oil product prices in the domestic market, mainly derived from adjustments in gasoline and diesel prices, higher electricity prices and the impact of the appreciation of the U.S. dollar (10%) on oil product prices that are adjusted to reflect international prices;

·A 4% increase in domestic oil product sales volumes, mainly of diesel (5%), gasoline (4%) and fuel oil (17%), offset by lower crude oil export volumes (43%), attributable to lower production levels and higher feedstock processed.

Cost of Sales

Cost of sales increased by 1% to U.S.$108,834 million from U.S.$108,276 million in 2012, due to:

·A 4% increase in domestic sales volumes of oil products, met by higher oil product output from our refineries;

·An increase in natural gas import volumes to meet thermoelectric demand and higher crude oil import volumes attributable to the increase in feedstock processed in our refineries;

·The impact of the appreciation of the U.S. dollar on our unit costs; and

·Increased crude oil production costs, attributable to the higher number of well interventions and to the production start-up of new systems, which are still not producing at full capacity.

Excluding foreign currency translation effects, the local currency cost of sales was 11% higher in 2013.

Selling Expenses

Selling expenses were relatively flat in 2013 (U.S.$4,904 million) when compared to 2012 (U.S.$4,927 million) expressed in U.S. dollars. Excluding foreign currency translation effects, selling expenses were 10% higher in 2013 when expressed in reais, primarily as a result of higher freight expenses, driven by increased domestic sales volumes.

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General and Administrative Expenses

General and administrative expenses decreased by 1% to U.S.$4,982 million in 2013 from U.S.$5,034 million in 2012. Excluding foreign currency translation effects, local currency general and administrative expenses increased by 9%, mainly as a result of higher employee compensation expenses arising from the 2012 and 2013 collective bargaining agreements.

Exploration Costs

Exploration costs were 26% lower in 2013 (U.S.$2,959 million) when compared to 2012 (U.S.$3,994 million), primarily due to lower write-offs of dry or sub-commercial wells. A breakdown of exploration costs by nature is set out in Note 15 to our audited consolidated financial statements.

Research and Development Expenses

Research and development expenses remained relatively flat in 2013 (U.S.$1,132 million) when compared to 2012 (U.S.$1,143 million). See Item 5. ”Operating and Financial Review and Prospects” for further details about our research and development activities.

Other Expenses, Net

The 66% decrease in our net other operating expenses in 2013 when compared to 2012 (U.S.$1,113 million as compared to U.S.$3,306 million) is attributable to gains on disposal of assets, including the disposal of 50% of our interest in assets in Africa and of block BC-10, as set out in Note 10 to our 2013 audited consolidated financial statements.

Net Finance Income (Expense)

Net finance expense was U.S.$2,791 million in 2013, a U.S.$865 million increase compared to 2012, resulting from:

·Lower finance income compared to 2012, when we benefited from the positive impact of gains on disposal of government bonds (National Treasury Notes – B Series) and interest income over judicial deposits (U.S.$1,280 million);

·Higher finance expense due to higher debt; and

·The settlement of certain of our tax debts and disputes through our participation in the federal tax settlement program (REFIS).

This increase in net finance expense was partially offset by lower exchange rate variation losses (U.S.$1,636 million) attributable to the extension of our cash flow hedge accounting, reducing by U.S.$5,924 million the impact of foreign currency effects on our finance expenses. For further information about our cash flow hedge accounting, see Notes 4.3.6 and 33.2 (a) to our audited consolidated financial statements.

Income Taxes

Income taxes were U.S.$984 million lower in 2013, when compared to 2012, due to the lower income before taxes and the impact of different jurisdictional tax rates applied for companies domiciled abroad, attributable to the disposal (and loss of control) of assets in Africa.

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Net Income (Loss) by Business Segment

We measure performance at the business segment level based on net income.  The following is a discussion of the net income of our six business segments for 2013, compared to 2012. See Item 4. “Information on the Company” and Note 4.2 to audited consolidated financial statements for more information about our business segments.

	Year Ended December 31,
	2013(1)	2012(1)	Percentage Change
	(U.S.$ million)
Exploration and Production	19,523	23,406	(17)%
Refining, Transportation and Marketing	(8,150)	(11,718)	(30) %
Gas and Power	631	861	(27)%
Biofuel	(117)	(112)	4%
Distribution	863	914	(6)%
International	1,729	719	140%
Corporate(2)	(3,331)	(2,565)	30%
Eliminations	(54)	(471)	(89)%
Net income	11,094	11,034	1%
______________________
(1)               Excluding non-controlling interests.
(2)               Our Corporate segment comprises our financing activities not attributable to other segments, including corporate  financial management, central administrative overhead and actuarial expenses related to our pension and medical benefits for retirees.

Exploration and Production

Exploration and Production (E&P) net income decreased by 17% in 2013, when compared to 2012, primarily due to a decrease in crude oil and NGL production (2%) resulting from the natural decline of fields (slightly offset by the production start-up of new systems), higher equipment depreciation costs, increased freight costs for oil platforms, higher employee compensation costs and higher well interventions and maintenance costs.

Higher domestic crude oil prices (sale/transfer, when expressed in reais), lower write-offs of dry or sub-commercial wells and a gain on the disposal of our total interest in block BC-10 partially offset this decrease in net income.

The spread between the average domestic oil price (sale/transfer) and the average Brent price increased to U.S.$10.47/bbl in 2013 from U.S.$6.98/bbl in 2012.

See Item 4. “Information on the Company—Overview of the Group—Changes in Proved Reserves” for information on changes in proved reserves.

Refining, Transportation and Marketing

In 2013, our RTM segment net losses decreased by 30% when compared to 2012, reflecting the diesel and gasoline price adjustments in the domestic market beginning in June 2012, and the higher feedstock processed in our refineries, reducing the share of oil product imports in our sales mix, partially offset by higher crude oil acquisition/transfer costs (when expressed in reais).

Gas and Power

Our Gas and Power segment net income decreased by 27% in 2013 due to higher LNG and natural gas import costs necessary to meet higher thermoelectric demand. This decrease was partially offset by higher thermoelectricity generation and higher average electricity prices, mainly attributable to lower water reservoir levels of hydroelectric power plants located in Brazil (caused by low rainfall), and thus increased difference settlement prices.

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Biofuel

Biofuel net losses increased by 4% in 2013, driven by lower biodiesel average sales prices (which fell by 11% compared to 2012). These net losses were partially offset by a decrease in our share of losses from ethanol investments, attributable to increases in ethanol, electricity and sugar sales volumes, as well as the higher average sales prices of ethanol and electricity.

Distribution

Our Distribution segment net income decreased by 6% in 2013 compared to 2012. Excluding foreign currency translation effects, local currency net income for our distribution segment increased due to a 7% increase in the average trade margins and a 4% increase in sales volumes. This increase was partially offset by higher selling and administrative expenses.

Distribution sales volumes increased in the fourth quarter of 2013, but we lost market share in 2013 (37.5%) when compared to 2012 (38.1%) due to a shift in our sales mix in order to achieve higher margins.

International

Our International segment net income increased by 140% due to gains on disposal of assets in accordance with our PRODESIN divestment program, mainly in Africa and in the United States, and to the recognition of tax credits in the Netherlands. Lower exploration costs and write-offs of wells also had a positive impact. This net income increase was partially offset by lower crude oil and NGL production.

See Note 29 to our audited consolidated financial statementsfor further information regarding our business segments.

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Additional Business Segment Information  

Additional selected financial data by business segment for 2014, 2013 and 2012 is set out below:

	For the Year Ended December 31,
	2014	2013	2012
	(U.S.$ million)
Exploration and Production
Sales revenues to third parties(1)(2)	500	1,114	843
Intersegment net revenues	65,116	67,096	73,871
Total sales revenues(2)	65,616	68,210	74,714
Net income (loss)(3)	14,133	19,523	23,406
Capital expenditures and investments	24,164	27,566	21,959
Property, plant and equipment	135,671	126,716	102,779
Refining, Transportation and Marketing
Sales revenues to third parties(1)(2)	73,069	74,290	78,876
Intersegment sales revenues	39,251	37,375	37,950
Total sales revenues(2)	112,320	111,665	116,826
Net income (loss)(3)	(15,405)	(8,150)	(11,718)
Capital expenditures and investments	7,778	14,243	14,745
Property, plant and equipment	49,662	66,522	63,822
Gas and Power
Sales revenues to third parties(1)(2)	16,187	12,826	10,515
Intersegment sales revenues	1,695	1,191	1,288
Total sales revenues(2)	17,882	14,017	11,803
Net income (loss)(3)	(410)	631	861
Capital expenditures and investments	2,545	2,716	2,113
Property, plant and equipment	22,126	20,882	21,585
Biofuel
Sales revenues to third parties(1)(2)	28	64	90
Intersegment sales revenues	238	324	365
Total sales revenues(2)	266	388	455
Net income (loss)(3)	(127)	(117)	(112)
Capital expenditures and investments	112	143	147
Property, plant and equipment	205	222	255
Distribution
Sales revenues to third parties(1)(2)	40,600	39,028	39,718
Intersegment sales revenues	1,129	995	878
Total sales revenues(2)	41,729	40,023	40,596
Net income (loss)(3)	499	863	914
Capital expenditures and investments	446	514	666
Property, plant and equipment	2,284	2,350	2,374
International
Sales revenues to third parties(1)(2)	13,273	14,140	14,061
Intersegment sales revenues	639	2,162	3,868
Total sales revenues(2)	13,912	16,302	17,929
Net income (loss)(3)	(1,145)	1,729	719
Capital expenditures and investments	1,513	2,368	2,572
Property, plant and equipment	6,058	7,971	10,882

(1)               As a vertically integrated company, not all of our segments have significant third-party revenues.  For example, our Exploration and Production segment accounts for a large part of our economic activity and capital expenditures, but has little third-party revenues.

(2)               Revenues from commercialization of oil to third parties are classified in accordance with the points of sale, which could be either the Exploration and Production or Refining, Transportation and Marketing segments.

(3)               Excluding non-controlling interests.

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Liquidity and Capital Resources

Overview

Our principal uses of funds in 2014 were for capital expenditures (U.S.$34,750 million) and payment of dividends (U.S.$3,918 million).  We met these requirements with cash provided by operating activities (amounting to U.S.$26,632 million), net long-term financing (amounting to U.S.$15,024 million) and disposal of assets (amounting to U.S.$3,744 million). As of December 31, 2014, our cash flow from operations was less than the resources needed to fund our capital expenditures, interest expenditures and payment of dividends. 

For 2015, our ability to invest available funds has been limited as a result of a decrease in expected future operating revenues following the decline of international crude oil prices, along with the devaluation of the real, which has increased our cash outflows to service debt in the near term, most of which is denominated in foreign currencies.  We have also recently had limited access to new sources of debt capital, largely as a result of the Lava Jato investigation.  As a result, our management decided to postpone projects affected by difficulties faced by contractors or by the lack of available qualified suppliers in Brazil.  See Note 3 to our audited consolidated financial statements for detailed information about the Lava Jato investigation.

We expect to regain regular access in 2015 to medium and long-term financing, including through the issuance of bonds in the international capital markets and bank financing.

In 2015, our major cash needs are to meet our budgeted capital expenditures for the year (amounting to U.S.$29 billion) and to make principal and interest payments of U.S.$16,042 million on our debt. 

Financing Strategy

Our financing strategy is to fund the capital expenditures necessary to meet our long-term growth objectives for oil production and to preserve our cash balance and liquidity while meeting our principal and interest payment obligations.

In the short term, we will pursue our financing strategy by continuing to use cash flow from our operations, drawdown our cash balance, cash equivalents and marketable securities (which at December 31, 2014 amounted to U.S.$26 billion) and use the proceeds from the sale of certain of our assets under our divestment program announced in March 2015.  We also expect to continue to raise debt capital through a variety of medium and long-term financing arrangements, including the issuance of bonds in the international capital markets, export credit financing and bank financing.  In doing so, we also plan to extend our current debt maturity profile.

In 2014, a portion of our funding requirements was met by the disposal of assets through our divestment program. Proceeds from disposals of assets amounted to U.S.$3,744 million in 2014 (compared to U.S.$3,820 million in 2013).  See Note 10 to our audited consolidated financial statements for further information regarding such disposals of assets.

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In 2015 and going forward, we intend to meet our funding requirements by supplementing our operating cash flow with a combination of divestments (that may amount to up to U.S.$13.7 billion across all of our business segments for the period between 2015 and 2016), new debt from a broad range of traditional funding sources, including BNDES, Brazilian and the international commercial banks, export credit agencies, non-Brazilian government development banks and international debt capital markets, as well as drawing down our year-end cash balances and existing credit facilities. As of April 30, 2015, we have entered into financing agreements (mainly lines of credit) with Brazilian and international commercial banks amounting to approximately U.S.$10 billion.  See Note 35 to our audited consolidated financial statements.

Government Regulation

We are required to submit our annual capital expenditures budget (Plano de Dispêndios Globais, or PDG) to the MPBM and the MME.  Following review by these governmental authorities, the Brazilian Congress must approve the budget.  Although the total level of our annual capital expenditures is regulated, the specific application of funds is left to our discretion. 

The MPBM controls the total amount of medium and long-term debt that we and our Brazilian subsidiaries can incur through the annual budget approval process.  Before raising medium and long-term debt, we and our Brazilian subsidiaries must also obtain the approval of the National Treasury Secretariat.  All of our foreign currency denominated debt, as well as the foreign currency denominated debt of our Brazilian subsidiaries, requires registration with the Central Bank.  We also have to obtain an authorization from the Central Bank, in accordance with applicable law, in order to make any eventual remittances of funds abroad required by guarantee instruments we have entered into in connection with the incurrence of foreign currency denominated debt.

However, the incurrence of debt by our non-Brazilian subsidiaries, including PGF, is not subject to registration with the Central Bank or approval by the National Treasury Secretariat.  

All medium and long-term debt incurred by Petrobras or its subsidiaries requires the approval of our board of executive officers, within the parameters established by our board of directors, except for the issuance of debentures, which require the approval of our board of directors.

Sources of Funds

Our Cash Flow

In 2014, the resources needed to fund our capital expenditures (U.S.$34,750 million) and payment of dividends (U.S.$3,918 million) were met by cash flow from operations (U.S.$26,632 million), net proceeds from long-term financing (U.S.$15,024 million) and cash provided by the disposal of assets (U.S.$3,744 million).  We also had a cash surplus that allowed the increase of our balance of cash and cash equivalents, as well as government bonds and time deposits with maturities of more than three months, amounting to U.S.$25,957 million as of December 31, 2014 from U.S.$19,746 million in December 31, 2013.

                Net cash provided by operating activities increased by 1% in 2014 compared to 2013. Excluding foreign currency translation effects, cash provided by operating activities increased by 11% when expressed in reais, as a result of higher gross profit and a decrease in inventories.

Proceeds from long-term financing, net of repayments, totaled U.S.$15,024 million in 2014. The principal sources of long-term financing were the issuance of global notes totaling U.S.$13.6 billion in the international capital markets, and long-term financing obtained in the domestic and international banking markets.

Proceeds in 2014 from disposals of assets totaled U.S.$3,744 million, mainly resulting from the sales of Petrobras Energia Peru, Brasil PCH, Innova and Gasmig.

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The uses of cash were primarily for capital expenditures and investments in operating units, which totaled U.S.$34,750 million in 2014, a decrease of 23% compared to 2013 (U.S.$45,163 million), mainly due to a decrease in RTM (U.S.$5,394 million) and in exploration and production capital expenditures (U.S.$3,612 million).

Payment of dividends increased by 48% to U.S.$3,918 million in 2014 from U.S.$2,656 million in 2013.

As of December 31, 2014, our balance of cash and cash equivalents amounted to U.S.$16,655 million, compared to U.S.$15,868 million as of December 31, 2013. Our balance of government bonds and time deposits with maturities of more than three months increased to U.S.$9,302 million as of December 31, 2014 from U.S.$3,878 million as of December 31, 2013.

Short-Term Debt

Our outstanding short-term debt serves many purposes, including supporting our working capital and our imports of crude oil and oil products. As of December 31, 2014, our total short-term debt amounted to U.S.$3,484 million and the current portion of our long-term debt amounted to U.S.$6,845 million, compared to U.S.$3,654 million and U.S.$3,118 million as of December 31, 2013, respectively.

Long-Term Debt

Our outstanding long-term debt consists primarily of securities issued in the international capital markets, funding from development banks (such as the BNDES), loans from Brazilian and international commercial banks and amounts outstanding under facilities guaranteed by export credit agencies and multilateral agencies.  The non-current portion of our total long-term debt amounted to U.S.$120,218 million as of December 31, 2014, compared to U.S.$106,235 million as of December 31, 2013.  This increase was primarily due to funding from the domestic and international banking markets and from the issuance of U.S. dollar, Euro and Pound Sterling denominated bonds. These financial resources will be used primarily to fund capital expenditures to develop crude oil and natural gas-producing properties, construct vessels and pipelines, and build and expand industrial plants, among other uses.  See Note 17 to our audited consolidated financial statements for a breakdown of our debt, a roll-forward schedule of our non-current debt by source and other information.

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The following international debt issues are included in these figures at December 31, 2014:

Notes(*)	Carrying amount as of December 31, 2014
	(U.S.$ million)
PGF’s 2.150% Japanese Yen Bonds due 2016(**)(1)	290
PGF’s 3.875% Global Notes due 2016(**)	2,497
PGF’s 6.125% Global Notes due 2016(**)	885
PGF’s 2.000% Global Notes due 2016	1,247
PGF’s Floating Rate Global Notes due 2016(2)	999
PGF’s 3.250% Global Notes due 2017	1,597
PGF’s 3.500% Global Notes due 2017(**)	1,744
PESA’s 5.875% Notes due 2017	300
PGF’s Floating Rate Global Notes due 2017(3)	1,397
PGF’s 2.750% Global Notes due 2018(4)	1,815
PGF’s 4.875% Global Notes due 2018(**)(5)	1,510
PGF’s 5.875% Global Notes due 2018(**)	1,743
PGF’s 8.375% Global Notes due 2018(**)	574
PGF’s 7.875% Global Notes due 2019(**)	2,776
PGF’s 3.000% Global Notes due 2019	1,987
PGF’s 3.250% Global Notes due 2019(6)	1,571
PGF’s Floating Rate Global Notes due 2019(7)	1,497
PGF’s 4.875% Global Notes due 2020	1,494
PGF’s 5.750% Global Notes due 2020(**)	2,482
PGF’s Floating Rate Global Notes due 2020(8)	499
PGF’s 3.750% Global Notes due 2021(9)	904
PGF’s 5.375% Global Notes due 2021(**)	5,317
PGF’s 5.875% Global Notes due 2022(**) (10)	723
PGF’s 4.250% Global Notes due 2023(11)	836
PGF’s 4.375% Global Notes due 2023	3,457
PGF’s 6.250% Global Notes due 2024	2,488
PGF’s 4.750% Global Notes due 2025(12)	962
PGF’s 6.250% Global Notes due 2026(**)(13)	1,069
PGF’s 5.375% Global Notes due 2029(14)	683
PGF’s 6.625% Global Notes due 2034(15)	921
PGF’s 6.875% Global Notes due 2040(**)	1,471
PGF’s 6.750% Global Notes due 2041(**)	2,370
PGF’s 5.625% Global Notes due 2043	1,710
PGF’s 7.250% Global Notes due 2044	988

(*)                  Petrobras fully and unconditionally guarantees the notes issued by PGF.

(**)                Originally issued by PifCo.

(1)                  Issued by PifCo on September 27, 2006 in the amount of ¥ 35 billion, with support from Petrobras through a standby purchase agreement.

(2)                  Floating rate equal to a three-month U.S. dollar LIBOR plus 1.620%.

(3)                  Floating rate equal to a three-month U.S. dollar LIBOR plus 2.360%.

(4)                  Issued by PGF on January 14, 2014 in the amount of €1.5 billion.

(5)                  Issued by PifCo on December 9, 2011 in the amount of €1.25 billion.

(6)                  Issued by PGF on October 01, 2012 in the amount of €1.3 billion.

(7)                  Floating rate equal to a three-month U.S. dollar LIBOR plus 2.140%

(8)                  Floating rate equal to a three-month U.S. dollar LIBOR plus 2.880%.

(9)                  Issued by PGF on January 14, 2014 in the amount of €750 million.

(10)               Issued by PifCo on December 9, 2011 in the amount of €600 million.

(11)               Issued by PGF on October 01, 2012 in the amount of €700 million.

(12)               Issued by PGF on January 14, 2014 in the amount of €800 million.

(13)               Issued by PifCo on December 12, 2011 in the amount of £700 million.

(14)               Issued by PGF on October 01, 2012 in the amount of £450 million.

(15)               Issued by PGF on January 14, 2014 in the amount of £600 million.

Off Balance Sheet Arrangements

As of December 31, 2014, we had no off-balance sheet arrangements that have, or are reasonably likely to have, a material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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Uses of Funds

Capital Expenditures and Investments

We invested a total of U.S.$37,004 million in 2014, a 23% decrease, when compared to our investments of U.S.$48,097 million in 2013. Our investments in 2014 were primarily directed toward increasing oil and gas production.  Of our total capital expenditures in 2014, U.S.$24,164 million was invested in exploration and development projects in Brazil and U.S.$1,336 million in exploration and development projects abroad.

The following table sets forth our consolidated capital expenditures for each of our business segments for 2014, 2013 and 2012:

	For the Year Ended December 31
	2014	2013	2012
	(U.S.$ million)
Exploration and Production	24,164	27,566	21,959
Refining, Transportation and Marketing	7,778	14,243	14,745
Gas and Power	2,545	2,716	2,113
Biofuel	112	143	147
Distribution	446	514	666
International
Exploration and Production	1,336	2,126	2,347
Refining, Transportation and Marketing	104	156	131
Gas and Power	26	26	5
Distribution	41	52	72
Others	6	8	17
Corporate	446	547	747
Total	37,004	48,097	42,949

On April 22, 2015, we announced planned capital expenditures of U.S.$29 billion in 2015 and approximately U.S.$25 billion in 2016.  We plan to meet our budgeted capital expenditures primarily through internally generated cash,  structured facilities and project finance loans, commercial bank loans, divestments, issuances in the international capital markets and other sources of capital.  Our actual capital expenditures may vary substantially from the projected numbers set forth above as a result of market conditions and the cost and availability of the necessary funds.

Dividends

Our board of directors proposed no distribution of dividends in 2015 for profits accrued in the year ended December 31, 2014 because we reported a net loss for the fiscal year.  See Note 23.5 to our audited consolidated financial statements.

For more information on our dividend policy, including a description of the minimum dividend to which our preferred shareholders are entitled under our bylaws, see “Mandatory Distribution” and “Payment of Dividends and Interest on Capital” in Item 10. “Additional Information—Memorandum and Articles of Incorporation.”

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Contractual Obligations

The following table summarizes our outstanding contractual obligations and commitments at December 31, 2014:

	Payments Due by Period
	Total	< 1 year	1-3 years	3-5 years	> 5 years
	(U.S.$ million)
Contractual obligations
Balance sheet items(1):
Debt obligations(2)	132,086	11,868	24,520	41,978	53,720
Finance lease obligations	72	16	18	13	25
Provision for decommissioning costs	8,267	445	540	55	7,227
Total balance sheet items	140,425	12,329	25,078	42,046	60,972
Other long-term contractual commitments
Natural gas ship-or-pay	3,815	630	1,276	1,289	620
Service contracts	90,495	29,093	20,780	16,897	23,725
Natural gas supply agreements	12,487	1,786	3,263	3,378	4,060
Operating leases	118,404	14,644	19,569	18,930	65,261
Purchase commitments	31,981	16,356	13,964	678	983
Total other long-term commitments	257,182	62,509	58,852	41,172	94,649
Total	397,607	74,838	83,930	83,218	155,621

(1)              Excludes the amount of U.S.$37,438 million related to our pension and medical benefits obligations, which are partially funded by U.S.$20,151 million in plan assets.  Information on employees’ post-retirement benefit plans, including a schedule of expected maturity of pension and medical benefits obligations, is set forth in Note 22 to our audited consolidated financial.

(2)              Includes accrued interest, short-term and long-term debt (current and non-current portions).  Information about our future interest and principal payments (undiscounted) for the coming years is set forth in Note 33.6 to our audited consolidated financial statements.

Critical Accounting Policies and Estimates

Information about those areas that require the most judgment or involve a higher degree of complexity in the application of the accounting policies that currently affect our financial condition and results of operations is provided in Note 5 to our audited consolidated financial statements (comprising oil and gas reserves, depreciation and impairment; identifying cash-generating units for impairment testing; pension and other post-retirement obligations; contingent liabilities and provisions; dismantling of areas; derivative financial instruments; hedge accounting; the accounting approach to the Lava Jato Operation; and allowance for impairment of trade receivables). Additional information about our accounting policies and new amendments and standards are provided in Notes 4 and 6 to our audited consolidated financial statements. Further information about impairment of assets is provided in Note 14 to our audited consolidated financial statements.  Additionally, we have expanded herein the discussion of some of the items addressed in the financial statements for certain topics, such as the estimation methodology for determining the write-off for overpayments incorrectly capitalized; dismantling of areas and environmental remediation; impairment testing of refining assets; pension and medical benefits; as well as allowance for impairment of trade receivables.

The accounting estimates we make in these contexts require us to make assumptions about matters that are highly uncertain. The aforementioned notes address only those estimates that we consider most important based on the degree of uncertainty and the likelihood of a material impact if we used a different estimate.  There are many other areas in which we use estimates about uncertain matters, but the reasonably likely effect of changed or different estimates is not material to our financial presentation.

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Estimation Methodology for Determining Write-Off for Overpayments Incorrectly Capitalized

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. 

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 Petrobras in connection with the acquisition of property, plant and equipment.  Two Petrobras executive officers and one executive manager were involved in this payment scheme, none of whom has been affiliated with us since April 2012.  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 receive or make the improper payments, which were made by the 27 contractors and suppliers and by intermediaries acting on behalf of the contractors and suppliers.

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. 

We believe that under IAS 16, the amounts we overpaid pursuant to this payment scheme and the unrelated payments described above 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.  The improper payments were made by outside suppliers and contractors so the exact amounts that we overpaid to fund these payments cannot be identified.  The information to determine the amount by which we were overcharged by the cartel members (and applicable dates) is not contained within our accounting records, and we cannot identify the amounts of overpayments for specific contractual payments or in specific accounting periods.  The money-laundering activities alleged to have occurred were designed to hide the origins and amounts of the funds involved, so a specific accounting should not be expected.

We concluded that the portion of the costs incurred to build our 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 order to account for the impact of overpayments, we developed an estimation methodology to serve as a proxy for the adjustment that should be made to property plant and equipment using the five steps described below:

(1)   Identify contractual counterparties: we listed all the companies identified in public testimony, and using that information we identified all of the contractors and suppliers that were either so identified or were consortia including entities so identified.

(2)   Identify the period: we concluded from the testimony that the payment scheme was operating from 2004 through April 2012.

(3)   Identify contracts: we identified all contracts entered into with the counterparties identified in step 1 during the period identified in step 2, which included supplemental contracts when the original contract was entered into between 2004 and April 2012.  We have identified all of the property, plant and equipment related to those contracts.

(4)   Identify payments: we calculated the total contract values under the contracts identified in step 3.

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(5)   Apply a fixed percentage to the amount determined in Step 4: we estimated the aggregate overpayment by applying a percentage indicated in the depositions (3%) to the total amounts for identified contracts.

For overpayments attributable to other contractors and suppliers, unrelated to the payment scheme, we included in the write-off for incorrectly capitalized overpayments the specific amounts of improper payments or percentages of contract values, as described in the testimony, which were used by those suppliers and contractors to fund improper payments.

We believe that this methodology produces the best estimate for the aggregate overstatement of our property, plant and equipment resulting from the payment scheme, in the sense that it represents the upper bound of the range of reasonable estimates. The estimate assumes that all contracts with the identified counterparties were affected and that 3% represents the amount by which we overpaid on those contracts.  Both assumptions are supported by the testimony, even though some testimony indicated lower percentages with respect to certain contracts, a shorter period (2006 to 2011), or fewer contractors involved.

We acknowledge the degree of uncertainty involved in the estimation methodology and have, therefore, developed a sensitivity analysis taking into account that approximately 26% of the write-off of overpayments incorrectly capitalized relates to assets that were charged for impairment in the fourth quarter of 2014.  Excluding these assets, an increase or decrease of 1% in the applicable percentage of the overcharge applied over total contract values would result in an increase or decrease of U.S.$603 million in the write-off of overpayments incorrectly capitalized. However, as discussed above, we believe we have used the most appropriate methodology and assumptions to determine the impact of the payment scheme based on the information available to us and there is no evidence that would indicate the possibility of a material change in the amounts that were written off.

The information available to us is generally consistent with respect to the existence of the payment scheme, the companies involved in the payment scheme, the former Petrobras personnel involved in the payment scheme, the period during which the payment scheme was in effect, and the maximum amounts involved in the payment scheme relative to the contract values of affected contracts. Petrobras will monitor the results of the investigations and the availability of other information concerning the payment scheme.  If information becomes available that indicates with sufficient precision that the estimate described above should be adjusted, Petrobras will evaluate whether the adjustment is material and, if so, recognize it.  However, we have no expectation that additional information bearing on these matters is or will be available from internal sources.

See Note 3 to our audited consolidated financial statements for a detailed description of the investigations, the payment scheme and our response to it, sources of information available to us, the estimation methodology and the impact of the improper payments on our financial statements.

Dismantling of Areas and Environmental Remediation

                Under various contracts, permits and regulations, we have material legal obligations to remove equipment and restore the land or seabed at the end of operations at production sites. Our most significant asset removal obligations involve removal and disposal of offshore oil and gas wells and production facilities worldwide.

We accrue the estimated discounted decommissioning costs (for dismantling and removing these facilities) at the time of installation of the assets. We also estimate costs for future environmental clean-up and remediation activities based on current information on costs and expected plans for remediation. Estimating asset retirement, removal and environmental remediation costs requires performing complex calculations that necessarily involve significant judgment because our obligations are many years in the future, the contracts and regulation have vague descriptions of what removal and remediation practices and criteria will have to be met when the removal and remediation events actually occur and asset removal technologies and costs are constantly changing, along with political, environmental, safety and public relations considerations. Consequently, the timing and amounts of future cash flows are subject to significant uncertainty.

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                We reviewed and revised our estimated costs associated with well abandonment and the demobilization of oil and gas production areas. As a result, for 2014, there was a U.S.$1.1 billion increase in the amounts related to the revision of the provision for decommissioning costs, mainly attributable to a U.S.$2.5 billion increase attributable to a revision of decommissioning estimates, adjusting forecasts to reflect previous experiences with respect to costs incurred and actual contracts for workover rigs.  

Those effects were partially offset by a U.S.$1.5 billion decrease attributable to an increase of our risk adjusted discount rate (from 3.03% p.a. at December 31, 2013 to 3.76% p.a. at December 31, 2014).  Other effects, like changes in timing of decommissioning cash flows were responsible for a U.S.$0.2 billion increase.

                Petrobras regularly conducts studies to incorporate the most recent technologies and procedures to optimize the abandonment of areas, considering industry best practices and previous experiences with respect to costs incurred.

                See Note 20 to our audited consolidated financial statements for more information about the annual changes in the provision for decommissioning costs.

Impairment Testing of Refining Assets

Until the third quarter of 2014, we grouped all refineries and associated assets, terminals and pipelines, as well as logistics assets operated by Transpetro, all located in Brazil, into a single cash generating unit ("CGU") referred to as the “Downstream Assets CGU.”

However, in the quarter ended December 31, 2014, changes in circumstances prompted a review of our planned projects and ultimately led Management to revise certain projects that were under construction.

Those circumstances include: (i) a decrease in expected future operating revenues following the decline of international crude oil prices; (ii) the devaluation of the Brazilian real, and the increased cash outflow to service our debt in the near-term, most of which is denominated in foreign currencies; (iii) Petrobras’s current inability to access the capital markets; (iv) insolvency of contractors and suppliers and a consequent shortage of qualified contractors and suppliers (as a result of the difficulties created for suppliers by the Lava Jato investigation or otherwise).

As a result, we recently decided to postpone 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 in the Abreu e Lima refinery (RNEST). For that reason, as of December 31, 2014, those assets under construction were removed from the “Downstream CGU” and were tested for impairment individually.

Except for the removal of these two projects, the “Downstream CGU” remains unchanged. This CGU was identified based on the concept of integrated optimization and performance management, which focuses on the global performance of the CGU, allowing a shift of margins from one refinery to another. All decisions concerning this CGU (operation, investments, and market strategy) seek to maximize the value of the whole system rather than improve the results of each constituent part.  Pipelines and terminals are also an interdependent portion of the refining assets, required to supply the market.

We determined the recoverable amounts of the following assets based on their value-in-use: (i) the “Downstream CGU”; (ii) Comperj; and (iii) the second refining unit of RNEST. The assessment of the value-in-use involves the use of estimates on uncertain assumptions, such as future production curves, future commodity prices, sales revenue growth, operating margins, discount rates, foreign exchange rates, inflation rates and investments required for carrying out projects.

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The key assumptions on which we based our cash flow projections to determine the value in use were approved by our management, and are described below:

·estimated average exchange rate of R$2.85 to U.S.$1.00 in 2015 and 2016 (converging to R$2.61 to U.S.$1.00 in the long-term);

·Brent crude oil price of U.S.$52 for 2015, converging to U.S.$85 in the long-term;

·domestic sales volume growth based on projected Brazilian and global GDP growth;

·EBITDA margin reflecting the convergence of diesel and gasoline prices in Brazil with international benchmarks; and

·post-tax discount rates derived from our weighted average cost of capital (reviewed annually). The post-tax discount rate for Comperj and the second refining unit of RNEST also include specific risks related to these assets.

These assumptions are subject to changes that could affect the carrying amounts of assets, and eventually cause impairment charges and reversals that would affect profit or loss.

Future price assumptions do not consider short-term increases or decreases in price as indicative of long-term trend changes and therefore tend to be stable. Nonetheless, such prices are subject to change.

In the fourth quarter of 2014, we recognized impairment losses of U.S.$8.2 billion related to Comperj and U.S.$3.4 billion related to the second refining unit in RNEST. No impairment losses have been recognized for the “Downstream CGU.”

For more detailed information about our impairment policies and impairment test results, see Notes 4.10, 5.2 and 14 to our audited consolidated financial statements.

Pension and Other Post-Retirement Benefits

We provide post-retirement benefits to our employees mainly through the Petros and Petros 2 pension plans and AMS health care plan (Assistência Multidisciplinar de Saúde), as well as other pension and health care plans internationally, with defined benefit characteristics.

                Net actuarial liabilities were U.S.$17,287 million as of December 31, 2014, a 37% increase from U.S.$12,573 million as of December 31, 2013, mainly due to the remeasurement of actuarial liabilities (U.S.$5,947 million) and to interest and service costs incurred during the year (U.S.$2,022 million), partially offset by contributions paid in 2014 (U.S.$648 million).

                The remeasurement of actuarial liabilities, recognized in other comprehensive income in shareholders' equity, was mainly attributable to: i) a decrease in the discount rate (real rate, excluding inflation) and an increase in projected medical costs (U.S.$3,782 million), and ii) return on pension and medical plan assets exceeding expected interest income (U.S.$2,165million).  Projected medical costs increased due to a higher use of medical procedures by participants, to an increase in our medical coverage (resulting from the current Collective Bargaining Agreement) and to a higher number of medicines included in the list of our assisted purchase program.

                Our discount rates used in calculating the actuarial liabilities for our pension and health care plans are determined based on the weighted average of Brazilian federal government long-term securities (NTN-B) for our post-retirement benefits obligations duration (i.e. considering the maturity profile of the actuarial obligations).

                See Note 22 to our audited consolidated financial statements for more detailed information about our actuarial obligations, including our actuarial assumptions, and for a sensitivity analysis of the impact of a 100 basis point change in our discount rates, as well as the effect of changes in other actuarial assumptions.

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Allowance for Impairment of Trade Receivables from the Isolated Electricity Sector in the Northern Region of Brazil

We continuously assess whether there is objective evidence that trade receivables are impaired and recognize allowances for impairment of trade receivables to cover losses.

In 2014, we recognized an allowance for impairment of trade receivables of U.S.$1,948 million to cover uncollateralized receivables from the isolated electricity sector as of October 31, 2014.

Beginning in 2015, the Brazilian federal government implemented a new pricing policy for the electricity sector and allowed electricity distribution companies to implement price increases in the first quarter of 2015, which will strengthen their financial situation.  No charges were recognized for companies that were not insolvent or for receivables from sales dated after November 1, 2014, because those amounts were included in the calculation of the new pricing policy.

See Notes 4.3.3, 5.9 and 8.4 to our audited consolidated financial statements for more detailed information about our accounting policies with respect to trade receivables and about the receivables from the isolated electricity system.

Research and Development

We are deeply committed to research and development as a means to extend our reach to new production frontiers and achieve continuous improvement in operations.  We have a history of successfully developing and implementing innovative technologies, including the means to drill, complete and produce wells in increasingly deep water.  We are one of the largest investors in research and development among the world’s major oil companies, and we spend a large percentage of revenues in research and development.  Our Brazilian oil and gas concession agreements require us to invest at least 1% of our gross revenues originating from high productivity oil fields on research and development, of which up to half is invested in our research facilities in Brazil and the remainder is invested in research and development in Brazilian universities and institutions registered with the ANP for this purpose.

In 2014, we spent U.S.$1,099 million on research and development, equivalent to 0.76% of our sales revenues, while in 2013, we spent U.S.$1,132 million, equivalent to 0.8% of our sales revenues, and in 2012, we spent U.S.$1,143 million, equivalent to 0.8% of our sales revenues.

Our research and development activities are based on strategic choices that we make regarding technological development, which we call our “Technological Focus,” namely:

For Exploration & Production

-       Exploration of New Frontiers;

-       Assessment of new potential natural gas sources, both in conventional and non-conventional reservoirs, spread throughout onshore sedimentary basins located in Brazil´s countryside;

-       Offshore wells building and maintenance optimization;

-       Subsea Production Systems;

-       Pre-Salt Production;

-       Offshore Logistics; and

-       Mature fields production optimization.

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For Downstream, Transport, Distribution, Biofuels and Petrochemical

-       Gasoline and medium oil products production optimization;

-       Pre-Salt Oils Refining;

-       Optimization and integration of operating logistics;

-       Innovative Products;

-       Bioproducts; and

-       More usage of both fossil and renewable streams as raw materials for petrochemicals.

For Gas and Energy

-       Valuation of new potentials of natural gas in both conventional and non-conventional reservoirs spread throughout onshore sedimentary basins located in Brazil´s countryside regions;

-       Integration and flexibility in the supply and demand of both energy and natural gas;

-       Natural Gas Logistics;

-       Cost Reduction;

-       Value-adding to Natural Gas via methane chemistry; and

-       Natural Gas Processing.

For all Business Segments and Sustainability

-       Development of building and assembly technology for naval and industrial design;

-       Optimization of productive processes;

-       Integrity, safety and reliability of new materials and equipment available;

-       Technology for mitigation of atmospheric emissions (CO2 and other emissions);

-       Technology for disposal, treatment, reusage and reduction of water consumption; and

-       Technology for recovery of environmentally affected areas.

                Forward-Thinking – 2030 Perspective

-       Increased reliability of risk estimates through the integrated simulation of geological processes;

-       Riserless Maritime Production Systems;

-       Energy production, storage and distribution systems that are used in electric and hybrid vehicles, improving mobility;

-       Nanotechnology applied to both processes and products;

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-       Development of new materials suitable for use in extreme operating conditions; and

-       Technologies used for improving gas hydrates prospection.

In the three-year period ended December 31, 2014, our research and development operations were awarded 100 patents in Brazil and 134 overseas. Our portfolio of patents covers all of our areas of activities.

We have operated a dedicated research and development facility in Rio de Janeiro, Brazil since 1963.  As a result of its expansion in 2010, this is one of the largest facilities of its kind in the energy sector and the largest in the southern hemisphere, with laboratories especially dedicated to pre-salt technologies.  As of December 31, 2014, this facility had 1,862 employees, 74.3% of which are exclusively dedicated to research, development and basic engineering.

We also have several semi-industrial scale prototype plants throughout Brazil that are in proximity to our industrial facilities and that are aimed at scaling up new industrial technologies at reduced costs.  In 2014, we conducted research and development through joint research projects with more than 100 universities and research centers in Brazil and abroad and participated in technology exchange and assistance partnerships with several oilfield service companies, small technology companies and other operators.

Trends

Despite the recent deceleration of the demand for oil products and economic growth in Brazil, attributable to countercyclical macroeconomic policies, we expect that the demand for oil products in Brazil will continue to grow in the medium- and long-terms, driven primarily by economic growth and the increase in purchasing power of the Brazilian population. In recent years, we met this incremental growth in demand by increasing imports of oil and oil products and improving the throughput of our refineries, since our oil production and our refining capacity were not sufficient to meet the increased demand.  Higher import of oil and oil products increased our cost of sales and decreased our distribution margins in recent years, because we have not fully adjusted our domestic prices to reflect the higher cost of oil and oil products and because of the devaluation of the real against the U.S. dollar. 

The price we realize for the crude oil we export is determined by international oil prices, although we generally sell our crude oil at a discount compared to Brent and other light oil benchmark prices because it is heavier and thus more expensive to refine.  In 2014, oil price trends were affected by supply and demand fundamentals as well as by fluctuations in macroeconomic conditions.  The Brent benchmark price experienced higher variation in 2014 as compared to 2013, with a strong decline in the second half of the year due to an oversupply of oil. In 2014, the minimum price was U.S.$55.76/bbl, the maximum price was U.S.$115.00/bbl and the average price was U.S.$98.91/bbl.  The response of oil supply and demand to the recent decline in oil prices will be the key determinant of oil price trends in the short term.  A fast-paced increase in demand coupled with a strong downward adjustment in supply may result in higher prices in the medium term.  On the other hand, if supply adjustments are not strong enough to rebalance the market, oil prices may drop below current levels.  In addition, geopolitical concerns in Russia, the Middle East and North Africa may persist, potentially driving prices higher in the short term.

Each year, we review and revise our long-term Business and Management Plan in order to adapt to changing market conditions and to revise our investment levels in accordance with updated scenarios and projected cash flows.

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We are currently working on our updated business and management plan and we expect to release it following approval by our board of directors. Due to the recent changes in the global and the Brazilian macroeconomic environment, the substantial decrease in Brent crude oil prices, the depreciation of the real against the U.S. dollar, as well as the impact of the ongoing Lava Jato investigations, our updated business and management plan may reflect a reduction of our capital expenditures, a revision of our financial performance indicators and delay of our oil production targets as compared with those in our 2014-2018 Plan.

Item 6.  Directors, Senior Management and Employees

Directors and Senior Management

Directors

Our board of directors, which we refer to as the conselho de administração, is composed of a minimum of five and maximum ten members and is responsible for, among other things, establishing our general business policies.  The members of the board of directors are elected at the annual general meeting of shareholders, including the employee representative previously selected by means of a separate voting procedure.

Under Brazilian Corporate Law, shareholders representing at least 10% of the company’s voting capital have the right to demand that a cumulative voting procedure be adopted to entitle each common share to as many votes as there are board members and to give each common share the right to vote cumulatively for only one candidate or to distribute its votes among several candidates.  Pursuant to regulations promulgated by the CVM, the 10% threshold requirement for the exercise of cumulative voting procedures may be reduced depending on the amount of capital stock of the company. For a company like Petrobras, the applicable threshold is 5%. Thus, shareholders representing 5% of our voting capital may demand the adoption of a cumulative voting procedure.

Our bylaws enable (i) minority preferred shareholders that together hold at least 10% of the total capital stock (excluding capital stock held by the controlling shareholders) to elect and remove one member to our board of directors; (ii) minority common shareholders to elect and remove one member to our board of directors, if a greater number of directors is not elected by such minority shareholders by means of the cumulative voting procedure; and (iii) our employees to elect one member to our board of directors by means of a separate voting procedure, pursuant to Law No. 12,353 and MPBM’s Act No. 26.  Our bylaws provide that, regardless of the rights above granted to minority shareholders, the Brazilian federal government always has the right to elect the majority of our directors, independently of their number.  In addition, under Law 10,683, one of the board members elected by the Brazilian federal government must be indicated by the Minister of Planning, Budget and Management.  The maximum term for a director is one year, but re-election is permitted. In accordance with the Brazilian Corporate Law, the shareholders may remove any director from office at any time with or without cause at an extraordinary meeting of shareholders.  Following an election of board members pursuant to the cumulative voting procedure, the removal of any board member by an extraordinary meeting of shareholders will result in the removal of all of the other members, after which new elections must be held.

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                We currently have ten directors.  The following table sets forth certain information with respect to these directors:

Name	Date of Birth	Position	Current Term Expires	Business Address
Murilo Pinto de Oliveira Ferreira(1)	June 22, 1953	Chair	April 2016	Av. Graça Aranha, 26 – 18th floor – Castelo – Rio de Janeiro ZIP code: 20030 900
Aldemir Bendine(1)	December 10, 1963	Director	April 2016	Avenida República do Chile, no. 65 23rd floor Rio de Janeiro – RJ ZIP code: 20.031-912
Luciano Galvão Coutinho(1)	September 29, 1946	Director	April 2016	Av. República do Chile, no. 100 22th floor Rio de Janeiro – RJ ZIP code: 20.031-917
Luiz Augusto Fraga Navarro de Britto Filho(1)	October 5, 1965	Director	April 2016	SCN Quadra 2 Bloco A - Edf. Corporate Financial Center 10th floor Brasília (Distrito Federal) ZIP code: 70712-900
Luiz Nelson Guedes de Carvalho(1)	November 18, 1945	Director	April 2016	Av. Prof. Luciano Gualberto, 908 – FEA3 – Cid. Universitária - São Paulo –SP ZIP code: 05508-010
Roberto da Cunha Castello Branco(1)	July 20, 1944	Director	April 2016	Praia de Botafogo 190, 11th floor Rio de Janeiro – RJ ZIP code: 22250-900
Segen Farid Estefen(1)	January 20, 1951	Director	April 2016	COPPE - Universidade Federal do Rio de Janeiro Centro de Tecnologia - Bloco I - room 108 - Cidade Universitária Rio de Janeiro – RJ ZIP code: 21941-909
Guilherme Affonso Ferreira(2)	May 9, 1951	Director	April 2016	Rua Estados Unidos, 1342 São Paulo – SP ZIP code: 01427-001
Walter Mendes de Oliveira Filho(3)	December 7, 1955	Director	April 2016	Av. República do Chile, 65 – 24th floor - Rio de Janeiro – RJ ZIP code: 20031-170
Deyvid Souza Bacelar da Silva(4)	February 18, 1980	Director	April 2016	Rodovia BA 523, Km 4, Mataripe, São Francisco do Conde – BA ZIP code: 49170-000

(1)                  Appointed by the controlling shareholder.

(2)                  Appointed by the minority preferred shareholders.

(3)                  Appointed by the minority common shareholders.
(4)                  Appointed by our employees.

Murilo Pinto de Oliveira Ferreira—Mr. Ferreira has been the chairman of our board of directors since May 5, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A.  He has been Vale S.A.’s Chief Executive Officer and member of Vale’s strategy and disclosure committees since May 2011.  Mr. Ferreira has held different positions at Vale S.A., with responsibility over several different departments from 2005 to 2008, including Business Development, M&A, Steel, Energy, Nickel and Base Metals; Chief Executive Officer of Vale Canada from 2007 to 2008 and member of its board of directors from 2006 to 2007; chairman of the board of directors of Alunorte from 2005 to 2008, Mineração Rio Norte from 2006 to 2008 and Valesul Alumínio S.A., a subsidiary of Vale involved in the production of aluminum, from 2006 to 2008; and member of the board of commissioners of PT VaIe Indonésia Tbk, from 2007 to 2008.  Mr. Ferreira has been a member of the board of directors of several companies, including Usiminas, a Brazilian steel company, from 2006 to 2008, and was a partner at Studio Investimentos, an asset management firm with a focus on the Brazilian stock market, from October 2009 to March 2011.  Mr. Ferreira is currently a member of the CEO Advisory Board of the Massachusetts Institute of Technology (MIT) and also a member of the Wise Men Group.  He received a bachelor’s degree in business management from Fundação Getúlio Vargas-FGV in São Paulo; a post-graduate degree in business management and finance from Fundação Getúlio Vargas-FGV in Rio de Janeiro and attended a senior executive education program at the IMD Business School in Lausanne, Switzerland.

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                Aldemir Bendine—Mr. Bendine has been our Chief Executive Officer since February 2015, and he is also a member of our board of directors and of the board of directors of Petrobras Distribuidora S.A. From to April 2009 to January 2015, he served as Chief Executive Officer of Banco do Brasil S.A.  Mr. Bendine joined Banco do Brasil in 1978, and from that time until earlier this year, he held several different positions, including as vice president of bank cards and new retail businesses (from July 2007 to April 2009), vice president of retail and distribution (from December 2006 to July 2007), executive secretary of the Banco do Brasil board of officers (from July to December 2006), manager of credit and debit cards, division manager and regional manager in Banco do Brasil São Paulo superintendence.  Mr. Bendine was a member of the board of officers of Banco Patagônia from October 2010 to early 2015 and Grupo Mapfre – BB SH1 Participações S.A. and Grupo Mapfre – BB SH2 Participações S.A. from June 2011 to early 2015.  He served as executive officer of the Federação Brasileira de Bancos - Febraban (Brazilian Federation of Banks), president of the Associação Brasileira de Empresas de Cartões e Serviços – Abecs from October 2008 to July 2009, chairperson of the board of directors of CBSS (Visa Vale) from February 2007 to March 2010, member of the board of directors of Banco Votorantim S.A. from September 2009 to February 2015 and chief executive officer of BB Administradora de Cartões S.A. and BB Administradora de Consórcios S.A., among others.  Mr. Bendine holds a bachelor’s degree in business management as well as master’s degrees in business administration for senior executives from the Fundação Instituto de Pesquisas Contábeis, Atuariais e Financeiras - FIPECAFI at Universidade de São Paulo-USP and in finance from Pontifícia Universidade Católica do Rio de Janeiro-PUC-Rio.

Luciano Galvão Coutinho—Mr. Coutinho has been a member of our board of directors since April 2008, and he is also a member of the board of directors of Petrobras Distribuidora S.A.  He has been the President of the BNDES since April 2007.  In addition, Mr. Coutinho is a member of the board of directors of Vale S.A. (Vale), a member of the Curator Committee for the Fundação Nacional da Qualidade—FNQ (the Brazilian Quality Foundation), and the BNDES representative at the Fundo Nacional de Desenvolvimento Científico e Tecnológico—FNDCT (the Brazilian Fund for Scientific and Technological Development).  Mr. Coutinho has a Ph.D. in economics from Cornell University, a master’s degree in economics from the Fundação Instituto de Pesquisas Econômicas—Fipe (the Institute of Economic Research) at Universidade de São Paulo-USP and a bachelor’s degree in economics from USP.

                Luiz Augusto Fraga Navarro de Britto Filho—Mr. Navarro has been a member of our board of directors since February 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A. He has been a senior counsel at Veirano Advogados law firm since 2013 and consultant to the Brazilian Federal Senate since 2004. Mr. Navarro worked for 10 years in the Controladoria Geral da União (General Federal Inspector’s Office), where he has held different positions, including Deputy Minister of State, Secretary for Corruption Prevention and General Inspector.  From 2003 to 2006 he also served as Brazil’s expert to the Committee of Experts on the Mechanism for Follow-up on the Implementation of the Inter-American Convention against Corruption (MESICIC) and as a member of the Conselho de Controle de Atividades Financeiras – COAF (Council for the Control of Financial Activities). Mr. Navarro is also a member of the Senior Advisory Board of the International Anti-Corruption Academy. Mr. Navarro has an LL.B degree from the Universidade de Brasília-UNB, a post-graduate course in Regulation in the Modern National Economy from George Washington University, a specialization degree in Law and State from Universidade de Brasília-UNB and a specialization degree in Public Policy and Government Management from the Escola Nacional de Administração Pública - ENAP (Brazilian National School of Public Administration).

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Luiz Nelson Guedes de Carvalho—Mr. Carvalho has been a member of our board of directors since May 4, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A. He has been a member of the board of directors of BMF&BOVESPA (and the coordinator of its audit committee) since 2013 and also the coordinator of Grupo Pão de Açucar audit committee since 2013.  He is currently a professor at Universidade do Estado de São Paulo – Faculdade de Economia, Administração e Contabilidade, officer of the Fundação Instituto de Pesquisas Contábeis, Atuariais e Financeiras - FIPECAFI, member of the Comitê de Pronunciamentos Contábeis CPC – Brasil, among others.  Mr. Carvalho has previously served as a member of the board of directors of XBRL International Inc., member of the Financial Crisis Advisory Group – FCAG, the first independent president of the Standards Advisory Council – SAC at IASB (from July 2005 to December 2008), consultant at the World Bank, and has served as a member of the board of directors of Banco Nossa Caixa, Caixa Econômica Federal, Banco Bilbao Vizcaya Argentaria Brasil – BBVA, Vicunha Têxtil S.A., Banco Fibra S.A., among others. Mr. Carvalho also served as Deputy Governor and head of banking supervision of the Central Bank of Brazil (from 1991 to 1993) and as commissioner of the CVM (from 1990 to 1991). Mr. Carvalho received a bachelor’s degree in economics from Universidade de São Paulo – Faculdade de Economia e Administração e Contabilidade and in accounting from Faculdades São Judas Tadeu and a master’s and a Ph.D degree in accounting and controllership from Universidade de São Paulo – Faculdade de Economia e Administração e Contabilidade.

                Roberto da Cunha Castello Branco—Mr. Castello Branco has been a member of our board of directors since April 30, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A. From June 1999 to January of 2014 he was the investor relations officer at Vale S.A. Mr. Castello Branco also served as a Deputy Governor of the Central Bank of Brazil (from March 1985 to September 1985), and he was executive director of Banco Boavista and Banco InterAtlântico, president of IBMEC, professor of the Graduate School of Economics at Fundação Getulio Vargas (EPGE/FGV), member of the board of trustees of the Fundação Getulio Vargas, president of the Instituto Brasileiro de Relações com Investidores, member of the board of directors of ABRASCA – the Brazilian Association of Public Companies, vice-president of the Chamber of Commerce Brasil-Canada and officer of the American Chamber of Commerce of the State of Rio de Janeiro. He is currently director of the Center for Growth and Economic Development (Centro de Estudos de Crescimento e Desenvolvimento Econômico) at Fundação Getulio Vargas. Mr. Castello Branco holds a bachelor’s degree in economics from Faculdade Brasileira de Ciências Econômicas, a Ph.D degree in economics from the graduate school of economics at Fundação Getulio Vargas – EPGE/FGV and a post-doctoral fellow degree in economics from the University of Chicago. He has also participated in executive training programs from the Sloan School of Management, MIT, IMD Business Schools and the University of Chicago Booth School of Business.

Segen Farin Estefen—Mr. Estefen has been a member of our board of directors since May 6, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A.  He has been an ocean structures and submarine engineering professor at Universidade Federal do Rio de Janeiro – COPPE, where he has been a professor since 1976 and held the position of dean from 1998 to 2001.  He is also the general manager of the Submarine Technology Laboratory and the coordinator of the Ocean Renewable Energies Group, both at Universidade Federal do Rio de Janeiro – COPPE, and is a member of the Ocean, Offshore and Artic Engineering division of the American Society of Mechanical Engineers (ASME), a fellow at the Society for Underwater Technology – SUT, technical coordinator of the Embrapii COPPE unit for submarine engineering and member of the Academia Nacional de Engenharia - ANE.  He received a bachelor’s degree in civil engineering from Universidade Federal de Juiz de Fora, a master’s degree in ocean engineering from Universidade Federal do Rio de Janeiro – COPPE, a Ph.D degree in civil engineering from Imperial College of Science, Technology and Medicine (London) and has been a post-doctoral research fellow at the Institute for Marine Technology, Norwegian University of Science and Technology.

Guilherme Affonso Ferreira—Mr. Ferreira has been a member of our board of directors since May 4, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A., Sul America S.A, Gafisa S.A., Valid S.A, Arezzo S.A. and T4F S.A. and a member of the board of directors of non-governmental organizations such as the Institute of Citizenship, AACD, Solidarity Sport, among others.  Mr. Ferreira received a bachelor’s degree in engineering from the Polytechnic School of the Universidade de São Paulo-USP and a post-graduate degree in political science from Macalester College.

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Walter Mendes de Oliveira Filho—Mr. Mendes has been a member of our board of directors since May 4, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A, the managing director of the Brazilian Takeover Panel (Comitê de Aquisições e Fusões – CAF) since September 2014 and a member of the Supervisory Board of Investment Analysts at APIMEC- Association of Analysts and Capital Market Professionals since 2011.  Previously, Mr. Mendes was a partner and fund manager at Cultinvest Asset Management Ltd (2010-2014).  From 2003 to 2010, he was the head of equity funds management of Banco ItauUnibanco S.A.  Mr. Mendes worked for Schroder Investment Management for nine years (1994-2003), six of them as the managing officer of its Brazilian office and the remaining years as the managing officer of its Latin America investments, based in London.  Mr. Mendes started his career at Unibanco S.A, where he became head of research in 1987.  Mr. Mendes holds a bachelor’s degree in economics and he also holds a post-graduate degree in economics.

Deyvid Souza Bacelar da Silva—Mr. Bacelar has been a member of our board of directors since April 29, 2015 and he is the representative of our employees.  Mr. Bacelar has been a Safety Junior Technician at Petrobras since May 2006 and he is also the General Coordinator of the Sindicato dos Petroleiros da Bahia (Oil Workers’ Union of the State of Bahia) for the 2014-2017 term.  From April 2008 to July 2008, he was an instructor in CETEB – Centro de Educação Tecnológica do Estado da Bahia and from November 2007 to February 2008, he was an instructor in SENAI – Serviço Nacional de Aprendizagem Industrial. Mr. Bacelar holds a bachelor’s degree in business from Universidade Federal da Bahia - UEFS and a specialization degree in human resources from Universidade Federal da Bahia.

Executive Officers

Our board of executive officers, which we refer to as the diretoria, is composed of the Chief Executive Officer (CEO) and seven executive officers, and is responsible for our day-to-day management.  Our executive officers are Brazilian nationals and reside in Brazil.  Pursuant to our bylaws, the board of directors elects the executive officers, including the CEO, and in electing executive officers to their respective areas, must consider personal qualification, knowledge and specialization.  The maximum term for our executive officers is three years, but re-election is permitted.  The board of directors may remove any executive officer from office at any time with or without cause.  Four of our current executive officers are experienced Petrobras career managers, engineers or technicians.

On November 25, 2014, our board of directors approved the termination of the Chief International Officer position. and the creation of a new executive officer position: Chief Governance, Risk and Compliance Officer.  The Chief Governance, Risk and Compliance Officer is charged with ensuring that Petrobras’s procedures and guidelines are being observed by Petrobras’s management and employees, that Petrobras complies with applicable laws and regulations and that risks of fraud and corruption are mitigated. Besides participating in the decision-making process of our board of executive officers, the Chief Governance, Risk and Compliance Officer must approve any matter submitted to our board of executive officers related to governance, risk and compliance. The Chief Governance, Risk and Compliance Officer will serve for a three-year term, which may be renewed, and such officer can only be removed by the majority of our board of directors, including the vote of at least one director appointed by either the minority preferred shareholders or the minority common shareholders. On January 13, 2015, Mr. João Adalberto Elek Junior was elected to this position by our board of directors, and he was appointed on January 19, 2015.

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The following table sets forth certain information with respect to our executive officers:

Name	Date of Birth	Position	Current Term
Aldemir Bendine	December 10, 1963	Chief Executive Officer	March 2017
Ivan de Souza Monteiro	November 15, 1960	Chief Financial Officer and Chief Investor Relations Officer	March 2017
Roberto Moro	November 8, 1962	Chief Engineering, Technology and Procurement Officer	March 2017
Solange da Silva Guedes	November 22, 1960	Chief Exploration and Production Officer	March 2017
Jorge Celestino Ramos	October 11, 1956	Chief Downstream Officer	March 2017
Hugo Repsold Júnior	July 23, 1959	Chief Gas and Power Officer	March 2017
José Eduardo de Barros Dutra	April 11, 1957	Chief Corporate and Services Officer	March 2017
João Adalberto Elek Junior	November 26, 1958	Chief Governance, Risk and Compliance Officer	January 2018

                Aldemir Bendine—Mr. Bendine has been our Chief Executive Officer since February 2015.  For biographical information regarding Mr. Bendine, see “—Directors.”

Ivan de Souza Monteiro—Mr. Monteiro has been our Chief Financial Officer and Chief Investor Relations Officer since February 2015.  Mr. Monteiro previously served as the vice-president of Financial Management and Investor Relations of Banco do Brasil S.A. from June 2009 to February 2015, where he has held different positions, including the position of Chief Commercial Officer and vice-president of Finance, Capital Markets and Investor Relations. He was also president of the Supervision Committee of BB AG, a Banco do Brasil subsidiary in Austria, from April 2014 to February 2015 and president of BB Banco de Investimentos S.A. from June 2009 to February 2012 (and vice-president from February 2012 to February 2015).  Mr. Monteiro was also a member of the board of directors of Banco Votorantim Participações S.A. from September 2009 to February 2015, Ultrapar Participações S.A. from March 2013 to February 2015, BB Seguridade Participações S.A. from August 2013 to February 2015 and an alternate member of the board of directors of Mapfre BB SH-2 Participações S.A. from June 2013 to February 2015.  Mr. Monteiro holds a degree in electronic engineering and telecommunications from INATEL-MG and an MBA in finance from IBMEC-RJ and in management from the Pontifícia Universidade Católica do Rio de Janeiro – PUC-Rio.

                Roberto Moro—Mr. Moro has been our Chief Engineering, Technology and Procurement Officer since February 2015. Mr. Moro joined Petrobras in 1981 and has held various positions in Petrobras’s E&P business segment, including the position of General Manager for the Implementation of E&P Projects and Executive Manager of Subsea Projects from October 2013 to February 2015.  Mr. Moro holds a degree in mechanical engineering from Universidade Gama Filho and a specialization in project management from Fundação Getúlio Vargas-FGV. 

Solange da Silva Guedes—Ms. Guedes has been our Chief Exploration and Production Officer since February 2015. Ms. Guedes joined Petrobras in 1985 and has held various positions in Petrobras’s E&P business segment, including the position of Executive Manager of Petrobras’s upstream activities in Northern and Northeastern Brazil from February 2003 to April 2008, Executive Manager of Engineering Production in the E&P business segment from April 2008 to December 2013 and Corporate Executive Manager in E&P from December 2013 to February 2015.  Ms. Guedes holds a degree in Civil Engineering from the Universidade Federal de Juiz de Fora – UFJF, a master’s degree in civil engineering from the Universidade Federal do Rio de Janeiro – UFRJ, a PhD in oil engineering from the Universidade Estadual de Campinas – UNICAMP and an MBA in management from COPPEAD/UFRJ.

                Jorge Celestino Ramos—Mr. Ramos has been our Chief Downstream Officer since February 2015. Mr. Ramos joined Petrobras in 1983 and has held various positions in Petrobras’s distribution and refining segments, including the position of Executive Manager of Logistics in Downstream from April 2014 to February 2015 and Executive Manager of Operations of Petrobras Distribuidora S.A. from February 2007 to April 2014.  Mr. Ramos holds a degree in chemical engineering from the Universidade do Estado do Rio de Janeiro–UERJ and he holds an MBA in marketing from Escola Superior de Propaganda e Marketing - ESPM and in management from Fundação Getúlio Vargas-FGV.

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Hugo Repsold Júnior—Mr. Repsold has been our Chief Gas and Power Officer since February 2015. Mr. Repsold joined Petrobras in 1985 and has held various positions at Petrobras, including the position of Executive Manager of Strategy and Corporate Performance from January 2011 to May 2012 and Corporate Executive Manager of Gas and Power from May 2012 to February 2015. Mr. Repsold holds a degree in Mechanical Engineering from the Universidade Federal Fluminense-UFF, a degree in economics from the Universidade do Estado do Rio de Janeiro-UERJ and a master’s degree in energy planning and economics from the Universidade Federal do Rio de Janeiro (Coppe/PPE-UFRJ).

José Eduardo de Barros Dutra—Mr. Dutra has been our Chief Corporate and Services Officer since March 2012.  In 1994, he was elected Senator of the Republic with a mandate from 1995 to 2002.  He was the CEO of Petrobras from January 2003 to July 2005, and held the position of director of Petrobras and director of Petrobras Distribuidora S.A. during such time.  He was CEO of Petrobras Distribuidora S.A. from September 2007 to August 2009, and also worked as a geologist at Petrobras Mineração S.A. – Petromisa from 1983 to 1990 and at Vale from 1990 to 1994.  In addition, Mr. Dutra was chairman of the board of directors of Gaspetro, Transpetro, Petroquisa, Petrobras Energia S.A. – Pesa and Liquigás.  Mr. Dutra received a degree in geology from the Universidade Federal Rural do Rio de Janeiro (the Federal Rural University of Rio de Janeiro) in 1979.

                João Adalberto Elek Junior —Mr. Elek Junior has been our Chief Governance, Risk and Compliance Officer since January 2015. Mr. Elek Junior was Chief Financial Officer at Fibria from August 2010 to February 2012. He also held several positions at Telmex and AT&T in Brazil and Latin America, from May 2000 to July 2010, and he served as Chief Financial and Investor Relations Officer at the telecommunications firm NET Serviços from April 2007 to July 2010. Mr. Elek Junior also worked for 20 years at Citibank, where he was Chief Financial Officer for retail services from November 1996 to May 2000. Mr. Elek Junior holds an bachelor’s degree in electronic engineering from the Pontifícia Universidade Católica do Rio de Janeiro – PUC-Rio, an MBA in marketing planning from COPPEAD/UFRJ and graduate studies in mergers and acquisitions from the Columbia Business School.

Compensation

For 2014, the aggregate amount of compensation we paid to all members of the board of directors and executive officers was U.S.$7.1 million. As of December 31, 2014 we had seven executive officers and ten board members.  See Note 19.3 to our audited consolidated financial statements for further information regarding compensation of our employees and officers.

In addition, the members of our board of directors and executive officers receive medical assistance benefits, as it is generally provided to our employees and their families.  Our executive officers also receive supplementary social security benefits and housing allowance.

We have no service contracts with members of our board of directors providing for benefits upon termination of employment.  We have a remuneration and succession committee in the form of an advisory committee.  See “—Other Committees.”

Share Ownership

As of April 30, 2015, the members of our board of directors, our executive officers, and the members of our fiscal council, as a group, beneficially held a total of 5,148 common shares and 73,894 preferred shares of our company.  Accordingly, on an individual basis, and as a group, our directors, executive officers, and fiscal council members beneficially owned less than one percent of any class of our shares.  The shares held by our directors, executive officers, and fiscal council members have the same voting rights as the shares of the same type and class that are held by our other shareholders.  None of our directors, executive officers, and fiscal council members holds any options to purchase common shares or preferred shares nor any other person has any option to purchase our common or preferred shares.  Petrobras does not have a stock option plan for its directors, officers or employees.

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Fiscal Council

We have a permanent fiscal council (Conselho Fiscal) in accordance with applicable provisions of the Brazilian Corporate Law, composed of up to five members.  As required by the Brazilian Corporate Law our fiscal council is independent of our management and external auditors.  The fiscal council’s responsibilities include, among others: (i) monitoring management’s activities and (ii) reviewing our annual report and financial statements.  The members and their respective alternates are elected by the shareholders at the annual general shareholder’s meeting.  Holders of preferred shares without voting rights and minority common shareholders are each entitled, as a class, to elect one member and his respective alternate to the fiscal council.  The Brazilian federal government has the right to appoint the majority of the members of the fiscal council and their alternates.  One of these members and his respective alternate are appointed by the Minister of Finance, representing the Brazilian Treasury.  The members of the fiscal council are elected at our annual general shareholders’ meeting for a one-year term and re-election is permitted.

The following table lists the current members of our fiscal council:

Name	Year of First Appointment
Paulo José dos Reis Souza	2012
César Acosta Rech	2008
Marisete Fátima Dadald Pereira	2011
Reginaldo Ferreira Alexandre	2013
Walter Luis Bernardes Albertoni	2013

The following table lists the alternate members of our fiscal council:

Name	Year of First Appointment
Paula Bicudo de Castro Magalhães	2015
Symone Christine de Santana Araújo	2015
Agnes Maria de Aragão da Costa	2015
Mário Cordeiro Filho	2013
Roberto Lamb	2013

Audit Committee

We have an Audit Committee that advises our board of directors, composed exclusively of members of our board of directors.

On June 17, 2005, our board of directors approved the appointment of our Audit Committee to satisfy the audit committee requirements of the Sarbanes-Oxley Act of 2002 and Rule 10A-3 under the Securities Exchange Act of 1934.

The Audit Committee is responsible for, among other matters:

·making recommendations to our board of directors with respect to the appointment, compensation and retention of our independent auditor;

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·assisting our board of directors with analysis of our financial statements and the effectiveness of our internal controls over financial reporting in consultation with internal and independent auditors;

·assisting in the resolution of conflicts between management and the independent auditor with respect to our financial statements;

·conducting an annual review of related party transactions involving interested members of our board of directors and executive officers and companies that employ any of these people, as well any other material transactions with related parties; and

·establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal control and auditing matters, including procedures for the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters.

The current members of our Audit Committee are Luiz Nelson Guedes de Carvalho, Luiz Augusto Fraga Navarro de Britto Filho and Roberto da Cunha Castello Branco. All members of our Audit Committee satisfy the requirements set forth in Rule 10A-3 under the Exchange Act.

Other Committees

Our board of directors has two additional advisory committees: the Comitê de Remuneração e Sucessão (Remuneration and Succession Committee), responsible for advising our board of directors with respect to the compensation of members of our senior management and with respect to Petrobras’s general compensation policies and mechanisms, among other matters, and the Comitê de Segurança, Meio Ambiente e Saúde (Health, Safety and Environmental Committee), responsible for advising our board of directors with respect to global policies related to the strategic management of health, safety and environmental issues, among other matters.

On December 23, 2014, our board of directors announced the formation of a special committee that serves as a reporting line for the internal investigations led by two independent law firms: U.S. firm Gibson, Dunn & Crutcher LLP and Brazilian firm Trench, Rossi e Watanabe Advogados (the “Special Committee”). These internal investigations are focused on collecting evidence regarding the nature, extent and impact of alleged illegal acts that may have been committed against Petrobras, as have been reported in testimony under plea bargain agreements provided to Brazilian courts, as well as to investigate related facts and circumstances that may have a significant impact on our business and results of operations.

This Special Committee acts independently, but it has a direct reporting line to our board of directors. It is responsible for: (i) the approval of independent law firms’ plan for the internal investigation; (ii) receiving and analyzing information produced by the independent law firms; (iii) ensuring that the independence of the investigations is not compromised; (iv) analyzing, approving and enabling the implementation of the recommendations made by the independent law firms; (v) communicating and/or authorizing communication between the independent law firms and the competent authorities, including regulators, regarding the investigation status, its results, as well as measures taken by us in connection with such investigations; (vi) preparing a final report about the results of the independent law firms investigations, as well as providing us with the Special Committee´s recommendations to improve our internal policies and procedures.

The Special Committee is composed of three members: two independent individuals from outside the company, a Brazilian and a non-Brazilian, with notable technical expertise, in addition to Petrobras’s Chief Governance, Risk and Compliance Officer.

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The following table sets forth certain information with respect to the members of the Special Committee:

Name	Date of Birth	Position
Ellen Gracie Northfleet	February 16, 1948	Member of the Special Committee
Andreas Pohlmann	January 24, 1958	Member of the Special Committee
João Adalberto Elek Junior	November 26, 1958	Member of the Special Committee

Ellen Gracie Northfleet—Chief Justice Northfleet has been a member of our Special Committee since December 2014.  She has served as Chief Justice of the Brazilian Supreme Court from 2006 to 2008 and was a Justice of the Brazilian Supreme Court from December 2000 to August 2011. Ms. Northfleet was also a Justice of the Regional Federal Court of Appeals -4^th Region  (Tribunal Regional Federal – 4ª Região) from 1989 to 2000 and a Federal Prosecutor (Procuradora da República) from 1973 to 1989.  Ms. Northfleet is recognized in Brazil and abroad for her expertise and experience with complex legal issues. Ms. Northfleet has an LL.B degree from the Universidade Federal do Rio Grande do Sul-UFRGS and a post-graduate degree in social anthropology from UFRGS as well.

                Andreas Pohlmann—Dr. Pohlmann has been a member of our Special Committee since December 2014 and a partner at Pohlmann & Company since February 2012.  Dr. Pohlmann has served as Chief Compliance Officer of Siemens AG from September 2007 to May 2010 and from May 2010 until November 2011 as a member of the executive board of Ferrostaal AG, responsible for compliance and administration.  Dr. Andreas Pohlmann was also the Chief Compliance Officer and member of the Executive Committee of SNC-Lavalin Group Inc. in Montreal, Canada, from 2013 to 2014. Dr. Andreas Pohlmann holds a law degree from Goethe University in Frankfurt and a PhD in law from Tuebingen University.

João Adalberto Elek Junior—Mr. Elek Junior has been a member of our Special Committee since January 2015. For biographical information regarding Mr. Elek Junior, see “—Executive Officers”.

Ombudsman

The Petrobras General Ombudsman’s Office has been an official part of our corporate structure since October 2005, when it became directly linked to the board of directors.  The General Ombudsman’s Office is the official channel for receiving and responding to denunciations and information regarding possible irregularities in accounting, internal controls and auditing.  The General Ombudsman’s Office reports directly to the Audit Committee and guarantees the anonymity of informants.

In December 2007, the board of directors approved the Policies and Directives of the Petrobras Ombudsman, which was an important step in aligning the General Ombudsman’s practices with those of the other ombudsmen office in the system, contributing to better corporate governance.  In April 2010, the board of directors approved a two-year renewable term for the Ombudsman Officer, during which he cannot be discretionarily dismissed by the management, ensuring its independence in performing his duties.

In May 2012, the Public Access to Information Law (Law No. 12,527/2011), which regulates the constitutional right for people to have access to public information became effective. This law states that all information produced or held in custody by the government and not classified as confidential must become accessible to all citizens.

The extension of this law encompasses public entities that are directly or indirectly controlled by the Brazilian federal government, which includes Petrobras.  In April 2012,  the General Ombudsman was appointed by our management as the authority responsible for implementing this law within Petrobras. In this respect, the General Ombudsman's Office ensures compliance with the rules on access to information by the public, monitors the implementation of this law and submits periodic reports to the board of directors, as well as makes recommendations and provides guidance to Petrobras’s business units with respect to the enforcement of the law.

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In May 2013, the Public Federal Employee Conflict of Interest Law (Law No. 12,813/2013) became effective. This law regulates the circumstances in which a conflict may arise between the public interest and the interests of certain current and past employees of the Brazilian federal government, which includes Petrobras, including people holding or that have held certain positions within the Brazilian federal government.  The law establishes subsequent restrictions on the activities performed by such people. It also provides mechanisms to avoid situations that could jeopardize the public interest, particularly with respect to insider trading and the existence of conflicting activities.

The General Ombudsman is also responsible for implementing this law within Petrobras, which includes tasks such as receiving and analyzing demands from our employees concerning the existence of conflict of interests, communicating to stakeholders the results of those analyses, performing preliminary reviews about the existence of potential conflicts of interest, verifying potential conflicts of interest before authorizing employees to engage in certain activities, as well as informing employees on how to prevent or avoid possible conflicts of interest.

Employees and Labor Relations

We attract and retain valuable employees by offering competitive compensation and benefits, merit-based promotions and a profit-sharing plan.

The table below shows our employee numbers for the last three years:

	As of December 31,
	2014	2013	2012
Petrobras employees:
Parent company	58,618	62,692	61,878
Subsidiaries	15,293	15,903	15,547
Abroad	6,997	7,516	7,640
Total Petrobras Group	80,908	86,111	85,065
Parent company by level:
High school	35,966	39,005	38,660
College	22,247	23,115	22,614
Maritime employees	405	572	604
Total parent company	58,618	62,692	61,878
Parent company by region:
Southeastern Brazil	41,207	43,309	42,186
Northeastern Brazil	12,818	14,651	15,022
Other locations	4,593	4,732	4,670
Total parent company	58,618	62,692	61,878

The table below sets forth the main expenses related to our employees for the last three years:   

	2014	2013	2012
	(U.S.$ million)
Salaries	8,001.4	8,184.1	7,989.4
Employee training	155.1	196.1	256.3
Profit-sharing distributions	444	520	524

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We maintain relations with 17 Brazilian oil workers’ unions and one federation. Approximately 45% of our employees are unionized, and since 1995 we have had no major labor stoppages. We negotiate collective bargaining agreements annually.  These agreements are composed of social clauses, which are valid for two years, and economic clauses, which are valid for one year. In 2014, we signed an amendment to the 2013 collective bargaining agreement, revising its economic clauses. Under this agreement, employees received a 6.51% cost of living increase, reflecting an adjustment for inflation in 2014, as measured by the Índice Nacional de Preços ao Consumidor Amplo, or IPCA, a real wage increase of 2.7%, and a one-time payment corresponding to 106% of (i) the sum of the employee’s minimum wage based on seniority and work regime (remuneração mínima por nível e regime) plus the employee’s bonus for length of employment (adicional por tempo de serviço), or (ii) R$7,688.00, whichever is higher.

Knowledge Transfer Initiatives

                We have developed knowledge management corporate practices, such as Petrobras’s Mentoring Program, Shadowing, Lessons Learned and Job Rotation and other initiatives in order to ensure the sharing and dissemination of knowledge within Petrobras through the implementation of several corporate policies. Currently, our efforts are focused on the inclusion of knowledge management in our management processes, as this is an important tool for the management of people, culture, projects and processes. In addition, we have been developing customized projects with Petrobras’s business segments to identify, preserve, share and apply relevant knowledge that may positively impact our results.

                Voluntary Separation Incentive Program - PIDV

                In January 2014, Petrobras launched a voluntary separation incentive program with the goal of contributing to the achievement of the performance targets set forth under our 2014-2018 Plan, including the improvement of our productivity.

                This voluntary separation incentive program has been developed along with knowledge management and managerial succession tools so that all knowledge is retained by Petrobras in this process, allowing a planned and systematic voluntary separation of the employees that enroll in this program. Voluntary separation of employees under this program must achieve the following results: (i) adjust our personnel to our 2014-2018 Plan, (ii)  achieve our interests in line with employees’ expectations, (iii) preserve existing knowledge within Petrobras and (iv) permit the development of leadership succession plans.

                The target group of this voluntary separation incentive program were 12,196 Petrobras employees over the age of 55, regardless of their position in Petrobras that would be eligible to retire under the Brazilian Social Security National Institute (INSS) rules until the end of incentive program enrollment period (March 31, 2014). Over 8,200 employees have taken advantage of Petrobras’s voluntary separation incentive program and were classified into different categories with retirement dates as far into the future as May 2017. In 2014, 4,936 employees retired under the program. The expected financial incentives to Petrobras’s system employees under this program amount to R$2.6 billion and Petrobras’s costs savings are expected to reach R$12.7 billion by 2018.  See Note 22.8 to our audited consolidated financial statements for more information about our voluntary separation incentive program.

Employees Internal Relocation Program – Mobiliza

                In 2013, Petrobras has launched an internal relocation program with a view to make compatible Petrobras’s human resources organizational needs with the interests of its employees by offering to Petrobras’s employees relocation opportunities in areas that will demand an increase in the number of employees in the following years. As such, by proper allocation of Petrobras’s current human resources within our organization, such program reduced the need for additional hiring in the short-term. In 2014, 629 employees were relocated under this program.

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                Pension and Health Care Plan

We sponsor a defined benefit pension plan, known as Petros, and a variable contribution pension plan, known as Petros-2, which together cover 96.80% of our employees.  The principal objective of our pension plans has been to supplement the social security pension benefits of our employees.  Employees that participate in the plans make mandatory monthly contributions. Our historical funding policy has been to make monthly contributions to the plans in the amounts determined by actuarial appraisals.  Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future.

The table below shows the benefits paid, contributions made, and outstanding pension and medical liabilities for 2014, 2013 and 2012:

	2014	2013	2012
	(U.S.$ million)
Total benefits paid – pension and medical plans	1,647	1,535	1,544
Total contributions – pension and medical plans(1)	812	825	871
Actuarial liabilities(2)	17,287	12,573	20,224

(1)Includes contributions by sponsors and employees.

(2)Unfunded pension and medical plans obligations.

As of August 9, 2002, the Petros Plan stopped admitting new participants and since 2003 we have been engaged in complex negotiations with representatives of the Brazilian Oil Worker’s National Union to address the deficits of the plan and develop a supplementary pension plan.  We agreed to pay R$5.8 billion, updated retroactively to December 31, 2006 by the consumer price index (IPCA) plus 6% per year, which will be paid in semi-annual installments until the payment of principal in 2028, as previously agreed during the renegotiation. We have also been subject to material legal proceedings in connection with the Petros Plan.  In August 2007, we approved new regulations for the Petros Plan that readjust benefits based on an inflation index rather than through salary readjustments proposed by the sponsors and retirement benefits readjustments proposed by the INSS.

In 2007, we implemented the Petros Plan 2, a variable contribution or mixed pension plan, for employees with no supplementary pension plan.  A portion of this plan has defined benefits characteristics including risk coverage for disability and death, a guaranty of a minimum benefit and a lifetime income, and the related actuarial commitments are recorded according to the projected credit unit method.  The portion of the plan with defined contribution characteristics, earmarked for forming a reserve for programmed retirement, is recognized in the results for the year as the contributions are made.  In 2014, contributions paid by Petrobras and its subsidiaries (sponsors) to the pension and medical plans amounted U.S.$648 million.

We maintain a health care benefit plan (AMS), which offers medical benefits and covers all employees (active and inactive) together with their dependents.  We manage the plan, with the employees contributing 26% of the total amount to cover principal risks and a portion of the costs relating to other types of coverage in accordance with participation tables defined by certain parameters, including salary levels.

Our commitment related to future benefits to plan participants is calculated on an annual basis by an independent actuary, based on the Projected Unit Credit method.  The health care plan is not funded or otherwise collateralized by assets.  Instead, we make benefit payments based on annual costs incurred by plan participants.

In addition, some of our consolidated subsidiaries have their own benefit plans.

                See Notes 4.16, 5.3 and 22 to our audited consolidated financial statements for more information about our Employee Benefits.

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Item 7.  Major Shareholders and Related Party Transactions

Major Shareholders

  Our capital stock is composed of common shares and preferred shares, all without par value.  On April 30, 2015, there were 1,576,715,022 outstanding common shares and 1,371,874,042 outstanding preferred shares represented by ADRs. The ratio of our common and preferred shares to ADRs is two shares to one ADR.  Except for the increase of our corporate capital in the past three fiscal years, in the amount of approximately R$52 million, due to the absorption of a portion of our tax reserves into our corporate capital, there has been no change in the past three fiscal years in the amount of our issued corporate capital, the number of our common and preferred shares or the voting rights of our common and preferred shares.  See Exhibit 1.1 for a copy of our Bylaws.

As of April 30, 2015, approximately 24.49% of our preferred shares and approximately 21.19% of our common shares were held of record in the United States directly or in the form of ADSs.

Under the Brazilian Corporate Law, as amended, the number of non-voting shares of our company may not exceed two-thirds of the total number of shares.  The Brazilian federal government is required by law to own at least a majority of our voting stock and currently owns 50.26% of our common shares, which are our only voting shares.  The Brazilian federal government does not have any different voting rights, but as long as it holds a majority of our voting stock, it will have the right to elect a majority of our directors, irrespective of the rights our minority shareholders may have to elect directors, set forth in our bylaws.

The following table sets forth information concerning the ownership of our common shares and preferred shares as of April 30, 2015, by the Brazilian federal government, certain public sector entities and our officers and directors as a group.

Shareholder	Common Shares	%	Preferred Shares	%	Total Shares	%
Brazilian federal government	3,740,470,811	50.26	0	0	3,740,470,811	28.67
BNDES	734,202,699	9.87	161,596,958	2.88	895,799,657	6.87
BNDES Participações S.A.—BNDESPar	11,700,392	0.16	1,341,348,766	23.94	1,353,049,158	10.37
Caixa de Previdência dos Funcionários do Banco do Brasil — PREVI	12,868,705	0.17	353,697,225	6.31	366,565,930	2.81
Other Brazilian public sector entities	2,315,596	0.03	667,914	0.01	2,983,510	0.02
All members of the board of directors, executive officers and members of our fiscal council (22 people in total)	5,148	0.00	73,894	0.00	79,042	0.00
Others	2,940,890,791	39.52	3,744,658,031	66.84	6,685,548,822	51.25
Total	7,442,454,142	100.00	5,602,042,788	100.00	13,044,496,930	100.00

Related Party Transactions

Board of Directors

Direct transactions with interested members of our board of directors or our executive officers are monitored by our board of directors, and must follow the conditions of an arms-length transaction and market practice guiding transactions with third parties. None of the members of our board of directors, our executive officers or close members of their families has had any direct interest in any transaction we effected that is or was unusual in its nature or conditions, or material to our business during the current or the three immediately preceding financial years or during any earlier financial year, and which remains in any way outstanding or unperformed.  In addition, we have not entered into any transaction with related parties which is or was unusual in its nature or conditions during the current or the three immediately preceding financial years, nor is any such transaction proposed, that is or would be material to our business.

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We have no outstanding loans or guaranties to the members of our board of directors, our executive officers or any close member of their families.

For a description of the shares beneficially held by the members of our board of directors and close members of their families, see Item 6. “Directors, Senior Management and Employees—Share Ownership.”

Brazilian Federal Government

We have engaged, and expect to continue to engage, in the ordinary course of business in numerous transactions with our controlling shareholder, the Brazilian federal government, and with banks and other entities under its control, including financing and banking, asset management and other transactions. The above-mentioned transactions amounted to a net liability of U.S.$16,851 million as of December 31, 2014. 

As of December 31, 2014, we had a receivable (the Petroleum and Alcohol Account) from the Brazilian federal government, our controlling shareholder, of U.S.$317 million.  For further information, see Note 19.2 to our audited consolidated financial statements.

In addition, according to Brazilian law, we are only permitted to invest in securities issued by the Brazilian federal government in Brazil.  This restriction does not apply to investment outside of Brazil.  As of December 31, 2014, the value of these marketable securities that has been directly acquired and held by us amounted to U.S.$4,339 million. 

Eletrobras’s Subsidiaries

In 2014, we recognized an allowance for impairment of U.S.$1,948 million, to cover certain trade receivables due by companies that operate in the isolated electricity sector in the Northern region of Brazil, which are mostly related to Eletrobras’s subsidiaries.  For further information, see Note 8.4 to our audited consolidated financial statements.

For additional information regarding our principal transactions with related parties, see Note 19 to our audited consolidated financial statements.

Item 8.  Financial Information

Consolidated Statements and Other Financial Information

See Item 18. “Financial Statements” and “Index to Financial Statements.”

Legal Proceedings

We are currently party to numerous legal proceedings relating to civil, administrative, tax, labor, environmental and corporate issues arising in the normal course of our business.  These proceedings involve claims for substantial amounts of money and other remedies.  Several individual disputes account for a significant part of the total amount of claims against us.  Our audited consolidated financial statements only include provisions for probable and reasonably estimable losses and expenses we may incur in connection with pending proceedings. Our material legal proceedings are described in Note 30 to our audited consolidated financial statements included in this annual report, and that description is incorporated by reference under this Item.

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Between December 8, 2014 and January 7, 2015, five putative securities class action complaints were filed against us in the United States District Court for the Southern District of New York (the “District Court”).  These actions were consolidated on February 17, 2015 (the “Consolidated Securities Litigation”).  The Court appointed a lead plaintiff, Universities Superannuation Scheme Limited (“USS”), on March 4, 2015.  USS filed a consolidated amended complaint on March 27, 2015 that purports to be on behalf of persons or entities (i) who purchased or acquired Petrobras securities on the New York Stock Exchange or pursuant to other U.S. domestic transactions between January 22, 2010 and March 19, 2015; (ii) who purchased certain debt securities issued by Petrobras’s finance subsidiaries in three public offerings between 2012 and 2014; and (iii) who purchased or otherwise acquired Petrobras securities on the Brazilian stock exchange during the period January 22, 2010 and March 19, 2015, who also purchased or otherwise acquired Petrobras securities traded on the NYSE or pursuant to other transactions in the U.S. during the same period.

The consolidated amended complaint alleges, among other things, that in Petrobras’s press releases, filings with the SEC and other communications, Petrobras made materially false and misleading statements and omissions regarding the value of its assets, the amounts of Petrobras’s expenses and net income, the effectiveness of Petrobras’s internal controls over financial reporting, and Petrobras’s anti-corruption policies due to alleged corruption purportedly in connection with certain contracts, which allegedly artificially inflated the market value of Petrobras’s securities.

On April 17, 2015, Petrobras, PGF and others filed a motion to dismiss.  The motion to dismiss is scheduled to be fully briefed by May 22, 2015.

In addition, to date four complaints have been filed by institutional investors in the District Court consisting of allegations similar to those in the consolidated amended complaint.  Those individual actions have been consolidated with the Consolidated Securities Litigation for pre-trial purposes.

The plaintiffs have not specified an amount of alleged damages in these actions.  Because these actions are in their early stages, Petrobras is unable to reasonably estimate the possible loss or range of losses, if any, arising from the litigations, and consequently we have made no provisions with respect to this litigation.  We have engaged a U.S. firm as legal counsel and intend to defend vigorously against the allegations made in the context of these actions.

SEC and DoJ Investigations

We have also received a subpoena from the SEC relating to the allegations concerning the Lava Jato investigation and are fully cooperating with the SEC, as well as with the DoJ, as to their investigation into this matter.  See Item 3. “Key Information—Risk Factors—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.”

Operação Lava Jato

                For further information regarding the Lava Jato investigation and its impacts on us, see “Explanatory Note” and Note 3 to our audited consolidated financial statements.

Internal Commissions

                We periodically establish ad hoc internal commissions (comissões internas de apuração) to evaluate our compliance with applicable law and regulations. The scope of each internal commission is established by our management. Upon the conclusion of each internal commission’s evaluation, its material findings are used to improve our compliance efforts.

                Recently, we had a number of internal commissions in place that were established in certain instances to evaluate past transactions mentioned in public press reports, including:

·A commission formed on August 13, 2013 to evaluate contracts of our International area with our service provider Construtora Norberto Odebrecht;

·A commission formed on March 24, 2014 to evaluate aspects of the Pasadena refinery acquisition;

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·A commission formed on April 11, 2014 to evaluate our contracts with our service provider EcoGlobal;

·A commission formed on April 14, 2014 to evaluate our contracts with our service provider Astro Marítima Navegação S.A.;

·Two commissions formed on April 25, 2014 to evaluate our contracts with service providers involved in our refining projects Refinaria Abreu e Lima (RNEST) and COMPERJ;

·A commission formed on October 4, 2014 to evaluate the process under which our supplier Sanko Sider was included in our registry of approved suppliers;

·A commission formed on November 5, 2014 to evaluate our contracts with our service provider Toyo Setal; and

·Commissions formed between March 9 and 27, 2015, which are currently evaluating our contracts with service providers involved in our refineries, terminal modernization projects and gas pipeline constructions.

                After analyzing documentation produced internally, the work of each of these commissions has been completed, with the finding in some instances that certain of Petrobras’s former and current employees did not comply with certain of our internal policies.  The findings of each of these commissions have been sent to applicable Brazilian authorities (including the Federal Public Prosecutor’s Office, Federal Police, CVM, CGDU and TCU) for their assessment.  These Brazilian authorities may take legal measures against the individuals involved, and until such time, we have relocated current employees who did not comply with certain of our internal policies to different positions within our company (and to the extent necessary, we may promote additional relocations and take other possible measures under Brazilian labor laws).  In this context, in order to improve our governance and internal control practices, we have also created a new department - Governance, Risk and Compliance Department, which is led by our new Chief Governance, Risk and Compliance Officer. See Item 6. “Directors, Senior Management and Employees—Directors and Senior Management—Executive Officers”.

On March 31, 2014, the internal commission we established to evaluate bribery allegations involving SBM Offshore confirmed that it found no internal evidence to support such allegations. Our findings and conclusions have also been sent to applicable Brazilian authorities to assist them in their ongoing investigations. On April 2, 2014, SBM Offshore also publicly confirmed that it has not found any evidence to support bribery allegations.

However, in late May 2014, SBM’s Offshore informed Petrobras that the Dutch Prosecutor’s Office had confirmed the existence of a transfer of funds from a bank account held by SBM Offshore’s commercial representative in Brazil to an unidentified Petrobras employee or former employee.  Petrobras sent this information to the CGDU, the Federal Public Prosecutor’s Office in Rio de Janeiro and the TCU.  We suspended SBM Offshore from participating in any of our procurement bids.

Independent from the findings of our internal commissions, between 2012 and 2014, and to mitigate potential risks of further non-compliance to our internal policies, Petrobras developed and implemented a number of measures aimed at improving corporate governance, our management of processes, risk management and control, including those related to fraud and corruption, such as our Corruption Prevention Program. See Item 16B. “Code of Ethics.”

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Dividend Distribution

The table below describes the amount of cash paid in the last three years to our shareholders, in the form of dividends and interest on capital.

	For the Year Ended December 31,
	2014	2013	2012
	(U.S.$ million)
Total amounts paid	3,918	2,656	3,272

                Our board of directors proposed no distribution of dividends in 2015 for profits accrued in the year ended December 31, 2014 because we reported a net loss for the fiscal year.  See Note 23.5 to our audited consolidated financial statements.

For information about dividend distribution requirements under Brazilian Corporate Law and our bylaws, see Item 10. “Additional Information—Memorandum and Articles of Incorporation—Payment of Dividends and Interest on Capital,” and Item 10. “—Mandatory Distribution.” 

Item 9.  The Offer and Listing

Trading Markets

Our shares and ADSs are listed or quoted on the following markets:

Common Shares	São Paulo Stock Exchange (BM&FBOVESPA)— São Paulo (ticker symbol PETR3); Mercado de Valores Latinoamericanos en Euros (Latibex)—Madrid, Spain (ticker symbol XPBR); Bolsa de Comercio de Buenos Aires (BCBA)—Buenos Aires, Argentina (ticker symbol APBR)
Preferred Shares	São Paulo Stock Exchange (BM&FBOVESPA)—São Paulo (ticker symbol PETR4); Mercado de Valores Latinoamericanos en Euros (Latibex)—Madrid, Spain (ticker symbol XPBRA); Bolsa de Comercio de Buenos Aires (BCBA)—Buenos Aires, Argentina (ticker symbol APBRA)
Common ADSs	New York Stock Exchange (NYSE)—New York (ticker symbol PBR)
Preferred ADSs	New York Stock Exchange (NYSE)—New York (ticker symbol PBRA)

Our common and preferred shares have been traded on the BM&FBOVESPA since 1968. Our ADSs representing two common shares and our ADSs representing two preferred shares have been traded on the New York Stock Exchange since 2000 and 2001, respectively. The Bank of New York Mellon serves as depositary for both the common and preferred ADSs.

Our common and preferred shares have been traded on the LATIBEX since 2002.  The LATIBEX is an electronic market created in 1999 by the Madrid Stock Exchange in order to enable trading of Latin American equity securities in euro denominations.

Our common and preferred shares have been traded on the Bolsa de Comerciode Buenos Aires (Buenos Aires Stock Exchange) since April 27, 2006.

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Share Price History

The following table sets forth information for our common sharesandpreferred shares, as reported by the BM&FBOVESPA, and for our common andpreferred ADSs, as reported by the New York Stock Exchange, for the periods indicated.  The ratio of our common and preferred shares to ADRs is two shares to one ADR. 

	Reais Per Common Share		Reais Per Preferred Share		U.S. Dollars Per Common ADS		U.S. Dollars Per Preferred ADS
	High	Low	High	Low	High	Low	High	Low
2009	45.10	27.45	39.79	23.06	53.01	23.01	46.91	19.48
2010	41.81	26.68	37.50	24.16	48.90	31.90	43.82	28.63
2011	33.65	19.80	29.08	18.21	41.57	21.50	36.22	19.85
2012	27.75	18.24	25.60	17.64	32.12	17.64	29.74	16.99
2013	16.57	15.57	17.63	16.78	14.20	13.34	15.05	14.33
First quarter	20.49	14.03	19.70	15.87	20.11	14.27	19.37	16.16
Second quarter	19.59	14.70	20.62	15.91	19.48	13.32	20.59	14.31
Third quarter	17.95	13.55	19.16	14.98	16.37	12.13	17.58	13.38
Fourth quarter	20.34	15.57	21.44	16.78	17.90	13.34	18.79	14.33
2014
First quarter	15.82	12.02	16.75	12.57	13.32	10.27	13.96	10.68
Second quarter	17.92	14.83	19.00	15.32	15.94	13.14	16.99	13.48
Third quarter	23.29	16.05	24.56	17.12	20.65	14.19	21.86	14.89
September 2014	23.29	17.25	24.56	18.09	20.65	14.19	21.86	14.89
Fourth quarter	20.75	8.52	22.13	9.18	17.27	6.26	18.44	6.66
October 2014	20.75	13.53	22.13	14.02	17.27	11.16	18.44	11.49
November 2014	14.25	11.94	14.85	12.45	11.32	9.33	11.69	9.64
December 2014	12.00	8.52	12.73	9.18	9.27	6.26	9.83	6.66
2015
First Quarter	9.95	8.04	10.25	8.18	7.65	5.01	7.97	5.10
January 2015	9.81	8.04	10.25	8.18	7.65	6.01	7.97	6.14
February 2015	9.95	8.57	10.12	8.66	7.29	6.23	7.44	6.31
March 2015	9.72	8.15	9.84	8.30	6.41	5.01	6.50	5.10
April 2015	14.70	10.08	13.33	10.21	9.99	6.35	8.91	6.41

BM&FBOVESPA

As of December 30, 2014, Petrobras’s common and preferred shares represented approximately 5.7% of the total market capitalization of the BM&FBOVESPA and Petrobras was the most actively traded company of the BM&FBOVESPA.  At December 30, 2014, the aggregate market capitalization of the 363 companies listed on the BM&FBOVESPA was approximately U.S.$845 billion and the ten largest companies represented approximately 50.7% of the total market capitalization of all listed companies.  All the outstanding shares of an exchange-listed company may trade on the BM&FBOVESPA, but in most cases, only a portion of the listed shares are actually available for trading by the public.  The remainder is held by small groups of controlling persons, by governmental entities or by one principal shareholder.

Trading directly on the BM&FBOVESPA by a holder not deemed to be a resident of Brazil for Brazilian tax and regulatory purposes (a non-Brazilian holder) is subject to certain limitations under Brazilian foreign investment legislation.  Non-Brazilian holders may only trade on the BM&FBOVESPA in accordance with the requirements of CMN Resolution No. 4,373 and Instruction CVM No. 560/2015.  CMN Resolution No. 4,373 requires that securities held by non-Brazilian holders be maintained in the custody of, or in deposit accounts with, financial institutions duly authorized by the CVM.

In addition, CVM Rule 560/2015 establishes limited situations where non-Brazilian holders are allowed to trade securities outside Brazilian stock exchanges or qualified over-the-counter markets, such as in transactions involving subscription, redemption, refund of shares and conversion of debentures into shares. 

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According to Brazilian regulations, the transfer of the ownership of investments from a non-Brazilian holder to another party through a private transaction is only allowed in limited situations, such as transfers resulting from transactions involving merger, split, amalgamation, corporate reorganizations, stock swaps, or a transfer resulting from bequest or inheritance. Such transfers are also permitted in situations where (i) the final beneficial owner of the transferred investment remains unchanged and (ii) the total amount of securities or financial assets owned, directly or indirectly, by all investors taking part in the transaction remains unchanged.  CVM may authorize trades or transfers in other situations upon request by the interested investor.  See Item 10. “Additional Information—Exchange Controls” for further information.

Item 10.   Additional Information

Memorandum and Articles of Incorporation

General

We are a publicly-traded company duly registered with the CVM under identification number 9512.  Article 3 of our bylaws establishes our corporate purposes as research, prospecting, extraction, processing, trade and transportation of crude oil from wells, shale and other rocks, of crude oil derivatives, of natural gas and other fluid hydrocarbons, as well as other related or similar activities, such as activities connected with energy, including research, development, production, transportation, distribution, sale and trade of all forms of energy, as well as other related or similar activities.  We may conduct outside Brazil, directly or through our subsidiaries, any of the activities within our corporate purpose.

Set forth below is certain information concerning our authorized and issued share capital and a brief summary of some significant provisions of our bylaws and Brazilian corporate law. This description does not purport to be complete and is qualified by reference to our bylaws (an English translation of which we have filed with the SEC) and to Brazilian corporate law.  See Exhibit 1.1 for a copy of our Bylaws.

Qualification of Directors

Law No. 12,431/2011, amended the Brazilian Corporate Law by eliminating the previous requirement that the members of a company’s board of directors must be shareholders of the company.  Members of our board of executive officers must be Brazilian nationals and reside in Brazil.  Our directors and executive officers are prevented from voting on any transaction involving companies in which they hold more than 10% of the total capital stock or of which they have held a management position in the period immediately prior to their taking office.  Under our bylaws, shareholders set the aggregate compensation payable to directors and executive officers.  The board of directors allocates the compensation among its members and the executive officers.

In addition, Law No. 12,353/2010 requires that public and mixed-capital companies, in which the Brazilian federal government holds a majority of the voting rights directly or indirectly, include as a member of the board of directors a representative elected by the company’s employees by means of a separate voting procedure.

Allocation of Net Income

At each annual general shareholders’ meeting, our board of directors is required to recommend how net income for the preceding fiscal year is to be allocated.  Brazilian Corporate Law defines net income as income after income taxes and social contribution taxes for a fiscal year, net of any accumulated losses from prior fiscal years and any amounts allocated to employees’ and management’s participation in company profits.  In accordance with Brazilian Corporate Law, the amounts available for dividend distribution or payment of interest on capital equals net income less any amounts allocated from such net income to the legal reserve.

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We are required to maintain a legal reserve, to which we must allocate 5% of net income for each fiscal year until the amount for such reserve equals 20% of our paid-in capital.  However, we are not required to make any allocations to our legal reserve in a fiscal year in which the legal reserve, when added to our other established capital reserves, exceeds 30% of our capital.  The legal reserve can only be used to offset losses or to increase our capital.

As long as we are able to make the minimum mandatory distribution described below, we must allocate an amount equivalent to 0.5% of subscribed and fully paid-in capital at year-end to a statutory reserve.  The reserve is used to fund the costs of research and technological development programs.  The accumulated balance of this reserve cannot exceed 5% of the subscribed and fully paid-in capital stock.

Brazilian Corporate Law also provides for three discretionary allocations of net income that are subject to approval by the shareholders at the annual general shareholders’ meeting, as follows:

·first, a percentage of net income may be allocated to a contingency reserve for anticipated losses that are deemed probable in future years.  Any amount so allocated in a prior year must be either reversed in the fiscal year in which the reasons justifying the reserve cease to exist, or written off in the event that the anticipated loss occurs;

·second, if the mandatory distributable amount exceeds the sum of realized net income in a given year, this excess may be allocated to an unrealized revenue reserve.  Brazilian Corporate Law defines realized net income as the amount of net income that exceeds the sum of the net positive result of equity adjustments and profits or revenues from operations whose financial results take place after the end of the next succeeding fiscal year; and

·third, a portion of our net income that exceeds the minimum mandatory distribution may be allocated to fund working capital needs and investment projects, as long as such allocation is based on a capital budget previously approved by our shareholders.  Capital budgets for more than one year must be reviewed at each annual shareholder meeting.

Mandatory Distribution

Under Brazilian Corporate Law, the bylaws of a Brazilian corporation such as ours may specify a minimum percentage of the amounts available for distribution by such corporation for each fiscal year that must be distributed to shareholders as dividends or interest on capital, also known as the mandatory distributable amount, which cannot be lower than 25% of the adjusted net income for the fiscal year.  Under our bylaws, the mandatory distributable amount has been fixed at an amount equal to not less than 25% of our adjusted net income, after deducting allocations to the legal reserve, tax incentives (if any), contingency reserve (if any), and adding reversed contingency reserve amounts from prior years (if any), as set forth in the Brazilian Corporate Law.  Furthermore, the net income that are not allocated to the reserves above, to fund working capital needs and investment projects as described above, or to the statutory reserve must be distributed to our shareholders as dividends or interest on capital.

As a Brazilian corporation with a class of non-voting shares and pursuant to our bylaws, to the extent that we declare dividends, holders of preferred shares are entitled to minimum annual non-cumulative preferential dividends equal to the higher of (i) 5% of their pro rata share of our paid-in capital, or (ii) 3% of the book value of their preferred shares.

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To the extent that we declare dividends on our common shares in any particular year in an amount that exceeds the minimum preferential dividends due to our preferred shares, holders of preferred shares would be entitled to an additional dividend amount per share, such that holders of preferred shares will receive the same additional dividend amount per share paid to holders of common shares. Holders of preferred shares participate equally with common shareholders in corporate capital increases obtained from the incorporation of reserves and profits.

The Brazilian Corporate Law, however, permits a publicly held company such as ours to suspend the mandatory distribution if the board of directors and the fiscal council report to the annual general shareholders’ meeting that the distribution would be inadvisable in view of the company’s financial condition.  In this case, the board of directors must file a justification for such suspension with the CVM.  Profits not distributed by virtue of the suspension mentioned above shall be allocated to a special reserve and, if not absorbed by subsequent losses, shall be distributed as soon as the financial condition of the company permits such payments.

Payment of Dividends and Interest on Capital

We are required by the Brazilian Corporate Law to hold an annual general shareholders’ meeting by the fourth month after the end of each fiscal year at which, among other things, the shareholders have to decide on the payment of an annual dividend.  The payment of annual dividends is based on the financial statements prepared for the relevant fiscal year.

Law No. 9,249/1995, as amended, provides for distribution of interest attributed to shareholders’ equity to shareholders as an alternative form of distribution.  Such interest is limited to the daily prorata variation of the TJLP interest rate, the Brazilian federal government’s long-term interest rate.

We may treat these payments as a deductible expense for corporate income tax and social contribution purposes, but the deduction cannot exceed the greater of:

·50% of net income (before taking into account such distribution and any deductions for income taxes and after taking into account any deductions for social contributions on net income) for the period in respect of which the payment is made; or

        ·     50% of retained earnings.

Any payment of interest on capital to holders of ADSs or common shares, whether or not they are Brazilian residents, is subject to Brazilian withholding tax at the rate of 15% or 25%.  The 25% rate applies if the beneficiary is resident in a tax haven.  See “—Taxation Relating to Our ADSs and Common and Preferred Shares—Brazilian Tax Considerations.”  The amount paid to shareholders as interest attributed to shareholders’ equity, net of any withholding tax, may be included as part of any mandatory distribution of dividends.  Under the Brazilian Corporate Law, we are required to distribute to shareholders an amount sufficient to ensure that the net amount received, after payment by us of applicable Brazilian withholding taxes in respect of the distribution of interest on capital, is at least equal to the mandatory dividend.

Under the Brazilian Corporate Law and our bylaws, dividends generally are required to be paid within 60 days following the date the dividend was declared, unless a shareholders’ resolution sets forth another date of payment, which, in either case, must occur prior to the end of the fiscal year in which the dividend was declared.  The amounts of dividends due to our shareholders are subject to financial charges at the SELIC rate from the end of each fiscal year through the date we actually pay such dividends.  Shareholders have a three-year period from the dividend payment date to claim dividends or interest payments with respect to their shares, after which the amount of the unclaimed dividends reverts to us.

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Our board of directors may distribute dividends or pay interest based on the profits reported in interim financial statements.  The amount of interim dividends distributed cannot exceed the amount of our capital reserves.

Shareholders’ Meetings

Our shareholders have the power, through voting at a general shareholders’ meeting, to decide on any matters related to our corporate purposes and to pass any resolutions they deem necessary for our protection and development.

Since 2012, we have convened our shareholders’ meetings by publishing a notice in the Diário Oficial do Estadodo Rio de Janeiro and Jornal Valor Econômico.  The notice must be published no fewer than three times, beginning at least 15 calendar days prior to the scheduled meeting date.  The notice must contain the meeting’s agenda and, in the case of a proposed amendment to the bylaws, an indication of the subject matter.  For ADS holders, we are required to provide notice to the ADS depositary at least 30 calendar days prior to a shareholders’ meeting, when practicable. Upon receipt of our shareholders’ meeting notice, the depositary must mail a notice, in a form of its choice, to the ADS holders.  This notice must contain i) the information from our notice of meeting sent to the ADS depositary; ii) a statement that owners of record, as of a specific record date, can instruct the depositary as to the exercise of their voting rights, subject to Brazilian law as well as our bylaws; and iii) a statement as to the manner in which these instructions can be given to the depositary.

The board of directors or, in some specific situations set forth in the Brazilian Corporate Law, the shareholders, call our general shareholders’ meetings.  A shareholder may be represented at a general shareholders’ meeting by an attorney-in-fact, so long as the attorney-in-fact was appointed within a year of the meeting.  The attorney-in-fact must be a shareholder, a member of our management, a lawyer or a financial institution.  The attorney-in-fact’s power of attorney must comply with certain formalities set forth by Brazilian law.

In order for a valid action to be taken at a shareholders’ meeting, shareholders representing at least one quarter of our issued and outstanding common shares must be present at the meeting.  However, in the case of a general meeting to amend our bylaws, shareholders representing at least two-thirds of our issued and outstanding common shares must participate in person.  If no such quorum is present, the board may call a second meeting giving at least eight calendar days’ notice prior to the scheduled meeting in accordance with the rules of publication described above.  The quorum requirements will not apply to the second meeting, subject to the voting requirements for certain matters described below.  Our shareholders may also register online to exercise their voting rights electronically in shareholders’ meetings.  In addition, our shareholders may also vote electronically in proxy contests (pedido público de procuração).  Electronic participation in shareholders’ meetings is not available to our ADS holders.  ADS holders may instruct the depositary in advance to vote on their behalf at the shareholders’ meetings, pursuant to depositary’s operational procedures and the deposit agreement.

Voting Rights

Pursuant to the Brazilian Corporate Law and our bylaws, each of our common shares carries the right to vote at a general meeting of shareholders.  The Brazilian federal government is required by law to own at least a majority of our voting stock.  Pursuant to Brazilian Corporate Law and our bylaws, our preferred shares do not confer voting rights.

Holders of common shares, voting at a general shareholders’ meeting, have the exclusive power to:

·amend our bylaws;

·approve any capital increase;

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·approve any capital reduction;

·elect or dismiss members of our board of directors and fiscal council, subject to the right of our preferred shareholders to elect or dismiss one member of our board of directors and to elect one member of our fiscal council;

·receive the yearly financial statements prepared by our management and accept or reject management’s financial statements, including the allocation of net income for payment of the mandatory dividend and allocation to the various reserve accounts;

·authorize the issuance of debentures, except for the issuance of non-convertible unsecured debentures, which may be approved by our board of directors;

·suspend the rights of a shareholder who has not fulfilled the obligations imposed by law or by our bylaws;

·accept or reject the valuation of assets contributed by a shareholder in consideration for issuance of capital stock;

·pass resolutions to approve corporate restructurings, such as mergers, spin-offs and transformation into another type of company;

·participate in a centralized group of companies;

·approve the disposal of the control of our subsidiaries;

·approve the disposal of convertible debentures issued by our subsidiaries and held by us;

·establish the compensation of our senior management;

·approve the cancellation of our registration as a publicly-traded company;

·decide on our dissolution or liquidation;

·waive the right to subscribe to shares or convertible debentures issued by our subsidiaries or affiliates; and

·choose a specialized company to work out the appraisal of our shares by economic value, in cases of the cancellation of our registry as a publicly-traded company or deviation from the standard rules of corporate governance defined by a stock exchange or an entity in charge of maintaining an organized over-the-counter market registered with the CVM, in order to comply with such corporate governance rules and with contracts that may be executed by us and such entities.

Except as otherwise provided by law, resolutions of a general shareholders’ meeting are passed by the majority of the outstanding common shares.  Abstentions are not taken into account.

The approval of holders of at least one-half of the issued and outstanding common shares is required for the following actions involving our company:

·reduction of the mandatory dividend distribution;

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·merger into another company or consolidation with another company, subject to the conditions set forth in the Brazilian Corporate Law;

·participation in a group of companies subject to the conditions set forth in the Brazilian Corporate Law;

·change of our corporate purpose, which must be preceded by an amendment in our bylaws by federal law as we are controlled by the government and our corporate purpose is established by law;

·cessation of the state of liquidation;

·spin-off of a portion of our company, subject to the conditions set forth in the Brazilian Corporate Law;

·transfer of all our shares to another company or receipt of shares of another company in order to make the company whose shares are transferred a wholly-owned subsidiary of such company, known as incorporação de ações; and

·approval of our liquidation.

Under Brazilian Corporate law, if a shareholder has a conflict of interest with the company in connection with any proposed transaction, the shareholder may not vote in any decision regarding such transaction.  For example, an interested shareholder may not vote to approve the valuation of assets contributed by that shareholder in exchange for capital stock or, when the shareholder is a member of senior management, to approve the management’s report on the company’s financial statements.  Any transaction approved with the vote of a shareholder having a conflict of interest may be annulled and such shareholder may be liable for any damages caused and be required to return to the company any gain it may have obtained as a result of the transaction.

According to the Brazilian Corporate Law, the following actions shall be submitted for approval by the outstanding adversely affected preferred shares before they are submitted for approval of at least half of the issued and outstanding common shares:

·creation of preferred shares or increase in the existing classes of preferred shares, without preserving the proportions to any other class of preferred shares, except as set forth in or authorized by the company’s bylaws;

·change in the preferences, privileges or redemption or amortization conditions of any class of preferred shares; and

·creation of a new class of preferred shares entitled to more favorable conditions than the existing classes.

Decisions on our transformation into another type of company require the unanimous approval of our shareholders, including the preferred shareholders, and an amendment of our bylaws by the federal law.

Under Brazilian Corporate Law, shareholders representing at least 10% of the company’s voting capital have the right to demand that a cumulative voting procedure be adopted to entitle each common share to as many votes as there are board members and to give each common share the right to vote cumulatively for only one candidate or to distribute its votes among several candidates.  Pursuant to regulations promulgated by the CVM, the 10% threshold requirement for the exercise of cumulative voting procedures may be reduced depending on the amount of capital stock of the company. For a company like Petrobras, the  threshold is 5%. Thus, shareholders representing 5% of our voting capital may demand the adoption of a cumulative voting procedure.

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Furthermore, minority common shareholders holding at least 10% of our voting capital also have the right to appoint or dismiss one member to or from our fiscal council.

Preferred shareholders holding, individually or as a group, 10% of our total capital have the right to appoint and/or dismiss one member to or from our board of directors.  Preferred shareholders have the right to separately appoint one member to our fiscal council.

In addition, pursuant to Law No. 12,353, our employees have the right to appoint or dismiss one member of our board of directors in accordance with a separate voting procedure.

Our bylaws provide that, independently from the exercise of the rights above granted to minority shareholders, through cumulative voting process, the Brazilian federal government always has the right to appoint the majority of our directors.

Preemptive Rights

Pursuant to the Brazilian Corporate Law, each of our shareholders has a general preemptive right to subscribe for shares or securities convertible into shares in any capital increase, in proportion to the number of shares held by them.  In the event of a capital increase that would maintain or increase the proportion of capital represented by the preferred shares, holders of preferred shares would have preemptive rights to subscribe to newly issued preferred shares only.  In the event of a capital increase that would reduce the proportion of capital represented by the preferred shares, holders of preferred shares would have preemptive rights to subscribe to any new preferred shares in proportion to the number of shares held by them, and to common shares only to the extent necessary to prevent dilution of their interests in our total capital.

A period of at least 30 days following the publication of notice of the issuance of new shares or securities convertible into shares is allowed for exercise of the right, and the right is negotiable.

In the event of a capital increase by means of the issuance of new shares, holders of ADSs, of common or preferred shares, would have, except under circumstances described above, preemptive rights to subscribe for any class of our newly issued shares.  However, holders of ADSs may not be able to exercise the preemptive rights relating to the preferred shares underlying their 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.  See Item 3. “Key Information—Risk Factors—Risks Relating to Our Equity and Debt Securities.”

Redemption and Rights of Withdrawal

Brazilian law provides that, under limited circumstances, shareholders have the right to withdraw their equity interest from the company and to receive payment for the portion of shareholder’s equity attributable to their equity interest.

This right of withdrawal may be exercised by the holders of the adversely affected common or preferred shares in the event that we decide:

·to create preferred shares or to increase the existing classes of preferred shares, without preserving the proportions to any other class of preferred shares, except as set forth in or authorized by our bylaws; or

·to change the preferences, privileges or redemption or amortization conditions of any class of preferred shares or to create a new class of preferred shares entitled to more favorable conditions than the existing classes.

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Holders of our common shares may exercise their right of withdrawal in the event we decide:

·to merge into another company or to consolidate with another company, subject to the conditions set forth in the Brazilian Corporate Law; or

·to participate in a centralized group of companies as defined under the Brazilian Corporate Law and subject to the conditions set forth therein.

The right of withdrawal may also be exercised by our dissenting shareholders in the event we decide:

·to reduce the mandatory distribution of dividends;

·to change our corporate purposes;

·to spin-off a portion of our company, subject to the conditions set forth in the Brazilian Corporate Law;

·to transfer all of our shares to another company or to receive shares of another company in order to make the company whose shares are transferred a wholly owned subsidiary of our company, known as incorporação de ações, subject to the conditions set forth in Brazilian Corporate Law; or

·to acquire control of another company at a price that exceeds the limits set forth in the Brazilian Corporate Law, subject to the conditions set forth in the Brazilian Corporate Law.

This right of withdrawal may also be exercised in the event that the entity resulting from a merger, incorporação de ações, as described above, or consolidation or spin-off of a listed company fails to become a listed company within 120 days of the shareholders’ meeting at which such decision was taken.

Any redemption of shares arising out of the exercise of such withdrawal rights would be made based on the book value per share, determined on the basis of the last balance sheet approved by our shareholders.  However, if a shareholders’ meeting giving rise to redemption rights occurred more than 60 days after the date of the last approved balance sheet, a shareholder would be entitled to demand that his or her shares be valued on the basis of a new balance sheet dated within 60 days of such shareholders’ meeting.  The right of withdrawal lapses 30 days after publication of the minutes of the shareholders’ meeting that approved the corporate actions described above.  We would be entitled to reconsider any action giving rise to withdrawal rights within ten days following the expiration of such rights if the withdrawal of shares of dissenting shareholders would jeopardize our financial stability.

Other Shareholders’ Rights

According to the Brazilian Corporate Law, neither a company’s bylaws nor actions taken at a general meeting of shareholders may deprive a shareholder of some specific rights, such as:

·the right to participate in the distribution of profits;

·the right to participate equally and ratably in any remaining residual assets in the event of liquidation of the company;

·the right to supervise the management of the corporate business as specified in the Brazilian Corporate Law;

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·the right to preemptive rights in the event of a subscription of shares, debentures convertible into shares or subscription bonuses (other than with respect to a public offering of such securities, as may be set out in the bylaws); and

·the right to withdraw from the company in the cases specified in the Brazilian Corporate Law.

Liquidation

In the event of a liquidation, holders of preferred shares are entitled to receive, prior to any distribution to holders of common shares, an amount equal to the paid-in capital with respect to the preferred shares.

Conversion Rights

According to our bylaws, our common shares are not convertible into preferred shares, nor are preferred shares convertible into common shares.

Liability of Our Shareholders for Further Capital Calls

Neither Brazilian law nor our bylaws provide for capital calls.  Our shareholders’ liability for capital calls is limited to the payment of the issue price of the shares subscribed or acquired.

Form and Transfer

Our shares are registered in book-entry form and we have hired Banco do Brasil to perform all the services of safe-keeping and transfer of shares.  To make the transfer, Banco do Brasil makes an entry in the register, debits the share account of the transferor and credits the share account of the transferee.

Our shareholders may choose, at their individual discretion, to hold their shares through the Companhia Brasileira de Liquidação e Custódia or CBLC.  Shares are added to the CBLC system through Brazilian institutions, which have clearing accounts with the CBLC.  Our shareholder registry indicates which shares are listed on the CBLC system.  Each participating shareholder is in turn registered in a registry of beneficial shareholders maintained by the CBLC and is treated in the same manner as our registered shareholders.

Dispute Resolution

Our bylaws provide for mandatory dispute resolution through arbitration, in accordance with the rules of the Câmara de Arbitragem do Mercado (Market Arbitration Chamber), with respect to any dispute regarding us, our shareholders, the officers, directors and fiscal council members and involving the provisions of the Brazilian Corporate Law, our bylaws, the rules of the CMN, the Central Bank of Brazil and the CVM or any other capital markets legislation, including the provisions of any agreement entered into by us with any stock exchange or over-the-counter entity registered with the CVM, relating to adoption of differentiated corporate governance practices.

However, decisions of the Brazilian federal government, as exercised through voting in any general shareholders’ meeting, are not subject to this arbitration proceeding, in accordance with Article 238 of the Brazilian Corporate Law.

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Self-Dealing Restrictions

Our controlling shareholder, the Brazilian federal government, and the members of our board of directors, board of executive officers and fiscal council are required, in accordance with our bylaws, to:

·refrain from dealing with our securities either in the one-month period prior to any fiscal year-end, up to the date when our financials are published, or in the period between any corporate decision to raise or reduce our stock capital, to distribute dividends or stock, and to issue any security, up to the date when the respective public releases are published; and

·communicate to us and to the stock exchange their periodical dealing plans with respect to our securities, if any, including any change or default in these plans.  If the communication is an investment or divestment plan, the frequency and planned quantities must be included.

Restrictions on Non-Brazilian Holders

Non-Brazilian holders face no legal restrictions on the ownership of our common or preferred shares or of ADSs based on our common or preferred shares, and are entitled to the rights and preferences of such common or preferred shares, as the case may be.

However, the ability to convert dividend payments and proceeds from the sale of common or preferred shares or preemptive rights into foreign currency and to remit such amounts outside Brazil is subject to restrictions under foreign investment legislation which generally requires, among other steps, the registration of the relevant investment with the Central Bank of Brazil.  Nonetheless, any non-Brazilian holder who registers with the CVM in accordance with CMN Resolution No. 4,373 may buy and sell securities directly on the BM&FBOVESPA.  Such non-Brazilian holders must appoint a local representative in Brazil who will be required, among other duties, to register and keep updated with the Central Bank of Brazil the record of all transactions of such investors on the BM&FBOVESPA.

In addition, Annex II to CMN Resolution No. 4,373 allows Brazilian companies to issue depositary receipts in foreign exchange markets.  We currently have an ADR program for our common and preferred shares duly registered with the CVM and the Central Bank of Brazil.  The proceeds from the sale of ADSs by holders outside Brazil are free of Brazilian foreign exchange controls.

Transfer of Control

According to Brazilian law and our bylaws, the Brazilian federal government is required to own at least the majority of our voting shares.  Therefore, any change in our control would require a change in the applicable legislation.

Disclosure of Shareholder Ownership  

Brazilian regulations require that any person or group of persons representing the same interest that has directly or indirectly acquired or sold an interest corresponding to 5% of the total number of shares of any type or class must disclose its share ownership or divestment to the CVM and the BM&FBOVESPA.  In addition, a statement containing the required information must be published in the newspapers.  Any subsequent increase or decrease by 5% or more in ownership of shares of any type or class must be similarly disclosed.

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Material Contracts

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, subject to a maximum production of five bnboe. The Assignment Agreement was entered into pursuant to specific provisions of Law No. 12,276. The draft of the Assignment Agreement was approved by our board of directors on September 1, 2010 and by the CNPE on September 1, 2010, following a negotiation between us and the Brazilian federal government based on independent experts reports obtained by us and the ANP according to a valuation procedure as required by Law No. 12,276. See Exhibit 2.78 for an English translation of the Assignment Agreement.

Basic Terms

Purpose.  Under the Assignment Agreement, we paid an initial contract price for the right to conduct activities of exploration and production of oil, natural gas and other fluid hydrocarbons in specified pre-salt areas, subject to a maximum production of five bnboe. Although the Assignment Agreement grants certain rights to us that are similar to those of a concession, the Assignment Agreement is a specific regime for exploration and production, not a concession under Brazilian law.

Area Covered.  The Assignment Agreement covers six firm blocks plus one contingent block, located in the pre-salt areas and identified in the Assignment Agreement. These blocks are located in the Santos Basin and have expected geological characteristics similar to the discoveries made elsewhere in the pre-salt area. On February 7, 2014, we returned to the Brazilian federal government the contingent block related to the Assignment Agreement because we have confirmed that the maximum volume initially provided for in the Assignment Agreement can be reached in the other six firm blocks (i.e., without the need of any contribution from the contingent block).

Supervision and Inspection.  The ANP has regulatory authority and inspection rights over our activities in the areas subject to the Assignment Agreement, as well as over our compliance with the Assignment Agreement.

Costs and Risks.  All our exploration, development and production activities under the Assignment Agreement will be conducted at our expense and at our risk.

Price

The initial contract price for our rights under the Assignment Agreement was R$74,807,616,407, which was equivalent to U.S.$42,533,327,500 as of September 1, 2010. As provided by Law No. 12,276, the contract price was determined by negotiation between us and the Brazilian federal government, based on the reports of independent experts obtained by us and by the ANP, which took into consideration a number of factors, including market conditions, current oil prices and industry costs.

We have used part of the proceeds of our sale of shares in our 2010 global offering for the payment of the initial contract price, including the use of Brazilian federal government bonds (Letras Financeiras do Tesouro, or LFTs) we received from the Brazilian federal government in such global offering. The LFTs were valued at the same price at which they were valued for purposes of the global offering.

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The Assignment Agreement sets forth the initial prices and volumes for each block, as follows:

	INITIAL EVALUATIONS
	Volume	Price	Value
	(millions of boe)	(U.S.$/boe)	(U.S.$)
Block 1 Florim	467	9.0094	4,207,389,800
Block 2 Franco	3,058	9.0400	27,644,320,000
Block 3 Guará South	319	7.9427	2,533,721,300
Block 4 Surrounding Iara	600	5.8157	3,489,420,000
Block 5 Tupi South	128	7.8531	1,005,196,800
Block 6 Tupi Northeast	428	8.5357	3,653,279,600
Block 7 (contingent block) Peroba	—	—	—
Initial Contract Price of the Assignment Agreement			42,533,327,500

Duration

The term of the Assignment Agreement is 40 years, which may be extended for an additional five years, upon our request, in cases of (i) force majeure, (ii) delay in obtaining applicable environmental licenses, provided that such delay is attributable only to the relevant environmental authority, (iii) suspension of the activities by determination of the ANP, or (iv) changes in the geological conditions forecast for each area. The extension will only apply to areas in which the ANP identifies the occurrence of one of the events specified above. The ANP will take into account the period of time of the delay occurred to determine the length of the extension, subject to the five-year limit indicated above. In addition, the duration of the Assignment Agreement is subject to the revision process.

Revision

The Assignment Agreement is subject to a revision process. We have notified the Brazilian federal government and the ANP ten months before the date for the declaration of commerciality of each area covered by the agreement, in order to initiate the arrangements for such revision process, which began immediately after the declaration of commerciality of each field in each of the blocks. The revision process, for all the areas subject to the Assignment Agreements, is currently ongoing and there is no formal or official date for its conclusion.

The conclusion of the revision process may result in the renegotiation of (i) the contract price, (ii) the maximum production volume of five bnbbl of oil equivalent, (iii) the contract duration, and (iv) the minimum levels of goods and services to be acquired from Brazilian providers.

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If the revised contract price is higher than the initial contract price, we may agree with the Brazilian federal government on one or more of the following payment options: (i) a payment to be made by us, in cash or LFTs, to the Brazilian federal government in an amount equal to the difference between the revised contract price (resulting from the revision process) and the initial contract price; or (ii) a reduction in the maximum production volume of five bnbbl of oil equivalent. If the revised contract price is lower than the initial contract price, then the Brazilian federal government will pay us in cash, LFTs, securities issued by us or through other means agreed between us, the difference between the revised contract price and the initial contract price. In either case, the difference between the revised contract price and the initial contract price in U.S. dollars will be converted into Brazilian reais, based on the average PTAX exchange rate for the purchase of U.S. dollars published by the Central Bank of Brazil for the 30 days preceding the revision of each area and will be adjusted by the interest rate of the Brazilian Special Clearance and Custody System (Sistema Especial de Liquidação e Custódia), or the SELIC rate, until the payment date. Payments must be made within three years of the completion of the revision process.

The revision process will be based on reports of independent experts to be engaged by us and by the ANP. Among other factors, the following will be considered in the revision process:

·Reference Date: for purposes of the economic analysis to occur during the revision process, it has been agreed with the Brazilian federal government that the Reference Date shall be the date of the Declaration of Commerciality of each block. This conclusion, however, is pending from a negotiation with the Brazilian federal government;

·Discount Rate: a discount rate of 8.83% per year;

·Oil Reference Price: will be equal to the average trading price of the month preceding the Reference Date of the revision process (Crude Light West Texas Intermediate — WTI), in U.S.$/barrel, as published by the New York Mercantile Exchange, the NYMEX, under the code “CL,” for the eighteenth futures contract in terms of maturity, minus the differential in relation to Brent crude oil. The Brent crude oil differential (the price of WTI minus the Brent price) shall be calculated using yearly averages of monthly projections as specified in the most recently published reports of the Pira Energy Group (available on their website for a fee) for the year following the revision, or, if not available, a comparable forecast published by an international entity renowned for its technical competence in the oil and natural gas industry. For each area under the Assignment Agreement, the calculation of the differential of the price of barrel of oil equivalent applicable to each area in relation to Brent crude oil shall be based on the most recent fluid characterization data available as of the revision date, and shall be conducted in accordance with the methodology specified in the ANP Ordinance No. 206/2000.

·Natural Gas Reference Price in U.S.$/MMBtu: the natural gas reference price equals the price in the reference market (PMR) minus installments in connection with transportation fees (TTr), processing fees (TP), transfer fees (TT) and sales expenses (DC), according to the following formula: PRGN = PMR - (TTr + TP + TT + DC), where:

·The price in the reference market (PMR) in U.S.$/MMBtu is the average sale price of domestic natural gas in the twelve months preceding the revision date, weighed per volume, consistent with our practices of firm commitments to the non-thermoelectric market in the states of Rio de Janeiro and São Paulo.

·Transportation fees (TTr) in U.S.$/MMBtu are contractual fees of gas pipelines used to transport natural gas between our processing plants and the delivery points, as follows: TTr = ∑ TTr (n), where TTr (n) equals the transportation fees of gas pipeline n.

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·The processing fees (TP) in U.S.$/MMBtu are based on the cost of processing pre-salt natural gas, in our Cabiúnas terminal in Macaé, State of Rio de Janeiro, taking into account the revenues from the commercialization of liquid hydrocarbons which will result from the processing of natural gas.

·The transfer fees (TT) in U.S.$/MMBtu are based on the cost of transferring natural gas from the pre-salt areas from our production units to the Cabiúnas terminal.

·Sales Expenses (DC) in U.S.$/MMBtu correspond to the costs incurred in the commercialization of natural gas, which include, among others, the preparation and management of natural gas commercialization contracts, logistics costs of supplying natural gas and invoicing costs.

·Calculations of the processing and transfer fees will be based on audited information we have available for similar projects involving processing and transfer of pre-salt natural gas. Calculations of sales expenses will be based on audited information we have available regarding natural gas commercialization.

·Tax: Applicable taxes will be the Brazilian taxes applicable to fields under the Assignment Agreement, in force at the revision period;

·Cost:

·For operations between the date of the execution of the Assignment Agreement and the revision date, the cost shall be the effective cost incurred by us, in U.S.$, separately for each area under the Assignment Agreement, provided they have been audited and are consistent with common market practices.

·Investments and operational costs, and additional future costs will be estimated according to best practices in the oil industry, taking into consideration the operational environment, and based on the market prices practiced for each good or service at the revision date.

·Lease and rent: in case lease and rent are applicable, they will be considered according to best practices in the oil industry, for production assets including, but not limited to, production units and underwater equipment. Lease and rent payments will be estimated based on daily lease rates of recent lease or rental contracts of Stationary Production Units that have an equivalent market value (CAPEX). Any taxes due pursuant to the remittance of lease and rent payments will be added to the lease and rent payments.

·Investment costs, operating costs and additional expenses will be calculated in U.S. dollars; and

·Exchange Rate: the exchange rate to be applied in the conversions from U.S. dollars to Brazilian reais will be the average PTAX exchange rate for the purchase of U.S. dollars (calculated by the Central Bank of Brazil) for the 30 days immediately preceding the payment.

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Phases

Our activities under the Assignment Agreement are divided into two phases:

·Exploration phase.  This phase comprises the appraisal for purposes of determining the commerciality of any discoveries of oil, natural gas and other fluid hydrocarbons. The exploration phase began upon the execution of the Assignment Agreement and ended with the declaration of commerciality of each respective reservoir discovered in each area covered by the Assignment Agreement.

·Production Phase.  The production phase for a particular discovery begins as of the date of the declaration of commerciality by us to the ANP, and it lasts until the termination of the Assignment Agreement. It comprises a development period, during which we will carry out activities pursuant to a development plan approved by the ANP. Following the development period, we may start production upon notice to the ANP.

Minimum Work Program

                During the exploration phase, which is now concluded, we were required to undertake a minimum work program, as specified in the Assignment Agreement as well as additional activities outside the scope of the minimum work program, that were approved by the ANP.  We accomplished the minimum work program in all blocks and performed additional activities in some blocks.
 

Reallocation of Volumes

After the conclusion of the Assignment Agreement revision process, the Brazilian federal government and we may negotiate the reallocation of the volume of oil and natural gas originally assigned for each block, observing the revised price per barrel of oil equivalent applicable to each area, in the following scenarios: (i) the relevant environmental authority does not grant a permanent license for the performance of oil and natural gas exploration and production activities in a certain block or field, or (ii) the production of the volume allotted for any block is not feasible under petroleum industry best practices due to the geological features of the reservoirs, observing the economic parameters established in the revision process (as discussed below).

Once reallocations are completed, the number of barrels of oil equivalent to be produced in the new block will equal the multiplication of (i) the number of barrels of oil equivalent that were reallocated from the original block to the new block and (ii) the value of the barrel of oil equivalent in the original block, to be divided by the value of the barrel of oil equivalent in the new block.

If it is not possible to reallocate all of the volumes of oil and natural gas not produced by us, the reallocation procedure will be performed in part, and the Brazilian federal government will pay us the amount resulting from the multiplication of the volume not subject to the reallocation by the value of the barrel in the block to which the reallocation has been made.  This dollar amount will be converted to reais using the average PTAX exchange rate for the purchase of U.S. dollars for the 30 days preceding the date of the reallocation process of such block, and adjusted by the SELIC rate during the period between the date of the reallocation process of such block and the date of payment by the Brazilian federal government.

If it is determined that it is not possible to reallocate any volumes of oil, natural gas and other hydrocarbons fluids as described above, the Brazilian federal government will reimburse us for an amount equivalent to total volume of barrels of oil equivalent that was not produced multiplied by the dollar price of barrel of oil equivalent applicable to the relevant block, converted in reais using the average PTAX exchange rate for the purchase of U.S. dollars for the 30 days preceding the date of the reallocation process, and adjusted by the SELIC rate from the date of the reallocation process of such block to the date of payment by the Brazilian federal government.

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The manner and terms of payment of the reimbursement in either case will be negotiated by us and the Brazilian federal government. Payments will be made no later than three years after the conclusion of the reallocation process.

Unitization

A reservoir covered by a block assigned to us in the Assignment Agreement may extend to adjacent areas outside such block. In such case, we must notify the ANP immediately after identifying the extension and we will be prevented from performing the exploration and production activities within such block, until we have negotiated an unitization agreement with the third-party concessionaire or contractor under a different exploration and production regime who has rights over such adjacent areas, unless otherwise authorized by the ANP.  The ANP will inform such third-party that we should negotiate an “Unitization Agreement.” If the adjacent area is not licensed, the Brazilian federal government, represented by PPSA or by ANP, shall negotiate with us.

If the parties are unable to reach an agreement within a deadline established by the ANP, the agency will determine the terms and obligations related to such unitization, on the basis of an expert report, and will also notify us and the third-party or the Brazilian federal government representative, as applicable, of such determination. Until the unitization agreement is approved by the ANP, operations for the development and production of such reservoir must remain suspended, unless otherwise authorized by the ANP. Our refusal to execute the unitization agreement will result in the return to the Brazilian federal government of the area subject to the unitization process.

Extensions to adjacent areas were identified and notified to the ANP in three of the six blocks of the Assignment Agreement. The ANP authorized us to continue our exploratory activities and oriented to start negotiating the necessary unitization agreements with third-party concessionaires.  These negotiation are being conducted for all three blocks, with no impact on the development of these projects.

Environmental

We are required to preserve the environment and protect the ecosystem in the area subject to the Assignment Agreement and to avoid harming local fauna, flora and natural resources. We will be liable for damages to the environment resulting from our operations, including costs related to any remediation measures.

Brazilian Content

The Assignment Agreement requires us to purchase a minimum proportion of goods and services from Brazilian providers and to extend equal treatment to such providers to compete with foreign companies. The minimum Brazilian content requirement is included in the Assignment Agreement and specifies certain equipment, goods and services, as well as different levels of required content, in accordance with the different phases and periods of activities under the Assignment Agreement. The minimum Brazilian content requirement is 37% for the exploration phase. For the development period, it is (i) 55% for the development periods beginning production by 2016, (ii) 58% for the development periods beginning production between 2017 and 2019, and (iii) 65% for the development periods beginning production from 2020. Despite the minimum percentages set forth for each development period timeframes, the average global percentage of Brazilian content in the development period shall be at least 65%. If we fail to comply with the Brazilian content obligations, we may be subject to fines imposed by the ANP. The Assignment Agreement allows the ANP to grant waivers from the local content requirements, in cases where any of the Assignment Agreement area operational needs (in terms of technology, pricing and timing) cannot be met by local suppliers.

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Royalties and Expenses with Research and Development

Once we begin commercial production in each field, we will be required to pay monthly royalties of 10% of the oil and natural gas production. We are also required to invest 0.5% of our yearly gross revenues from oil, natural gas and other fluid hydrocarbons production under the Assignment Agreement in research and development activities related to energy and environmental issues being conducted in universities and national research and technical development institutions, public or private, previously registered with the ANP for this purpose.

Miscellaneous Provisions

·We shall not assign our rights under the Assignment Agreement.

·The Assignment Agreement shall terminate upon (i) the production of the maximum volume of barrels of oil equivalent as specified in the Assignment Agreement, (ii) the expiration of the term, or (iii) upon the request of the ANP, if we fail to observe the cure period established by the ANP in connection with the breach of an obligation that proves relevant for the continuation of operations in each block. Such cure period may not be less than 90 days, except in cases of extreme emergency.

·The Brazilian federal government and we will only be excused from the performance of the activities set forth in the Assignment Agreement in cases of force majeure, which include, among others, delays in the obtaining an environmental license, provided that such delay is attributable only to the relevant environmental authority.

·The Assignment Agreement is governed by Brazilian law.

·The Brazilian federal government and we will use our best efforts to settle any disputes amicably. If we are unable to do so, we may submit such dispute for arbitral review by the Brazilian Federal Attorney’s Office (Advocacia-Geral da União Federal), which may rely on independent experts to address technical matters, or initiate a legal proceeding at the Federal Court located in Brasília, Brazil.

Additional Production in the Assignment Agreement Areas

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.  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. ANP estimates indicate that these four areas may contain additional volumes amounting to between 9.8 bnboe and 15.2 bnboe.

Under the terms of CNPE’s approval, Petrobras must share with the Brazilian federal government “profit oil” in exchange for the right to produce these surplus volumes available in the designated Assignment Agreement areas. The Brazilian federal government’s share of profit oil will be: (i) 51.37% in Búzios, (ii) 50.60% in Entorno de Iara, (iii) 51.20% in Florim and (iv) 51.48% in Nordeste de Tupi, considering a U.S.$105.00 price per barrel of crude oil and the average production of 11,000 bbl/d per active production well.  CNPE’s approval also contemplated Brazilian content requirements.

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The next steps with respect to this CNPE decision involve the negotiation of the terms of different production sharing agreements with the MME, PPSA and the ANP.  However, In November 2014, the TCU determined that the execution of these production sharing agreements must be negotiated only after the conclusion of the revision process of the Assignment Agreement.  We have not initiated any negotiations and have no estimate for when these production sharing agreements will be executed.  The production sharing agreement for each these four areas will have a term of 35 years.

Production Sharing Agreement (Contrato de Partilha de Produção)

On December 2, 2013, following a public auction held on October 21, 2013, a consortium formed by us (with a 40% interest), Shell Brasil Petróleo Ltda. (with a 20% interest), Total E&P do Brasil Ltda. (with a 20% interest), CNODC Brasil Petróleo e Gás Ltda. (with a 10% interest) and CNOOC Petroleum Brasil Ltda. (with a 10% interest) (the “Libra Consortium”), entered into a production sharing agreement with the Brazilian federal government, ANP and PPSA (the “Production Sharing Agreement”). Under the agreement, the Libra Consortium was awarded the rights and obligations to operate and explore a strategic pre-salt area known as Libra block, located in the ultra-deep waters of the Santos Basin. This was the first oil and gas production-sharing agreement signed in Brazil under Law 12,351/2010. For further information about Law 12,351/2010, see Item 4.“Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Production-Sharing Contract Regime for Unlicensed Pre-Salt and Potentially Strategic Areas”. See also Exhibit 2.79 for an English translation of the Production Sharing Agreement.

Basic Terms

                Purpose. The purpose of the Production Sharing Agreement is to execute and manage the exploration and production rights over oil and gas reserves in the Libra block. In accordance with Law No. 12,351/2010, we will be the exclusive operator of exploration and production activities in the Libra block. The Libra Consortium paid R$15 billion (U.S.$6.6 billion) to the Brazilian federal government as a signing bonus for the execution of the Production Sharing Agreement. Under the terms of the Production Sharing Agreement, upon the declaration of commerciality of the Libra block, the Libra Consortium will recover in oil, any royalties expenses, as well as the investments made and recoverable as “cost oil”, and share with the Brazilian federal government “profit oil” produced in exchange for the right to explore and produce oil and gas in the Libra block. The government average share of profit oil will be 41.625%, varying with the price of the barrel of oil and the productivity of the wells.

Area Covered. The Libra block encompasses a pre-salt areacovering approximately 1,547.76 km² or 0.4 million acres.

Estimated Recoverable Volume. The Libra block has an estimated recoverable volume of between 8 and 12 bnboe.

                Operating Committee. The Libra Consortium is managed by an Operating Committee in which Petrobras, Shell, Total, CNODC, CNOOC and PPSA all participate, where PPSA represents the interests of the Brazilian federal government. The PPSA will not invest in the Libra block, but it holds 50% of the Operating Committee voting rights and also has a casting vote and veto powers, as defined in the Production Sharing Agreement.

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Risks, Costs and Compensation.  All exploration, development and production activities under the Production Sharing Agreement will be conducted at the expense and risk of the members of the Libra Consortium. For commercial discoveries of oil or gas in the Libra block, the Libra Consortium will be entitled to recover, on a monthly basis, (i) a portion of the production of oil and gas in the Libra block corresponding to its royalty expenses and (ii) the “cost oil” corresponding to costs incurred (which is the amount associated with the capital and operating costs of the Libra Consortium’s exploration and production activities), up to a limit of 50% of gross production in the first two years (which may be extended if any prior costs have not been fully recovered within two years of their actual incurrence) and 30% of gross production in the following years, subject to the conditions, proportions and terms set forth on the Production Sharing Agreement.  In addition, for each commercial discovery, the Libra Consortium is entitled to receive, on a monthly basis, its share of the “profit oil” as defined under the Production Sharing Agreement.

Duration

The term of the Production Sharing Agreement is 35 years, which is not subject to renewal.

Phases

Our activities under the Production Sharing Agreement are divided into two phases:

Exploration phase.  This phase comprises appraisal activities for purposes of determining the commerciality of any discoveries of oil and natural gas. The exploration phase began upon the execution of the Production Sharing Agreement and will end for each discovery upon the declaration of commerciality. We will have four years (which may be extended upon ANP’s prior approval, according to the terms and conditions set forth in the Production Sharing Agreement) to comply with the minimum work program and other ANP-approved activities provided for in the Production Sharing Agreement.

Production Phase.  The production phase for each particular discovery begins as of the date of the declaration of commerciality by Libra Consortium to the ANP, and lasts until the termination of the Production Sharing Agreement. It comprises a development period, during which we will carry out activities pursuant to a development plan approved by the ANP. We will have a period of five years, counted from the date of delivery of the declaration of commerciality, to begin production from the Libra block.

Minimum Work Program

During the exploration phase, we are required to undertake a minimum work program, as specified in the Production Sharing Agreement, which includes 3D seismic acquisition for the whole block, two exploratory wells and one extended well test. We may perform other activities outside the scope of the minimum work program, provided that such activities are approved by the ANP.

If the Libra Consortium fails to fulfill the minimum work program, ANP will be able to enforce the financial guaranties provided by the Libra Consortium, but such enforcement would not preclude ANP's right to apply other reasonable remedies.

Unitization

A reservoir covered by a block assigned to us in the Production Sharing Agreement may extend to adjacent areas outside such block. In such case, we must notify the ANP immediately after identifying the extension and we will be prevented from performing development and production activities within such block, until we have negotiated an unitization agreement with the third-party concessionaire or contractor who has rights over such adjacent areas, unless otherwise authorized by the ANP.  The ANP will inform such third-party that we should negotiate an “Unitization Agreement.” If the adjacent area is not licensed, the Brazilian federal government, represented by PPSA or by ANP, shall negotiate with us.

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If the parties are unable to reach an agreement within a deadline established by the ANP, the agency will determine the terms and obligations related to such unitization, on the basis of an expert report, and will also notify us and the third-party or the Brazilian federal government representative, as applicable, of such determination. Until the unitization agreement is approved by the ANP, operations for the development and production of such reservoir must remain suspended, unless otherwise authorized by the ANP. Our refusal to execute the unitization agreement will result in the termination of the Production Sharing Agreement.

Environmental

                We are required to preserve the environment and protect the ecosystem in the area subject to the Production Sharing Agreement and to avoid harming local fauna, flora and natural resources. We will be liable for damages to the environment resulting from our operations, including costs related to any remediation measures.

Brazilian Content

The Production Sharing Agreement requires us to purchase a minimum proportion of goods and services from Brazilian providers and to extend equal treatment to such providers to compete with foreign companies. The minimum Brazilian content requirement is included in the Production Sharing Agreement and specifies certain equipment, goods and services, as well as different levels of required content, in accordance with the different phases and periods of activities under the Production Sharing Agreement. The minimum Brazilian content requirement is 37% for the exploration phase. For the development period, it is (i) 55% for modules beginning first oil through 2021 and (ii) 59% for modules beginning production from 2022. If we fail to comply with the Brazilian content obligations, we may be subject to fines imposed by the ANP. The Production Sharing Agreement allows the ANP to grant waivers from the local content requirements, in cases where any of the Libra Consortium’s operational needs (in terms of technology, pricing and timing) cannot be met by local suppliers.

Royalties and Expenses with Research and Development

Once we begin commercial production in each field, the Libra Consortium will be required to pay monthly royalties of 15% of the oil and natural gas production, to be recovered from a portion of the production of oil and gas in the Libra block. The Libra Consortium will also be required to invest 1.0% its yearly gross revenues from oil and natural gas production under the Production Sharing Agreement in research and development activities related to the oil, gas and biofuel sectors.

Miscellaneous Provisions

·We can assign our rights and obligations under the Production Sharing Agreement to the extent that such assigned rights and obligations correspond only to those in excess of our 30% minimum interest established by CNPE. If any proposed assignment is requested, ANP shall issue an opinion to MME within 90 (ninety) days, and MME shall take a decision within 60 (sixty) days after the ANP opinion is received.

·All members of the Libra Consortium have a right of first refusal with respect to an eventual assignment of rights and obligations to be made by any other member of the Libra Consortium.

·The Production Sharing Agreement shall be terminated in the following circumstances: (i) the expiration of its term; (ii) if the minimum work program has not been completed by the end of the Exploration Phase; (iii) if there has not been any commercial discovery by the end of the Exploration Phase; (iv) if the Libra Consortium exercises its withdrawal rights during the Exploration Phase; (v)  if the Libra Consortium fails to execute a production individualization agreement upon ANP’s instruction (which termination may be complete or partial) and (vi) any other basis described in the Production Sharing Agreement.

·The Production Sharing Agreement is governed by Brazilian law.

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For information concerning our other material contracts, see Item 4. “Information on the Company” and Item 5. “Operating and Financial Review and Prospects.”

Exchange Controls

There are no restrictions on ownership of the common or preferred shares by individuals or legal entities domiciled outside Brazil.

The right to convert dividend payments and proceeds from the sale of shares into foreign currency and to remit such amounts outside Brazil may be subject to restrictions under foreign investment legislation, which generally requires, among other things, that the relevant investments be registered with the Central Bank of Brazil.  If any restrictions are imposed on the remittance of foreign capital abroad, they could hinder or prevent Companhia Brasileira deliquidação e Custódia, or CBLC, as custodian for the common and preferred shares represented by the ADSs, or registered holders who have exchanged ADSs for common shares or preferred shares, from converting dividends, distributions or the proceeds from any sale of such common shares or preferred shares, as the case may be, into U.S. dollars and remitting the U.S. dollars abroad.

Foreign investors may generally register their investment under Law No. 4,131/1962 (foreign direct investment) or CMN Resolution No. 4,373 (portfolio investments in regulated market, such as stock exchanges). Registration under CMN Resolution No. 4,373 affords a more favorable tax treatment to foreign investors who are not residents of tax havens, as defined by Brazilian tax laws. See “—Taxation Relating to Our ADSs and Common and Preferred Shares—Brazilian Tax Considerations.”

Under CMN Resolution No. 4,373, foreign investors may invest in almost all financial assets and engage in almost all transactions available in the Brazilian financial and capital markets, provided that certain requirements are fulfilled.  In accordance with CMN Resolution No. 4,373, the definition of foreign investor includes individuals, legal entities, mutual funds and other collective investment entities, domiciled or headquartered abroad.

Under CMN Resolution No. 4,373, a foreign investor must:

·appoint at least one representative in Brazil, with powers to perform actions relating to its investment;

·register as a foreign investor with the CVM;

·appoint at least one authorized custodian in Brazil for its investments; and

·register all of its portfolio investments in Brazil, through its representative, with the Central Bank of Brazil.

Securities and other financial assets held by CMN Resolution No. 4,373 investors must be registered or maintained in deposit accounts or under the custody of an entity duly licensed by the Central Bank of Brazil or the CVM.  In addition, any transfer of securities held under CMN Resolution No. 4,373 and Instruction CVM No. 560/2015 must be carried out in the stock exchanges or through organized over-the-counter markets licensed by the CVM, except for transfers resulting from transactions involving merger, split, amalgamation, corporate reorganizations, stock swaps, or a transfer resulting from bequest or inheritance.

Annex II of CMN Resolution No. 4,373 provides for the issuance of depositary receipts in foreign markets with respect to shares of Brazilian issuers.  The depositary of the ADSs has obtained from the Central Bank of Brazil an electronic certificate of registration with respect to our existing ADR program.  Pursuant to the registration, the custodian and the depositary will be able to convert dividends and other distributions with respect to the relevant shares represented by ADSs into foreign currency and to remit the proceeds outside Brazil. 

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In the event that a holder of ADSs exchanges such ADSs for the underlying common or preferred shares, the holder will be required to obtain registration as a foreign investor in Brazil pursuant to CMN Resolution No. 4,373 (Annex I), by appointing a local representative and obtaining a certificate of registration from the Central Bank of Brazil.  Failure to take these measures may subject the holder to the inability of converting the proceeds from the disposition of, or distributions with respect to, the relevant shares, into foreign currency and to remit proceeds outside of Brazil.  Additionally, the holder may be subjected to a less favorable Brazilian tax treatment than a holder of ADSs.  In addition, if the foreign investor resides in a “tax haven” jurisdiction, the investor will be also subject to less favorable tax treatment.  See Item 3. “Key Information—Risk Factors—Risks Relating to Our Equity and Debt Securities” and “—Taxation Relating to Our ADSs and Common and Preferred Shares—Brazilian Tax Considerations.”

Taxation Relating to Our ADSs and Common and Preferred Shares

The following summary contains a description of material Brazilian and U.S. federal income tax considerations that may be relevant to the purchase, ownership and disposition of preferred or common shares or ADSs by a holder.  This summary does not describe any tax consequences arising under the laws of any state, locality or taxing jurisdiction other than Brazil and the United States.

This summary is based upon the tax laws of Brazil and the United States as in effect on the date of this annual report, which are subject to change (possibly with retroactive effect).  This summary is also based upon therepresentations of the depositary and on the assumption that the obligations in the deposit agreement and any related documents will be performed in accordance with their respective terms.

This description is not a comprehensive description of the tax considerations that may be relevant to any particular investor, including tax considerations that arise from rules that are generally applicable to all taxpayers or to certain classes of investors or rules that investors are generally assumed to know.  Prospective purchasers of common or preferred shares or ADSs should consult their own tax advisors as to the tax consequences of the acquisition, ownership and disposition of common or preferred shares or ADSs.

There is no income tax treaty between the United States and Brazil. In recent years, the tax authorities of Brazil and the United States have held discussions that may culminate in such a treaty.  We cannot predict, however, whether or when a treaty will enter into force or how it will affect the U.S. Holders of common or preferred shares or ADSs.

Brazilian Tax Considerations

General

The following discussion summarizes the material Brazilian tax consequences of the acquisition, ownership and disposition of preferred or common shares or ADSs, as the case may be, by a holder that is not deemed to be domiciled in Brazil for purposes of Brazilian taxation, also called a non-Brazilian holder.

Under Brazilian law, investors (non-Brazilian holders) may invest in the preferred or common shares under CMN Resolution No. 4,373 or under Law No. 4,131/1962.  The rules of CMN Resolution No. 4,373 allow foreign investors to invest in almost all instruments and to engage in almost all transactions available in the Brazilian financial and capital markets, provided that certain requirements are met. In accordance with CMN Resolution No. 4,373, the definition of foreign investor includes individuals, legal entities, mutual funds and other collective investment entities, domiciled or headquartered abroad.

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Pursuant to this rule, foreign investors must: (i) appoint at least one representative in Brazil with powers to perform actions relating to their foreign investment (such as registration and keeping updated records of all transactions with the Central Bank of Brazil); (ii) complete the appropriate foreign investor registration form; (iii) register as a foreign investor with the CVM; and (iv) register the foreign investment with the Central Bank of Brazil.

Securities and other financial assets held by foreign investors pursuant to CMN Resolution No. 4,373 must be registered or maintained in deposit accounts or under the custody of an entity duly licensed by the CVM. In addition, securities trading is restricted to transactions carried out in the stock exchanges or organized over-the-counter markets authorized by the CVM.

Taxation of Dividends

Generally speaking, dividends paid by us, including stock dividends and other dividends paid in property to the depositary in respect of the ADSs, or to a non-Brazilian holder in respect of the preferred or common shares, are not subject to withholding income tax in Brazil, to the extent that such amounts are related to profits generated as of January 1, 1996.

We must pay to our shareholders (including non-Brazilian holders of common or preferred shares or ADSs) interest on the amount of dividends payable to them, at the SELIC rate, from the end of each fiscal year through the date of effective payment of those dividends. These interest payments are considered fixed-yield income and are subject to withholding income tax at varying rates depending on the length of period of interest accrual. The tax rate varies from 15%, in case of interest accrued for a period greater than 720 days, 17.5% in case of interest accrued for a period between 361 and 720 days, 20% in case of interest accrued for a period between 181 and 360 days, and to 22.5%, in case of interest accrued for a period up to 180 days. However, the withholding income tax is imposed at the rate of 15% in the case of a non-Brazilian holder of ADSs or common or preferred shares investing under CMN Resolution No. 4,373 who is not resident or domiciled in a country or other jurisdiction that does not impose income tax or imposes it at a maximum income tax rate lower than 17% (a Low or Nil Tax Jurisdiction) or, based on the position of the Brazilian tax authorities, a country or other jurisdiction where the local legislation does not allow access to information related to the shareholding composition of legal entities, to their ownership or to the identity of the effective beneficiary of the income attributed to shareholders (the Non-Transparency Rule).  See “—Clarifications on Non-Brazilian Holders Resident or Domiciled in a Low or Nil Tax Jurisdiction.”

Taxation on Interest on Capital

Any payment of interest on capital to holders of ADSs or preferred or common shares, whether or not they are Brazilian residents, is subject to Brazilian withholding income tax at the rate of 15% at the time we record such liability, whether or not the effective payment is made at that time. See “—Memorandum and Articles of Incorporation—Payment of Dividends and Interest on Capital.” In the case of non-Brazilian residents that are resident in a Low or Nil Tax Jurisdiction (including in the view of Brazilian authorities the jurisdictions to which the Non-Transparency Rule applies), the applicable withholding income tax rate is 25%.  See “—Clarifications on Non-Brazilian Holders Resident or Domiciled in a Low or Nil Tax Jurisdiction.”  The payment of interest at the SELIC rate that is applicable to payments of dividends applies equally to payments of interest on capital. The determination of whether or not we will make distributions in the form of interest on capital or in the form of dividends is made by our board of directors at the time distributions are to be made. We cannot determine how our board of directors will make these determinations in connection with future distributions.

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Taxation of Gains

For purposes of Brazilian taxation on capital gains, two types of non-Brazilian holders have to be considered: (i) non-Brazilian holders of ADSs, preferred shares or common shares that are not resident or domiciled in a Low or Nil Tax Jurisdiction, and that, in the case of preferred or common shares, have registered before the Central Bank of Brazil and the CVM in accordance with CMN Resolution No. 4,373; and (ii) any other non-Brazilian holder, including non-Brazilian holders who invest in Brazil not in accordance with CMN Resolution No. 4,373 (including registration under Law No. 4,131/1962) and who are resident or domiciled in a Low or Nil Tax Jurisdiction.  See “—Clarifications on Non-Brazilian Holders Resident or Domiciled in a Low or Nil Tax Jurisdiction.”

According to Law No. 10,833/2003, capital gains realized on the disposition of assets located in Brazil by non-Brazilian holders, whether or not to other non-residents and whether made outside or within Brazil, may be subject to taxation in Brazil. With respect to the disposition of common or preferred shares, as they are assets located in Brazil, the non-Brazilian holder may be subject to income tax on any gains realized, following the rules described below, regardless of whether the transactions are conducted in Brazil or with a Brazilian resident. We understand the ADSs do not fall within the definition of assets located in Brazil for the purposes of this law, but there is still neither pronunciation from tax authorities nor judicial court rulings in this respect. Therefore, we are unable to predict whether such understanding will prevail in the courts of Brazil.

                Although there are grounds to sustain otherwise, the deposit of preferred or common shares in exchange for ADSs may be subject to Brazilian taxation on capital gains if the acquisition cost of the preferred or common shares is lower than: (i) the average price per preferred or common share on a Brazilian stock exchange on which the greatest number of such shares were sold on the day of deposit; or (ii) if no preferred or common shares were sold on that day, the average price on the Brazilian stock exchange on which the greatest number of preferred or common shares were sold in the 15 trading sessions immediately preceding such deposit. In such a case, the difference between the amount previously registered and the average price of the preferred or common shares calculated as above, will be considered a capital gain.

The difference between the acquisition cost and the average price of the preferred or common shares calculated as described above will be considered to be a capital gain realized that is subject to taxation as described below. There are grounds to sustain that such taxation is not applicable with respect to non-Brazilian holders registered under the rules of CMN Resolution No. 4,373 and not resident or domiciled in a Low or Nil Tax Jurisdiction.

The withdrawal of ADSs in exchange for preferred or common shares should not be considered as giving rise to a capital gain subject to Brazilian income tax, provided that on receipt of the underlying preferred or common shares, the non-Brazilian holder complies with the registration procedure with the Central Bank of Brazil as described below in “Registered Capital.”

Capital gains realized by a non-Brazilian holder on a sale or disposition of preferred or common shares carried out on a Brazilian stock exchange (which includes transactions carried out on the organized over-the-counter market) are:

·exempt from income tax when the non-Brazilian holder (i) has registered its investment in accordance with CMN Resolution No. 4,373 and (ii) is not resident or domiciled in a Low or Nil Tax Jurisdiction; or

·in all other cases, including a case of capital gains realized by a non-Brazilian holder that is not registered in accordance with CMN Resolution No. 4,373 and/or is resident or domiciled in a Low or Nil Tax Jurisdiction, subject to income tax at a 15% rate. In these cases, a withholding income tax at a rate of 0.005% of the sale value is levied on the transaction which can be offset against the eventual income tax due on the capital gain.

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Any capital gains realized on a disposition of preferred or common shares that is carried out outside the Brazilian stock exchange are subject to income tax at the rate of 15%, or 25% in case of gains realized by a non-Brazilian holder that is domiciled or resident in a Low or Nil Tax Jurisdiction or a jurisdiction to which the Non-Transparency Rule applies. In this last case, for the capital gains related to transactions conducted on the Brazilian non-organized over-the-counter market with intermediation, the withholding income tax of 0.005% will also apply and can be offset against the eventual income tax due on the capital gain.

In the case of a redemption of preferred or common shares or ADSs or a capital reduction made by us, the positive difference between the amount received by the non-Brazilian holder and the acquisition cost of the preferred or common shares or ADSs redeemed or reduced is treated as capital gain derived from the sale or exchange of shares not carried out on a Brazilian stock exchange market and is therefore generally subject to income tax at the rate of 15% or 25%, as the case may be.  See “—Clarifications on Non-Brazilian Holders Resident or Domiciled in a Low or Nil Tax Jurisdiction.”

Any exercise of preemptive rights relating to the preferred or common shares will not be subject to Brazilian taxation. Any gain on the sale or assignment of preemptive rights will be subject to Brazilian income taxation according to the same rules applicable to the sale or disposition of preferred or common shares.

No assurance can be made that the current preferential treatment of non-Brazilian holders of the ADSs and some non-Brazilian holders of the preferred or common shares under CMN Resolution No. 4,373 will continue to apply in the future.

Clarifications on Non-Brazilian Holders Resident or Domiciled in a Low or Nil Tax Jurisdiction

Law No. 9,779/1999 states that, except for limited prescribed circumstances, income derived from transactions by a person resident or domiciled in a Low or Nil Tax Jurisdiction will be subject to withholding income tax at the rate of 25%. A Low or Nil Tax Jurisdiction is generally considered to be a country or other jurisdiction which does not impose any income tax or which imposes such tax at a maximum rate lower than 17%. Under certain circumstances, the Non-Transparency Rule is also taken into account for determining whether a country or other jurisdiction is a Low or Nil Tax Jurisdiction. In addition, Law No. 11,727/2008 introduced the concept of a “privileged tax regime”, which is defined as a tax regime which (i) does not tax income or taxes it at a maximum rate lower than 17%; (ii) grants tax benefits to non-resident entities or individuals (a) without the requirement to carry out a substantial economic activity in the country or other jurisdiction or (b) contingent on the non-exercise of a substantial economic activity in the country or other jurisdiction; (iii) does not tax or that taxes foreign source income at a maximum rate lower than 17%; or (iv) does not provide access to information related to shareholding composition, ownership of assets and rights or economic transactions carried out. We believe that the best interpretation of Law No. 11,727/2008 is that the concept of a “privileged tax regime” will apply solely for purposes of the transfer pricing rules in export and import transactions, deductibility for Brazilian corporate income taxes and the thin capitalization rules and, would therefore generally not have an impact on the taxation of a non-Brazilian holder of preferred or common shares or ADSs, as discussed herein. However, we are unable to ascertain whether the privileged tax regime concept will also apply in the context of the rules applicable to Low or Nil Tax Jurisdictions, although the Brazilian tax authorities appear to agree with our position, in view of the provisions of the Normative Ruling No. 1,037 of June 4, 2010.

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Taxation of Foreign Exchange Transactions (IOF/Exchange)

Brazilian law imposes the IOF/Exchange on the conversion of reais into foreign currency and on the conversion of foreign currency into reais.  Currently, for most foreign currency exchange transactions, the rate of IOF/Exchange is 0.38%. However, foreign exchange transactions related to inflows of funds to Brazil for investments made by foreign investors in the Brazilian financial and capital markets are generally subject to IOF/Exchange at a zero percent rate. Foreign exchange transactions related to outflows of proceeds from Brazil in connection with investments made by foreign investors in the Brazilian financial and capital markets are also subject to the IOF/Exchange tax at a zero percent rate.  This zero percent rate applies to payments of dividends and interest on capital received by foreign investors with respect to investments in the Brazilian financial and capital markets, such as investments made by a non-Brazilian holder as provided for in CMN Resolution No. 4,373. The Brazilian Executive Branch may increase such rates at any time, up to 25% of the amount of the foreign exchange transaction, but not with retroactive effect.

Taxation on Bonds and Securities Transactions (IOF/Bonds)

Brazilian law imposes IOF/Bonds on transactions involving equity securities, bonds and other securities, including those carried out on a Brazilian stock exchange. The rate of IOF/Bonds applicable to transactions involving preferred or common shares is currently zero. However, the Brazilian federal government may increase such rate at any time up to 1.5% of the transaction amount per day, but the tax cannot be applied retroactively.

The IOF on transfer of shares, which are admitted to trading on a stock exchange located in Brazil, with the specific purpose of backing the issuance of depositary receipts traded abroad have been reduced from 1.5% to zero, as of December 24, 2013.

Other Brazilian Taxes

There are no Brazilian inheritance, gift or succession taxes applicable to the ownership, transfer or disposition of preferred or common shares or ADSs by a non-Brazilian holder, except for gift and inheritance taxes which are levied by certain states of Brazil on gifts made or inheritances bestowed by a non-Brazilian holder to individuals or entities resident or domiciled within such states in Brazil. There are no Brazilian stamp, issue, registration, or similar taxes or duties payable by holders of preferred or common shares or ADSs.

                Registered Capital

The amount of an investment in preferred or common shares held by a non-Brazilian holder who obtains registration under CMN Resolution No. 4,373, or by the depositary representing such holder, is eligible for registration with the Central Bank of Brazil; and such registration allows the remittance outside Brazil of foreign currency, converted at the commercial market rate, acquired with the proceeds of distributions on, and amounts realized with respect to dispositions of, such preferred or common shares.  The amount registered (“registered capital”) for each preferred or common share purchased as part of the international offering or purchased in Brazil after the date hereof, and deposited with the depositary, will be equal to its purchase price (in U.S. dollars).  The registered capital for a preferred or common share that is withdrawn upon surrender of an ADS will be the U.S. dollar equivalent of:

(a)   the average price of a preferred or common share on the Brazilian stock exchange on which the highest volume of such shares were traded on the day of withdrawal; or

(b)   if no preferred or common shares were traded on that day, the average price on the Brazilian stock exchange on which the highest volume of preferred or common shares were traded in the 15 trading sessions immediately preceding the date of such withdrawal.

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The U.S. dollar value of the average price of preferred or common shares is determined on the basis of the average of the U.S. dollar/real commercial market rates quoted by the Central Bank of Brazil information system on that date (or, if the average price of preferred or common shares is determined under the second option above, price will be determined by the average quoted rates verified on the same 15 preceding trading sessions as described above).

A non-Brazilian holder of preferred or common shares may be subject to delays in effecting such registration, which in turn may delay remittances abroad. Such a delay may adversely affect the amount, in U.S. dollars, received by the non-Brazilian holder.  See Item 3. “Key Information—Risk Factors—Risks Relating to Our Equity and Debt Securities.”

U.S. Federal Income Tax Considerations

This summary describes the principal U.S. federal income tax consequences of the ownership and disposition of common or preferred shares or ADSs, based on the U.S. Internal Revenue Code of 1986, as amended (the Code), its legislative history, existing and proposed U.S. Treasury regulations promulgated thereunder, published rulings by the U.S. Internal Revenue Service (IRS), and court decisions, all as in effect as of the date hereof, and all of which are subject to change or differing interpretations, possibly with retroactive effect. This summary does not purport to be a comprehensive description of all of the tax consequences that may be relevant to a decision to hold or dispose of common or preferred shares or ADSs. This summary applies only to purchasers of common or preferred shares or ADSs who hold the common or preferred shares or ADSs as “capital assets” (generally, property held for investment), and does not apply to special classes of holders such as dealers or traders in securities or currencies, holders whose functional currency is not the U.S. dollar, holders of 10% or more of our shares (taking into account shares held directly or through depositary arrangements), tax-exempt organizations, partnerships or partners therein, financial institutions, holders liable for the alternative minimum tax, securities traders who elect to account for their investment in common or preferred shares or ADSs on a mark-to-market basis, persons that enter into a constructive sale transaction with respect to common or preferred shares or ADSs, and persons holding common or preferred shares or ADSs in a hedging transaction or as part of a straddle or conversion transaction.

EACH HOLDER SHOULD CONSULT ITS OWN TAX ADVISOR CONCERNING THE OVERALL TAX CONSEQUENCES IN ITS PARTICULAR CIRCUMSTANCES, INCLUDING THE CONSEQUENCES UNDER LAWS OTHER THAN U.S. FEDERAL INCOME TAX LAWS, OF AN INVESTMENT IN COMMON OR PREFERRED SHARES OR ADSs.

Shares of our preferred stock will be treated as equity for U.S. federal income tax purposes. In general, a holder of an ADS will be treated as the holder of the shares of common or preferred stock represented by those ADSs for U.S. federal income tax purposes, and no gain or loss will be recognized if you exchange ADSs for the shares of common or preferred stock represented by that ADS.

In this discussion, references to ADSs refer to ADSs with respect to both common and preferred shares, and references to a “U.S. Holder” are to a holder of an ADS that is:

·an individual who is a citizen or resident of the United States;

·a corporation organized under the laws of the United States, any state thereof, or the District of Columbia; or

·otherwise subject to U.S. federal income taxation on a net basis with respect to the shares or the ADS.

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Taxation of Distributions

A U.S. Holder will recognize ordinary dividend income for U.S. federal income tax purposes in an amount equal to the amount of any cash and the value of any property we distribute as a dividend to the extent that such distribution is paid out of our current or accumulated earnings and profits, as determined for U.S. federal income tax purposes, when such distribution is received by the custodian, or by the U.S. Holder in the case of a holder of common or preferred shares. The amount of any distribution will include distributions characterized as interest on capital and the amount of Brazilian tax withheld on the amount distributed, and the amount of a distribution paid in reais will be measured by reference to the exchange rate for converting reais into U.S. dollars in effect on the date the distribution is received by the custodian, or by a U.S. Holder in the case of a holder of common or preferred shares. If the custodian, or U.S. Holder in the case of a holder of common or preferred shares, does not convert such reais into U.S. dollars on the date it receives them, it is possible that the U.S. Holder will recognize foreign currency loss or gain, which would be U.S. source ordinary loss or gain, when the reais are converted into U.S. dollars. Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code.

Subject to certain exceptions for short-term and hedged positions, the U.S. dollar amount of dividends received by a non-corporate U.S. Holder with respect to the ADSs will generally be subject to taxation at preferential rates if the dividends are “qualified dividends.” Dividends paid on the ADSs will be treated as qualified dividends if (i) the ADSs are readily tradable on an established securities market in the United States and (ii) Petrobras was not, in the year prior to the year in which the dividend was paid, and is not, in the year in which the dividend is paid, a “passive foreign investment company” as defined for U.S. federal income tax purposes (a PFIC). The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States so long as they are so listed. Based on our audited financial statements and relevant market and shareholder data, we believe that we should not be treated as a PFIC for U.S. federal income tax purposes with respect to its 2013 or 2014 taxable year. In addition, based on our audited financial statements and our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not anticipate becoming a PFIC for our 2015 taxable year. Based on existing guidance, it is not clear whether dividends received with respect to the shares will be treated as qualified dividends, because the shares are not themselves listed on a U.S. exchange. In addition, the U.S. Treasury has announced its intention to promulgate rules pursuant to which holders of ADSs and intermediaries through whom such securities are held will be permitted to rely on certifications from issuers to treat dividends as qualified for tax reporting purposes.  Because such procedures have not yet been issued, it is not clear whether we would be able to comply with these procedures. U.S. Holders of our ADSs should consult their own tax advisors regarding the availability of the reduced dividend tax rate in the light of their particular circumstances.

Distributions out of earnings and profits with respect to the shares or ADSs generally will be treated as dividend income from sources outside of the United States and generally will be treated as “passive category income” for U.S. foreign tax credit purposes. Subject to certain limitations, Brazilian income tax withheld in connection with any distribution with respect to the shares or ADSs may be claimed as a credit against the U.S. federal income tax liability of a U.S. Holder, or, at the U.S. Holder’s election, such Brazilian withholding tax may be taken as a deduction against taxable income. A U.S. foreign tax credit may not be allowed for Brazilian withholding tax imposed in respect of certain short-term or hedged positions in securities or in respect of arrangements in which a U.S. Holder’s expected economic profit is insubstantial. U.S. Holders should consult their own tax advisors regarding the availability of the U.S. foreign tax credit, including the translation of reais into U.S. dollar for these purposes, in light of their particular circumstances.

Holders of ADSs that are foreign corporations or nonresident alien individuals (non-U.S. Holders) generally will not be subject to U.S. federal income tax, including withholding tax, on distributions with respect to shares or ADSs that are treated as dividend income for U.S. federal income tax purposes unless such dividends are effectively connected with the conduct by the holder of a trade or business in the United States.

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Holders of shares and ADSs should consult their own tax advisers regarding the availability of the reduced dividend tax rate in the light of the considerations discussed above and their own particular circumstances.

Taxation of Capital Gains

Upon the sale or other disposition of a share or an ADS, a U.S. Holder will generally recognize U.S. source capital gain or loss for U.S. federal income tax purposes, equal to the difference between the amount realized on the disposition and the U.S. Holder’s tax basis in such share or ADS. Any gain or loss will be long-term capital gain or loss if the shares or ADSs have been held for more than one year. Non-corporate U.S. Holders of shares or ADSs may be eligible for a preferential rate of U.S. federal income tax in respect of long-term capital gains. Capital losses may be deducted from taxable income, subject to certain limitations. For U.S. federal income tax purposes, such disposition would not result in foreign source-income to a U.S. Holder. As a result, a U.S. Holder may not be able to use the foreign tax credit associated with any Brazilian income taxes imposed on such gains, unless such holder can use the credit against U.S. tax due on other foreign-source income. U.S. Holders should consult their own tax advisors regarding the availability of the U.S. foreign tax credit, including the translation of reais into U.S. dollar for purposes of their investment in our shares or ADSs.

A non-U.S. Holder will not be subject to U.S. federal income tax or withholding tax on gain realized on the sale or other disposition of a share or an ADS, unless:

·such gain is effectively connected with the conduct by the holder of a trade or business in the United States; or

·such holder is an individual who is present in the United States for 183 days or more in the taxable year of the sale and certain other conditions are met.

Information Reporting and Backup Withholding

The payment of dividends on, and proceeds from the sale or other disposition of, the ADSs or common or preferred shares to a U.S. Holder within the United States (or through certain U.S. related financial intermediaries) will generally be subject to information reporting unless the U.S. Holder is a corporation or other exempt recipient. Such dividends and proceeds may be subject to backup withholding unless the U.S. Holder (i) is an exempt recipient, or (ii) timely provides a taxpayer identification number and certifies that no loss of exemption from backup withholding has occurred. Backup withholding is not an additional tax. The amount of any backup withholding collected from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability and may entitle the U.S. Holder to a refund, so long as the required information is properly furnished to the IRS.

U.S. Holders should consult their own tax advisors about any additional reporting requirements that may arise as a result of their purchasing, holding or disposing of our ADSs, or common or preferred shares.

A non-U.S. Holder generally will be exempt from these information reporting requirements and backup withholding tax, but may be required to comply with certain certification and identification procedures in order to establish its eligibility for such exemption.

Taxation Relating to PGF’s Notes

The following summary contains a description of material Brazilian, Dutch, European Union and U.S. federal income tax considerations that may be relevant to the purchase, ownership, and disposition of PGF’s debt securities.  This summary does not describe any tax consequences arising under the laws of any state, locality or taxing jurisdiction other than the Netherlands, Brazil and the United States.

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This summary is based on the tax laws of the Netherlands, Brazil and the United States as in effect on the date of this annual report, which are subject to change (possibly with retroactive effect).  This description is not a comprehensive description of all tax considerations that may be relevant to any particular investor, including tax considerations that arise from rules generally applicable to all taxpayers or to certain classes of investors or that investors are generally assumed to know.  Prospective purchasers of notes should consult their own tax advisors regarding the tax consequences of the acquisition, ownership and disposition of the notes.

There is no tax treaty to avoid double taxation between Brazil and the United States. In recent years, the tax authorities of Brazil and the United States have held discussions that may culminate in such a treaty.  We cannot predict, however, whether or when a treaty will enter into force or how it will affect the U.S. Holders of notes.

Dutch Taxation

The following generally outlines the Dutch tax consequences to holders of the notes in connection with the acquisition, ownership and disposal of notes in a Dutch company. It does not purport to describe all possible Dutch tax considerations or consequences that may be relevant to a holder.

For the purpose of this section, “Dutch Taxes” shall mean taxes of whatever nature levied by or on behalf of the Netherlands or any of its subdivisions or taxing authorities. The Netherlands means the part of the Kingdom of the Netherlands located in Europe.

For Dutch tax purposes, a holder of notes may include an individual or an entity who does not have the legal title to the notes, but to whom the notes are attributed based either on such individual or entity holding a beneficial interest in the notes or based on specific statutory provisions, including statutory provisions pursuant to which the notes are attributed to an individual who is, or who has directly or indirectly inherited the notes from a person who was, the settlor, grantor or similar originator of a trust, foundation or similar entity that holds the notes.

This section does not describe all the possible Dutch tax consequences that may be relevant to the holder of the notes who receives or has received any benefits from these notes as employment income, deemed employment income or otherwise as compensation for work or services.

Taxes on Income and Capital Gains

A holder of notes will not be subject to any Dutch taxes on income or capital gains in respect of the notes, including such tax on any payment under the notes or in respect of any gain realised on the disposal, deemed disposal, redemption or exchange of the notes, provided that:

·such holder is neither a resident nor deemed to be a resident of the Netherlands, nor, if he is an individual, has elected to be taxed as a resident of the Netherlands;

·such holder does not have, and is not deemed to have, an enterprise or an interest in an enterprise that is, in whole or in part, carried on through a permanent establishment (vaste inrichting) or a permanent representative (vaste vertegenwoordiger) in the Netherlands and to which enterprise or part of an enterprise, as the case may be, the notes are attributable;

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·if such holder is an individual, such income or capital gains do not form "benefits from miscellaneous activities in the Netherlands" (resultaat uit overige werkzaamheden in Nederland), which would for instance be the case if the activities in the Netherlands with respect to the notes exceed "normal asset management" (normaal vermogensbeheer) or if income and gains are derived from the holding, whether directly or indirectly, of (a combination of) shares, debt claims or other rights (together, a "lucrative interest") that the holder thereof has acquired under such circumstances that such income and gains are intended to be remuneration for work or services performed by such holder (or a related person) in the Netherlands, whether within or outside an employment relation, where such lucrative interest provides the holder thereof, economically speaking, with certain benefits that have a relation to the relevant work or services;

·the holders of the notes do not hold directly or indirectly, a substantial shareholding (i.e., generally speaking, an interest of 5% or more of the shares, options, profit rights or voting rights) in PGF;

·If such holder is an entity, the holder is not entitled to a share in the profits of an enterprise nor a co-entitlement to the net worth of an enterprise, which is effectively managed in the Netherlands, other than by way of securities, and to which enterprise the notes are attributable; and

·if such holder is an individual, the holder is not entitled to a share in the profits of an enterprise that is effectively managed in the Netherlands, other than by way of securities, and to which enterprise the notes are attributable.

A holder of notes will not be subject to taxation in the Netherlands by reason only of the execution, delivery and/or enforcement of its rights and obligations connected to the notes, the issue of the notes or the performance by PGF of its obligations under the notes.

Dutch Withholding Tax

All payments made under the notes will not be subject to any withholding taxes of whatever nature imposed, levied, withheld or assessed by the Netherlands provided that such payments qualify as interest on the notes for Dutch tax purposes.

Dutch Gift, Estate and Inheritance Taxes

No gift, estate or inheritance taxes will arise in the Netherlands with respect to an acquisition or deemed acquisition of notes by way of a gift by, or on the death of, a holder of notes who is neither resident, deemed to be resident for Dutch inheritance and gift tax purposes, unless in the case of a gift of notes by an individual who at the date of the gift was neither resident nor deemed to be resident in the Netherlands, such individual dies within 180 days after the date of the gift, while being resident or deemed to be resident in the Netherlands.

For the purposes of Netherlands gift, estate and inheritance tax, a gift that is made under a condition precedent is deemed to be made at the moment such condition precedent is satisfied or, if earlier, the moment the donor dies.

For purposes of Netherlands gift, estate and inheritance tax, an individual who holds the Netherlands nationality will be deemed to be resident in the Netherlands if he has been resident in the Netherlands at any time during the ten years preceding the date of the gift or his death.

For purposes of Netherlands gift tax, an individual not holding the Netherlands nationality will be deemed to be resident in the Netherlands if he has been resident in the Netherlands at any time during the twelve months preceding the date of the gift.

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Turnover Tax

No Dutch turnover tax will arise in respect of any payment in consideration for the issue of the notes or with respect to any payment by PGF of principal, interest or premium (if any) on the notes.

Other Taxes and Duties

No other Dutch taxes, including taxes of a documentary nature, such as capital tax, stamp or registration tax or duty, are payable in The Netherlands by or on behalf of a holder of the notes by reason only of the purchase, ownership and disposal of the notes.

European Union Savings Directive

Under the Directive, each Member State of the European Union is required to provide to the tax or other relevant authorities of another Member State details of payments of interest (or similar income) paid by a paying agent within its jurisdiction to, or collected by such a paying agent for, an individual beneficial owner resident in that other Member State or to certain limited types of entities established in that other Member State. However, for a transitional period (the ending of which is, among others, dependent upon the conclusion of agreements by the European Commission with certain non-EU countries to exchange information relating to interest and other similar income or the introduction of an automatic exchange of information by the country applying the transitional regime), Austria will (unless during that period it elects otherwise) operate a withholding system in relation to such payments deducting tax at the rate of 35%, unless the beneficial owner of the interest payments elects that certain provision of information procedures should be applied instead of withholding. The withholding tax levied by Austria during the transitional period may be entirely creditable or refundable in the investor's state of tax residence.

A number of non-EU countries, including Switzerland, and certain dependent or associated territories of certain Member States have agreed to adopt similar measures with the EU (with a withholding system applying in the case of Switzerland).

The European Commission adopted on March 24, 2014 the revised Directive which strengthens the existing rules on exchange of information on savings income with the aim of better enabling Member States to prevent tax evasion. The European Commission has requested that the revised Directive should be implemented by the Member States by January 2016 and is currently renegotiating the agreements with a number of non-EU countries, including Switzerland, and certain dependent or associated territories of certain Member States in line with the revised Directive and international developments.

Holders of notes who are in any doubt as to their position should consult their financial or tax advisers.

Brazilian Taxation

The following discussion is a summary of the Brazilian tax considerations relating to an investment in the notes by a non-resident of Brazil.  The discussion is based on the tax laws of Brazil as in effect on the date hereof and is subject to any change in Brazilian law that may come into effect after such date.  The information set forth below is intended to be a general discussion only and does not address all possible consequences relating to an investment in the notes.

INVESTORS SHOULD CONSULT THEIR OWN TAX ADVISERS AS TO THE CONSEQUENCES OF PURCHASING THE NOTES, INCLUDING, WITHOUT LIMITATION, THE CONSEQUENCES OF THE RECEIPT OF INTEREST AND THE SALE, REDEMPTION OR REPAYMENT OF THE NOTES OR COUPONS.

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Generally, an individual, entity, trust or organization domiciled for tax purposes outside Brazil, or a “Non-resident,” is taxed in Brazil only when income is derived from Brazilian sources or when the transaction giving rise to such earnings involves assets in Brazil.  Therefore, any gains or interest (including original issue discount), fees, commissions, expenses and any other income paid by PGF in respect of the notes issued by them in favor of non-resident holders are not subject to Brazilian taxes.

Interest, fees, commissions, expenses and any other income payable by Petrobras as guarantor resident in Brazil to a Non-resident are generally subject to income tax withheld at source.  The rate of withholding income tax in respect of interest payments is generally 15%, unless (i) the holder of the notes is resident or domiciled in a “tax haven jurisdiction” (that is deemed to be a country or jurisdiction which does not impose any tax on income or which imposes such tax at a maximum effective rate lower than 17% or where the local legislation imposes restrictions on disclosing the identities of shareholders, the ownership of investments, or the ultimate beneficiary of earnings distributed to the Non-resident— “tax haven jurisdiction”), in which case the applicable rate is 25% or (ii) such other lower rate as provided for in an applicable tax treaty between Brazil and another country where the beneficiary is domiciled.  In case the guarantor is required to assume the obligation to pay the principal amount of the notes, Brazilian tax authorities could attempt to impose withholding income tax at the rate of up to 25% as described above.  Although Brazilian legislation does not provide a specific tax rule for such cases and there is no official position from tax authorities or precedents from the Brazilian court regarding the matter, we believe that the remittance of funds by Petrobras as a guarantor for the payment of the principal amount of the notes will not be subject to income tax in Brazil, because the mere fact that the guarantor is making the payment does not convert the nature of the principal due under the notes into income of the beneficiary.

If the payments with respect to the notes are made by Petrobras, as provided for in the guaranties, the Non-resident holders will be indemnified so that, after payment of all applicable Brazilian taxes collectable by withholding, deduction or otherwise, with respect to principal, interest and additional amounts payable with respect to the notes (plus any interest and penalties thereon), a Non-resident holder will receive an amount equal to the amount that such Non-resident holder would have received as if no such Brazilian taxes (plus interest and penalties thereon) were withheld.  The Brazilian obligor will, subject to certain exceptions, pay additional amounts in respect of such withholding or deduction so that the Non-resident holder receives the net amount due.

Gains on the sale or other disposition of the notes made outside of Brazil by a Non-resident, other than a branch or a subsidiary of Brazilian resident, to another Non-resident are not subject to Brazilian income tax.

In addition, payments made from Brazil are subject to the tax on foreign exchange transactions (IOF/Câmbio), which is levied on the conversion of Brazilian currency into foreign currency and on the conversion of foreign currency into Brazilian currency at a general rate of 0.38%.  Other IOF/Câmbio rates may apply to specific transactions. In any case, the Brazilian federal government may increase, at any time, such rate up to 25% but only with respect to future transactions.

Generally, there are no inheritance, gift, succession, stamp, or other similar taxes in Brazil with respect to the ownership, transfer, assignment or any other disposition of the notes by a Non-resident, except for gift and inheritance taxes imposed by some Brazilian states on gifts or bequests by individuals or entities not domiciled or residing in Brazil to individuals or entities domiciled or residing within such states.

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U.S. Federal Income Taxation

The following summary sets forth certain United States federal income tax considerations that may be relevant to a holder of a note that is, for U.S. federal income purposes, a citizen or resident of the United States or a domestic corporation or that otherwise is subject to U.S. federal income taxation on a net income basis in respect of the notes (a “U.S. Holder”). This summary is based upon the Code, its legislative history, existing and proposed U.S. Treasury regulations promulgated thereunder, published rulings by the IRS, and court decisions, all as in effect as of the date hereof, all of which are subject to change or differing interpretations, possibly with retroactive effect. This summary does not purport to discuss all aspects of the U.S. federal income taxation which may be relevant to special classes of investors, such as financial institutions, insurance companies, dealers or traders in securities or currencies, securities traders who elect to account for their investment in notes on a mark-to-market basis, regulated investment companies, tax-exempt organizations, partnerships or partners therein, holders that are subject to the alternative minimum tax, certain short-term holders of notes, persons that hedge their exposure in the notes or hold notes as part of a position in a “straddle” or as part of a hedging transaction or “conversion transaction” for U.S. federal tax purposes, persons that enter into a “constructive sale” transaction with respect to the notes or U.S. Holder whose functional currency is not the U.S. dollar.  U.S. Holders should be aware that the U.S. federal income tax consequences of holding the notes may be materially different for investors described in the prior sentence.

In addition, this summary does not discuss any foreign, state or local tax considerations.  This summary only applies to original purchasers of notes who have purchased notes at the original issue price and hold the notes as “capital assets” (generally, property held for investment).

EACH INVESTOR SHOULD CONSULT ITS OWN TAX ADVISOR CONCERNING THE OVERALL TAX CONSEQUENCES IN ITS PARTICULAR CIRCUMSTANCES, INCLUDING THE CONSEQUENCES UNDER LAWS OTHER THAN U.S. FEDERAL INCOME TAX LAWS, OF AN INVESTMENT IN THE NOTES.

Payments of Interest

Payment of “qualified stated interest,” as defined below, on a note (including additional amounts, if any) generally will be taxable to a U.S. holder as ordinary interest income when such interest is accrued or received, in accordance with the U.S. holder’s applicable method of accounting for U.S. federal tax purposes.  In general, if the “issue price” of a note is less than the “stated redemption price at maturity” by more than a de minimis amount, such note will be considered to have “original issue discount,” or OID.  The “issue price” of a note is the first price at which a substantial amount of such notes are sold to investors. The stated redemption price at maturity of a note generally includes all payments other than payments of qualified stated interest.

In general, each U.S. Holder of a note, whether such holder uses the cash or the accrual method of tax accounting, will be required to include in gross income as ordinary interest income the sum of the “daily portions” of OID on the note, if any, for all days during the taxable year that the U.S. Holder owns the note.  The daily portions of OID on a note are determined by allocating to each day in any accrual period a ratable portion of the OID allocable to that accrual period.  In general, in the case of an initial holder, the amount of OID on a note allocable to each accrual period is determined by (i) multiplying the “adjusted issue price,” as defined below, of the note at the beginning of the accrual period by the yield to maturity of the note, and (ii) subtracting from that product the amount of qualified stated interest allocable to that accrual period. U.S. Holders should be aware that they generally must include OID in gross income as ordinary interest income for U.S. federal income tax purposes as it accrues, in advance of the receipt of cash attributable to that income.  The “adjusted issue price” of a note at the beginning of any accrual period will generally be the sum of its issue price (generally including accrued interest, if any) and the amount of OID allocable to all prior accrual periods, reduced by the amount of all payments other than payments of qualified stated interest (if any) made with respect to such note in all prior accrual periods. The term “qualified stated interest” generally means stated interest that is unconditionally payable in cash or property (other than debt instruments of the issuer) at least annually during the entire term of a note at a single fixed rate of interest, or subject to certain conditions, based on one or more interest indices.

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Interest income, including OID, in respect of the notes will constitute foreign source income for U.S. federal income tax purposes and, with certain exceptions, will be treated separately, together with other items of “passive category income,” for purposes of computing the foreign tax credit allowable under the U.S. federal income tax laws.  The calculation of foreign tax credits involves the application of complex rules that depend on a U.S. Holder’s particular circumstances.  U.S. Holders should consult their own tax advisors regarding the availability of foreign tax credits and the treatment of additional amounts.

Sale or Disposition of Notes

A U.S. Holder generally will recognize capital gain or loss upon the sale, exchange, retirement or other disposition of a note in an amount equal to the difference between the amount realized upon such sale, exchange, retirement or other disposition (other than amounts attributable to accrued qualified stated interest, which will be taxed as such) and such U.S. Holder’s adjusted tax basis in the note.  A U.S. Holder’s adjusted tax basis in the note generally will equal the U.S. Holder’s cost for the note increased by any amounts included in gross income by such U.S. Holder as OID, if any, and reduced by any payments other than payments of qualified stated interest on that note.  Gain or loss realized by a U.S. Holder on the sale, exchange, retirement or other disposition of a note generally will be U.S. source gain or loss for U.S. federal income tax purposes unless it is attributable to an office or other fixed place of business outside the United States and certain other conditions are met.  The gain or loss realized by a U.S. Holder will be capital gain or loss, and will be long-term capital gain or loss if the notes were held for more than one year.  The net amount of long-term capital gain recognized by an individual holder generally is subject to taxation at preferential rates.  Capital losses may be deducted from taxable income, subject to certain limitations.

Backup Withholding and Information Reporting

A U.S. Holder may, under certain circumstances, be subject to “backup withholding” with respect to certain payments to that U.S. Holder, unless the holder (i) is an exempt recipient, and demonstrates this fact when so required, or (ii) provides a correct taxpayer identification number, certifies that it is not subject to backup withholding and otherwise complies with applicable requirements of the backup withholding rules.  Any amount withheld under these rules generally will be creditable against the U.S. Holder’s U.S. federal income tax liability.  While non-U.S. Holders generally are exempt from backup withholding, a non-U.S. Holder may, in certain circumstances, be required to comply with certain information and identification procedures in order to prove entitlement to this exemption.

U.S. Holders should consult their own tax advisors about any additional reporting requirements that may arise as a result of their purchasing, holding or disposing of the notes.

Non-U.S. Holder

A holder or beneficial owner of a note that is not a U.S. Holder (a “non-U.S. Holder”) generally will not be subject to U.S. federal income or withholding tax on interest received on the notes.  In addition, a non-U.S. Holder will not be subject to U.S. federal income or withholding tax on gain realized on the sale of notes unless such gain is effectively connected with the conduct by such holder of a trade or business in the United States or, in the case of gain realized by an individual non-U.S. Holder, the non-U.S. Holder is present in the United States for 183 days or more in the taxable year of the sale and certain other conditions are met.

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Documents on Display

We are subject to the information requirements of the Securities Exchange Act of 1934, as amended, and accordingly file reports and other information with the SEC.  Reports and other information filed by us with the SEC may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, D.C.  20549.  You can obtain further information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  You may also inspect Petrobras’s reports and other information at the offices of the New York Stock Exchange, 11 Wall Street, New York, New York 10005, on which Petrobras’s ADSs are listed.  Our SEC filings are also available to the public from the SEC’s Web site at http://www.sec.gov.  For further information about obtaining copies of Petrobras’s public filings at the New York Stock Exchange, call (212) 656-5060.

We also file financial statements and other periodic reports with the CVM.

Item 11.   Qualitative and Quantitative Disclosures about Market Risk

Risk Management

We are exposed to a number of risks arising from our operations.  Such risks include the possibility that changes in prices of oil and oil products, foreign currency exchange rates or interest rates may adversely affect the value of our financial assets, liabilities, future cash flows and earnings.

We are also exposed to the credit risk of customers and financial institutions, arising from our business operations and cash management. Such risks involve the possibility of not receiving sales made and amounts invested, deposited or guaranteed by financial institutions.

We adopt the practice of integrated risk management according to which management, does not focus  on the individual risks of operations or business units, but rather, takes a wider view of our consolidated activities, capturing possible natural hedges where available. For the management of market risk, financial structural actions are taken through the proper management of our capital and indebtedness rather than through the use of derivative financial instruments.

Commodity Price Risk

Our purchases and sales of crude oil and oil products are related to international prices, which exposes us to price fluctuations in international markets.

For the purposes of managing our exposure to price fluctuations, we avoid, whenever possible and reasonable, the use of derivatives for hedging systemic operations (namely, buying and selling oil and oil products in order to provide for our operational needs).

The derivatives transactions are intended to protect the expected results of the transactions carried out abroad.  Our derivatives contracts provide economic hedges for anticipated crude oil and byproducts purchases and sales in the international markets, generally forecast to occur within a 30- to 360-day period.  See Note 33 to our audited consolidated financial statements for more information about our commodity derivatives transactions, including a sensitivity analysis demonstrating the net change in fair value of a 25% (or 50%) adverse change in the price of the underlying commodity as of December 31, 2014, which is a 25% (or 50%) change in the price of the underlying commodity for options, futures and swaps.

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Interest Rate and Exchange Rate Risk

The table below provides summary information regarding our exposure to interest rate and exchange rate risk in our total debt portfolio for 2014 and 2013, including short-term and long-term debt.   

	Total Debt Portfolio (1)
	2014	2013
	(%)
Real-denominated:
Fixed rate	4.0	3.1
Floating rate	13.8	16.9
Sub-total	17.8	20.0
U.S.dollar-denominated:
Fixed rate	36.6	37.2
Floating rate	35.3	34.4
Sub-total	71.9	71.6
Other currencies:
Fixed rate	9.8	8.0
Floating rate	0.5	0.4
Sub-total	10.3	8.4
Total	100.0	100.0
Floating rate debt:
Real-denominated	13.8	16.9
Foreign currency-denominated	35.8	34.8
Fixed rate debt:
Real-denominated	4.0	3.1
Foreign currency denominated	46.4	45.2
Total	100.0	100.0
U.S. dollars	71.9	71.6
Euro	7.4	5.6
GBP	2.1	1.6
Japanese Yen	0.8	1.2
Brazilian reais	17.8	20.0
Total	100.0	100.0

(1)     Short term and long term.

In general, our foreign currency floating rate debt is principally subject to fluctuations in LIBOR.  Our floating rate debt denominated in reais is principally subject to fluctuations in the Taxa de Juros de Longo Prazo (Brazilian long-term interest rate, or TJLP), as fixed by the CMN.

We generally do not utilize derivative instruments to manage our exposure to interest rate fluctuation. However, we continuously consider various forms of derivatives to reduce our exposure to interest rate fluctuations and may utilize these financial instruments in the future.

The exchange rate risk to which we are exposed has greater impact on the balance sheet and derives principally from the incidence of non-real denominated obligations in our debt portfolio.  With respect to the management of foreign exchange risks, we seek to identify them and treat them in an integrated analysis of natural protections (hedges), benefiting from the correlation between our income and expenses. For the short term, the management of our foreign exchange risk involves allocating our cash investments between the Brazilian real and other foreign currencies. In this context, our strategy may involve the use of derivative financial instruments to protect against foreign exchange rate volatility, which may impact the value of some of our obligations.

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We have designated cash flow hedging relationships to manage the exchange rate risk on our highly probable future exports. See Item 5. “Operating and Financial Review and Prospects—Inflation and Exchange Rate Variation” and Notes 4.3.6 and 33.2(a) to our audited consolidated financial statements for further information about our cash flow hedge.

Information regarding expected maturity dates and currency, the principal cash flows,related average interest rates of our debt obligations and liquidity risk is set out in Notes 17 and 33.6 to our audited consolidated financial statements.

Item 12.   Description of Securities other than Equity Securities

American Depositary Shares  

Effective January 3, 2012, The Bank of New York Mellon succeeded JPMorgan Chase Bank, N.A. as the Depositary for both of our common and preferred ADSs. In its capacity as Depositary, The Bank of New York Mellon will register and deliver the ADSs, each of which represents (i) two shares (or a right to receive two shares) deposited with the principal São Paulo office of Itaú Unibanco S.A., as custodian for the Depositary, and (ii) any other securities, cash or other property which may be held by the Depositary. The Depositary’s corporate trust office at which the ADSs will be administered is located at 101 Barclay Street, 22 West, New York, New York 10286.

Fees Payable by holders of our ADSs

ADS holders are required to pay various fees to the Depositary, and the Depositary may refuse to provide any service for which a fee is assessed until the applicable fee has been paid.

ADS holders are required to pay the Depositary: (i) an annual fee of U.S.$0.02 (or less) per ADS for administering the ADR program, and (ii) amounts in respect of expenses incurred by the Depositary or its agents on behalf of ADS holders, including expenses arising from compliance with applicable law, taxes or other governmental charges, facsimile transmission, or conversion of foreign currency into U.S. dollars. In both cases, the depositary may decide in its sole discretion to seek payment by directly billing investors, by deducting the applicable amount from cash distributions or by charging the book-entry system accounts of ADS holders or their representatives. ADS holders may also be required to pay additional fees for certain services provided by the depositary, as set forth in the table below.

Depositary service	Fee payable by ADS holders
Issuance and delivery of ADSs, including issuances resulting from a distribution of shares or rights or other property	U.S.$5.00 per 100 ADSs (or portion thereof)
Distribution of dividends	U.S.$0.02 (or less) per ADS per year
Cancellation of ADSs for the purpose of withdrawal	U.S.$5.00 per 100 ADSs (or portion thereof)

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Fees Payable by the Depositary to Petrobras

 The Depositary reimburses us for certain expenses we incur in connection with the administration and maintenance of the ADR program. These reimbursable expenses comprise investor relations expenses, listing fees, legal fees and other expenses related to the administration and maintenance of the ADR program. In addition, the Depositary has agreed to provide us with an additional reimbursement per annum equal to 80% of the dividend fee collected by the Depositary.  For the year ended December 31, 2014, the gross aggregate amount of such reimbursements was approximately U.S.$37.9 million.

PART II

Item 13.   Defaults, Dividend Arrearages and Delinquencies

None.

Item 14.   Material Modifications to the Rights of Security Holders and Use of Proceeds

None.

Item 15.   Controls and Procedures

Disclosure Controls and Procedures

                We have evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures as of December 31, 2014.  Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as a result of the material weaknesses in our internal control over financial reporting described below, as of December 31, 2014 our disclosure controls and procedures were not effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Management Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting.

                Our internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and our Chief Financial Officer, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with IFRS, as issued by the IASB.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements on a timely basis. Therefore even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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                Our management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on such assessment and criteria, and due to the material weaknesses described below, our management has concluded that our internal control over financial reporting was not effective as of December 31, 2014.

Material Weaknesses in Internal Control over Financial Reporting

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim consolidated financial statements will not be prevented or detected on a timely basis.

                During our management's assessment of internal control over financial reporting as of December 31, 2014, it identified the material weaknesses described below.

                Management Override of Controls

                During 2014, our management identified certain decisions taken during the period between 2004 and April 2012, specifically relating to our large investment projects in the Exploration and Production, Refining, and Gas and Power business segments, that did not comply with our existing internal controls over the process of contracting services in these segments. The internal controls over contracting of services include procedures such as the Petrobras Contracting Manual (Manual da Petrobras de Contratação – MPC) and the Investment Projects Corporate Procedures (Sistemática Corporativa de Projetos de Investimento). 

                In some of our contracting processes, one or more senior managers, together with third parties (namely, some of the contractors and suppliers involved in the construction projects), colluded to eliminate, infringe upon, override or circumvent these controls, which resulted in the commission of wrongful acts contrary to our interests and policies. Our management has identified the following internal control deficiencies related to the failure to detect these acts that together constitute a material weakness in our control environment: (i) inadequate “tone at the top” regarding internal controls; (ii) failure to communicate the ethical values prescribed in our Code of Conduct; and (iii) lack of an effective whistleblower program.

                These deficiencies contributed to our failure to prevent an overstatement of property, plant and equipment.

Controls Related to Property, Plant and Equipment

Our management has determined that our internal controls at December 31, 2014 did not identify possible risks arising from the economic and financial condition of contractors and suppliers in light of recent project postponements and from guarantees that have not yet been fully performed, which resulted in a failure to identify the need to write down payments advanced to contractors and suppliers that will not result in future economic benefits. Our internal controls at such date also failed to identify the need to recognize expenses related to the termination of these contracts.

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                We also identified deficiencies related to monitoring the need to reclassify certain property, plant and equipment from assets under construction to completed property, plant and equipment. A failure to make that reclassification when the circumstances warrant it could lead to a failure to account timely and in full for the depreciation associated with the project. 

                Our management also identified a deficiency related to the failure to recognize impairment losses in five Exploration and Production projects that were in their initial planning phase, for which we did not have estimated future cash flows. 

                These deficiencies resulted in an overstatement of property, plant and equipment and an understatement of our expenses.            

                Review and Approval of Manual Journal Entries

                Our management identified failure to timely monitor possible changes in the control parameters of the enterprise resource planning (“ERP”) environment, which are used to support the internal controls related to the review and approval of manual journal entries. This failure to timely monitor ERP parameter changes could subject us to the risk of non-detection of the totality of manual journal entries to be reviewed or confirmed. Our management also identified deficiencies in the design of our internal control over review and approval of manual journal entries. These deficiencies constituted a material weakness.

This deficiency did not result in misstatements or irregularities in our financial statements. 

                Access Management in Business and Information Technology Processes, and Segregation of Business Process Duties in the ERP Environment

                Our management identified deficiencies in control operations related to granting access procedures and segregation of duties analysis at the business process level that, when evaluated in the aggregate, constitute a material weakness.

                The identified control deficiencies relating to the management, review and monitoring of access showed exceptions, mainly deficiencies in the operation of controls related to the implementation of specific rules regarding access revision.  As for the management of access to critical ERP functions and segregation of duties in the ERP business processes, deficiencies in operating controls occurred.

                This deficiency did not result in misstatements or irregularities in our financial statements.

                Impact of Material Weaknesses

                These material weaknesses could result in a misstatement of the account balances or disclosures representing material misstatements in our annual or interim consolidated financial statements that would not be prevented or detected.

                Audit of the Effectiveness of Internal Control over Financial Reporting

                Our independent registered public accounting firm, PricewaterhouseCoopers Auditores Independentes – PwC, has audited the effectiveness of our internal control over financial reporting, as stated in their report, which is included herein.

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Remediation

                Our management has been actively engaged in the design and implementation of remediation efforts to address the identified material weaknesses, as well as other identified areas of risk.  The remediation efforts outlined below, which have been implemented or are in the process of implementation, are intended to address both the identified material weaknesses and related areas. The design and implementation of these and other remedial efforts are the responsibility of our management.

                Notwithstanding the identified material weaknesses, our management has concluded that our consolidated financial statements fairly present, in all material respects, our financial condition and results of operations at and for the periods presented, and the impact of all facts known to our management to date has been reflected in the consolidated financial statements.

Management Override

We are implementing the following remedial measures in response to the material weakness relating to management override of controls:

·We created a new Governance, Risk and Compliance Department, to improve Petrobras’s procedures and guidelines, and to ensure such procedures and guidelines are being observed by Petrobras’s management and employees. The creation of a Governance, Risk and Compliance Department and the reflection of its work into our highest levels of decision-making demonstrates the firm commitment of senior management to the execution and monitoring of compliance programs (tone at the top). For further information about our new Governance, Risk and Compliance Department, see Item 6. “Directors, Senior Management and Employees—Executive Officers.”

·We have implemented measures to improve our governance and compliance systems aiming to ensure legal and procedural compliance and mitigate risks, including those related to fraud and corruption. This includes improvements in our hotline for receiving complaints, improved whistleblower protections, training programs for our employees and improved disciplinary proceedings.  For further information regarding our Corruption Prevention Program, Code of Ethics and Conduct Guide see Item 16B. “Code of Ethics.”

·We have engaged two independent law firms, one Brazilian and one American, to conduct an independent internal investigation regarding, among other matters, the nature, extent and impact of alleged improper actions by former Petrobras personnel. In December 2014, our board of directors formed a Special Committee to serve as a reporting line with respect to the investigations by these firms. The Special Committee is composed of three members: two independent individuals from outside Petrobras, a Brazilian and a non-Brazilian member, with notable technical expertise, in addition to Petrobras’s Chief Governance, Risk and Compliance Officer. We expect the investigations to result in recommendations for further improvements in internal controls.  For more information about the Special Committee, see Item 6. “Directors, Senior Management and Employees—Other Committees.”

·We are updating our procurement guidelines and corporate procedures to expressly require an analysis of price proposals submitted by bidders, and a comparison with internal reference prices. 

·We are improving controls related to the review of the financial, tax, technical and legal terms of service contracts, prior to completion of the bidding process.

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·We are modifying our Investment Projects Corporate Procedures to require detailed terms for the duration and cost of projects from the commencement of the process for construction and assembly services.

·We are improving systematic monitoring of the physical and financial execution of our major investment projects, so the results are reviewed on a centralized and integrated basis to facilitate the planning and control of these projects.

Property, Plant and Equipment

We are implementing the following remedial measures with respect to our controls relating to property, plant and equipment:

·Our management approved the creation of the Program for the Improvement of Management of our Supply Base (Programa de Melhorias na Gestão da Base de Fornecedores – PGBF), which is being developed with the support of a specialized external consultant to improve our criteria for registering contractors and suppliers. 

·We are in the process of evaluating and standardizing a specific internal control that will require a detailed report assessing the economic and financial condition of contractors and suppliers for our strategic projects. 

·We are also improving controls to require the regular and timely review of the outstanding balances of payments advanced to contractors and suppliers.

·We are strengthening controls over timely incorporation of projects for accounting purposes, with an emphasis on improving systematic monitoring of the physical and financial execution of our projects.

·We improved our internal controls by requiring the recognition of the totality of impairment losses identified in the recoverable amount of all Exploration and Production assets, regardless of the phase of the project. 

                Manual Journal Entries

In response to the material weakness relating to review and approval of manual journal entries, we are implementing adjustments to our control design by monitoring, on a monthly basis, changes in the ERP environment parameters, to eliminate any possibility that risks relating to the manual journal entry control will materialize.

                In addition to changes in our control design, approval of manual journal entries will occur in an automated solution system in the ERP through our Continuous Controls Monitoring (Monitoramento Contínuo de Controles – CCM), integrated into the module evaluation cycle of the GRC tool, which directs the request for approval of manual journal entries to the managers and verifies the timing required for confirmation of all the criteria that comprise the control design.

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   Access Management and Segregation of Duties

                Our management considers the design of the controls of the general environment of information technology and the business processes of the ERP system adequate, and believes that we present a structured model of governance, management and GRC tools in operation. We are implementing the following remedial measures in response to the material weakness relating to access management and segregation of duties:

·We are improving automated rules related to access management.

·Our management has developed measures to strengthen our internal controls over access to critical ERP functions and segregation of duties in ERP transactions, in order to improve these activities along with the responsible managers in each macro-process of our businesses.

·Our management is improving our compensating controls of segregation of duties in ERP transactions, and the expansion of the set of monitors and their respective automated reports that have already been developed and used to identify, monitor and treat any materialization of conflict, expanding them where there is a risk and occurrence of technically justifiable conflicts.

Changes in Internal Control Over Financial Reporting

                Changes in our internal control over financial reporting that occurred during fiscal 2014, as well as planned changes in such internal control, which have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting are described above under “Remediation.”

Item 16A.   Audit Committee Financial Expert

On June 17, 2005, our board of directors approved the appointment of an Audit Committee for purposes of the Sarbanes-Oxley Act of 2002. Mr. Luiz Nelson Guedes de Carvalho is the Audit Committee financial expert and he is independent, as defined in 17 CFR 240.10A-3.

Item 16B.    Code of Ethics

Our business and our relations with third parties are guided by ethical principles.  In 1998, our board of executive officers approved the Petrobras Code of Ethics, which was extended to all Petrobras subsidiaries, and which in 2002 was renamed to Petrobras System Code of Ethics.

In 2006, after undergoing a revision process with wide participation from our business segments, employees and subsidiaries, the current version of the Code of Ethics was approved by the board of executive officers and the board of directors.  The Code of Ethics is applicable to our workforce, executive officers and board of directors.  It is available on our website at http://www.investidorpetrobras.com.br/en/governance/code-of-ethics/.

Our executive officers further developed our ethics management through the creation of the Petrobras Ethics Commission in 2008 which has since become responsible for promoting corporate compliance with ethical principles, as well as acting as a forum for discussion of subjects related to ethics.

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In connection with our compliance programs, in July 2013, our board of executive officers approved our Corruption Prevention Program (Programa Petrobras de Prevenção da Corrupção - PPPC), which is focused on the prevention, detection and penalization of acts of fraud and corruption committed against Petrobras.  The program is managed across areas of Petrobras, and is designed to improve our governance structure and operational accountability and to foster our commitment to good governance. This program is currently managed by our Governance, Risk and Compliance Department.  A copy of our Corruption Prevention Program Manual is available on our website at http://www.investidorpetrobras.com.br/en/governance/petrobras-corruption-prevention-program/.

In November 2014, our board of executive officers also approved Petrobras’s Conduct Guide, which contains the guidelines to implement Petrobras System Code of Ethics (Code of Ethics) and other internal regulations. Petrobras’s Conduct Guide establishes the basic rules for ethical behavior and professional conduct to be adopted within Petrobras.  In February 2015, Petrobras’s procurement guidelines were amended to subject all of Petrobras’s suppliers and service providers to Petrobras’s Conduct Guide.

Item 16C.    Principal Accountant Fees and Services

Audit and Non-Audit Fees

The following table sets forth the fees billed to us by our independent auditors, PricewaterhouseCoopers Auditores Independentes, during the fiscal years ended December 31, 2014 and December 31, 2013:

	Year Ended December 31,
	2014	2013
	(U.S.$ thousand)
Audit fees	9,418	8,316
Audit-related fees	154	80
Tax fees	328	253
Total fees	9,899	8,649

                Audit fees in the above table are the fees billed by PricewaterhouseCoopers Auditores Independentes in connection with the audit of our annual financial statements (IFRS and Brazilian GAAP), interim reviews (IFRS and Brazilian GAAP), audits of our subsidiaries (IFRS and Brazilian GAAP, among others) and review of periodic documents filed with the SEC.  In 2014, audit fees included fees billed by PricewaterhouseCoopers Auditores Independentes, in the amount of U.S.$636 thousand, related to the audit of internal controls. “Audit-related fees” in the above table are the fees billed by PricewaterhouseCoopers Auditores Independentes for assurance and related services that are reasonably related to the performance of the audit or reviews of our financial statements and are not reported under “audit fees.”

Tax fees in the table above are fees billed by PricewaterhouseCoopers Auditores Independentes for services related to tax compliance reviews conducted in connection with the audit procedures on the financial statements for the years 2014 and 2013.

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Audit Committee Approval Policies and Procedures

Our Audit Committee has the authority to recommend pre-approval policies and procedures to our board of directors for the engagement of our independent auditor’s services.  At present, our board of directors has decided not to establish such pre-approval policies and procedures.  Our board of directors expressly approves on a case-by-case basis any engagement of our independent auditors for all services provided to our subsidiaries or to us.  Our bylaws prohibit our independent auditor from providing any consulting services to our subsidiaries or to us during the term of such auditor’s contract.

Item 16D.   Exemptions from the Listing Standards for Audit Committees

Under the listed company audit committee rules of the NYSE and the SEC, we must comply with Exchange Act Rule 10A-3, which requires that we establish an audit committee, composed of members of the board of directors, that meets specified requirements.  In reliance on the exemption in Rule 10A-3(b)(iv)(E), we have designated three members to our Audit Committee, Luiz Nelson Guedes de Carvalho, Luiz Augusto Fraga Navarro de Britto Filho and Roberto da Cunha Castello Branco, who are designees of the Brazilian federal government, which is our controlling shareholder and therefore one of our affiliates.  In our assessment, each of these members acts independently in performing the responsibilities of an audit committee member under the Sarbanes-Oxley Act and satisfies the other requirements of Exchange Act Rule 10A-3.

Item 16E.    Purchases of Equity Securities by the Issuer and Affiliated Purchasers

During the fiscal year ended December 31, 2014, neither any “affiliated purchaser,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act, nor we have purchased any of our equity securities.

Item 16F.    Change in Registrant’s Certifying Accountant

Not applicable.

Item 16G.   Corporate Governance

Comparison of Petrobras’s Corporate Governance Practices with NYSE Corporate Governance Requirements Applicable to U.S. Companies

Under the rules of the New York Stock Exchange, foreign private issuers are subject to a more limited set of corporate governance requirements than U.S. domestic issuers.  As a foreign private issuer, we must comply with four principal NYSE corporate governance rules:  (i) we must satisfy the requirements of Exchange Act Rule 10A-3; (ii) our Chief Executive Officer must promptly notify the NYSE in writing after any executive officer becomes aware of any material non-compliance with the applicable NYSE corporate governance rules; (iii) we must provide the NYSE with annual and interim written affirmations as required under the NYSE corporate governance rules; and (iv) we must provide a brief description of any significant differences between its corporate governance practices and those followed by U.S. companies under NYSE listing standards.

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The table below briefly describes the significant differences between our domestic practices and the NYSE corporate governance rules.

Section	New York Stock Exchange Corporate GovernanceRules for U.S. Domestic Issuers	Petrobras’s Practices
Director Independence
303A.01	Listed companies must have a majority of independent directors. “Controlled companies” are not required to comply with this requirement.	Petrobras is a controlled company because more than a majority of its voting power is controlled by the Brazilian federal government. As a controlled company, Petrobras would not be required to comply with the majority of independent directors requirement if it were a U.S. domestic issuer. There is no legal provision or policy that requires us to have independent directors.
303A.03	The non-management directors of each listed company must meet at regularly scheduled executive sessions without management.	With the exception of the CEO of the company (who is also a director), all of Petrobras’s directors are non-management directors. The internal regulation of Petrobras’s board of directors provides for the occurrence of an executive session without the presence of the CEO if a particular matter may represent a conflict of interests.
Nominating/Corporate Governance Committee
303A.04	Listed companies must have a nominating/corporate governance committee composed entirely of independent directors, with a written charter that covers certain minimum specified duties. “Controlled companies” are not required to comply with this requirement.	Petrobras does not have a nominating committee. Petrobras also does not have a corporate governance committee composed of directors. Petrobras’s board of directors develops, evaluates and approves corporate governance principles. As a controlled company, Petrobras would not be required to comply with the nominating/corporate governance committee requirement if it were a U.S. domestic issuer.
Compensation Committee
303A.05	Listed companies must have a compensation committee composed entirely of independent directors, with a written charter that covers certain minimum specified duties. “Controlled companies” are not required to comply with this requirement.	Petrobras has a committee that advises the board of directors with respect to compensation and management succession. There is no legal provision or policy that requires the members of this committee to be independent. As a controlled company, Petrobras would not be required to comply with the compensation committee requirement if it were a U.S. domestic issuer.
Audit Committee
303A.06 303A.07	Listed companies must have an audit committee with a minimum of three independent directors that satisfy the independence requirements of Rule 10A-3 under the Exchange Act, with a written charter that covers certain minimum specified duties.	Petrobras’s Audit Committee is an advisory committee to the board of directors and is composed of members that satisfy the independence requirements set forth in Rule 10A-3 under the Exchange Act. The Audit Committee has a written charter that sets forth its responsibilities that include, among other things: (i) strengthening ties with the external auditors, permitting closer supervision of their work and of issues regarding their competency and independence, (ii) assuring legal and regulatory compliance, including with regard to certification, internal controls, compliance procedures and ethics, and (iii) monitoring the financial position of the company, especially as to risks, internal auditing work and financial disclosure.
Equity Compensation Plans
303A.08	Shareholders must have the opportunity to vote for compensation plans through shares and material reviews, with limited exceptions as set forth by the NYSE’s rules.	Under the Brazilian Corporate Law, shareholder approval is required for the adoption and revision of any equity compensation plans. Petrobras does not currently have any equity compensation plans.

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Section	New York Stock Exchange Corporate GovernanceRules for U.S. Domestic Issuers	Petrobras’s Practices
Corporate Governance Guidelines
303A.09	Listed companies must adopt and disclose corporate governance guidelines.	Petrobras has a set of Corporate Governance Guidelines (Diretrizes de Governança Corporativa) that address director qualification standards, responsibilities, compensation, orientation, self-appraisals and access to management. The guidelines do not reflect the independence requirements set forth in Sections 303A.01 and 303A.02 of the NYSE rules. Certain portions of the guidelines, including the responsibilities and compensation sections, are not discussed with the same level of detail set forth in the commentaries to the NYSE rules. The guidelines are available on Petrobras’s website.
Code of Ethics for Directors, Officers and Employees
303A.10	Listed companies must adopt and disclose a code of business conduct and ethics for directors, officers and employees, and promptly disclose any waivers of the code for directors or executive officers.	Petrobras has a Code of Ethics (Código de Ética) and a Conduct Guide (Guia de Conduta), applicable to its directors, executive officers, senior management, employees, interns and service providers within the Petrobras group, and a Code of Good Practices (Código de Boas Práticas) applicable to its directors, executive officers and senior management. No waivers of the provisions of the Code of Ethics, Conduct Guide or Code of Good Practices are permitted. These documents are available on Petrobras’s website.
Certification Requirements
303A.12	Each listed company CEO must certify to the NYSE each year that he or she is not aware of any violation by the company of NYSE corporate governance listing standards.	Our CEO will promptly notify the NYSE in writing if any executive officer becomes aware of any material noncompliance with any applicable provisions of the NYSE corporate governance rules.

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PART III

Item 17.   Financial Statements

Not applicable.

Item 18.   Financial Statements

See pages F-2 through F-108, incorporated herein by reference.

Item 19.   Exhibits

No.	Description
1.1	Amended Bylaws of Petróleo Brasileiro S.A.-Petrobras, dated as of March 19, 2012 (incorporated by reference to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on April 30, 2014 (File No. 001-15106)).
2.1	Amended and Restated Deposit Agreement, dated as of January 3, 2012, among Petrobras, The Bank of New York Mellon, as depositary, and registered holders and beneficial owners from time to time of the ADSs, representing the common shares of Petrobras, and Form of ADR evidencing ADSs representing the common shares of Petrobras (incorporated by reference to Exhibit 2.1 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on April 2, 2012 (File Nos. 001-15106 and 001-33121)).
2.2	Amended and Restated Deposit Agreement, dated as of January 3, 2012, among Petrobras, The Bank of New York Mellon, as depositary, and registered holders and beneficial owners from time to time of the ADSs, representing the preferred shares of Petrobras, and Form of ADR evidencing ADSs representing the preferred shares of Petrobras (incorporated by reference to Exhibit 2.2 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on April 2, 2012 (File Nos. 001-15106 and 001-33121)).
2.3	Indenture, dated as of July 19, 2002, between Petrobras International Finance Company and JPMorgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.5 of the Registration Statement of Petrobras International Finance Company and Petrobras on Form F-3, filed with the Securities and Exchange Commission on July 5, 2002, and amendments to which were filed on July 19, 2002 and August 14, 2002 (File Nos. 333-92044 and 333-92044-01)).
2.4	Indenture, dated as of December 15, 2006, between Petrobras International Finance Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.9 to the Registration Statement of Petrobras and Petrobras International Finance Company on Form F-3, filed with the Securities and Exchange Commission on December 18, 2006 (File Nos. 333-139459 and 333-139459-01)).
2.5	Amended and Restated Second Supplemental Indenture, initially dated as of February 11, 2009, as amended and restated as of July 9, 2009, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon, as Trustee, relating to the 7.875% Global Notes due 2019 (incorporated by reference to Exhibit 2.33 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 20, 2010 (File Nos. 001-15106 and 001-33121)).
2.6	Amended and Restated Guaranty for the 7.875% Global Notes due 2019, initially dated as of February 11, 2009, as amended and restated as of July 9, 2009, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 2.34 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 20, 2010 (File Nos. 001-15106 and 001-33121)).
2.7	Third Supplemental Indenture, dated as of October 30, 2009, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon, as Trustee, relating to the 5.75% Global Notes due 2020 (incorporated by reference to Exhibit 2.35 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 20, 2010 (File Nos. 001-15106 and 001-33121)).
2.8	Fourth Supplemental Indenture, dated as of October 30, 2009, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon, as Trustee, relating to the 6.875% Global Notes due 2040 (incorporated by reference to Exhibit 2.36 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 20, 2010 (File Nos. 001-15106 and 001-33121)).
2.9	Guaranty for the 5.75% Global Notes due 2020, dated as of October 30, 2009, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 2.37 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 20, 2010 (File Nos. 001-15106 and 001-33121)).

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2.10	Guaranty for the 6.875% Global Notes due 2040, dated as of October 30, 2009, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 2.38 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 20, 2010 (File Nos. 001-15106 and 001-33121)).
2.11	Amended and Restated First Supplemental Indenture, initially dated as of November 1, 2007, as amended and restated as of January 11, 2008, as amended and restated as of March 31, 2010, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon, as Trustee, relating to the 5.875% Global Notes due 2018 (incorporated by reference to Exhibit 2.15 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 20, 2010 (File Nos. 001-15106 and 001-33121)).
2.12	Amended and Restated Fifth Supplemental Indenture, initially dated as of October 6, 2006, as amended and restated as of February 7, 2007, as amended and restated as of March 31, 2010, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee, relating to the 6.125% Global Notes due 2016 (incorporated by reference to Exhibit 2.14 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 20, 2010 (File Nos. 001-15106 and 001-33121)).
2.13	Fifth Supplemental Indenture, dated as of January 27, 2011, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon, as Trustee, relating to the 3.875% Global Notes due 2016 (incorporated by reference to Exhibit 2.39 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 26, 2011 (File Nos. 001-15106 and 001-33121)).
2.14	Guaranty for the 3.875% Global Notes due 2016, dated as of January 27, 2011, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 2.40 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 26, 2011 (File Nos. 001-15106 and 001-33121)).
2.15	Eighth Supplemental Indenture, dated as of December 9, 2011, among Petrobras International Finance Company, Petrobras, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, London Branch, as Principal Paying Agent and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg Paying Agent, relating to the 4.875% Global Notes due 2018 (incorporated by reference to Exhibit 4.2 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on December 9, 2011 (File Nos. 001-15106 and 001-33121)).
2.16	Ninth Supplemental Indenture, dated as of December 9, 2011, among Petrobras International Finance Company, Petrobras, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, London Branch, as Principal Paying Agent and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg Paying Agent, relating to the 5.875% Global Notes due 2022 (incorporated by reference to Exhibit 4.5 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on December 9, 2011 (File Nos. 001-15106 and 001-33121)).
2.17	Guaranty for the 4.875% Global Notes due 2018, dated as of December 9, 2011, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.1 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on December 9, 2011 (File Nos. 001-15106 and 001-33121)).
2.18	Guaranty for the 5.875% Global Notes due 2022, dated as of December 9, 2011, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.4 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on December 9, 2011 (File Nos. 001-15106 and 001-33121)).
2.19	Tenth Supplemental Indenture, dated as of December 12, 2011, among Petrobras International Finance Company, Petrobras, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, London Branch, as Principal Paying Agent and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg Paying Agent, relating to the 6.250% Global Notes due 2026 (incorporated by reference to Exhibit 4.2 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on December 12, 2011 (File Nos. 001-15106 and 001-33121)).
2.20	Guaranty for the 6.250% Global Notes due 2026, dated as of December 12, 2011, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.1 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on December 12, 2011 (File Nos. 001-15106 and 001-33121)).
2.21	Amended and Restated Sixth Supplemental Indenture, dated as of February 6, 2012, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon, as Trustee, relating to the 5.375% Global Notes due 2021 (incorporated by reference to Exhibit 4.2 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on February 6, 2012 (File Nos. 001-15106 and 001-33121)).
2.22	Amended and Restated Seventh Supplemental Indenture, dated as of February 6, 2012, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon, as Trustee, relating to the 6.750% Global Notes due 2041 (incorporated by reference to Exhibit 4.5 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on February 6, 2012 (File Nos. 001-15106 and 001-33121)).

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2.23	Twelfth Supplemental Indenture, dated as of February 6, 2012, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon, as Trustee, relating to the 3.500% Global Notes due 2017 (incorporated by reference to Exhibit 4.11 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on February 6, 2012 (File Nos. 001-15106 and 001-33121)).
2.24	Amended and Restated Guaranty for the 5.375% Global Notes due 2021, dated as of February 6, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.1 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on February 6, 2012 (File Nos. 001-15106 and 001-33121)).
2.25	Amended and Restated Guaranty for the 6.750% Global Notes due 2041, dated as of February 6, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.4 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on February 6, 2012 (File Nos. 001-15106 and 001-33121)).
2.26	Guaranty for the 3.500% Global Notes due 2017, dated as of February 6, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.10 to Form 6-K of Petrobras and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on February 6, 2012 (File Nos. 001-15106 and 001-33121)).
2.27	Sixth Supplemental Indenture, dated as of February 10, 2012, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 2.11 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on April 2, 2012 (File Nos. 001-15106 and 001-33121)).
2.28	Thirteenth Supplemental Indenture, dated as of February 10, 2012, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 2.60 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on April 2, 2012 (File Nos. 001-15106 and 001-33121)).
2.29	Amended and Restated Guaranty for the 7.75% Global Notes due 2014, dated as of February 10, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 2.29 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on April 2, 2012 (File Nos. 001-15106 and 001-33121)).
2.30	Amended and Restated Guaranty for the 6.125% Global Notes due 2016, dated as of February 10, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 2.31 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on April 2, 2012 (File Nos. 001-15106 and 001-33121)).
2.31	Amended and Restated Guaranty for the 8.375% Global Notes due 2018, dated as of February 10, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 2.16 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on April 2, 2012 (File Nos. 001-15106 and 001-33121)).
2.32	Amended and Restated Guaranty for the 5.875% Global Notes due 2018, dated as of February 10, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 2.33 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on April 2, 2012 (File Nos. 001-15106 and 001-33121)).
2.33	Amended and Restated Third Supplemental Indenture, initially dated as of December 10, 2003, as amended and restated as of March 31, 2010, and as further amended and restated as of March 25, 2013, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee, relating to the 8.375% Global Notes due 2018 (incorporated by reference to Exhibit 2.41 to the Annual Report on Form 20-F of Petrobras, filed with the Securities and Exchange Commission on April 29, 2013 (File No. 001-15106).
2.34	Amended and Restated Fourth Supplemental Indenture, initially dated as of September 15, 2004, as amended and restated as of March 31, 2010, and as further amended and restated as of March 25, 2013, among Petrobras International Finance Company, Petrobras and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee, relating to the 7.75% Global Notes due 2014 (incorporated by reference to Exhibit 2.42 to the Annual Report on Form 20-F of Petrobras, filed with the Securities and Exchange Commission on April 29, 2013 (File No. 001-15106).

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2.35	Indenture, dated as of August 29, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.3 to the Registration Statement of Petrobras, Petrobras International Finance Company and Petrobras Global Finance B.V. on Form F-3, filed with the Securities and Exchange Commission on August 29, 2012 (File Nos. 333-183618, 333-183618-01 and 333-183618-02))
2.36	Indenture, dated as of August 29, 2012, between Petrobras Global Finance B.V. and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form F-3 of Petrobras, Petrobras International Finance Company and Petrobras Global Finance B.V., filed with the Securities and Exchange Commission on August 29, 2012 (File Nos. 333-183618, 333-183618-01 and 333-183618-02))
2.37	First Supplemental Indenture, dated as of October 1, 2012, among Petrobras Global Finance B.V., Petrobras, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, London Branch, as principal paying agent, and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg paying agent, relating to the 3.25% Global Notes due 2019 (incorporated by reference to Exhibit 4.2 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on October 1, 2012 (File No. 001-15106)).
2.38	Second Supplemental Indenture, dated as of October 1, 2012, among Petrobras Global Finance B.V., Petrobras, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, London Branch, as principal paying agent, and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg paying agent, relating to the 4.25% Global Notes due 2023 (incorporated by reference to Exhibit 4.5 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on October 1, 2012 (File No. 001-15106)).
2.39	Third Supplemental Indenture, dated as of October 1, 2012, among Petrobras Global Finance B.V., Petrobras, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, London Branch, as principal paying agent, and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg paying agent, relating to the 5.375% Global Notes due 2029 (incorporated by reference to Exhibit 4.8 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on October 1, 2012 (File No. 001-15106)).
2.40	Guaranty for the 3.25% Global Notes due 2019, dated as of October 1, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.1 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on October 1, 2012 (File No. 001-15106)).
2.41	Guaranty for the 4.25% Global Notes due 2023, dated as of October 1, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.4 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on October 1, 2012 (File No. 001-15106)).
2.42	Guaranty for the 5.375% Global Notes due 2029, dated as of October 1, 2012, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.7 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on October 1, 2012 (File No. 001-15106)).
2.43	Fourth Supplemental Indenture, dated as of May 20, 2013, between Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the 2.000% Global Notes due 2016 (incorporated by reference to Exhibit 4.2 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.44	Fifth Supplemental Indenture, dated as of May 20, 2013, between Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the 3.000% Global Notes due 2019 (incorporated by reference to Exhibit 4.5 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.45	Sixth Supplemental Indenture, dated as of May 20, 2013, between Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the 4.375% Global Notes due 2023 (incorporated by reference to Exhibit 4.8 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.46	Seventh Supplemental Indenture, dated as of May 20, 2013, between Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the 5.625% Global Notes due 2043 (incorporated by reference to Exhibit 4.11 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.47	Eighth Supplemental Indenture, dated as of May 20, 2013, between Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the Floating Rate Global Notes due 2016 (incorporated by reference to Exhibit 4.14 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.48	Ninth Supplemental Indenture, dated as of May 20, 2013, between Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the Floating Rate Global Notes due 2019 (incorporated by reference to Exhibit 4.17 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.49	Guaranty for the 2.000% Global Notes due 2016, dated as of May 20, 2013, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.1 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.50	Guaranty for the 3.000% Global Notes due 2019, dated as of May 20, 2013, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.4 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).

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2.51	Guaranty for the 4.375% Global Notes due 2023, dated as of May 20, 2013, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.7 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.52	Guaranty for the 5.625% Global Notes due 2043, dated as of May 20, 2013, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.10 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.53	Guaranty for the Floating Rate Global Notes due 2016, dated as of May 20, 2013, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.13 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.54	Guaranty for the Floating Rate Global Notes due 2019, dated as of May 20, 2013, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.16 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on May 20, 2013(File No. 001-15106)).
2.55	Tenth Supplemental Indenture, dated as of January 14, 2014, among Petrobras Global Finance B.V., Petrobras, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, London Branch, as principal paying agent, and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg paying agent, relating to the 2.750% Global Notes due 2018 (incorporated by reference to Exhibit 4.2 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 14, 2014 (File No. 001-15106)).
2.56	Eleventh Supplemental Indenture, dated as of January 14, 2014, among Petrobras Global Finance B.V., Petrobras, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, London Branch, as principal paying agent, and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg paying agent, relating to the 3.750% Global Notes due 2021 (incorporated by reference to Exhibit 4.5 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 14, 2014 (File No. 001-15106)).
2.57	Twelfth Supplemental Indenture, dated as of January 14, 2014, among Petrobras Global Finance B.V., Petrobras, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, London Branch, as principal paying agent, and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg paying agent, relating to the 4.750% Global Notes due 2025 (incorporated by reference to Exhibit 4.8 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 14, 2014 (File No. 001-15106)).
2.58	Thirteenth Supplemental Indenture, dated as of January 14, 2014, among Petrobras Global Finance B.V., Petrobras, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, London Branch, as principal paying agent, and The Bank of New York Mellon (Luxembourg) S.A., as Luxembourg paying agent, relating to the 6.625% Global Notes due 2034 (incorporated by reference to Exhibit 4.11 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 14, 2014 (File No. 001-15106)).
2.59	Guaranty for the 2.750% Global Notes due 2018, dated as of January 14, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.1 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 14, 2014 (File No. 001-15106)).
2.60	Guaranty for the 3.750% Global Notes due 2021, dated as of January 14, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.4 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 14, 2014 (File No. 001-15106)).
2.61	Guaranty for the 4.750% Global Notes due 2025, dated as of January 14, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.7 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 14, 2014 (File No. 001-15106)).
2.62	Guaranty for the 6.625% Global Notes due 2034, dated as of January 14, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.10 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 14, 2014 (File No. 001-15106)).
2.63	Fourteenth Supplemental Indenture, dated as of March 17, 2014, among Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the 3.250% Global Notes due 2017 (incorporated by reference to Exhibit 4.2 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.64	Fifteenth Supplemental Indenture, dated as of March 17, 2014, among Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the 4.875% Global Notes due 2020 (incorporated by reference to Exhibit 4.5 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.65	Sixteenth Supplemental Indenture, dated as of March 17, 2014, among Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the 6.250% Global Notes due 2024 (incorporated by reference to Exhibit 4.8 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.66	Seventeenth Supplemental Indenture, dated as of March 17, 2014, among Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the 7.250% Global Notes due 2044 (incorporated by reference to Exhibit 4.11 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).

188

 

2.67	Eighteenth Supplemental Indenture, dated as of March 17, 2014, among Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the Floating Rate Global Notes due 2017 (incorporated by reference to Exhibit 4.14 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.68	Nineteenth Supplemental Indenture, dated as of March 17, 2014, among Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee, relating to the Floating Rate Global Notes due 2020 (incorporated by reference to Exhibit 4.17 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.69	Guaranty for the 3.250% Global Notes due 2017, dated as of March 17, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.1 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.70	Guaranty for the 4.875% Global Notes due 2020, dated as of March 17, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.4 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.71	Guaranty for the 6.250% Global Notes due 2024, dated as of March 17, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.7 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.72	Guaranty for the 7.250% Global Notes due 2044, dated as of March 17, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.10 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.73	Guaranty for the Floating Rate Global Notes due 2017, dated as of March 17, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.13 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.74	Guaranty for the Floating Rate Global Notes due 2020, dated as of March 17, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.16 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on March 17, 2014 (File No. 001-15106)).
2.75	Seventh Supplemental Indenture, dated as of December 28, 2014, among Petrobras International Finance Company S.A., Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.1 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 15, 2015 (File No. 001-15106)).
2.76	Fourteenth Supplemental Indenture, dated as of December 28, 2014, among Petrobras International Finance Company S.A., Petrobras Global Finance B.V., Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.2 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 15, 2015 (File No. 001-15106)).
2.77	First Amendment to the Guaranties, dated as of December 28, 2014, between Petrobras and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.3 to Form 6-K of Petrobras, furnished to the Securities and Exchange Commission on January 15, 2015 (File No. 001-15106)).
2.78	Assignment Agreement, dated as of September 3, 2010, among Petrobras, the Brazilian federal government and the National Petroleum, Natural Gas and Biofuels Agency (incorporated by reference to Exhibit 2.47 to the Annual Report on Form 20-F of Petrobras and Petrobras International Finance Company, filed with the Securities and Exchange Commission on May 26, 2011 (File Nos. 001-15106 and 001-33121)).
2.79	Production Sharing Agreement, dated as of December 2, 2013, among Petrobras, Shell Brasil Petróleo Ltda., Total E&P do Brasil Ltda., CNODC Brasil Petróleo e Gás Ltda. and CNOOC Petroleum Brasil Ltda.,the Brazilian federal government, Pré-Sal Petróleo S.A. - PPSA and the National Petroleum, Natural Gas and Biofuels Agency (incorporated by reference to the Annual Report on Form 20-F of Petrobras, filed with the Securities and Exchange Commission on April 30, 2014 (File No. 001-15106)).
	The amount of long-term debt securities of Petrobras authorized under any given instrument does not exceed 10% of its total assets on a consolidated basis. Petrobras hereby agrees to furnish to the SEC, upon its request, a copy of any instrument defining the rights of holders of its long-term debt or of its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed.
4.1	Form of Concession Agreement for Exploration, Development and Production of crude oil and natural gas executed between Petrobras and the ANP (incorporated by reference to Exhibit 10.1 of Petrobras’s Registration Statement on Form F-1 filed with the Securities and Exchange Commission on July 14, 2000 (File No. 333-12298)).
4.2	Purchase and Sale Agreement of natural gas, executed between Petrobras and Yacimientos Petroliferos Fiscales Bolivianos-YPFB (together with and English version) (incorporated by reference to Exhibit 10.2 to Petrobras’s Registration Statement on Form F-1 filed with the Securities and Exchange Commission on July 14, 2000 (File No. 333-12298)).
8.1	List of subsidiaries.
12.1	Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
13.1	Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
15.1	Consent letter of PwC.
15.2	Consent letter of DeGolyer and MacNaughton.
99.1	Third Party Reports of DeGolyer and MacNaughton.

189

 

SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant hereby certifies that it meets all the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Rio de Janeiro, on May 15, 2015.

	Petróleo Brasileiro S. A. PETROBRAS
By:	/s/ Aldemir Bendine
	Name: Aldemir Bendine
	Title: Chief Executive Officer
By:	/s/ Ivan de Souza Monteiro
	Name: Ivan de Souza Monteiro
	Title: Chief Financial Officer and Chief Investor
	Relations Officer

190

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated financial statements as of

December 31, 2014, 2013 and 2012 with report of independent registered public accounting firm

 

Petróleo Brasileiro S.A. – Petrobras

Index

(Expressed in millions of US Dollars, unless otherwise indicated)

Report of Independent Registered Public Accounting Firm		F-3
Consolidated Statement of Financial Position		F-4
Consolidated Statement of Income		F-5
Consolidated Statement of Comprehensive Income		F-6
Consolidated Statement of Cash Flows		F-7
Consolidated Statement of Changes in Shareholders’ Equity		F-8
Notes to the financial statements		F-9
1.	The Company and its operations	F-9
2.	Basis of preparation	F-9
3.	The “Lava Jato (Car Wash) Operation” and its effects on the Company	F-9
4.	Summary of significant accounting policies	F-18
5.	Critical accounting policies: key estimates and judgments	F-28
6.	New standards and interpretations	F-34
7.	Cash and cash equivalents and Marketable securities	F-35
8.	Trade and other receivables	F-36
9.	Inventories	F-38
10.	Disposal of assets and legal mergers	F-38
11.	Investments	F-41
12.	Property, plant and equipment	F-45
13.	Intangible assets	F-48
14.	Impairment	F-50
15.	Exploration for and evaluation of oil and gas reserves	F-54
16.	Trade payables	F-56
17.	Finance debt	F-56
18.	Leases	F-59
19.	Related party transactions	F-60
20.	Provision for decommissioning costs	F-61
21.	Taxes	F-62
22.	Employee benefits (Post-Employment)	F-65
23.	Shareholders’ equity	F-73
24.	Sales revenues	F-75
25.	Other expenses, net	F-75
26.	Costs and Expenses by nature	F-76
27.	Net finance income (expense)	F-76
28.	Supplemental information on statement of cash flows	F-76
29.	Segment Information	F-77
30.	Provisions for legal proceedings	F-82
31.	Commitment to purchase natural gas	F-87
32.	Collateral for crude oil exploration concession agreements	F-87
33.	Risk management	F-87
34.	Fair value of financial assets and liabilities	F-93
35.	Subsequent events	F-94
36.	Information Related to Guaranteed Securities Issued by Subsidiaries	F-95
Supplementary information on Oil and Gas Exploration and Production (unaudited)		F-96

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

Petróleo Brasileiro S.A. - Petrobras

In our opinion, the accompanying consolidated statement of financial position and the related consolidated statements of income, comprehensive income, changes in equity and cash flows present fairly, in all material respects, the financial position of Petróleo Brasileiro S.A. - Petrobras and its subsidiaries (the “Company”) at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.  Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because the following material weaknesses in internal control over financial reporting existed as of that date:

· inadequate “tone at the top” regarding internal controls, failure to communicate the ethical values prescribed in the Company’s Code of Conduct, and lack of an effective whistleblower program;  

· failure to identify the need to write down payments advanced to contractors and suppliers that will not result in future economic benefits and failure to identify the need to recognize expenses related to the termination of these contracts;  

· deficiencies related to monitoring the need to reclassify certain property, plant and equipment from assets under construction to completed property, plant and equipment;  

· failure to recognize impairment losses in five Exploration and Production projects that were in their initial planning phase, for which there were no estimated future cash flows;  

· failure to timely monitor possible changes in the control parameters of the enterprise resource planning (“ERP”) environment, which are used to support the internal controls related to the review and approval of manual journal entries, and deficiencies in the design of the internal control over review and approval of manual journal entries; and  

· deficiencies in control operations related to granting access procedures and segregation of duties analysis at the business process level.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weaknesses referred to above are described in Management Report on Internal Control over Financial Reporting appearing under Item 15.  We considered these material weaknesses in determining the nature, timing, and extent of audit tests applied in our audit of the 2014 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.  The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in management's report referred to above.  Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 3 to the financial statements, the Company wrote off US$ 2,527 million of overpayments on the acquisition of property plant and equipment incorrectly capitalized according to testimony obtained from Brazilian criminal investigations.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Rio de Janeiro, May 15, 2015.

/s/ PricewaterhouseCoopers Auditores Independentes
PricewaterhouseCoopers Auditores Independentes

F-3

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statement of Financial Position

December 31, 2014 and 2013 (In millions of US Dollars)

Assets	Note	12.31.2014	12.31.2013	Liabilities	Note	12.31.2014	12.31.2013
Current assets				Current liabilities
Cash and cash equivalents	7	16,655	15,868	Trade payables	16	9,760	11,919
Marketable securities	7	9,323	3,885	Finance debt	17	11,868	8,001
Trade and other receivables, net	8	7,969	9,670	Finance lease obligations	18	16	16
Inventories	9	11,466	14,225	Income taxes payable	21.1	247	281
Recoverable income taxes	21.1	1,063	1,060	Other taxes payable	21.1	4,064	4,669
Other recoverable taxes	21.1	2,748	3,911	Dividends payable	23.5	−	3,970
Advances to suppliers		423	683	Payroll, profit sharing and related charges		2,066	2,052
Other current assets		1,180	946	Pension and medical benefits	22	796	816
		50,827	50,248	Others		2,301	2,429
						31,118	34,153
Assets classified as held for sale	10.2	5	2,407	Liabilities on assets classified as held for sale	10.2	−	1,073
		50,832	52,655			31,118	35,226
Non-current assets				Non-current liabilities
Long-term receivables				Finance debt	17	120,218	106,235
Trade and other receivables, net	8	5,437	4,532	Finance lease obligations	18	56	73
Marketable securities	7	109	131	Deferred income taxes	21.2	3,031	9,906
Judicial deposits	30.1	2,682	2,504	Pension and medical benefits	22	16,491	11,757
Deferred income taxes	21.2	1,006	1,130	Provisions for legal proceedings	30.1	1,540	1,246
Other tax assets	21.1	4,008	5,380	Provision for decommissioning costs	20	8,267	7,133
Advances to suppliers		2,409	3,230	Others		988	724
Others		3,212	1,875			150,591	137,074
		18,863	18,782
				Total liabilities		181,709	172,300
				Shareholders' equity	23.1
Investments	11	5,753	6,666	Share capital (net of share issuance costs)		107,101	107,092
Property, plant and equipment	12	218,730	227,901	Change in interest in subsidiaries		148	674
Intangible assets	13	4,509	15,419	Profit reserves		66,423	73,795
		247,855	268,768	Accumulated other comprehensive (deficit)		(57,400)	(33,034)
				Attributable to the shareholders of Petrobras		116,272	148,527
				Non-controlling interests		706	596
				Total equity		116,978	149,123
Total assets		298,687	321,423	Total liabilities and shareholder's equity		298,687	321,423
The Notes form an integral part of these Financial Statements.

F-4

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statement of Income

December 31, 2014, 2013 and 2012 (In millions of US Dollars, unless otherwise indicated)

	Note	2014	2013	2012
Sales revenues	24	143,657	141,462	144,103
Cost of sales		(109,477)	(108,834)	(108,276)
Gross profit		34,180	32,628	35,827
Income (expenses)
Selling expenses		(6,827)	(4,904)	(4,927)
General and administrative expenses		(4,756)	(4,982)	(5,034)
Exploration costs	15	(3,058)	(2,959)	(3,994)
Research and development expenses		(1,099)	(1,132)	(1,143)
Other taxes		(760)	(780)	(386)
Impairment of assets	14	(16,823)	(544)	(137)
Write-off - overpayments incorrectly capitalized	3	(2,527)	−	−
Other expenses, net	25	(5,293)	(1,113)	(3,306)
		(41,143)	(16,414)	(18,927)
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
Finance income		1,949	1,815	3,659
Finance expenses		(3,923)	(2,673)	(2,016)
Foreign exchange and inflation indexation charges		339	(1,933)	(3,569)
Net finance income (expense)	27	(1,635)	(2,791)	(1,926)
Share of earnings in equity-accounted investments	11.2	218	507	43
Profit sharing	22.7	(444)	(520)	(524)
Net income (loss) before income taxes		(8,824)	13,410	14,493
Income taxes	21.3	1,321	(2,578)	(3,562)
Net income (loss)		(7,503)	10,832	10,931
Net income (loss) attributable to:
Shareholders of Petrobras		(7,367)	11,094	11,034
Non-controlling interests		(136)	(262)	(103)
		(7,503)	10,832	10,931
Basic and diluted earnings (loss) per weighted-average of common and preferred share - in U.S. dollars	23.6	(0.56)	0.85	0.85
The Notes form an integral part of these Financial Statements.

F-5

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statement of Comprehensive Income

December 31, 2014, 2013 and 2012 (In millions of US Dollars)

	2014	2013	2012
Net income (loss)	(7,503)	10,832	10,931
Items that will not be reclassified to the statement of income:
Actuarial gains (losses) on defined benefit pension plans	(5,947)	7,248	(4,693)
Deferred income tax	1,157	(2,153)	1,533
Cumulative translation adjustments	(15,606)	(20,397)	(14,049)
	(20,396)	(15,302)	(17,209)
Items that may be reclassified subsequently to the statement of income:
Unrealized gains / (losses) on available-for-sale securities
Recognized in shareholders' equity	−	1	498
Reclassified to the statement of income	−	(44)	(714)
Deferred income tax	−	15	72
	−	(28)	(144)
Unrealized gains / (losses) on cash flow hedge - highly probable future exports
Recognized in shareholders' equity	(6,443)	(6,226)	−
Reclassified to the statement of income	702	303	−
Deferred income tax	1,953	2,012	−
	(3,788)	(3,911)	−
Unrealized gains / (losses) on cash flow hedge - others
Recognized in shareholders' equity	6	9	(3)
Reclassified to the statement of income	1	9	7
Deferred income tax	−	−	1
	7	18	5
Share of other comprehensive income (losses) in equity-accounted investments	(263)	(265)	−
Total other comprehensive income (loss):	(24,440)	(19,488)	(17,348)
Total comprehensive income (loss)	(31,943)	(8,656)	(6,417)
Comprehensive income (loss) attributable to:
Shareholders of Petrobras	(31,729)	(8,263)	(6,136)
Non-controlling interests	(214)	(393)	(281)
Total comprehensive income (loss)	(31,943)	(8,656)	(6,417)
The Notes form an integral part of these Financial Statements.

F-6

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statement of Cash Flows

December 31, 2014, 2013 and 2012 (In millions of US Dollars)

	2014	2013	2012
Cash flows from Operating activities
Net income (loss) attributable to the shareholders of Petrobras	(7,367)	11,094	11,034
Adjustments for:
Non-controlling interests	(136)	(262)	(103)
Share of earnings in equity-accounted investments	(218)	(507)	(43)
Depreciation, depletion and amortization	13,023	13,188	11,119
Impairment of assets	16,823	544	137
Inventory write-down to net realizable value	1,015	580	742
Exploration expenditures written off	2,178	1,892	2,847
Write-off - overpayments incorrectly capitalized	2,527	−	−
Allowance for impairment of trade receivables	2,378	73	39
(Gains) losses on disposal of assets / write-offs of non-current assets, E&P areas returned and cancelled projects	481	(1,745)	2
Foreign exchange variation, indexation and finance charges	3,571	3,167	4,308
Deferred income taxes, net	(3,045)	402	1,266
Pension and medical benefits (actuarial expense)	2,022	2,566	2,091
Decrease (Increase) in assets
Trade and other receivables, net	(2,507)	(1,142)	(1,522)
Inventories	570	(2,128)	(1,864)
Other assets	(2,803)	(303)	(2,028)
Increase (Decrease) in liabilities
Trade payables	(1,211)	1,108	1,039
Taxes payable	(1,245)	(1,517)	(151)
Pension and medical benefits	(834)	(796)	(735)
Other liabilities	1,410	75	(290)
Net cash provided by operating activities	26,632	26,289	27,888
Cash flows from Investing activities
Capital expenditures	(34,808)	(45,110)	(40,802)
Investments in investees	(329)	(199)	(146)
Proceeds from disposal of assets (divestment)	3,744	3,820	276
Divestment (investment) in marketable securities	(5,469)	5,718	2,051
Dividends received	387	146	241
Net cash (used in) investing activities	(36,475)	(35,625)	(38,379)
Cash flows from Financing activities
Acquisition of Non-controlling interest	(98)	(70)	255
Financing and loans, net:
Proceeds from long-term financing	31,050	39,542	25,205
Repayment of principal	(10,031)	(18,455)	(11,347)
Repayment of interest	(5,995)	(5,066)	(4,772)
Dividends paid	(3,918)	(2,656)	(3,272)
Net cash provided by financing activities	11,008	13,295	6,069
Effect of exchange rate changes on cash and cash equivalents	(378)	(1,611)	(1,115)
Net increase (decrease) in cash and cash equivalents	787	2,348	(5,537)
Cash and cash equivalents at the beginning of the year	15,868	13,520	19,057
Cash and cash equivalents at the end of the year	16,655	15,868	13,520
The Notes form an integral part of these Financial Statements.

F-7

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statement of Changes in Shareholders’ Equity

December 31, 2014, 2013 and 2012 (In millions of US Dollars)

	Share capital (net of share issuance costs)			Accumulated other comprehensive income (deficit)				Profit Reserves
	Share Capital	Share issuance costs	Change in interest in subsidiaries	Cumulative translation adjustment	Cash flow hedge - highly probable future exports	Actuarial gains (losses) on defined benefit pension plans	Other comprehensive income (loss)	Legal	Statutory	Tax incentives	Profit retention	Retained earnings	Shareholders' equity attributable to shareholders of Petrobras	Non-controlling interests	Total consolidated shareholders' equity
Balance at December 31, 2011	107,355	(279)	595	7,697	−	(4,440)	246	6,812	1,108	727	51,577	(82)	171,316	1,272	172,588
Capital increase with reserves	7									(7)			−		−
Realization of deemed cost							(5)					5	−		−
Change in interest in subsidiaries			33										33	270	303
Net income												11,034	11,034	(103)	10,931
Other comprehensive income				(13,871)		(3,160)	(139)						(17,170)	(178)	(17,348)
Appropriations:													−		−
Allocation of net income								552	537	9	5,442	(6,540)	−		−
Dividends												(4,499)	(4,499)	(109)	(4,608)
	107,362	(279)	628	(6,174)	−	(7,600)	102	7,364	1,645	729	57,019	(82)	160,714	1,152	161,866
Balance at December 31, 2012		107,083	628				(13,672)					66,675	160,714	1,152	161,866
Capital increase with reserves	9									(9)			−	−	−
Realization of deemed cost							(5)					5	−		−
Change in interest in subsidiaries			46										46	(102)	(56)
Net income												11,094	11,094	(262)	10,832
Other comprehensive income				(20,266)	(3,911)	5,095	(275)						(19,357)	(131)	(19,488)
Appropriations:													−		−
Allocation of net income								555	537	9	5,946	(7,047)	−		−
Dividends												(3,970)	(3,970)	(61)	(4,031)
	107,371	(279)	674	(26,440)	(3,911)	(2,505)	(178)	7,919	2,182	729	62,965	−	148,527	596	149,123
Balance at December 31, 2013		107,092	674				(33,034)					73,795	148,527	596	149,123
Capital increase with reserves	9									(9)			−		−
Realization of deemed cost							(4)					4	−		−
Change in interest in subsidiaries			(526)										(526)	393	(133)
Net income (loss)												(7,367)	(7,367)	(136)	(7,503)
Other comprehensive income (loss)				(15,528)	(3,788)	(4,790)	(256)						(24,362)	(78)	(24,440)
Appropriations:													−		−
Transfer from reserves											(7,363)	7,363	−		−
Dividends													−	(69)	(69)
	107,380	(279)	148	(41,968)	(7,699)	(7,295)	(438)	7,919	2,182	720	55,602	−	116,272	706	116,978
Balance at December 31, 2014		107,101	148				(57,400)					66,423	116,272	706	116,978
The Notes form an integral part of these Financial Statements.

F-8

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

1.The Company and its operations 

Petróleo Brasileiro S.A. - Petrobras is dedicated, directly or through its subsidiaries  (referred to jointly as “Petrobras” or “the Company”) to prospecting, drilling, refining, processing, trading and transporting crude oil from producing onshore and offshore oil fields and from shale or other rocks, as well as oil products, natural gas and other liquid hydrocarbons. In addition, Petrobras carries out energy related activities, such as research, development, production, transport, distribution and trading of all forms of energy, as well as other related or similar activities. The Company’s head office is located in Rio de Janeiro – RJ, Brazil.

2.Basis of preparation

2.1.Statement of compliance and authorization of financial statements

These consolidated financial statements have been prepared and are being presented in accordance with the International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). The information is presented in U.S. dollars.

These financial statements have been prepared under the historical cost convention, as modified by available-for-sale financial assets, financial assets and financial liabilities measured at fair value and certain current and non-current assets and liabilities, as set out in the summary of significant accounting policies.

The annual consolidated financial statements were approved and authorized for issue by the Company’s Board of Directors in a meeting held on April 22, 2015.

2.2.Functional and presentation currency

The functional currency of Petrobras and all of its Brazilian subsidiaries is the Brazilian Real. The functional currency of most of the Petrobras entities that operate outside Brazil is the U.S. dollar. The functional currency of Petrobras Argentina is the Argentine Peso.

Petrobras has selected the U.S. Dollar as its presentation currency. The financial statements have been translated from the functional currency (Brazilian Real) into the presentation currency (U.S. Dollar) in accordance with IAS 21 – “The effects of changes in foreign exchange rates”. All assets and liabilities are translated into U.S. dollars at the closing exchange rate at the date of the financial statements; income and expenses, as well as the cash flows are translated into U.S. dollars using the average exchange rates prevailing during the year. Equity items are translated using the exchange rates prevailing at the dates of the transactions. All exchange differences arising from the translation of the consolidated financial statements from the functional currency into the presentation currency are recognized as cumulative translation adjustments (CTA) within accumulated other comprehensive income (loss) in the consolidated statements of changes in shareholders’ equity.

Brazilian Real x U.S. Dollar	Mar 2014	Jun 2014	Sep 2014	Dec 2014	Mar 2013	Jun 2013	Sep 2013	Dec 2013
Quarterly average exchange rate	2.36	2.23	2.28	2.55	2.00	2.07	2.29	2.28
Period-end exchange rate	2.26	2.20	2.45	2.66	2.01	2.22	2.23	2.34

The Brazilian real x U.S. dollar exchange rate at April 15, 2015 was R$ 3.07 per U.S. dollar.

3.The “Lava Jato (Car Wash) Operation” and its effects on the Company

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

F-9

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

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 the Company in connection with the acquisition of property, plant and equipment.  Two Petrobras executive officers (diretores) and one executive manager were involved in this payment scheme, none of whom has been affiliated with the Company since April 2012; they are referred to below 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.  The Company itself 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.

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

Background

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 Operation is extremely broad and involves numerous investigations into several criminal practices focusing on crimes committed by individuals in different parts of the country 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, including the former Petrobras personnel. Based on the information available to Petrobras, the payment scheme involved a group of 27 companies that, between 2004 and April 2012, colluded to obtain contracts with Petrobras, overcharge the Company under those contracts and use the overpayment received under the contracts 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 scheme. Petrobras refers to this scheme as the “payment scheme” and to the companies involved in the scheme as “cartel members.”

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 the Company to fund improper payments, unrelated to the payment scheme, to certain Petrobras employees, including the former Petrobras personnel and a former Chief International Officer. Those contractors and suppliers are not cartel members and acted individually. Petrobras refers to these specific cases as the “unrelated payments.”

In connection with the investigation of the payment scheme, Paulo Roberto Costa, a former Chief Downstream Officer of Petrobras, was arrested in March 2014 and subsequently charged for money-laundering and passive corruption. Other former executives of Petrobras, including Renato de Souza Duque (a former Chief Services Officer), Nestor Cerveró (a former Chief International Officer) and Pedro José Barusco Filho (a former executive manager of the Services area), as well as former executives of Petrobras contractors and suppliers, have been or are expected to be charged as a result of the investigation.

F-10

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

When the Company issued its 2013 audited financial statements on February 27, 2014, when it filed its 2013 Form 20-F on April 30, 2014, and when it issued its interim financial statements for the six months ended June 30, 2014 on August 8, 2014, there was no evidence available to Petrobras related to the Lava Jato investigation that would have affected the conclusions of the Company regarding the fact that its financial statements fairly presented its financial position, and the extent of the payment scheme had not been made public.

Information and sources available to Petrobras

On October 8, 2014, Costa and Alberto Youssef testified in the 13th Criminal District Court of Curitiba (Vara Federal Criminal de Curitiba) (“Paraná Court”), publicly describing the payment scheme.  Since then, extensive testimony of participants in the payment scheme who have entered into plea agreements has been made public.  The Company’s understanding of the payment scheme, and its methodology for measuring its impact on the Company, are based on this testimony, which includes the complete testimony of two of the former Petrobras personnel (Costa and Barusco), the complete testimony of two individuals who acted as intermediaries in the payment scheme  (Youssef and Julio Gerin de Almeida Camargo), partial testimony of another individual who acted as an intermediary in the payment scheme (Shinko Nakandakari), and the complete testimony of one representative of a construction company (Augusto Ribeiro de Mendonça Neto).

The Brazilian Federal Prosecutor’s Office, which is in possession of the full record of the investigation to date, filed administrative misconduct complaints (ações de improbidade administrativa) on February 20, 2015 against five cartel members based on the payment scheme and relied on the same approach used by the Company to measure the actual damages attributable to the payment scheme, as set out below.

A significant portion of the information mentioned above was made public after January 28, 2015, when the Company issued its interim financial statements as of and for the nine months ended September 30, 2014 not reviewed by independent auditors, amplifying and corroborating the information that was previously available, namely the testimony of Barusco, Costa, Youssef and Nakandakari.

The information available to the Company is generally consistent with respect to the existence of the payment scheme, the companies involved in the payment scheme, the former Petrobras personnel involved in the payment scheme, the period during which the payment scheme was in effect, and the maximum amounts involved in the payment scheme relative to the contract values of affected contracts.

Petrobras will monitor the results of the investigations and the availability of other information concerning the payment scheme.  If information becomes available that indicates with sufficient precision that the estimate described above should be adjusted, Petrobras will evaluate whether the adjustment is material and, if so, recognize it.  However, the Company has no expectation that additional information bearing on these matters is or will be available from internal sources.

Other information obtained in the course of the Lava Jato investigation, including portions of Nakandakari’s testimony, has not been made public. However, the Company believes that, at this point, the risk that new information emerges causing material changes to the known facts and materially affecting the adjustment described below is low. This belief is largely based on the fact that a significant amount of information has become public, it is unlikely that the Brazilian authorities (in possession of the full record of the investigation to date) would withhold information that is inconsistent with what they have publicly released (they have relied on the same approach to measure the actual damages attributable to the payment scheme in the civil and criminal proceedings they have already filed) and the public information is consistent even though it comes from a range of individuals with different positions and motivations, including two of the former Petrobras personnel, alleged intermediaries in the payment scheme and representatives of contractors and suppliers.

F-11

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The Company’s response to the facts uncovered in the Lava Jato investigation, a description of the payment scheme and the accounting issue regarding the payment scheme, as well as the approach adopted by the Company to account for the impact of the payment scheme are set out below.

3.1.The Company’s response to the facts uncovered in the investigation

While the internal and external investigations are ongoing, the Company is taking the necessary procedural steps with Brazilian authorities to seek compensation for the damages it has suffered, including those related to its reputation. To the extent that any of the proceedings resulting from the Lava Jato investigation involve leniency agreements with cartel members or plea agreements with individuals pursuant to which they agree to return funds, Petrobras may be entitled to receive a portion of such funds.

The proceedings will also include civil proceedings against cartel members, which Petrobras would have the right to join as a plaintiff, and it expects to do so.  The civil proceedings typically result in three types of relief:  effective damages, civil fines and moral damages.  Petrobras would be entitled to any effective damages and possibly civil fines.  Moral damages would typically be contributed to a federal fund, although Petrobras may seek to obtain moral damages once it joins the proceedings as a plaintiff.

Petrobras does not tolerate corruption or any illegal business practices of its contractors or suppliers or the involvement of its employees in such practices, and it has therefore undertaken the following initiatives in furtherance of the investigation of irregularities involving its business activities and to improve its corporate governance system:

-The Company has established several Internal Investigative Committees (Comissões Internas de Apuração – CIA) to investigate instances of non-compliance with corporate rules, procedures or regulations. We have provided the findings of the internal commissions that have been concluded to Brazilian authorities.

-On October 24 and 25, 2014, the Company engaged two independent law firms, U.S. firm Gibson, Dunn & Crutcher LLP and Brazilian firm Trench, Rossi e Watanabe Advogados, to conduct an independent internal investigation.

-The Company has been cooperating fully with the Brazilian Federal Police (Polícia Federal), the Brazilian Public Prosecutor’s Office (Ministério Público Federal), the Brazilian Judiciary, and other Brazilian authorities (the Federal Audit Court – Tribunal de Contas da União – TCU, and the Federal General Controller – Controladoria Geral da União – CGU).

-The Company has established committees to analyze the application of sanctions against contractors and suppliers, and imposed a provisional ban on contracting with the cartel members (and entities related to them) mentioned in the testimony that has been made public.

-The Company has developed and implemented measures to improve corporate governance, risk management and control, which are documented in standards and minutes of management meetings that establish procedures, methods, responsibilities and other guidelines to integrate such measures into the Company’s practices.

-The Company has created a position of Governance, Risk and Compliance Officer, with the aim of supporting the Company’s compliance programs and mitigating risks in its activities, including fraud and corruption. The new Officer participates in the decisions of the Executive Board, and any matter submitted to the Executive Board for approval must previously be approved by this Officer as they relate to governance, risk and compliance.

F-12

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

-On January 13, 2015 the Board of Directors appointed Mr. João Adalberto Elek Junior to the position of Governance, Risk and Compliance Officer. Mr. João Adalberto Elek Junior took office on January 19, 2015. He will serve a three-year term, which may be renewable, and may only be removed by a vote of the Board of Directors, including the vote of at least one Board Member elected by the non-controlling shareholders or by the preferred shareholders.

-A Special Committee was formed to act independently and to serve as a reporting line to the Board of Directors for the firms conducting the independent internal investigation. The Special Committee is composed of Ellen Gracie Northfleet, retired Chief Justice of the Brazilian Supreme Court (as chair of the Committee), Andreas Pohlmann, Chief Compliance Officer of Siemens AG from 2007 to 2010, and the executive officer of Governance, Risk and Compliance, João Adalberto Elek Junior.

3.2.Description of the payment scheme and its impact on the Company’s financial statements

The following items discuss the need to correct the carrying amount of specified property, plant and equipment due to the impact of the payment scheme, as well as the impracticability of identifying actual improper payments, tying the overpayments to specific contract payments, or measuring the exact amount of the overpayments to be corrected. They also discuss the approach adopted by the Company to write off capitalized costs representing amounts that Petrobras overpaid for property, plant and equipment. Note 5.8 below discusses the two alternative approaches considered and rejected by the Company as surrogates for measuring the exact amounts.

3.2.1.The payment scheme and the need to correct the carrying amount of specified property, plant and equipment

According to the information available to the Company described above, under the payment scheme, a large number of contractors and suppliers colluded with the former Petrobras personnel to overcharge Petrobras under construction contracts and contracts to provide Petrobras with goods and services, and used the overpayments to make improper payments to political parties, elected officials or public officials, individual contractor personnel, or the former Petrobras personnel.

In particular, the former Chief Downstream Officer, the former Chief Services Officer and the former executive manager of the Services area of Petrobras were involved in the payment scheme.  Those individuals, who were all in positions of authority at Petrobras, not only failed to report the existence of the cartel, but they also used their influence to further the objectives of the payment scheme, primarily by ensuring that the cartel members would be selected to participate in bidding rounds for goods and services contracts with Petrobras so that the cartel members would secure contracts with the Company.  However, there is no available information indicating that these individuals controlled or directed the use of the overpayments once the funds left Petrobras.

In addition to the payment scheme, the investigations identified several other specific instances in which Petrobras was overcharged in connection with the acquisition of property, plant and equipment. The amount that Petrobras was overcharged was used to make unrelated payments to Petrobras personnel.

3.2.2.Impracticability of determining the actual amount of overpayment and the periods to be corrected

It is impracticable to identify the exact date and amount of each overpayment by the Company to the contractors and suppliers because of the limitations described below:

The information available to the Company in the testimony identifies the companies involved in the payment scheme and the period of time it was in effect, but the testimony does not identify all the affected contracts, the

F-13

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

individual contractual payments that include overcharges or the reporting periods in which overpayments occurred.

Petrobras itself did not make or receive any improper payments. They were made by outside contractors and suppliers, so the exact amounts that the Company overpaid to fund these payments cannot be identified. The information to determine the amount by which the Company was overcharged by the cartel members is not contained within the Company’s accounting records.  These records reflect the terms of the contract entered into by the Company, which entailed payments that were inflated because of the conspiracy among the cartel members and the former Petrobras personnel to overcharge Petrobras. Since the Company cannot identify the amount of overpayments for specific contractual payments or in specific accounting periods,   it cannot determine the period in which to adjust property, plant and equipment.  

Two independent law firms are conducting an independent internal investigation, under the direction of the Special Committee mentioned above. The independent internal investigation is not expected to provide additional quantitative information of a kind to support an adjustment to the Company’s financial statements. The information available to the investigators is limited to internal information of Petrobras, so it will not be able to produce specific identified information on the amount by which the Company was overcharged. The money-laundering activities alleged to have occurred were designed to hide the origins and amounts of the funds involved, so a specific accounting should not be expected.

The ongoing investigations by Brazilian authorities will focus on the criminal liability of individuals, and not on establishing a full accounting of the amounts that Petrobras was overcharged by the cartel members or all improper payments made by contractors and suppliers from the Company’s contract payments. These investigations may take several years before all the evidence and allegations are evaluated.

The Brazilian authorities have filed actions against contractors and suppliers and their respective representatives. In these actions, the prosecutors have sought judicial remedies for administrative misconduct (ação de improbidade administrativa) using 3% of the contract prices paid to the contractors and suppliers to measure the actual damages attributable to the payment scheme, which is consistent with the methodology used by the Company to account for the effects of the payment scheme. The scope of this process is not expected to produce a full accounting of all improper payments, even after the significant amount of time the investigations by Brazilian authorities may take. Brazilian law does not provide for discovery in civil proceedings, so the information that is produced in these proceedings would not be expected to exceed the information produced in the investigation and the criminal proceedings.

As previously discussed, despite the limitations described above, the information available to the Company is, in general, consistent in terms of the individuals and companies involved in the payment scheme, the period during which the payment scheme was in effect, and the percentage of overcharging applied over the total contract values under affected contracts and used to fund the improper payments made by contractors and suppliers.

3.2.3.Approach adopted by the Company to adjust its property, plant and equipment for overpayments

As it is impracticable to identify specific periods and amounts for the overpayments by the Company, the Company considered all the information available (as described above) to quantify the impact of the payment scheme.

The Company included in its historical cost for property, plant and equipment all of the amounts paid under the affected contracts. However, the Company believes that the amount of its contract payments representing overpayments to contractors and suppliers pursuant to the payment scheme should not have been capitalized as property, plant and equipment.

F-14

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The testimony identified 27 cartel members (Brazilian contractors and suppliers involved in the payment scheme) and several additional instances where a contractor or supplier acting individually overcharged to make improper payments unrelated to the payment scheme.

The testimony states that the cartel and the payment scheme were active from 2004 through April 2012.  The Company also evaluated whether the payment scheme affected periods before 2004. However, the testimony does not indicate that the payment scheme was in effect before 2004 and even if it were, the impact of contractors and suppliers overcharging the Company prior to 2004 is not material, as most of the Company’s property, plant and equipment assets were built between 2004 and 2014 (the balance of property, plant and equipment was US$30.8 billion as of December 31, 2003) and the assets existing as of December 31, 2003 were substantially depreciated by 2014.

Based on the available information described above, the Company concluded that the portion of the costs incurred to build its property, plant and equipment that resulted from contractors and suppliers in the cartel overcharging the Company to make improper payments should not have been capitalized.  In order to account for the impact of overpayments, the Company developed an estimation methodology to serve as a proxy for the adjustment that should be made to property plant and equipment using the five steps described below:

(1)          Identify contractual counterparties: the Company listed all the companies identified in public testimony, and using that information the Company identified all of the contractors and suppliers that were either so identified or were consortia including entities so identified.

(2)          Identify the period: the Company concluded from the testimony that the payment scheme was operating from 2004 through April 2012.

(3)          Identify contracts: the Company identified all contracts entered into with the counterparties identified in step 1 during the period identified in step 2, which included supplemental contracts when the original contract was entered into between 2004 and April 2012.  It has identified all of the property, plant and equipment related to those contracts.

(4)          Identify payments: the Company calculated the total contract values under the contracts identified in step 3.

(5)          Apply a fixed percentage to the amount determined in Step 4: the Company estimated the aggregate overpayment by applying a percentage indicated in the depositions (3%) to the total amounts for identified contracts. 

The calculation considered all the recorded amounts in the Company’s books and records from 2004 through September 2014 with respect to contracts initially entered into between 2004 and April 2012, and any related supplemental contracts, between the companies of the Petrobras group and the cartel members (individually or in a consortium). This broad scope was used to produce the best estimate for quantifying the aggregate amount of the overpayment, even if there was no specific evidence of overcharging or improper payments under every affected contract. The Company also identified amounts recorded in its books and records concerning specific contracts and projects with the non-cartel members to account for the amounts those companies overcharged Petrobras to fund improper payments they made, unrelated to the payment scheme and the cartel.

For overpayments attributable to non-cartel members, unrelated to the payment scheme, the Company included in the write-off for incorrectly capitalized overpayments the specific amounts of improper payments or percentages of contract values, as described in the testimony, which were used by those suppliers and contractors to fund improper payments.

F-15

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The Company has a number of ongoing projects in which the original contract was entered into between 2004 and April 2012. The approach adopted by the Company considers that the overcharge was applied over total contract values.  These include contract payments to be incurred by Petrobras in future periods, because it is impracticable to allocate the aggregate overpayments to specific periods and the portion of the overcharge that relates to future contract payments may have been charged to the Company in prior periods. Therefore, the write-off of overpayments incorrectly capitalized takes into account the total contract values and not only contract payments already incurred.  However, as mentioned above, based on the available information, the Company believes that the cartel and the payment scheme were dismantled after April 2012 and that, considering all the developments in the ongoing criminal investigation, the improper payments related to the payment scheme have stopped.

Petrobras believes that this methodology produces the best estimate for the aggregate overstatement of its property, plant and equipment resulting from the payment scheme, in the sense that it represents the upper bound of the range of reasonable estimates.  The estimate assumes that all contracts with the identified counterparties were affected and that 3% represents the amount by which the Company overpaid on those contracts. Both assumptions are supported by the testimony, even though some testimony indicated lower percentages with respect to certain contracts, a shorter period (2006 to 2011), or fewer contractors involved. 

Along with the write-off to reduce the carrying amount of specified property, plant and equipment, the impact in the current period includes write-offs of tax credits (VAT and correlated taxes) and a provision for credits applied in prior periods with respect to property, plant and equipment that has been written-down, as well as the reversal of depreciation of affected assets beginning on the date they started operating.

As previously discussed, the testimony does not provide sufficient information to allow the Company to determine the specific period during which the Company made specific overpayments. Accordingly, the write-off of overpayments incorrectly capitalized was recognized in the third quarter of 2014, because it is impracticable to determine the period-specific effect in each prior period. The Company believes this approach is the most appropriate pursuant to the requirements of IFRS for the correction of an error.

In addition, the Company has evaluated the materiality of the impact of the payment scheme on prior periods presented in its financial statements for comparative purposes using two different analyses: it estimated the allocation of the overpayments to specific prior periods if all overpayments were made on a pro rata basis out of each of the actual contract payments and capitalized correspondingly; and it also estimated the materiality of improper payments to prior periods if the improper payments had been made at inception (on the date the contracts were entered into). Both allocation exercises indicated writing off the overpayment that was improperly capitalized would not have been material to any of the prior periods presented for comparative purposes.

The Company has not recovered and cannot reliably estimate any recoverable amounts at this point. Any amounts ultimately recovered would be recorded as income when received (or when their realization becomes virtually certain).

As previously mentioned, Petrobras believes that under IAS 16, the amounts it overpaid pursuant to the payment scheme should not have been included in the historical cost of the property, plant and equipment. Therefore, under Brazilian tax legislation, this write-off is considered a loss resulting from unlawful activity and subject to the evolution of the investigations in order to establish the actual extent of the losses before they can be deducted from an income tax perspective.

As a result, at September 30, 2014, it is not possible for the Company to estimate the amounts that will ultimately be considered deductible or the timing for the deduction. Accordingly no deferred tax assets were recognized for the write-off of overpayments incorrectly capitalized.

F-16

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The Company carefully considered all available information and, as discussed above, does not expect that new developments in the investigations by the Brazilian authorities, by the independent law firms conducting an internal investigation, or by new internal commissions set up (or a review of the results of previous internal investigations) could materially impact or change the methodology described above. Notwithstanding this expectation, the Company will continuously monitor the investigations for additional information and will review its potential impact on the adjustment.

The total impact of the adjustments described above by business area is set out below.

“Write-off – overpayments incorrectly capitalized”	E&P	RTM	GAS & POWER	DISTRIB.	INTER.	CORP.	TOTAL
Payment scheme:
Total contract amounts (*)	25,573	45,233	8,663	309	307	1,355	81,440
Estimated aggregate overpayments (3%)	767	1,358	260	9	9	41	2,444
Unrelated payments (outside the cartel)	57	−	4	−	−	−	61
	824	1,358	264	9	9	41	2,505
Reversal of depreciation of the affected assets	(35)	(81)	(21)	−	−	(4)	(141)
Impact on property, plant and equipment	789	1,277	243	9	9	37	2,364
Write-down of tax credits related to affected assets (**)	15	121	23	−	−	4	163
Write-off – overpayments incorrectly capitalized	804	1,398	266	9	9	41	2,527
(*) Of this amount, US$ 17,999 represents amounts scheduled to be paid after September 30, 2014.
(**) Write-down of tax credits that will not be applicable in the future.

The Company has conducted a sensitivity analysis taking into account that approximately 26% of the write-off of overpayments incorrectly capitalized relates to assets that were charged for impairment in the fourth quarter of 2014. Excluding these assets, an increase or decrease of 1% in the applicable percentage of the overcharge applied over total contract values would result in an increase or decrease of US$ 603 in the write-off of overpayments incorrectly capitalized. However, as discussed above, the Company believes it has used the most appropriate methodology and assumptions to determine the impact of the payment scheme and there is no evidence that would indicate the possibility of a material change in the amounts that were written off.

3.3.Changes in the current business context

Changes in the Company’s business context and the impact of the Lava Jato investigation prompted a review of the Company’s future prospects and ultimately led to the reduction in the pace of the Company’s capital expenditures.

Petrobras’s ability to invest its available funds has been limited as a result of a decrease in expected future operating revenues following the decline of oil prices, along with the devaluation of the Brazilian real, which has increased the Company’s cash outflows to service debt in the near term, most of which is denominated in foreign currencies. For a variety of reasons, including the economic and political environment in Brazil, Petrobras is currently unable to access the capital markets. Other sources of available financing are limited, and in any event would be insufficient to meet Petrobras’s investment needs. Petrobras also faces a shortage of qualified contractors and suppliers as a result of the difficulties created for suppliers by the Lava Jato investigation.

As a result, Petrobras has recently determined to delay or suspend the completion of some of the assets and projects included in Petrobras’s capital expenditure plan that are expected to contribute little to its cash generation from its operations or that present complications due to contractor insolvency or to a lack of availability of qualified suppliers (as a result of the Lava Jato investigation or otherwise). Those changes had a material impact in the Company’s impairment tests, as described in note 14.

F-17

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

3.4.Investigations involving the Company

Petrobras is not a target of the Lava Jato investigation.  On November 21, 2014, Petrobras received a subpoena from the U.S. Securities and Exchange Commission (SEC) requesting certain documents and information about the Company.  The Company has been complying with the subpoena and intends to continue to do so, working with the independent Brazilian and U.S. law firms that were hired to conduct an independent internal investigation.

3.5.Legal proceedings involving the Company

See note 30 for information about class actions and the Company’s other material legal proceedings.

4.Summary of significant accounting policies

The accounting policies set out below have been consistently applied to all periods presented in these consolidated financial statements.

4.1.Basis of consolidation

 The consolidated financial statements include the financial information of Petrobras and the entities it controls (its subsidiaries), joint operations and consolidated structured entities.

Control is achieved when Petrobras: i) has power over the investee; ii) is exposed, or has rights, to variable returns from involvement with the investee; and iii) has the ability to use its power to affect its returns.

Subsidiaries are consolidated from the date on which control is obtained until the date that such control no longer exists. Accounting policies of subsidiaries have been changed, where necessary, to ensure consistency with the policies adopted by Petrobras.

Note 11 sets out the consolidated entities and other direct investees.

Petrobras has no equity interest in its consolidated structured entities and control is not determined by voting rights, but by the power the Company has over the relevant operating activities of such entities. Consolidated structured entities are set out below:

Consolidated structured entities	Country	Main segment
Charter Development LLC – CDC (i)	U.S.A	E&P
Companhia de Desenvolvimento e Modernização de Plantas Industriais – CDMPI	Brazil	RT&M
PDET Offshore S.A.	Brazil	E&P
Fundo de Investimento em Direitos Creditórios Não-padronizados do Sistema Petrobras	Brazil	Corporate
Fundo de Investimento em Direitos Creditórios Padronizados do Sistema Petrobras	Brazil	Corporate
(i) Companies abroad with financial statements prepared in foreign currencies.

The consolidation procedures involve combining assets, liabilities, income and expenses, according to their function and eliminating all intragroup balances and transactions, including unrealized profits arising from intragroup transactions.

4.2.Business segment reporting

The information related to the Company’s operating segments (business areas) is prepared based on items directly attributable to each segment, as well as items that can be allocated to each segment on a reasonable basis.

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Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The measurement of segment results includes transactions carried out with third parties and transactions between business areas, which are charged at internal transfer prices defined by the relevant areas using methods based on market parameters.

The Company operates under the following business areas:

a) Exploration and Production (E&P): this segment covers the activities of exploration, development and production of crude oil, NGL (natural gas liquid) and natural gas in Brazil for the purpose of supplying, primarily, its domestic refineries; and also selling the crude oil surplus and oil products produced in the natural gas processing plants to the domestic and foreign markets. The exploration and production segment also operates through partnerships with other companies.

b) Refining, Transportation and Marketing (RTM): this segment covers the refining, logistics, transport and trading of crude oil and oil products activities, exporting of ethanol, extraction and processing of shale, as well as holding interests in petrochemical companies in Brazil.

c) Gas and Power: this segment covers the activities of transportation and trading of natural gas produced in Brazil and imported natural gas, transportation and trading of LNG (liquid natural gas), generation and trading of electricity, as well as holding interests in transporters and distributors of natural gas and in thermoelectric power plants in Brazil, in addition to being responsible for the fertilizer business.

d) Biofuels: this segment covers the activities of production of biodiesel and its co-products, as well as the ethanol-related activities: equity investments, production and trading of ethanol, sugar and the surplus electric power generated from sugarcane bagasse.

e) Distribution: this segment includes the activities of Petrobras Distribuidora S.A., which operates through its own retail network and wholesale channels to sell oil products, ethanol and vehicle natural gas in Brazil to retail, commercial and industrial customers, as well as other fuel wholesalers.

f) International: this segment covers the activities of exploration and production of oil and gas, refining, transportation and marketing, gas and power, and distribution, carried out outside of Brazil in a number of countries in the Americas, Africa, Europe and Asia.

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

4.3.Financial instruments

4.3.1.Cash and cash equivalents

Cash and cash equivalents comprise cash in hand, term deposits with banks and short-term highly liquid financial investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and have a maturity of three months or less from the date of acquisition.

4.3.2.Marketable securities

Marketable securities comprise investments in debt or equity securities. These instruments are initially measured at fair value, are classified according to the Company’s intention and are subsequently measured as set out below:

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Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

-Fair value through profit or loss – includes financial instruments purchased and held for trading in the short term. These instruments are subsequently measured at fair value with changes recognized in the statement of income in finance income (expenses).

-Held-to-maturity – includes non-derivative financial instruments with fixed or determinable payments and fixed maturity, for which Management has the positive intention and ability to hold to maturity. These instruments are subsequently measured at amortized cost using the effective interest rate method.

-Available-for-sale – includes non-derivative financial instruments that are either designated as available for sale or are not classified as financial assets at fair value through profit or loss or held-to-maturity investments. These instruments are subsequently measured at fair value. Subsequent changes in fair value are recognized in other comprehensive income, in the shareholders’ equity and recycled to the statement of income when the instruments are derecognized.

Subsequent value changes attributable to interest income or changes in foreign exchange rates or inflation indexation (price indices) are recognized in the statement of income for all categories, when applicable.

4.3.3.Trade receivables

Trade receivables are initially measured at the fair value of the consideration to be received and, subsequently, at amortized cost using the effective interest rate method and adjusted for allowances for impairment or uncollectibility.

The Company recognizes an allowance for impairment of trade receivables when there is objective evidence that a loss event occurred after the initial recognition of the receivable and has an impact on the estimated future cash flows, which can be reliably estimated. Impairment losses on trade receivables are recognized in the statement of income in selling expenses.

4.3.4.Loans and financing (Debt)

Loans and financing are initially recognized at fair value less transaction costs incurred and, after initial recognition, are measured at amortized cost using the effective interest rate method.

4.3.5.Derivative financial instruments

Derivative financial instruments are recognized in the statement of financial position as assets or liabilities and are initially and subsequently measured at fair value.

Gains or losses arising from changes in fair value are recognized in the statement of income in finance income (finance expense), unless the derivative is qualified and designated for hedge accounting.

4.3.6.Hedge accounting

Hedge accounting is formally documented at inception in terms of the hedging relationship and the Company’s risk management objective and strategy for undertaking the hedge.

Hedging relationships that qualify for hedge accounting are classified as:  (i) fair value hedge, when they involve a hedge of the exposure to changes in fair value of a recognized asset or liability, unrecognized firm commitments, or an identifiable portion of such assets, liabilities or firm commitments; and (ii) cash flow hedges when they involve a hedging of the exposure to variability in cash flows that is attributable to a particular risk associated with a recognized asset or liability or a highly probable forecast transaction.

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Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

In hedging relationships that qualify for fair value hedge accounting, the gain or loss from remeasuring the hedging instrument and the hedged item at fair value is recognized in the statement of income.

In hedging relationships that qualify for cash flow hedge accounting, the Company designates derivative financial instruments and long-term debt (non-derivative financial instruments) as hedging instruments. Gains or losses relating to the effective portion of the hedge are recognized in other comprehensive income, in the shareholders’ equity and recycled to the statement of income in finance income (expense) in the periods when the hedged item affects the statement of income. The gains or losses relating to the ineffective portion are recognized in the statement of income.

When, the hedging instrument expires or is sold, terminated or exercised or no longer meets the criteria for hedge accounting or the Company revokes the designation, the cumulative gain or loss on the hedging instrument that has been recognized in other comprehensive income from the period when the hedge was effective remains separate in equity until the forecast transaction occurs. When, the forecast transaction is no longer expected to occur, the cumulative gain or loss on the hedging instrument that has been recognized in other comprehensive income is immediately reclassified from equity to the statement of income.

4.4.Inventories

Inventories are determined by the weighted average cost flow method and mainly comprise crude oil, intermediate products and oil products, as well as natural gas, LNG, fertilizers and biofuels, stated at the lower of the average cost, and their net realizable value.

Crude oil and LNG inventories can be traded or used for production of oil products and/or electricity generation, respectively.

Intermediate products are those product streams that have been through at least one of the refining processes, but still need further treatment, processing or converting to be available for sale.

Biofuels mainly include ethanol and biodiesel inventories.

Maintenance materials, supplies, and others are mainly comprised of production supplies and operating and consumption materials used in the operations of the Company, stated at the average purchase cost, not exceeding replacement cost.

Net realizable value is the estimated selling price of inventory in the ordinary course of business, less estimated cost of completion and estimated expenses to complete its sale.

The amounts presented in the categories above include imports in transit, which are stated at the identified cost.

4.5.Investments in other companies

An associate is an entity over which the Company has significant influence. Significant influence is the power to participate in the financial and operating policy decisions of the investee but not the ability to exercise control or joint control over those polices. The definition of control is set out in note 4.1.

A joint arrangement is an arrangement over which two or more parties have joint control (pursuant to contractual provisions). A joint arrangement is classified either as a joint operation or as a joint venture depending on the rights and obligations of the parties to the arrangement.

In a joint operation the parties have rights to the assets, and obligations for the liabilities, relating to the arrangement and in a joint venture, the parties have rights to the net assets of the arrangement.

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Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Profit or loss, assets and liabilities related to joint ventures and associates are accounted for by the equity method. In a joint operation the Company recognizes the amount of its share of assets, liabilities and related income and expenses.

Accounting policies of joint ventures and associates have been modified, where necessary, to ensure consistency with the policies adopted by Petrobras.

Distributions received from an investee reduce the carrying amount of the investment.

4.6.Business combinations and goodwill

Acquisitions of businesses are accounted for using the acquisition method when control is obtained. Combinations of entities under common control are not accounted for as business combinations.

The acquisition method requires that the identifiable assets acquired and the liabilities assumed be measured at the acquisition-date fair value. Amounts paid in excess of the fair value are recognized as goodwill. In the case of a bargain purchase, a gain is recognized in the statement of income when the acquisition cost is lower than the acquisition-date fair value of the net assets acquired.

Changes in ownership interest in subsidiaries that do not result in loss of control of the subsidiary are equity transactions. Any excess of the amounts paid/received over the carrying value of the ownership interest acquired/disposed is recognized in shareholders’ equity as changes in interest in subsidiaries.

4.7.Oil and Gas exploration and development expenditures

The costs incurred in connection with the exploration, appraisal, development and production of crude oil and natural gas are accounted for using the successful efforts method of accounting, as set out below:

- Costs related to geological and geophysical activities are expensed when incurred.

- Amounts paid for obtaining concessions for exploration of crude oil and natural gas (capitalized acquisition costs) are initially capitalized.

- Costs directly attributable to exploratory wells pending determination of proved reserves are capitalized within property, plant and equipment. Unsuccessful exploratory wells are charged to expense when they are considered dry holes, uneconomic (did not encounter potentially economic oil and gas quantities) or were abandoned due to mechanical accidents. Exploratory wells that have found oil and gas reserves, but those reserves cannot be classified as proved when drilling is completed, continue to be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and progress on assessing the reserves and the economic and operating viability of the project is under way. An internal commission of technical executives of Petrobras reviews these conditions monthly for each well, by analysis of geoscience and engineering data, existing economic conditions, operating methods and government regulations.

- Costs related to exploratory wells drilled in areas of unproved reserves are charged to expense when determined to be dry or uneconomic.

- Costs related to the construction, installation and completion of infrastructure facilities, such as drilling of development wells, construction of platforms and natural gas processing units, construction of equipment and facilities for the extraction, handling, storing, processing or treating crude oil and natural gas, pipelines, storage facilities, waste disposal facilities and other related costs incurred in connection with the development of proved reserve areas are capitalized within property, plant and equipment.

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Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

4.8.Property, plant and equipment

Property, plant and equipment are measured at the cost to acquire or construct, including all costs necessary to bring the asset to working condition for its intended use, including the present value of the estimated cost of dismantling and removing the asset and restoring the site, reduced by accumulated depreciation and impairment losses.

A condition of continuing to operate certain items of property, plant and equipment, such as industrial plants, offshore plants and vessels is performing regular major inspections and maintenance. Those expenditures are capitalized if the recognition criteria are met or otherwise expensed when incurred. The capitalized costs are depreciated over the period through the next major maintenance.

Spare parts are capitalized when they are expected to be used during more than one period and can only be used in connection with an item of property, plant and equipment. These are depreciated over the useful life of the item of property, plant and equipment to which they relate.

General and specific borrowing costs directly attributable to the acquisition or construction of qualifying assets are capitalized as part of the costs of these assets. General borrowing costs are capitalized based on the Company’s weighted average of the cost of borrowings outstanding applied over the balance of assets under construction. Borrowing costs are amortized during the useful lives of the assets or by applying the unit-of-production method to the related assets. The Company suspends capitalization of borrowing costs during extended periods in which it suspends active development of a qualifying asset.

Except for assets with useful lives shorter than the life of the field, which are depreciated based on the straight line method, depreciation, depletion and amortization of proved oil and gas producing properties are accounted for pursuant to the unit-of-production method.

Assets with useful lives shorter than the life of the field, floating platforms and assets that are unrelated to oil and gas production are depreciated based on the straight line method.

The unit-of-production method of depreciation (amortization) is computed based on a unit-of-production basis (monthly production) over the proved developed oil and gas reserves, applied on a field by field basis.

Amortization of amounts paid for obtaining concessions for exploration of oil and natural gas of producing properties, such as signature bonuses (capitalized acquisition costs) and the acquisition costs with respect to the Assignment Agreement, referring to the right to carry out prospection and drilling activities for oil, natural gas and other liquid hydrocarbons located in blocks in the pre-salt area (“Cessão Onerosa”) is recognized using the unit-of-production method, computed based on the units of production over the total proved oil and gas reserves, applied on a field by field basis.

Except for land, which is not depreciated, other property, plant and equipment are depreciated on a straight line basis. See note 12 for further information about the estimated useful life by class of assets.

4.9.Intangible assets

Intangible assets are measured at the acquisition cost, less accumulated amortization and impairment losses and comprise rights and concessions, including the signature bonus paid for obtaining concessions for exploration of oil and natural gas (capitalized acquisition costs); public service concessions; trademarks; patents; software and goodwill.

Signature bonuses paid for obtaining concessions for exploration of oil and natural gas are initially capitalized within intangible assets and are transferred to property, plant and equipment upon the declaration of

F-23

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

commerciality. The acquisition costs with respect to the Assignment Agreement were reclassified to property, plant and equipment during 2013 and 2014. On December 29, 2014 the Company submitted the declaration of commerciality of the last area of the agreement to the Brazilian Agency of Petroleum, Natural Gas and Biofuels      (Agência Nacional de Petróleo, Gás Natural e Biocombustíveis) - ANP. Signature bonuses are not amortized until they are transferred to property, plant and equipment.

Intangible assets with a finite useful life, other than amounts paid for obtaining concessions for exploration of oil and natural gas of producing properties, are amortized over the useful life of the asset on a straight-line basis.

Internally-generated intangible assets are not capitalized and are expensed as incurred, except for development costs that meet the recognition criteria related to completion and use of assets, probable future economic benefits, and others.

Intangible assets with an indefinite useful life are not amortized but are tested annually for impairment considering individual assets or cash-generating units. Their useful lives are reviewed annually to determine whether events and circumstances continue to support an indefinite useful life assessment for those assets. If they do not, the change in the useful life assessment from indefinite to finite is accounted for on a prospective basis.

4.10.Impairment

Property, plant and equipment and intangible assets with definite useful lives are tested for impairment when there is an indication that the carrying amount may not be recoverable. Assets related to exploration and development of oil and gas and assets that have indefinite useful lives, such as goodwill acquired in business combinations are tested for impairment annually, irrespective of whether there is any indication of impairment.

The impairment test is performed by a comparison of the carrying amount of an individual asset or a cash-generating unit (CGU) with its recoverable amount. Whenever the recoverable amount is less than the carrying amount, an impairment loss is recognized to reduce the carrying amount to the recoverable amount. The recoverable amount of an asset or a cash-generating unit is the higher of its fair value less costs of disposal and its value in use. Considering the specificity of the Company’s assets, value in use is generally used by the Company for impairment testing purposes, except when specifically indicated.

Value in use is estimated based on the present value of the risk-adjusted (for specific risks) future cash flows expected to arise from the continuing use of an asset or cash-generating unit (based on assumptions that represent the Company’s best estimates), discounted at a pre-tax discount rate. This rate is obtained from the Company’s post-tax weighted average cost of capital (WACC). Cash flow projections are mainly based on the following assumptions: prices based on the Company’s most recent strategic plan; production curves associated with existing projects in the Company's portfolio, operating costs reflecting current market conditions, and investments required for carrying out the projects.

For purposes of the impairment test, assets are grouped at the smallest identifiable group that generates largely independent cash inflows from other assets or groups of assets (the cash-generating unit). Assets related to exploration and development of oil and gas are tested annually for impairment or when there is an indication that the carrying amount may not be recoverable, on a field by field basis.

Reversal of previously recognized impairment losses is permitted for assets other than goodwill.

4.11.Leases

Leases that transfer substantially all the risks and rewards incidental to ownership of the leased item are recognized as finance leases.

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Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

For finance leases, when the Company is the lessee, assets and liabilities are recognized at the lower of the fair value of the leased property or the present value of the minimum lease payments, both determined at the inception of the lease.

Capitalized lease assets are depreciated on a systematic basis consistent with the depreciation policy the Company adopts for property, plant and equipment that are owned. Where there is no reasonable certainty that the Company will obtain ownership by the end of the lease term, capitalized lease assets are depreciated over the shorter of the lease term or the estimated useful life of the asset.

When the Company is the lessor, a receivable is recognized at the amount of the net investment in the lease.

If a lease does not transfer substantially all the risks and rewards incidental to ownership of the leased item, it is classified as an operating lease. Operating leases are recognized as expenses over the period of the lease.

Contingent rents are recognized as expenses when incurred.

4.12.Assets classified as held for sale

Assets, disposal groups and liabilities directly associated with those assets are classified as held for sale if their carrying amounts will principally be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is approved by the Company’s Board of Directors and the asset or disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. In addition, the sale should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale.

However, events or circumstances may extend the period to complete the sale beyond one year. An extension of the period required to complete a sale does not preclude an asset (or disposal group) from being classified as held for sale if the delay is caused by events or circumstances beyond the Company’s control and there is sufficient evidence that it remains committed to its plan to sell the assets (or disposal groups).

Assets (or disposal groups) classified as held for sale and the associated liabilities are measured at the lower of their carrying amount and fair value less costs to sell. Assets and liabilities are presented separately in the statement of financial position.

4.13.Decommissioning costs

Decommissioning costs are future obligations to perform environmental restoration, dismantle and remove a facility when it terminates its operations due to the exhaustion of the area or economic conditions.

Costs related to the abandonment and dismantling of areas are recognized as part of the cost of an asset (with a corresponding liability) based on the present value of the expected future cash outflows, discounted at a risk-adjusted rate when a future legal obligation exists and can be reliably measured. Unwinding of the discount of the corresponding liability is recognized as a finance expense, when incurred. The asset is depreciated similarly to property, plant and equipment, based on the class of the asset.

Future decommissioning costs for oil and natural gas producing properties are initially recognized after a field is declared to be commercially viable, on a field by field basis, and are revised annually. Decommissioning costs related to proved developed oil and gas reserves are depreciated by applying the unit-of-production method, computed based on a unit-of-production basis over the proved developed oil and gas reserves, applied on a field by field basis.

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Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

4.14.Provisions, contingent assets and contingent liabilities

Provisions are recognized when there is a present obligation (legal or constructive) that arises from past events and for which it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation, which must be reasonably estimable.

Contingent assets are not recognized.

Contingent liabilities for which the likelihood of loss is considered to be possible or which are not reasonably estimable are not recognized in the financial statements but are disclosed unless the expected outflow of resources embodying economic benefits is considered remote.

4.15.Income taxes

Income tax expense for the period comprises current and deferred tax.

a)Current income taxes

The Company has adopted the Transition Tax Regime in Brazil (RTT) in order to exclude potential tax impacts from the adoption of IFRS in the determination of taxable profit. RTT is based on Brazilian tax/corporate regulations and accounting principles as of December 31, 2007. Therefore, taxable profit differs from accounting profit due to certain adjustments required by tax regulations.

Law 12,973, dated as of May 13, 2014, terminated the RTT and established a new tax regime. The new tax regime is mandatory for 2015 and optional for 2014. The Company has not adopted the new tax regime for 2014 and, therefore, its taxable profit was determined based on the RTT.

The Company does not expect the adoption of the new tax regime to result in material impacts in its tax expense or in its financial statements.

The tax currently payable is computed based on taxable profit for the year, calculated using tax rates that have been enacted or substantively enacted by the end of the reporting period.

b)Deferred income taxes

Deferred income taxes are recognized on temporary differences between the tax base of an asset or liability and its carrying amount. Deferred income tax liabilities are generally recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary differences and carryforward of unused tax losses or credits to the extent that it is probable that taxable profit will be available against which those deductible temporary differences can be utilized.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted by the end of the reporting period.

Current and deferred tax assets and current and deferred tax liabilities are offset when they relate to income taxes levied on the same taxable entity.

4.16.Employee benefits (Post-Employment)

Actuarial commitments related to post-employment defined benefit plans and health-care plans are recognized as liabilities in the statement of financial position based on actuarial calculations which are revised annually by an

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Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

independent qualified actuary (to update for material changes in actuarial assumptions and estimates of expected future benefits),  using the projected unit credit method, net of the fair value of plan assets, when applicable, out of which the obligations are to be directly settled.

Actuarial assumptions include: demographic assumptions; financial assumptions; medical costs estimates, historical data related to benefits paid and employee contributions.

Under the projected credit unit method, each period of service gives rise to an additional unit of benefit entitlement and each unit is measured separately to determine the final obligation.

Changes in the net defined benefit liability (asset) are recognized when they occur, as follows: i) service cost and net interest cost in the statement of income; and ii) remeasurements in other comprehensive income.

Service cost comprises: (i) current service cost, which is the increase in the present value of the defined benefit obligation resulting from employee service in the current period; (ii) past service cost, which is the change in the present value of the defined benefit obligation for employee service in prior periods, resulting from a plan amendment (the introduction, modification, or withdrawal of a defined benefit plan) or a curtailment (a significant reduction by the entity in the number of employees covered by a plan); and (iii) any gain or loss on settlement.

Net interest on the net defined benefit liability (asset) is the change during the period in the net defined benefit liability (asset) that arises from the passage of time.

Remeasurement of the net defined benefit liability (asset) is recognized in other comprehensive income and comprises: (i) actuarial gains and losses; (ii) the return on plan assets, excluding amounts included in net interest on the net defined benefit liability (asset); and (iii) any change in the effect of the asset ceiling, excluding amounts included in net interest on the net defined benefit liability (asset).

The Company also contributes amounts to defined contribution plans, that are expensed when incurred and are computed based on a percentage over salaries.

4.17.Share capital and distributions to shareholders

Share capital comprises common shares and preferred shares. Incremental costs directly attributable to the issue of new shares (share issuance costs) are presented (net of tax) in shareholders’ equity as a deduction from the proceeds.

To the extent the Company proposes dividend distributions to shareholders, it comprises dividends and interest on capital determined in accordance with the limits defined in the Brazilian Corporation Law and in the Company’s bylaws.

Interest on capital is a form of dividend distribution which is deductible for tax purposes in Brazil to the entity distributing interest on capital. Tax benefits from the deduction of interest on capital are recognized in the statement of income.

4.18.Other comprehensive income

Other comprehensive income includes changes in fair value of available-for-sale financial instruments, effective portion of cash flow hedge, actuarial gains and losses (remeasurement of the net defined benefit liability) and cumulative translation adjustment.

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Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

4.19.Government grants

A government grant is recognized when there is reasonable assurance that the grant will be received and the Company will comply with the conditions attached to the grant.

Government grants related to expenses are recognized as revenue in the statement of income on a systematic basis over the periods in which the Company recognizes as expenses the related costs for which the grants are intended to compensate. Government grants related to assets are initially recognized as deferred income and transferred to the statement of income over the useful life of the asset on a straight-line basis.

4.20.Recognition of revenue, costs and expenses

Revenue is recognized when it is probable that the economic benefits associated with the transaction will flow to the Company and the amount of revenue and the costs incurred or to be incurred in the transaction can be measured reliably. Revenue is measured at the fair value of the consideration received or receivable for products sold and services provided in the normal course of business, net of returns, discounts and sales taxes.

Revenues from the sale of crude oil and oil products, petrochemical products, natural gas, biofuels and other related products are recognized when the Company retains neither continuing managerial involvement nor effective control over the products sold and the significant risks and rewards of ownership have been transferred to the customer, which is usually when legal title passes to the customer, pursuant to the terms of the sales contract. Sales revenues from freight and other services provided are recognized based on the stage of completion of the transaction.

Finance income and expense mainly comprise interest income on financial investments and government bonds, interest expense on debt, gains or losses on marketable securities measured at fair value, as well as net foreign exchange and inflation indexation charges. Finance expense does not include borrowing costs directly attributable to the construction of assets that necessarily take a substantial period of time to become operational, which are capitalized as part of the costs of these assets. 

Revenue, costs and expenses are recognized on the accrual basis.

5.Critical accounting policies: key estimates and judgments

The preparation of the consolidated financial information requires the use of estimates and judgments for certain transactions and their impacts on assets, liabilities, income and expenses. The assumptions are based on past transactions and other relevant information and are periodically reviewed by Management, although the actual results could differ from these estimates.

Information about those areas that require the most judgment or involve a higher degree of complexity in the application of the accounting practices and that could materially affect the Company’s financial condition and results of operations are set out following.

5.1.Oil and gas reserves

Oil and gas reserves are estimated based on economic, geological and engineering information, such as well logs, pressure data and drilling fluid sample data and are used as the basis for calculating unit-of-production depreciation, depletion and amortization rates and for impairment tests.

These estimates require the application of judgment and are reviewed at least annually, or on an interim basis if objective evidence of significant changes becomes available based on a re-evaluation of already available geological, reservoir or production data and new geological, reservoir or production data, as well as changes in

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Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

prices and costs that are used in the estimation of reserves. Revisions can also result from significant changes in the Company’s development strategy or in the production capacity of equipment and facilities.

The Company determines its oil and gas reserves both pursuant to the SEC criteria and to the ANP/SPE (Brazilian Agency of Petroleum, Natural Gas and Biofuels / Society of Petroleum Engineers) criteria. The main differences between the two criteria are: selling price of crude oil, improved recovery criteria, undrilled acreage limits, fluid contacts limits, definitions for analog reservoir used for reserves estimates and the concession period in Brazil. Only proved reserves are determined pursuant to the SEC criteria, while proved and unproved reserves are determined pursuant to the ANP/SPE criteria.

According to the definitions prescribed by the SEC proved oil and gas reserves are the estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic, operating conditions (i.e., prices and costs as of the date the estimate is made) and government regulations. Proved reserves can be further subdivided into developed and undeveloped reserves.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Although the Company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory aspects and significant changes in long-term oil and gas price levels.

Other information about reserves is presented as supplementary information.

a)Oil and gas reserves: depreciation, depletion and amortization

Depreciation, depletion and amortization are measured based on estimates of reserves prepared by the Company’s technicians in a manner consistent with SEC definitions. Revisions to the Company’s proved developed and undeveloped reserves impact prospectively the amounts of depreciation, depletion and amortization recognized in the statement of income and the carrying amounts of oil and gas properties assets.

Therefore all other variables being equal, a decrease in estimated proved reserves would increase, prospectively, depreciation, depletion and amortization expense, while an increase in reserves would reduce depreciation, depletion and amortization.

See notes 4.8 and 12.2 for more detailed information about depreciation, amortization and depletion.

b)Oil and gas reserves: impairment testing

The Company assesses the recoverability of the carrying amounts of oil and gas exploration and development assets based on their value in use, as defined in note 4.10. In general, analyses are based on proved reserves and probable reserves pursuant to the ANP/SPE definitions.

The Company performs asset valuation analyses on an ongoing basis as a part of its management program by reviewing the recoverability of their carrying amounts based on estimated volumes of oil and gas reserves, as well as estimated future oil and natural gas prices.

Oil and gas exploration and production assets are tested annually for impairment, irrespective of whether there is any indication of impairment.

F-29

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The markets for crude oil and natural gas have a history of significant price volatility and although prices will occasionally drop precipitously, industry prices over the long term will continue to be driven by market supply and demand fundamentals. The impairment tests that the Company performs make use of its long-term price assumptions used in its planning and budgeting processes and its capital expenditure decisions, which are considered reasonable estimates, given market indicators and experience. When determining the value in use of those assets, short-term price volatility affects the cash flow estimates for the first years.

Lower future oil and gas prices, when considered long-term trends, as well as negative impacts of significant changes in reserve volumes, production curve expectations, lifting costs or discount rates could trigger the need for impairment assessment.

See notes 4.8 and 12 for more detailed information about oil and natural gas exploration and development assets.

5.2.Identifying cash-generating units for impairment testing

Identifying cash-generating units (CGU’s) requires management assumptions and judgment, based on the Company’s business and management model, and may significantly impact the results of the impairment tests of long-lived assets. The assumptions set out below have been consistently applied by the Company:

-Exploration and Production CGU’s: producing properties: oil and natural gas producing properties comprised of a group of exploration and development assets.

-Refining, transportation and marketing CGU’s: i) Downstream CGU: a single CGU comprised of all refineries and associated assets, terminals and pipelines, as well as logistics assets operated by Transpetro. This CGU was identified based on the concept of integrated optimization and performance management, which focus on the global performance of the CGU, allowing a shift of margins from one refinery to another. Pipelines and terminals are an integral part and interdependent portion of the refining assets, required to supply the market. Complexo Petroquímico do Rio de Janeiro (Comperj) and the second refining unit of Refinaria Abreu e Lima (RNEST) are both under construction and have been removed from the Downstream CGU in the quarter ended December 31, 2014 and assessed for impairment individually, as set out in note 14; ii) Petrochemical CGU: petrochemical plants from PetroquímicaSuape and Citepe; and iii) Transportation CGU: the transportation CGU is comprised of the Transpetro’s fleet vessels.

-Gas & Power CGU’s: i) Natural gas CGU: comprised of natural gas pipelines, natural gas processing plants and fertilizers and nitrogen products plants. A fertilizers plant under construction, Unidade de Fertilizantes Nitrogenados III (UFN III), has been excluded from this CGU, as set out note 14; and ii) Power CGU: thermoelectric power generation plants.

-Distribution CGU: comprised of the distribution assets related to the operations of Petrobras Distribuidora S.A.

-Biofuels CGU’s: i) Biodiesel CGU: group of assets that comprise the biodiesel plants. This CGU comprises an integrated unit of the biodiesel plants and is defined based on the production planning and operation process, considering domestic market conditions, the production capacity of each plant, as well as the results of biofuels auctions and raw materials supply; and ii) Ethanol CGU: comprised of investments in associates and joint ventures in the ethanol sector.

-International CGU: i) International exploration and production CGU: this CGU comprises the oil and natural gas producing properties, including exploration and development assets, outside Brazil; ii) other operations of the international business segment: smallest identifiable group of assets that generates largely independent cash inflows.

F-30

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Investments in associates and joint ventures including goodwill are individually tested for impairment.

See notes 4.10 and 14 for more detailed information about impairment.

5.3. Pension and other post-retirement benefits

The actuarial obligations and net expenses related to defined benefit pension and health care post-retirement plans are computed based on several financial and demographic assumptions, of which the most significant are:

-Discount rate: comprises the projected future inflation in addition to an equivalent real interest rate that matches the duration of the pension and health care obligations with the future yield curve of long-term Brazilian Government Bonds; and

-Medical costs: comprise several projected annual growth rates based on per capita health care benefits paid over the last five years, which are used as a basis for projections, decreasing gradually over 30 years, to converge with a general price inflation index.

These and other estimates are reviewed at least annually and may differ materially from actual results due to changing market and financial conditions, as well as actual results of actuarial assumptions.

The sensitivity analysis of discount rates and changes in medical costs as well as additional information about actuarial assumptions are set out in note 22.

5.4.Estimates related to contingencies and legal proceedings

The Company is a defendant in numerous legal proceedings involving tax, civil, labor, corporate and environmental issues arising from the normal course of its business for which estimates are made by Petrobras of the amounts of the obligations and the probability that an outflow of resources will be required. Those estimates are based on legal counsel and Management’s best estimates.

See note 30 for more detailed information about contingencies and legal proceedings.

5.5.Dismantling of areas and environmental remediation

The Company has legal and constructive obligations to remove equipment and restore onshore and offshore areas at the end of operations at production sites. Its most significant asset removal obligations involve removal and disposal of offshore oil and gas production facilities in Brazil and abroad. Estimates of costs for future environmental cleanup and remediation activities are based on current information about costs and expected plans for remediation.

These estimates require performing complex calculations that involve significant judgment because the obligations are long-term; the contracts and regulations contain subjective descriptions of what removal and remediation practices and criteria will have to be met when the events actually occur; and asset removal technologies and costs are constantly changing, along with political, environmental, safety and public relations considerations.

The Company is constantly conducting studies to incorporate technologies and procedures seeking to optimize the operations of abandonment, considering industry best practices. However, the timing and amounts of future cash flows are subject to significant uncertainty.

See notes 4.13 and 20 for more detailed information about the decommissioning provisions.

F-31

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

5.6.Fair value of derivative financial instruments

Derivative financial instruments are measured at fair value in the financial statements. Fair value measurement requires judgment related to the availability of identical or similar assets quoted in active markets or otherwise the use of alternate measurement models that can become increasingly complex and depend on the use of estimates such as future prices, long-term interest rates and price indices (inflation indices).

See notes 4.3.5 and 33 for more detailed information about derivative financial instruments.

5.7.Hedge accounting

Identifying hedging relationships between hedged items and hedging instruments (derivative financial instruments and non-derivative financial instruments, such as long-term debt) requires critical judgments related to the existence of the hedging relationship and its effectiveness. In addition, the Company continuously assesses the alignment between the hedging relationships identified and the objectives and strategy of its risk management policy.

5.8.Accounting approach to the “Lava Jato (Car Wash) Operation”

5.8.1.Estimation Methodology

As set out in note 3, in the third quarter of 2014, the Company wrote off US$2,527 of capitalized costs representing amounts that Petrobras overpaid for the acquisition of property, plant and equipment in prior years.

To account for these overpayments, the Company developed an estimation methodology described in note 3. Petrobras acknowledges the degree of uncertainty involved in the estimation methodology and has developed a sensitivity analysis (set out in note 3) and will continue to monitor the ongoing investigations and the availability of other information concerning the amounts it may have overpaid in the context of the payment scheme.  If reliable information becomes available that indicates with sufficient precision that the Company’s estimate should be adjusted, it will evaluate whether the adjustment is material and, if so, recognize it.

However, as previously discussed, the Company believes it has used the most appropriate methodology and assumptions to determine the amounts of overpayments incorrectly capitalized and there is no evidence that would indicate the possibility of a material change in the amounts written-off.

5.8.2.Possible alternative approaches considered and rejected

IFRS allows the use of a revaluation model under IAS 16 to re-measure the carrying amount of property, plant and equipment, but the use of revaluation models is not permitted by Brazilian Corporation Law. As a result, the Company did not consider that approach as a viable alternative to address the impact of the overpayment on the affected property, plant and equipment. 

The Company considered whether it could develop a surrogate or proxy to quantify the errors to be corrected. The proposed proxy would involve determining the fair value of each affected asset (measured on a stand-alone basis), and estimating the amount of overpayments as being the difference between the fair value of each affected asset and its carrying amount.

The proposed approach would be different than a charge for impairment because the assets would be valued on a stand-alone basis and not as a group of assets included in a cash generating unit. The recoverable amount of those assets would also not be determined by the higher amount between their fair value and their value in use, but would be considered to be their fair value.

F-32

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The Company engaged two global firms internationally known as independent appraisers to determine the fair value of most of the affected assets based on the valuation technique that was most appropriate to the specificities of each asset and for which relevant data was available.

For 31 individual assets, book value exceeded fair value by an aggregate of US$36.1 billion, while the book value of the 21 other individual assets was an aggregate of US$11.1 billion below fair value. As previously discussed, the difference between the fair value and the carrying amount of those assets would conceptually be attributable to improper payments.

However, after the difference was measured, the Company concluded that the shortfall between the fair value and the carrying amount of the assets was significantly larger than any reasonable estimate of the improper payments uncovered in the context of the Lava Jato investigation. Fair value shortfalls originate not primarily from improper payments, but from different sources (both related to the method of measuring the fair value and to changes in the business context), which cannot be individually or separately quantified, such as:

-The fair value of the assets was measured on a stand-alone basis and did not consider value that would be added to the assets when used in an integrated manner, in which value is transferred from one asset to another, depending on how the company operates the assets, because management seeks to achieve the global optimum of the portfolio of assets instead of the individual optimum (especially for the refining assets). Those gains are captured when those assets are evaluated inside cash-generating units (CGU) for impairment testing and many of the affected assets are in a single CGU;

-The discount rate used by the appraisers considered a risk premium related to the acquisition of a single asset by a third party inside a market highly concentrated in a single large-scale player (Petrobras). This would be applicable to evaluate the acquisition of new property, plant and equipment, but not to determine the value in use of assets which already belong to the portfolio of the Company;

-Changes in economic and financial variables (exchange rate, discount rate, risk metrics and cost of capital);

-Changes in estimates of prices and margins of inputs;

-Changes in projections of prices, margins and demand for products sold in light of recent changes in market conditions;

-Changes in equipment and input prices, wages and other correlated costs;

-The impact of local content requirements; and

-Project planning deficiencies (especially in the Engineering and Downstream areas).

Therefore, the Company concluded that using the fair value as a surrogate or proxy to adjust its property, plant and equipment would not have been appropriate, as the adjustment would include elements with no direct relation to the overpayments.

5.9.Allowance for impairment of trade receivables

Management continuously assesses whether there is objective evidence that trade receivables are impaired and recognizes allowances for impairment of trade receivables to cover losses. Such evidence includes insolvency, defaults, judicial recovery claims, a significant probability of a debtor filing for bankruptcy and others.

See note 8 for more detailed information about allowance for impairment of trade receivables.

F-33

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

6.New standards and interpretations

a)IASB - International Accounting Standards Board

During 2014, the following interpretation issued by the International Accounting Standards Board (IASB) became effective but did not have a significant impact on the Company’s financial statements for year ended December 31, 2014:

- IFRIC 21 - "Levies" is an interpretation of IAS 37, ‘Provisions, contingent liabilities and contingent assets’. IAS 37 sets out criteria for the recognition of a liability, one of which is the requirement for the entity to have a present obligation as a result of a past event (known as an obligating event). The interpretation addresses what the obligating event is (the transaction described in the tax regulations) that gives rise to the payment of a levy and when a liability should be recognized.

The main standards and amendments to standards issued by the IASB and not effective as of December 31, 2014 are set out following. The Company did not early adopt those standards:

Standards	Brief Description	Effective Date
Amendment to IFRS 11 “Joint Arrangements”	The amendments require an investor to apply the principles of business combination accounting when it acquires an interest in a joint operation (as defined under IFRS 11) that constitutes a "business (as defined under IFRS 3)."	January 1, 2016
Amendment to IFRS 10 “Consolidated Financial Statements” and IAS 28 “Investments in Associates and Joint Ventures”	A full gain or loss is recognized when a transaction involves a business (as defined under IFRS 3). A partial gain or loss is recognized when a transaction involves assets that do not constitute a business, even if those assets are in a subsidiary.	January 1, 2016
IFRS 15 – “Revenue from Contracts with Customers”	Sets out requirements for revenue recognition, measurement and disclosure. According to IFRS 15, revenue is recognized when a customer obtains control of a good or service. It changes the current model, based on which revenue is recognized when significant risks and rewards of ownership are transferred. In addition IFRS 15 provides guidance for revenue recognition in more complex cases.	January 1, 2017
IFRS 9 - "Financial Instruments"	Simplifies the mixed measurement model and establishes two primary measurement categories for financial assets: amortized cost and fair value. The basis of classification depends on the entity's business model and the contractual cash flows characteristics of the financial asset. IFRS 9 changes the requirements for hedge effectiveness in hedge accounting. IAS 39 is still applicable for impairment of financial assets and hedge accounting.	January 1, 2018

The Company is assessing the impact the new standards and amendments to standards may have on future periods.

b)Brazilian Tax Law

On May 14, 2014, Law 12,973 was enacted, establishing the following:

- Repeals the Transition Tax Regime (Regime Tributário de Transição - RTT) established by Law 11,941 enacted on May 27, 2009;

- Establishes regulations for changes in federal taxes (income tax, PIS and COFINS) in contemplation of adoption of the International Financial Reporting Standards - IFRS;

Except for articles 3, 72 to 75 and 93 to 119, which were effective as of the date the law was enacted, law 12,973 will be effective on January 1, 2015.

Regulation for this law was established by Normative Instruction 1,515, issued by the Federal Revenue Secretariat of Brazil on November 24, 2014.

F-34

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

As Management has decided to adopt articles 1, 2 and 4 to 70 of Law 12,973, with respect to the adoption of the new tax regime (repealing RTT), beginning in 2015, there has been no impact to the 2014 financial statements. The Company does not expect the adoption of the new tax regime to result in material impacts in its tax expense or in its financial statements from 2015.

7.Cash and cash equivalents and Marketable securities

Cash and cash equivalents

	2014	2013
Cash at bank and in hand	709	951
Short-term financial investments
- In Brazil
Single-member funds (Interbank Deposit) and other short-term deposits	1,999	3,493
Other investment funds	41	53
	2,040	3,546
- Abroad
Time deposits	8,700	6,075
Automatic investing accounts	3,097	3,982
Other financial investments abroad	2,109	1,314
	13,906	11,371
Total short-term financial investments	15,946	14,917
Total cash and cash equivalents	16,655	15,868

Short-term financial investments in Brazil comprise investments in exclusive (single-member) funds, mainly holding Brazilian Federal Government Bonds. Short-term financial investments abroad are comprised of time deposits, highly-liquid automatic investing accounts and other short-term fixed income instruments from highly-rated financial institutions with maturities of three months or less.

Marketable securities

	2014	2013
Trading securities	2,690	3,878
Available-for-sale securities	21	17
Held-to-maturity securities	6,721	121
	9,432	4,016
Current	9,323	3,885
Non-current	109	131

Trading securities refer mainly to investments in Brazilian Government Bonds and held-to-maturity securities are mainly comprised of time deposits in highly-rated financial institutions.

These financial investments have maturities of more than three months and are classified as current assets due to their maturity or the expectation of their realization in the short term.

F-35

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

8.Trade and other receivables

8.1.Trade and other receivables, net

	2014	2013
Trade receivables
Third parties	10,627	10,153
Related parties (Note 19)
Investees	863	658
Receivables from the electricity sector	2,966	1,849
Petroleum and alcohol accounts -Federal Government	317	357
Other receivables	2,005	2,591
	16,778	15,608
Provision for impairment of trade receivables	(3,372)	(1,406)
	13,406	14,202
Current	7,969	9,670
Non-current	5,437	4,532

8.2.Changes in the allowance for impairment of trade receivables

	2014	2013	2012
Opening balance	1,406	1,452	1,487
Additions (*)	2,484	133	244
Write-offs	(131)	(68)	(210)
Cumulative translation adjustment	(387)	(111)	(69)
Closing balance	3,372	1,406	1,452
Current	1,448	800	854
Non-current	1,924	606	598
(*) Relates primarily to the electricity sector (see note 8.4).

8.3.Trade receivables overdue - Third parties

	2014	2013
Up to 3 months	823	911
From 3 to 6 months	178	272
From 6 to 12 months	181	395
More than 12 months	1,832	1,827
	3,014	3,405

F-36

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

8.4.Trade receivables – electricity sector (isolated electricity system in the northern region of Brazil)

	12.31.2014			12.31.2013
	Not yet due	Overdue	Total	Not yet due	Overdue	Total
Clients
Eletrobras Group (Note 19)	2,536	430	2,966	663	1,186	1,849
Companhia de Gás do Amazonas (CIGÁS)	1,266	167	1,433	−	682	682
Others	24	394	418	43	264	307
	3,826	991	4,817	706	2,132	2,838
(-) Allowance for impairment of trade receivables	(1,090)	(621)	(1,711)	−	(15)	(15)
Total	2,736	370	3,106	706	2,117	2,823
Related parties	2,473	165	2,638	663	1,180	1,843
Third parties	263	205	468	43	937	980

As of December 31, 2014, US$ 4,198 of the Company’s receivables from the isolated electricity system in the northern region of Brazil were classified as non-current assets. The balance of those receivables was US$ 4,817 as of December 31, 2014 (US$ 2,838 as of December 31, 2013) and comprise:

(i) US$ 4,526 (US$ 2,659 as of December 31, 2013) from fuel oil, natural gas and other products sold to thermoelectric power plants (which are subsidiaries of Eletrobras), state-owned natural gas distribution companies and independent electricity producers (Produtores Independentes de Energia – PIE) located in the northern region of Brazil.

(ii) US$ 291 (US$ 179 as of December 31, 2013) from an electricity supply contract entered into by Petrobras and a subsidiary of Eletrobras in 2005 classified as a finance lease of two thermoelectric power plants in the northern region of Brazil. The thermoelectric power plants will be transferred to the subsidiary of Eletrobras by the end of the lease term (20 years) for no additional cost. These receivables are not overdue.

A portion of the costs related to the fuel supplied to those thermoelectric power plants is borne by funds from the Fuel Consumption Account (Conta de Consumo de Combustível – CCC), which is managed by Eletrobras.

Funds transferred from the CCC to the electricity companies in the northern region of Brazil have not been sufficient for them to meet their financial obligations, and, as a result, some of these companies are experiencing financial difficulties and have not been able to pay for the products supplied by Petrobras. The Company entered into a debt acknowledgement agreement with subsidiaries of Eletrobras on December 31, 2014 with respect to the balance of its receivables as of November 30, 2014. Eletrobras acknowledged being indebted in the amount of US$ 3,509. This amount will be updated based on the Selic interest rate (Brazilian short-term interest rate) every month. Under the agreement, the amounts are expected to be paid in 120 monthly installments beginning in February 2015.

Pursuant to the debt acknowledgment agreement, receivables due to Petrobras in the amount of US$ 2,483 were collateralized by receivables from the CCC that were pledged as security. The collateralized receivables relate to amounts payable from the Brazilian Energy Development Account (Conta de Desenvolvimento Energético - CDE) to the CCC. One of the purposes of the CDE is to refund the costs incurred by the CCC to support electricity generation and distribution in the isolated electricity system. The debt acknowledgement agreement was collateralized when the Brazilian Electricity Agency - Agência Nacional de Energia Elétrica (ANEEL) recognized in February 2015 a debt acknowledgement for the payables from the CDE to the CCC.

Beginning in 2015 the Brazilian government implemented a new pricing policy for the electricity sector and has already implemented price increases in the first quarter of 2015. The new policy will strengthen the financial situation of the companies in the electricity sector and reduce their insolvency on payables from fuel oil and other products supplied. The Company expects that the impact of the higher electricity prices resulting from the new policy will be more significant after the first quarter of 2015, notably because the funds received from the end customer will be transferred to the CCC and used to refund the electricity generation companies.

F-37

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The Company’s Management has determined that an allowance for impairment of trade receivables was required to cover receivables as of October 31, 2014 with no guarantees, including the balances of previous debt acknowledgement agreements and from companies that were not part of the most recent debt acknowledgment agreement with Eletrobras. An allowance for impairment of trade receivables of US$ 1,696 was recognized in 2014 (US$ 1,948 charged to selling expenses, partially offset by a US$ 252 cumulative translation adjustment -CTA effect). No charges were recognized for companies that were not insolvent or for receivables from sales after November 1, 2014, because those amounts were included in the calculation of ANEEL’s new pricing policy.

9.Inventories

	2014	2013
Crude oil	3,977	5,849
Oil products	4,333	4,985
Intermediate products	854	924
Natural gas and LNG (*)	358	401
Biofuels	150	158
Fertilizers	34	26
	9,706	12,343
Materials, supplies and others	1,806	1,935
	11,512	14,278
Current	11,466	14,225
Non-current	46	53
(*) Liquid natural gas

Inventories are presented net of a US$ 150 allowance reducing inventories to net realizable value (US$ 88 as of December 31, 2013), mainly due to the decrease in international prices of crude oil and oil products. The amount of write-down of inventories to net realizable value recognized as cost of sales in 2014 is US$ 1,015 (US$ 580 in 2013).

A portion of the crude oil and/or oil products inventories have been pledged as security for the Terms of Financial Commitment (TFC) signed by Petrobras and Petros in the amount of US$ 2,316 (US$ 2,976 as of December 31, 2013), as set out in note 22.1.

10.Disposal of assets and legal mergers

10.1.Disposal of assets

Brasil PCH S.A.

On June 14, 2013, Petrobras entered into an agreement with Cemig Geração e Transmissão S.A. (which subsequently assigned the sale and purchase contract to Chipley SP Participações) for the disposal of its entire equity interest in Brasil PCH S.A., equivalent to 49% of its voting stock, for a consideration of US$ 304, before contractual price adjustments.

On February 14, 2014, the remaining conditions precedent for this transaction were met and the disposal was concluded for a total amount of US$ 301, after contractual price adjustments. A pre-tax gain of US$ 274 was recognized in other income.

F-38

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Petrobras Colombia Limited (PEC)

On September 13, 2013, the Board of Directors of Petrobras approved the disposal of 100% of the share capital of Petrobras Colombia Limited (PEC), a subsidiary of Petrobras International Braspetro B.V. (PIB BV), to Perenco Colombia Limited, for a consideration of US$ 380, subject to price adjustments through the close of the transaction.

On April 30, 2014 the transaction was concluded, the respective assets and liabilities were transferred to Perenco and a US$ 101 gain was recognized in other income.

UTE Norte Fluminense S.A.

On April 11, 2014 Petrobras disposed of its 10% interest in Usina Termelétrica Norte Fluminense (UTE - NF) to Électricité de France (EDF) for US$ 82. A US$ 37 gain was recognized in other income. There are no precedent conditions to the transaction.

Transierra S.A.

On August 5, 2014, Petrobras disposed of its 44.5% interest in Transierra S.A. to Yacimientos Petrolíferos Fiscales Bolivianos (YPFB) for US$ 107. A US$ 32 gain was recognized in other income. There are no precedent conditions to the transaction.

Innova S.A.

On August 16, 2013, the Board of Directors of Petrobras approved the disposal of 100% of the share capital of Innova S.A. to Videolar S.A. and its controlling shareholder at a consideration of US$ 369, subject to certain condition precedent, such as approval by the Brazilian Antitrust Regulator (Conselho Administrativo de Defesa Econômica – CADE).

On October 1, 2014 the Brazilian Antitrust Regulator (Conselho Administrativo de Defesa Econômica – CADE) approved the purchase of Innova S.A by Videolar S.A with restrictions. The approval of the transaction was conditioned on the fulfillment of a set of measures set out in the Merger Control Agreement (Acordo em Controle e Concentrações – ACC) entered into by the antitrust agency and the merging parties.

On October 30, 2014 the transaction was concluded as set out in the sales and purchase agreement and a US$ 57 gain was recognized in other income.

Petrobras Energia Peru S.A.

On November 12, 2013, the Board of Directors of Petrobras approved the disposal of 100% of Petrobras Energia Peru S.A. by Petrobras de Valores Internacional de España S.L. – PVIE and Petrobras International Braspetro B.V. – PIB BV to China National Petroleum Corporation (CNPC), for US$ 2,643, subject to price adjustment through the close of the transaction. Price adjustments are being calculated, pursuant to the sales and purchase agreement.

In November 2014 the conditions precedent for the transaction were met. The conditions included approval by the Chinese and Peruvian governments, and compliance with the procedures under their "Joint Operating Agreement” (JOA). A US$ 1,304 pre-tax gain was recognized in other income, US$ 869 net of income taxes of US$ 435.

F-39

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Companhia de Gás de Minas Gerais

On July 18, 2014, the Board of Directors of Petrobras approved the disposal of its 40% interest in Companhia de Gás de Minas Gerais (Gasmig) to Companhia Energética de Minas Gerais (Cemig).

On October 10, 2014 the conditions precedent were met and the transaction was concluded for US$ 251. A US$ 68 a gain was recognized in other income.

10.2.Assets classified as held for sale

As of December 31, 2014, the Company had assets classified as held for sale in the amount of US$ 5 (US$ 2,407 as of December 31, 2013, with associated liabilities of US$ 1,073). Those assets comprise PI, PIII, PIV and PV drilling rigs and PXIV platform, all related to exploration and production in Brazil.

The conditions precedent were met and other assets classified as held for sale as of December 31, 2013 were sold during 2014.

10.3.Legal mergers

On April 2, 2014, the Petrobras Shareholders’ Extraordinary General Meeting approved the mergers of Termoaçu S.A., Termoceará Ltda. and Companhia Locadora de Equipamentos Petrolíferos – CLEP into Petrobras.

On January 30, 2015, the Shareholders’ Extraordinary General Meeting of Petrobras approved the mergers of Arembepe Energia S.A. and Energética Camaçari Muricy S.A. into Petrobras.

These mergers did not affect share capital.

The objective of these mergers is to simplify the corporate structure of the Company, reduce costs and capture synergies. These mergers did not affect the Company’s consolidated financial statements.

F-40

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

11.Investments

11.1.Information about direct subsidiaries, joint arrangements and associates

	Main business segment	% Petrobras' ownership	% Petrobras' voting rights	Shareholders’ equity (deficit)	Net income (loss) for the year	Country
Entities that are consolidated
Subsidiaries
Petrobras Netherlands B.V. - PNBV (i)	E&P	100.00%	100.00%	14,209	1,061	Netherlands
Petrobras Distribuidora S.A. - BR	Distribution	100.00%	100.00%	4,566	481	Brazil
Transportadora Associada de Gás S.A. - TAG	Gas & Power	100.00%	100.00%	2,490	243	Brazil
Petrobras Transporte S.A. - Transpetro	RT&M	100.00%	100.00%	1,889	319	Brazil
Petrobras Logística de Exploração e Produção S.A. - PB-LOG	E&P	100.00%	100.00%	1,316	190	Brazil
Petrobras Gás S.A. - Gaspetro	Gas & Power	100.00%	100.00%	977	634	Brazil
Petrobras International Braspetro - PIB BV (i) (ii)	International	88.12%	88.12%	984	(698)	Netherlands
Petrobras Biocombustível S.A.	Biofuels	100.00%	100.00%	832	(113)	Brazil
Companhia Integrada Têxtil de Pernambuco S.A. - CITEPE	RT&M	100.00%	100.00%	396	(1,128)	Brazil
Liquigás Distribuidora S.A.	RT&M	100.00%	100.00%	343	23	Brazil
Termomacaé Ltda.	Gas & Power	99.99%	99.99%	306	79	Brazil
Companhia Petroquímica de Pernambuco S.A. - PetroquímicaSuape	RT&M	100.00%	100.00%	292	(531)	Brazil
Araucária Nitrogenados S.A.	Gas & Power	100.00%	100.00%	286	(79)	Brazil
Breitener Energética S.A.	Gas & Power	93.66%	93.66%	227	41	Brazil
Braspetro Oil Services Company - Brasoil (i)	Corporate	100.00%	100.00%	183	204	Cayman Islands
Petrobras Comercializadora de Energia Ltda. - PBEN	Gas & Power	99.91%	99.91%	163	105	Brazil
Termobahia S.A.	Gas & Power	98.85%	98.85%	151	28	Brazil
Arembepe Energia S.A.	Gas & Power	100.00%	100.00%	146	50	Brazil
5283 Participações Ltda.	International	100.00%	100.00%	117	(83)	Brazil
Baixada Santista Energia S.A.	Gas & Power	100.00%	100.00%	103	1	Brazil
Energética Camaçari Muricy I Ltda.	Gas & Power	100.00%	100.00%	84	51	Brazil
Fundo de Investimento Imobiliário RB Logística - FII	E&P	99.00%	99.00%	66	(31)	Brazil
Termomacaé Comercializadora de Energia Ltda	Gas & Power	100.00%	100.00%	35	4	Brazil
Cordoba Financial Services GmbH (i)	Corporate	100.00%	100.00%	20	(3)	Austria
Petrobras Negócios Eletrônicos S.A. - E-Petro	Corporate	99.95%	99.95%	13	1	Brazil
Downstream Participações Ltda.	Corporate	99.99%	100.00%	(1)	−	Brazil
Joint operations
Fábrica Carioca de Catalizadores S.A. - FCC	RT&M	50.00%	50.00%	94	20	Brazil
Ibiritermo S.A.	Gas & Power	50.00%	50.00%	59	17	Brazil
Entities that are not consolidated
Joint ventures
Logum Logística S.A.	RT&M	20.00%	20.00%	126	(62)	Brazil
Cia Energética Manauara S.A.	Gas & Power	40.00%	40.00%	52	1	Brazil
Petrocoque S.A. Indústria e Comércio	RT&M	50.00%	50.00%	50	14	Brazil
Brentech Energia S.A.	Gas & Power	30.00%	30.00%	28	15	Brazil
Brasympe Energia S.A.	Gas & Power	20.00%	20.00%	28	(1)	Brazil
Refinaria de Petróleo Riograndense S.A.	RT&M	33.20%	50.00%	25	(1)	Brazil
METANOR S.A. - Metanol do Nordeste	RT&M	34.54%	34.54%	20	2	Brazil
Eólica Mangue Seco 4 - Geradora e Comercializadora de Energia Elétrica S.A.	Gas & Power	49.00%	49.00%	15	−	Brazil
Eólica Mangue Seco 3 - Geradora e Comercializadora de Energia Elétrica S.A.	Gas & Power	49.00%	49.00%	15	−	Brazil
Eólica Mangue Seco 2 - Geradora e Comercializadora de Energia Elétrica S.A.	Gas & Power	51.00%	51.00%	14	−	Brazil
Eólica Mangue Seco 1 - Geradora e Comercializadora de Energia Elétrica S.A.	Gas & Power	49.00%	49.00%	13	(1)	Brazil
Companhia de Coque Calcinado de Petróleo S.A. - COQUEPAR	RT&M	45.00%	45.00%	4	(13)	Brazil
Participações em Complexos Bioenergéticos S.A. - PCBIOS	Biofuels	50.00%	50.00%	−	(27)	Brazil
GNL do Nordeste Ltda.	Gas & Power	50.00%	50.00%	−	−	Brazil
Associates
Fundo de Investimento em Participações de Sondas	E&P	4.59%	4.59%	2,972	50	Brazil
Sete Brasil Participações S.A.	E&P	5.00%	5.00%	2,883	400	Brazil
Braskem S.A.	RT&M	36.20%	47.03%	2,274	367	Brazil
UEG Araucária Ltda.	Gas & Power	20.00%	20.00%	370	201	Brazil
Deten Química S.A.	RT&M	27.88%	27.88%	123	25	Brazil
Energética SUAPE II	Gas & Power	20.00%	20.00%	82	31	Brazil
Termoelétrica Potiguar S.A. - TEP	Gas & Power	20.00%	20.00%	27	(6)	Brazil
Nitroclor Ltda.	RT&M	38.80%	38.80%	−	−	Brazil
Bioenergética Britarumã S.A.	Gas & Power	30.00%	30.00%	−	−	Brazil
(i) Companies abroad with financial statements prepared in foreign currencies.
(ii) 5283 Participações Ltda holds an 11.88% interest in PIB BV and, therefore, PIB BV is a wholly-owned subsidiary.

F-41

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

11.2.Investments in associates and joint ventures

	Carrying amount of the investments		Share of earnings in the investments
Investments accounted for using the equity method	12.31.2014	12.31.2013	12.31.2014	12.31.2013
Braskem S.A.	1,711	2,201	141	68
Petrobras Oil & Gas B.V. - PO&G	1,714	1,707	126	229
Guarani S.A.	518	510	(24)	(13)
State-controlled Natural Gas Distributors	340	533	121	128
Nova Fronteira Bioenergia S.A.	163	170	16	(6)
Petrowayu S.A.	136	185	(62)	(1)
Petroritupano S.A.	112	198	(109)	(38)
Other petrochemical investees	66	84	2	12
UEG Araucária Ltda	73	59	45	3
Petrokariña S.A.	45	66	(27)	(10)
Transierra S.A.	−	68	8	5
Other associates	858	863	(19)	130
	5,736	6,644	218	507
Other investees	17	22	−	−
	5,753	6,666	218	507

11.3.Investments in listed companies

	Thousand-share lot			Quoted stock exchange prices (US$  per share)		Market value
Company	12.31.2014	12.31.2013	Type	12.31.2014	12.31.2013	12.31.2014	12.31.2013
Indirect subsidiary
Petrobras Argentina S.A.	1,356,792	1,356,792	Common	0.65	0.80	879	1,083
						879	1,083
Associate
Braskem S.A.	212,427	212,427	Common	4.07	7.04	864	1,496
Braskem S.A.	75,793	75,793	Preferred A	6.59	8.96	499	680
						1,363	2,176

The market value of these shares does not necessarily reflect the realizable value upon sale of a large block of shares.

Braskem S.A. - Investment in publicly traded associate:

The main assumptions on which cash flow projections were based to determine Braskem’s value in use are set out in note 14.2.

F-42

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

11.4.Non-controlling interest

The total amount of non-controlling interest at December 31, 2014 is US$ 706, of which US$ 484 is related to Petrobras Argentina S.A. Condensed financial information of Petrobras Argentina S.A. is set out following:

	Petrobras Argentina S.A.
	2014	2013
Current assets	1,008	980
Long-term receivables	83	174
Property, plant and equipment	1,355	1,468
Other non-current assets	410	636
	2,856	3,258
Current liabilities	689	618
Non-current liabilities	693	834
Shareholders' equity	1,474	1,806
	2,856	3,258
Sales revenues	145	254
Net income	43	139
Increase (decrease) in cash and cash equivalents	118	(40)

Petrobras Argentina S.A. is an integrated energy company, indirectly controlled by Petrobras (directly controlled by PIB BV, which holds a 67.19% interest in this company) and its main place of business is Argentina.

11.5.Summarized information on joint ventures and associates

The Company invests in joint ventures and associates in Brazil and abroad, whose activities are related to petrochemical companies, gas distributors, biofuels, thermoelectric power plants, refineries and other activities. Condensed financial information is set out below:

	2014
	Joint ventures		Associates
	In Brazil	Abroad	In Brazil	Abroad
Current assets	1,474	1,347	10,701	2,241
Non-current assets	438	40	2,695	210
Property, plant and equipment	1,598	3,014	12,207	3,600
Other non-current assets	753	18	4,342	79
	4,263	4,419	29,945	6,130
Current liabilities	1,841	503	6,795	3,482
Non-current liabilities	732	1,438	13,426	992
Shareholders' equity	1,681	2,328	9,779	1,656
Non-controlling interest	9	150	(55)	−
	4,263	4,419	29,945	6,130
Sales revenues	5,583	2,491	22,540	189
Net Income for the year	144	252	769	331
Ownership interest - %	20 to 83%	34 to 50%	5 to 49%	11 to 49%

F-43

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

	2013
	Joint ventures		Associates
	In Brazil	Abroad	In Brazil	Abroad
Current assets	1,603	1,349	9,677	2,749
Non-current assets	830	81	3,103	53
Property, plant and equipment	1,639	2,879	13,141	2,783
Other non-current assets	933	50	2,945	71
	5,005	4,359	28,866	5,656
Current liabilities	1,733	495	6,750	2,562
Non-current liabilities	1,022	1,442	13,864	1,035
Shareholders' equity	2,240	2,268	8,190	2,059
Non-controlling interest	10	154	62	−
	5,005	4,359	28,866	5,656
Sales revenues	5,646	1,791	21,363	93
Net Income for the Year	254	507	1,201	322
Ownership interest - %	20 to 83%	34 to 50%	5 to 49%	11 to 49%

F-44

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

12.Property, plant and equipment

12.1.By class of assets

	Land, buildings and improvement	Equipment and other assets	Assets under construction (*)	Exploration and development costs (Oil and gas producing properties)	Total
Balance at January 1, 2013	8,164	81,708	81,663	33,366	204,901
Additions	68	1,794	36,125	663	38,650
Additions to / review of estimates of decommissioning costs	−	−	−	(629)	(629)
Capitalized borrowing costs	−	−	3,909	−	3,909
Business combinations	17	31	16	−	64
Write-offs	(4)	(121)	(2,399)	(25)	(2,549)
Transfers (***)	1,224	23,626	(29,620)	25,896	21,126
Depreciation, amortization and depletion	(518)	(7,513)	−	(4,939)	(12,970)
Impairment recognition (****)	−	(11)	(6)	(85)	(102)
Impairment reversal (****)	−	49	−	72	121
Cumulative translation adjustment	(1,083)	(9,158)	(9,930)	(4,449)	(24,620)
Balance at December 31, 2013	7,868	90,405	79,758	49,870	227,901
Cost	10,729	133,368	79,758	77,117	300,972
Accumulated depreciation, amortization and depletion	(2,861)	(42,963)	−	(27,247)	(73,071)
Balance at December 31, 2013	7,868	90,405	79,758	49,870	227,901
Additions	30	2,031	30,362	580	33,003
Additions to / review of estimates of decommissioning costs	−	−	−	1,999	1,999
Capitalized borrowing costs	−	−	3,592	−	3,592
Write-offs	(9)	(57)	(4,024)	(196)	(4,286)
Write-off - overpayments incorrectly capitalized	(35)	(1,160)	(1,078)	(91)	(2,364)
Transfers (***)	2,685	25,371	(36,178)	23,078	14,956
Depreciation, amortization and depletion	(534)	(7,381)	−	(4,888)	(12,803)
Impairment recognition (note 14)(****)	(899)	(1,398)	(11,670)	(2,839)	(16,806)
Impairment reversal (****)	−	17	−	3	20
Cumulative translation adjustment	(1,071)	(9,832)	(7,819)	(7,760)	(26,482)
Balance at December 31, 2014	8,035	97,996	52,943	59,756	218,730
Cost	10,979	142,030	52,943	88,023	293,975
Accumulated depreciation, amortization and depletion	(2,944)	(44,034)	−	(28,267)	(75,245)
Balance at December 31, 2014	8,035	97,996	52,943	59,756	218,730
Weighted average of useful life in years	40 (25 to 50 ) (except land)	20 (3 to 31) (**)		Units of production method
(*) See note 29 for assets under construction by business area
(**) Includes exploration and production assets depreciated based on the units of production method.
(***) Includes US$ 10,446 (US$ 22,134 in 2013), reclassified from Intangible Assets to Property, Plant and Equipment in 2014, as a result of the declaration of commerciality of areas of the Assignment Agreement (note 12.3).
(****) Recognized in the statement of income.

As of December 31, 2014, property, plant and equipment includes assets under finance leases of US$ 72 (US$ 86 as of December 31, 2013).

F-45

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

12.2.Estimated useful life

Buildings and improvements, equipment and other assets
Estimated useful life	Cost	Accumulated depreciation	Balance at 2014
5 years or less	4,534	(2,862)	1,672
6 - 10 years	10,897	(5,278)	5,619
11 - 15 years	1,044	(486)	558
16 - 20 years	47,225	(12,341)	34,884
21 - 25 years	19,962	(6,616)	13,346
25 - 30 years	22,727	(4,097)	18,630
30 years or more	25,055	(5,129)	19,926
Units of production method	20,957	(10,168)	10,789
	152,401	(46,977)	105,424
Buildings and improvements	10,371	(2,943)	7,428
Equipment and other assets	142,030	(44,034)	97,996

The estimated useful life of equipment and other assets was revised in 2014, based on reports of internal appraisers.

12.3.Concession for exploration of oil and natural gas - Assignment Agreement (“Cessão Onerosa”)

Petrobras, the Brazilian Federal Government (assignor) and the Brazilian Agency of Petroleum, Natural Gas and Biofuels (Agência Nacional de Petróleo, Gás Natural e Biocombustíveis) - ANP (regulator and inspector) entered into the Assignment Agreement in 2010, which grants the Company the right to carry out prospection and drilling activities for oil, natural gas and other liquid hydrocarbons located in blocks in the pre-salt area (Franco, Florim, Nordeste de Tupi, Entorno de Iara, Sul de Guará and Sul de Tupi), limited to the production of five billion barrels of oil equivalent in up to 40 (forty) years and renewable for a further 5 (five) years subject to certain conditions.

On December 29, 2014, the Company submitted the last declaration of commerciality of crude oil and natural gas accumulations - located in the Entorno de Iara block to the ANP. Following the last declaration of commerciality, the exploration stage of the entire Assignment Agreement is concluded.

The agreement establishes that, immediately after the declaration of commerciality for each area, the review procedures, which must be based on independent technical appraisal reports, will commence. The review commenced in January 2014 after the declarations of commerciality of Franco and Sul de Tupi were submitted to the ANP, and beginning in January 2015, following the last declaration of commerciality, all the Assignment Agreement areas were included in the review procedures. The review of the Assignment Agreement will be concluded after the review of all the areas. However, no specific date has been established for the review procedures to be concluded.

The formal review procedures for each block are based on costs incurred through the exploration stage and estimated costs and production levels included in the independent technical appraisal reports. The review of the Assignment Agreement may result in modifications to: (i) local content requirements and commitments; (ii) total volume (in barrels of oil) assigned and (iii) the value of acquired rights.

If the review of the Assignment Agreement determines that the value of acquired rights is greater than initially paid, the Company may be required to pay the difference to the Federal Government, or may proportionally reduce the total volume of barrels acquired under the agreement. If the review determines that the value of the acquired rights is lower than initially paid by the Company, the Federal Government will reimburse the Company for the difference by delivering cash or bonds, subject to budgetary regulations.

F-46

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Once the effects of the aforementioned review become probable and can be reliably measured, the Company will make the respective adjustments to the purchase prices of the rights.

During 2014 acquisition costs of US$ 10,446, related to Florim (now Itapu field), Sul de Guará (now Sul de Sapinhoá field), Entorno de Iara (now Norte de Berbigão, Sul de Berbigão, Norte de Sururu, Sul de Sururu and Atapu fields) and Nordeste de Tupi (now Sepia field) were reclassified from intangible assets to property, plant and equipment. During 2013, acquisition costs of US$ 22,134, related to Franco (now Búzios field) and Sul de Tupi (now Sul de Lula field), were reclassified from intangible assets to property, plant and equipment.

As of December 31, 2014, the Company’s property, plant and equipment include US$ 28,164 (US$ 21,510 as of December 31, 2013) related to the Assignment Agreement.

The agreement also establishes a compulsory exploration program for each of the blocks and minimum commitments related to the acquisition of goods and services from Brazilian suppliers in the exploration and development stages, which will be subject to certification by the ANP. In the event of non-compliance, the ANP may apply administrative sanctions pursuant to the terms in the agreement.

Based on drilling results obtained, expectations regarding the production potential of the areas were confirmed and the Company will continue to develop its investment program and activities as established in the agreement.

12.4.Premium I and Premium II refineries

On January 22, 2015 the Company decided to abandon the construction projects of Premium I and Premium II refineries.

Based on projected demand growth in the domestic and international oil product markets and the absence of a construction phase financial support partner (one of the assumptions in the 2014-2018 Business and Management Plan - BMP), the Company decided to abandon these projects.

The decision to abandon the projects resulted in a charge of US$ 1,236 recognized in other expenses to write-off all capitalized costs with respect to those projects.

F-47

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

13.Intangible assets

13.1.By class of assets

		Software
	Rights and Concessions	acquired	developed in-house	Goodwill	Total
Balance at January 1, 2013	38,513	188	577	461	39,739
Addition	2,931	33	128	−	3,092
Capitalized borrowing costs	−	−	12	−	12
Write-offs	(80)	(2)	(3)	−	(85)
Transfers (**)	(22,222)	(15)	(14)	(17)	(22,268)
Amortization	(38)	(47)	(133)	−	(218)
Impairment recognition	(524)	−	−	−	(524)
Cumulative translation adjustment	(4,199)	(15)	(71)	(44)	(4,329)
Balance at December 31, 2013	14,381	142	496	400	15,419
Cost	14,804	607	1,442	400	17,253
Accumulated amortization	(423)	(465)	(946)	−	(1,834)
Balance at December 31, 2013	14,381	142	496	400	15,419
Addition	92	41	118	−	251
Capitalized borrowing costs	−	−	8	−	8
Write-offs	(93)	(5)	(10)	−	(108)
Transfers (**)	(10,346)	7	9	(1)	(10,331)
Amortization	(35)	(54)	(131)	−	(220)
Impairment recognition	(8)	−	−	−	(8)
Impairment reversal	6	−	−	−	6
Cumulative translation adjustment	(405)	(12)	(58)	(33)	(508)
Balance at December 31, 2014	3,592	119	432	366	4,509
Cost	4,003	578	1,281	366	6,228
Accumulated amortization	(411)	(459)	(849)	−	(1,719)
Balance at December 31, 2014	3,592	119	432	366	4,509
Estimated useful life - years	(*)	5	5	Indefinite
(*) Mainly comprised of assets with indefinite useful lives, which are reviewed annually to determine whether events and circumstances continue to support an indefinite useful life assessment.
(**) Includes US$ 10,446 (US$ 22,134 in 2013), reclassified from Intangible Assets to Property Plant and Equipment in 2014, as a result of the declaration of commerciality of areas of the Assignment Agreement (Franco and Sul de Tupi in 2013 and Florim, Sul de Guará and Nordeste de Tupi in 2014) - Note 12.3.

As of December 31, 2013, the Company had intangible assets in the amount of US$ 10,424 with respect to acquisition costs under the Assignment Agreement. This amount was reclassified from intangible assets to property, plant and equipment during 2014, after the declaration of commerciality of the remaining blocks and conclusion of the exploratory stage, as set out in Note 12.3.

13.2.Exploration rights returned to the Brazilian Agency of Petroleum, Natural Gas and Biofuels - Agência Nacional de Petróleo, Gás Natural e Biocombustíveis (ANP)

Exploration areas returned to the ANP in 2014, totaling US$ 83 (US$ 61 in 2013) are set out below:

Area	Exploratory stage
	Exclusive Concession	Partnership
Campos Basin	5	−
Santos Basin	3	3
Solimões Basin	2	−
Espírito Santo Basin	1	2
Recôncavo Basin	1	1
Potiguar Basin	1	−
Jequitinhonha Basin	1	−
Camamu Almada Basin	−	1
Pará - Maranhão Basin	−	3
Parnaíba Basin	−	1

F-48

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

13.3.Oil and Gas fields operated by Petrobras returned to ANP

During 2014 the following oil and gas fields were returned to ANP: Cação, Carapiá, Moréia, Caravela, Cavalo Marinho, Estrela do Mar, Tubarão, Rio Mariricu, Rio Mariricu Sul, Lagoa Parda Sul, Urutau, Iraúna and Mosquito Norte.

13.4.Exploration rights - production sharing contract

Following a public auction held on October 21, 2013, the Libra consortium – comprised of Petrobras (40% interest), Shell (20% interest), Total (20% interest), Petrochina (10% interest) and CNOOC (10% interest) entered into a production sharing contract with the ANP and the Brazilian Pre-Salt Oil and Natural Gas Management Company (Empresa Brasileira de Administração de Petróleo e Gás Natural S.A. - Pré-Sal Petróleo PPSA) on December 2, 2013.

The contract granted rights to explore and operate oil and gas production in a strategic pre-salt area known as the Libra block, located in ultra-deep waters in the Santos Basin. This was the first oil and gas production sharing contract signed in Brazil. The contract is for 35 years and cannot be renewed.

A signature bonus (acquisition cost) of US$ 6,589 was paid by the consortium. The Company paid US$ 2,636 (its share of the acquisition cost paid by the consortium) recognized in its intangible assets as rights and concessions in 2013.

13.5.Service concession agreement - Distribution of piped natural gas

As of December 31, 2014, intangible assets include service concession agreements related to piped natural gas distribution in Brazil, in the amount of US$ 210 maturing between 2029 and 2043, which may be renewed. According to the distribution agreements, service is be provided to customers in the industrial, residential, commercial, automotive, air conditioning and transport sectors, among others.

The consideration receivable is a factor of a combination of operating costs and expenses, and return on capital invested. The rates charged for gas distribution are subject to periodic reviews by the state regulatory agency.

The agreements establish an indemnity clause for investments in assets which are subject to return at the end of the service agreement, to be determined based on evaluations and appraisals.

F-49

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

14.Impairment

14.1.Property, plant and equipment and intangible assets

For impairment testing purposes the Company generally uses the value in use of its property, plant and equipment and intangible assets (individually or grouped into cash-generating units - CGUs) as their recoverable amount. In measuring value in use the Company bases its cash flow projections on (i) the estimated useful life of the asset or assets grouped into the CGU; (ii) assumptions and financial budgets/forecasts approved by Management for the period corresponding to the expected life cycle of each different business; and (iii) a pre-tax discount rate, which is derived from the Company’s post-tax weighted average cost of capital (WACC). The Company’s identified cash-generating units are set out in note 5.2.

Cash flow projections used to measure the value in use of the CGUs are mainly based on the following assumptions: (i) average Brazilian real x U.S. dollar exchange rate of R$ 2.85 / US$ 1 in 2015 and 2016 converging to R$ 2.61 in the long run; and (ii) Brent crude oil price at US$ 52 in 2015 and converging to US$ 85 over  the long term.

14.1.1.Changes in the CGUs into which certain assets are grouped

As set out in note 5.2, the Company excluded two assets from the “Downstream CGU”: (i) Complexo Petroquímico do Rio de Janeiro (Comperj) and (ii) the second refining unit in the Abreu e Lima refinery (RNEST); and one asset from the natural gas CGU: Unidade de Fertilizantes Nitrogenados (UFNIII).

a)Downstream CGU

The Company had grouped all refineries and associated assets, terminals and pipelines, as well as logistics assets operated by Transpetro, located in Brazil into a single CGU referred to as the “Downstream CGU”.

However, during the quarter ended December 31, 2014, changes in circumstances prompted a review of the Company’s planned projects and ultimately led Management to revise certain projects under construction. As a result, Petrobras has recently decided to postpone 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 in the Abreu e Lima refinery (RNEST). For that reason, as of December 31, 2014, those assets under construction were removed from the “Downstream CGU” and were tested for impairment individually.

Those circumstances include: (i) a decrease in expected future operating revenues following the decline of international crude oil prices; (ii) the devaluation of the Brazilian real, and the increased cash outflows to service the Company’s debt in the near term, most of which is denominated in foreign currencies; (iii) Petrobras’s current inability to access the capital markets; and (iv) insolvency of contractors and suppliers and a consequent shortage of qualified contractors and suppliers (as a result of the difficulties created for suppliers by the Lava Jato investigation or otherwise).

Comperj was designed to increase the Company’s refining capacity and meet the expected growth in oil products demand in Brazil, especially diesel, naphtha, jet fuel, coke, LPG (liquid petroleum gas) and fuel oil. Its first refining unit is expected to process 165 thousand bpd when completed.

RNEST was designed to process 230 thousand bpd, 70% of which would be diesel, including a potential production capacity increase to 260 thousand bpd following the Company’s Intermediate Products and Gasoline Production Increase Program (Programa de Elevação de Médios e Gasolina - Promega). The refining process comprises two identical refining units with a production capacity of 115 thousand bpd each when completed . Each refining unit

F-50

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

includes units for atmospheric distillation, delayed coking, hydro-treating of diesel and naphtha, hydrogen production, amine treating, acid water treating, caustic regeneration and support facilities.

Postponing the construction work for those projects for an extended period of time was the basis for the Company’s decision to remove Comperj and the second refining unit of RNEST from the Downstream CGU and test their recoverability individually. Petrobras understands it would not be appropriate to maintain those assets grouped into the Downstream CGU for an extended period of time, based exclusively on Management’s expectations with respect to the future use of those assets, which would not be corroborated, especially considering the postponement of construction work.

b)Natural Gas CGU

The Company had grouped all natural gas pipelines, natural gas processing plants and fertilizers and nitrogen products plants located in Brazil into a single CGU referred to as the “Natural Gas CGU”.

However, during the quarter ended December 31, 2014, after the postponement of construction work of Unidade de Fertilizantes Nitrogenados III (UFN III), a fertilizers plant in the state of Mato Grosso do Sul, the Company rescinded the construction contract with Consórcio UFN III due to poor performance. Following the postponement of construction work the Company decided to revise the project’s start-up schedule and postpone the engagement of a different contractor to continue construction work, for the period during which its cash preserving measures are in force. For those reasons, the Company considers the postponement of UFN III the basis for the decision to remove it from the “Natural Gas CGU” as of December 31, 2014, and has tested UFN III for impairment individually.

UFN III is projected to have a production capacity of 1.2 million tons of urea and 70 thousand tons of amine to meet the demand for those products in the states of Mato Grosso, Mato Grosso do Sul, Goiás, São Paulo and Paraná.

14.1.2.Impairment of property, plant and equipment and intangible assets

In the quarter ended December 31, 2014 the Company recognized impairment losses and reversals of impairment losses for certain assets and CGUs in the statement of income, as set out below:

	Carrying amount	Recoverable amount	Impairment (*) / (**)	Business segment	Comments
Assets or CGUs, by nature
Producing properties: assets related to E&P activities in Brazil (several CGUs)	6,425	4,863	1,562	E&P - Brazil	item (a)
Oil and gas production and drilling equipment	1,091	555	536	E&P - Brazil	item (b)
Oil and gas producing properties abroad	3,126	1,458	1,668	E&P - International	item (c)
Comperj	9,721	1,501	8,220	RTM - Brazil	item (d)
2nd refining unit of RNEST	6,207	2,765	3,442	RTM - Brazil	item (e)
Suape Petrochemical Complex	2,847	1,726	1,121	RTM - Brazil	item (f)
Araucária (fertilizers plant)	367	251	116	Gas & Power - Brazil	item (g)
Nansei Sekiyu K.K. refinery	129	−	129	RTM - International	item (h)
Others	26	32	(6)
Total	29,939	13,151	16,788
(*) Impairment losses and reversals.
(**) Excludes impairment charges on assets classified as held for sale of US$ 35.

a)Producing properties in Brazil

Impairment losses of US$ 1,562 were recognized, mainly with respect to certain oil and gas fields under E&P concessions, whose recoverable amount was determined to be below their carrying amount. Cash flow

F-51

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

projections are based on: financial budgets/forecasts approved by Management; and a 7.2% p.a. (6.1% p.a. in 2013) post-tax discount rate (real rate, excluding inflation) derived from the WACC for the E&P business. The impairment losses are mainly related to the impact of the recent decline in international crude oil prices on the Company’s price assumptions and were principally recognized for the following fields: Frade, Pirapitanga, Tambuatá, Carapicu and Piracucá.

b)Oil and gas production and drilling equipment in Brazil

Impairment losses of US$ 536 were recognized in oil and gas production and drilling equipment, unrelated to oil and gas producing properties. Cash flow projections are based on: financial budgets/forecasts approved by Management; and an 8% p.a. (6.6% p.a. in 2013) post-tax discount rate (real rate, excluding inflation) derived from the WACC for the oil and gas services and equipment industry. The impairment losses are mainly related to 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.

c)Producing properties abroad

Impairment losses of US$ 1,668 were recognized in international E&P assets. Cash flow projections are based on: financial budgets/forecasts approved by Management; and 5.4% p.a. to 11.2% p.a. (5.1% p.a. to 10.9% p.a. in 2013) post-tax discount rates (real rates, excluding inflation) derived from the WACC for the E&P business in different countries. The impairment losses are mainly in Cascade and Chinook producing properties located in the United States (US$ 1,567) and are mainly attributable to the recent decline in international crude oil prices.

d)Comperj

An impairment loss of US$ 8,220 was recognized in Comperj. Cash flow projections are based on: financial budgets/forecasts approved by Management; and a 7% p.a. (5.8% p.a. in 2013, when this asset was tested for impairment grouped into the Downstream CGU) post-tax discount rate (real rate, excluding inflation) derived from the WACC for the refining business. The impairment loss is mainly attributable to: (i) project planning deficiencies; (ii) the use of a higher discount rate, reflecting a specific risk premium for the postponed projects; iii) a delay in expected future cash inflows resulting from postponing the project; and (iv) the Company’s business context of lower projected economic growth.

e)Second refining unit in RNEST

An impairment loss of US$ 3,442 was recognized in the second refining unit in RNEST. Cash flow projections are based on: financial budgets/forecasts approved by Management; and a 7% p.a. (5.8% p.a. in 2013, when this asset was tested for impairment grouped into the Downstream CGU) post-tax discount rate (real rate, excluding inflation) derived from the WACC for the refining business. The impairment loss is mainly attributable to: (i) project planning deficiencies; (ii) the use of a higher discount rate, reflecting a specific risk premium for the postponed projects; (iii) a delay in expected future cash inflows resulting from postponing the project; and (iv) the Company’s business context of lower projected economic growth.

f)Suape Petrochemical Complex

An impairment loss of US$ 1,121 was recognized in Companhia Integrada Têxtil de Pernambuco S.A. - CITEPE and Companhia Petroquímica de Pernambuco S.A. – PetroquímicaSuape. Cash flow projections are based on: 30-year period and zero-growth rate perpetuity; financial budgets/forecasts approved by Management; and a 6.2% p.a. (5.4% p.a. in 2013) post-tax discount rate (real rate, excluding inflation) derived from the WACC for the petrochemical business. The impairment loss is mainly attributable to changes in market assumptions and

F-52

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

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.

g)Araucária Nitrogenados S.A.

An impairment loss of US$ 116 was recognized in Araucária Nitrogenados S.A. (a fertilizers plant). Cash flow projections are based on: financial budgets/forecasts approved by Management; and a 6.1% p.a. (5.9% p.a. in 2013) post-tax discount rate (real rate, excluding inflation) derived from the WACC for the fertilizers business. The impairment loss is mainly attributable to operational inputs that required higher capital expenditures during 2014.

h)Nansei Sekiyu K.K. refinery

A US$ 129 impairment loss was recognized for the international downstream assets resulting from the Company’s  decision to close its Japanese refinery, Nansei Sekiyu KK.

14.2.Investments in associates and joint ventures (including goodwill)

Value in use is generally used for impairment test of goodwill associated with investments in associates and joint ventures. The basis for estimates of cash flow projections includes: projections covering a period of 5 to 12 years, zero-growth rate perpetuity, budgets, forecasts and assumptions approved by management and a pre-tax discount rate derived from the WACC or the Capital Asset Pricing Model (CAPM), when applicable.

The carrying amount and the value in use of the investments in associates and joint ventures which include goodwill as of December 31, 2014 are set out below:

Investments	Segment	Post-tax discount rate (real interest rate) p.a. (*)	Value in use	Carrying Amount
Braskem S.A.	RTM	9.7% to 10.1%	3,330	1,711
Natural Gas Distributors	Natural Gas	4,8%	1,276	340
Guarani S.A.	Biofuels	7.3%	850	518
(*) Post-tax discount rate in 2013 (real interest rate p.a.) of 8.9% to 9.6% to Braskem; 4.1% to Natural Gas Distributors; and 5.9% to Guarani.

14.3.Investment in publicly traded associate (Braskem S.A.)

Braskem’s shares are publicly traded on stock exchanges in Brazil and abroad. The quoted market value as of December 31, 2014, was U.S.$ 1,363, based on the quoted values of both Petrobras’s interest in Braskem’s common stock (47% of the outstanding shares), and preferred stock (22% of the outstanding shares) as set out note 11.4. However, there is extremely limited trading of the common shares, since non-signatories of the shareholders’ agreement hold only approximately 3% of the common shares.

In addition, given the operational relationship between Petrobras and Braskem, the recoverable amount of the investment, for impairment testing purposes, was determined based on value in use, considering future cash flow projections and the manner in which the Company can derive value from this investment via dividends and other distributions to arrive at its value in use. As the recoverable amount was higher than the carrying amount, no impairment losses were recognized for this investment.

Cash flow projections to determine the value in use of Braskem were based on the following key assumptions: (i) estimated average exchange rate of R$ 2.85 to U.S.$1 in 2015 and 2016 (converging to R$ 2.61 in the long run);

F-53

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

(ii) Brent crude oil price of US$ 52 for 2015, increasing to U.S.$ 85 over the long term; (iii) prices of feedstock and petrochemical products reflecting projected international prices; (iv) petrochemical products sales volume estimates reflecting projected Brazilian and global G.D.P growth; and (v) increases in the EBITDA margin during the growth cycle of the petrochemical industry in the next years and declining in the long run.

The carrying amount of the investment as of December 31, 2014 was US$ 1,711 (US$ 2,201 as of December 31, 2013).

14.4.Allowance for losses on net investments

E&P operations of affiliates of Petrobras Argentina S.A. (a subsidiary of Petrobras International Braspetro B.V. – PIB BV) and of a joint venture of PIB BV, Petrobras Oil & Gas B.V. (PO&G) in Africa were negatively affected by a decrease international crude oil prices. Allowances for losses on those investments were recognized in the amounts of US$ 163 and US$ 88, respectively, in share of earnings in equity-accounted investments.

14.5.Assets classified as held for sale

Impairment losses were recognized in E&P assets classified as held for sale. The Board of Directors approved the disposal of PI, PIII, PIV and PV drilling rigs and PXIV platform and their fair value was below their carrying amount. Therefore, impairment losses in the amount of US$ 35 were recognized.

15.Exploration for and evaluation of oil and gas reserves

The exploration and evaluation activities include the search for oil and gas from obtaining the legal rights to explore a specific area to the declaration of the technical and commercial viability of the reserves.

Changes in the balances of capitalized costs directly associated with exploratory wells pending determination of proved reserves and the balance of amounts paid for obtaining rights and concessions for exploration of oil and natural gas (capitalized acquisition costs) are set out in the table below:

Capitalized Exploratory Well Costs / Capitalized Acquisition Costs (*)	12.31.2014	12.31.2013
Property plant and equipment
Opening Balance	8,802	10,649
Additions to capitalized costs pending determination of proved reserves	4,272	4,981
Capitalized exploratory costs charged to expense	(1,366)	(1,251)
Transfers upon recognition of proved reserves	(3,835)	(4,174)
Cumulative translation adjustment	(873)	(1,403)
Closing Balance	7,000	8,802
Intangible Assets (**)	3,044	13,880
Capitalized Exploratory Well Costs / Capitalized Acquisition Costs	10,044	22,682
(*) Amounts capitalized and subsequently expensed in the same period have been excluded from the table above.
(**) The balance of intangible assets in 2013 includes amounts related to the Assignment Agreement (note 12.3).

F-54

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Exploration costs recognized in the statement of income and cash used in oil and gas exploration and evaluation activities are set out in the table below:

Exploration costs recognized in the statement of income	2014	2013	2012
Geological and geophysical expenses	830	968	1,022
Exploration expenditures written off (incl. dry wells and signature bonuses)	2,178	1,892	2,847
Other exploration expenses	50	99	89
Total expenses	3,058	2,959	3,958
Cash used in :	2014	2013	2012
Operating activities	879	1,073	1,139
Investment activities	4,899	8,605	6,640
Total cash used	5,778	9,678	7,779

15.1.Aging of Capitalized Exploratory Well Costs

The tables below set out the amounts of exploratory well costs that have been capitalized for a period of one year or for a period of greater than one year after the completion of drilling, the number of projects to which the costs that have been capitalized for a period of greater than one year relate and an aging of those amounts by year (including the number of wells to which those costs relate).

Aging of capitalized exploratory well costs (*)
	2014	2013
Exploratory well costs capitalized for a period of one year	2,024	2,568
Exploratory well costs capitalized for a period of greater than one year	4,976	6,234
Total capitalized exploratory well costs	7,000	8,802
Number of projects to which the exploratory well costs capitalized for a period of greater than one year relate	69	86

	Capitalized costs (2014)	Number of wells
2013	1,963	32
2012	1,500	25
2011	637	15
2010	291	5
2009 and previous years	585	15
Exploratory well costs that have been capitalized for a period of greater than one year	4,976	92
(*) Amounts paid for obtaining rights and concessions for exploration of oil and gas (capitalized acquisition costs) are not included.

Exploratory well costs that have been capitalized for a period of greater than one year since the completion of drilling amount to US$ 4,976. Those costs relate to 69 projects comprising (i) US$ 3,850 for wells in areas in which there has been ongoing drilling or firmly planned drilling activities in the near term and for which an evaluation plan (“Plano de Avaliação”) has been submitted for approval by ANP; and (ii) US$ 1,126 relate to costs incurred to evaluate the reserves and their potential development.

F-55

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

16.Trade payables

	2014	2013
Third parties in Brazil	4,949	5,346
Third parties abroad	4,240	6,061
Related parties	571	512
Balance on current liabilities	9,760	11,919

17.Finance debt

The Company obtains funding through debt financing for capital expenditures to develop crude oil and natural gas producing properties, construct vessels and pipelines, construct and expand industrial plants, among other uses.

The Company has covenants in its loan agreements and notes issued in the capital markets requiring, among other obligations, the presentation of interim financial statements within 90 days of the end of each quarter (not reviewed by independent auditors) and audited financial statements within 120 days of the end of each fiscal year. These obligations do not represent immediate events of default and the grace period in which the Company has to deliver these financial statements ranges from 30 to 60 days in the difference agreements. Delivering financial statements is an obligation included in most financing agreements and non-compliance with that obligation can trigger an event of default and thus acceleration of the debt.

A roll-forward of non-current debt is set out below:

F-56

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

	Export Credit Agencies	Banking Market	Capital Market	Others	Total
Non-current
In Brazil
Opening balance at January 1 , 2013	−	30,977	1,255	64	32,296
Additions (new funding obtained)	−	10,463	237	−	10,700
Interest incurred during the year	−	86	16	3	105
Foreign exchange/inflation indexation charges	−	1,510	54	2	1,566
Transfer from long term to short term	−	(9,894)	(181)	(13)	(10,088)
Transfer to liabilities associated with assets classified as held for sale	−	(14)	−	−	(14)
Cumulative translation adjustment (CTA)	−	(4,128)	(170)	(7)	(4,305)
Balance at December 31, 2013	−	29,000	1,211	49	30,260
Abroad
Opening balance at January 1 , 2013	5,045	19,484	31,031	629	56,189
Additions (new funding obtained)	1,557	9,178	10,990	87	21,812
Interest incurred during the year	1	14	36	8	59
Foreign exchange/inflation indexation charges	159	893	280	30	1,362
Transfer from long term to short term	(671)	(1,310)	(418)	(42)	(2,441)
Transfer to liabilities associated with assets classified as held for sale	−	(393)	−	−	(393)
Cumulative translation adjustment (CTA)	(286)	(958)	653	(22)	(613)
Balance at December 31, 2013	5,805	26,908	42,572	690	75,975
Total Balance at December 31, 2013	5,805	55,908	43,783	739	106,235
Non-current
In Brazil
Opening balance at January 1 , 2014	−	29,000	1,211	49	30,260
Additions (new funding obtained)	−	4,319	359	−	4,678
Interest incurred during the year	−	202	2	−	204
Foreign exchange/inflation indexation charges	−	1,033	79	1	1,113
Transfer from long term to short term	−	(1,440)	(156)	(18)	(1,614)
Cumulative translation adjustment (CTA)	−	(3,826)	(194)	(4)	(4,024)
Balance as of December 31, 2014	−	29,288	1,301	28	30,617
Abroad
Opening balance at January 1 , 2014	5,805	26,908	42,572	690	75,975
Additions (new funding obtained)	281	6,710	13,766	−	20,757
Interest incurred during the year	4	22	46	8	80
Foreign exchange/inflation indexation charges	103	412	(1,433)	20	(898)
Transfer from long term to short term	(742)	(3,411)	(1,260)	(42)	(5,455)
Cumulative translation adjustment (CTA)	(207)	(743)	119	(27)	(858)
Balance as of December 31, 2014	5,244	29,898	53,810	649	89,601
Total Balance as of December 31, 2014	5,244	59,186	55,111	677	120,218

	12.31.2014	12.31.2013
Short-term debt	3,484	3,654
Current portion of long-term debt	6,845	3,118
Accrued interest	1,539	1,229
	11,868	8,001

F-57

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

17.1.Summarized information on current and non-current finance debt

Maturity in	up to 1 year	1 to 2 years	2 to 3 years	3 to 4 years	4 to 5 years	5 years and onwards	Total (*)	Fair value
Financing in Brazilian Reais (BRL):	1,413	2,787	2,387	2,565	4,179	10,094	23,425	20,176
Floating rate debt	889	2,365	1,713	1,928	3,556	7,755	18,206
Fixed rate debt	524	422	674	637	623	2,339	5,219
Average interest rate	9.9%	11.9%	13.7%	11.0%	10.2%	8.2%	10.0%
Financing in U.S. Dollars (USD):	9,345	8,986	8,754	11,102	17,730	30,394	86,311	80,558
Floating rate debt	7,368	4,314	5,067	8,645	12,542	8,608	46,544
Fixed rate debt	1,977	4,672	3,687	2,457	5,188	21,786	39,767
Average interest rate	3.0%	4.3%	4.5%	4.1%	4.2%	5.3%	4.5%
Financing in BRL indexed to USD:	258	391	700	699	696	6,118	8,862	9,584
Floating rate debt	17	19	19	18	15	50	138
Fixed rate debt	241	372	681	681	681	6,068	8,724
Average interest rate	6.9%	7.1%	7.0%	7.0%	7.0%	7.0%	7.0%
Financing in Pound Sterling (£):	72	−	−	−	−	2,674	2,746	2,400
Fixed rate debt	72	−	−	−	−	2,674	2,746
Average interest rate	4.1%	−	−	−	−	6.2%	6.2%
Financing in Japanese Yen (¥):	443	392	94	85	−	−	1,014	1,030
Floating rate debt	86	85	85	85	−	−	341
Fixed rate debt	357	307	9	−	−	−	673
Average interest rate	1.2%	1.9%	1.2%	1.1%	−	−	1.5%
Financing in Euro (€):	331	13	13	3,338	1,584	4,440	9,719	8,956
Floating rate debt	27	12	12	12	12	190	265
Fixed rate debt	304	1	1	3,326	1,572	4,250	9,454
Average interest rate	3.5%	2.1%	2.1%	3.8%	3.9%	4.3%	4.0%
Financing in other currencies:	6	3	−	−	−	−	9	9
Fixed rate debt	6	3	−	−	−	−	9
Average interest rate	14.0%	15.3%	−	−	−	−	14.4%
Total as of December 31, 2014	11,868	12,572	11,948	17,789	24,189	53,720	132,086	122,713
Total Average interest rate	3.9%	6.0%	6.4%	5.2%	5.3%	6.0%	5.6%
Total as of December 31, 2013	8,001	7,266	12,692	8,679	16,051	61,547	114,236	115,238
* The average maturity of outstanding debt as of December 31, 2014 is 6.1 years (7.1 years as of December 31, 2013).

The fair value of the Company's finance debt is determined primarily by quoted prices in active markets for identical liabilities (level 1), when applicable. When a quoted price for an identical liability is not available, the fair value is determined based on the yield curve of the Company's most liquid bonds (level 2)

The sensitivity analysis for financial instruments subject to foreign exchange variation is set out in note 32.2.

17.2. Capitalization rate used to determine the amount of borrowing costs eligible for capitalization

The capitalization rate used to determine the amount of borrowing costs eligible for capitalization was the weighted average of the borrowing costs applicable to the borrowings that were outstanding during the period, other than borrowings made specifically for the purpose of obtaining a qualifying asset. In 2014 the capitalization rate was 4.9% p.a. (4.5% p.a. in 2013). This rate was applied to the balance of assets under construction as the basis for capitalizing borrowing costs, when eligible.

F-58

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

17.3.Lines of credit – Outstanding balance

Company	Available (Lines of Credit)	Used	Balance
Abroad
PGT	500	−	500
Petrobras	2,500	530	1,970
In Brazil
Transpetro	3,787	1,070	2,717
Petrobras	5,460	4,707	753
PNBV	3,719	372	3,347
Liquigás	53	51	2

17.4.Guarantees

The financial institutions which have provided financing have not required Petrobras to provide guarantees related to loans, except for certain specific funding instruments to promote economic development, which are collateralized by tangible assets.

The loans obtained by structured entities are collateralized based on the projects’ assets, as well as liens on receivables and shares of the structured entities. Certain subsidiaries issue securities fully and unconditionally guaranteed by Petrobras (note 36).

The Company’s capital market financing relates primarily to unsecured global notes.

18.Leases

Future minimum lease payments/receivables from non-cancelable operating leases and finance leases are set out below:

	Operating leases	Finance leases
Estimated lease payments / receivable	Future minimum payments	Total future minimum payments receivable	Annual finance charges	Present value of minimum lease payments receivable	Total future minimum payments	Annual finance charges	Present value of minimum lease payments
2015	14,644	191	(112)	79	21	(5)	16
2016 – 2019	38,499	795	(451)	344	68	(37)	31
2020 and thereafter	65,261	1,762	(670)	1,091	229	(204)	25
As of December 31, 2014	118,404	2,748	(1,233)	1,514	318	(246)	72
Current				59			16
Non-current				1,455			56
As of December 31, 2013	125,851			1,521			89

In 2014, the balance of estimated future minimum lease payments under operating leases includes US$ 69,565 (US$ 81,044 in 2013) with respect to assets under construction, for which the lease term has not commenced.

During 2014 the Company recognized expenditures of US$ 10,652 (US$ 11,520 during 2013) for operating lease installments.

Operating leases mainly include oil and gas production facilities, drilling rigs and other exploration and production equipment, vessels and support vessels, helicopters, land and buildings.

F-59

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

19.Related party transactions

The Company carries out commercial transactions with its subsidiaries, joint arrangements, consolidated structure entities and associates at market prices and market conditions.

19.1.Transactions with joint ventures, associates, government entities and pension funds

The balances of significant transactions are set out in the table below:

	2014	2013	2014		2013
	Income (expense)	Income (expense)	Assets	Liabilities	Assets	Liabilities
Joint ventures and associates
State-controlled gas distributors	4,507	3,920	506	195	424	209
Petrochemical companies	7,703	7,456	205	82	94	120
Other associates and joint ventures	537	940	152	263	140	193
	12,747	12,316	863	540	658	522
Government entities
Government bonds	662	1,044	4,339	−	6,247	−
Banks controlled by the Federal Government	(3,246)	(1,973)	3,814	28,304	2,801	29,791
Receivables from the Electricity sector (Note 8.4)	687	747	2,966	−	1,849	−
Petroleum and alcohol account - receivables from Federal government (Note 19.2)	3	−	317	−	357	−
Federal Government - dividends and interest on capital	22	(18)	−	−	−	834
Others	74	92	241	224	210	334
	(1,798)	(108)	11,677	28,528	11,464	30,959
Pension plans	1	−	−	135	−	156
	10,950	12,208	12,540	29,203	12,122	31,637
Revenues (mainly sales revenues)	13,207	13,164
Foreign exchange and inflation indexation charges, net	(904)	(791)
Finance income (expenses), net	(1,353)	(165)
Current assets			6,715		7,572
Non-current assets			5,825		4,550
Current liabilities				1,855		3,568
Non-current liabilities				27,348		28,069
	10,950	12,208	12,540	29,203	12,122	31,637

19.2.Petroleum and Alcohol accounts - Receivables from Federal Government

As of December 31, 2014, the balance of receivables related to the Petroleum and Alcohol accounts was US$ 317 (US$ 357 as of December 31, 2013). Pursuant to Provisional Measure 2,181 of August 24, 2001, the Federal Government may settle this balance by using National Treasury Notes in an amount equal to the outstanding balance, or allow the Company to offset the outstanding balance against amounts payable to the Federal Government, including taxes payable, or both options.

The Company has provided all the information required by the National Treasury Secretariat (Secretaria do Tesouro Nacional - STN) in order to resolve disputes between the parties and conclude the settlement with the Federal Government.

Following several negotiation attempts at the administrative level, the Company filed a lawsuit in July 2011 to collect the receivables. Court-ordered expert proceedings are ongoing.

F-60

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

19.3.Compensation of employees and officers

The criteria for compensation of employees and officers are established based on the current labor legislation and the Company’s policies related to Positions, Salaries and Benefits (Plano de Cargos e Salários e de Benefícios e Vantagens).

The compensation of employees (including those occupying managerial positions) and officers in the months of December 2014 and December 2013 were:

Compensation of employees (amounts refer to monthly compensation in U.S. dollars)	2014	2013
Lowest compensation	1,064.74	1,126.35
Average compensation	5,905.34	6,015.75
Highest compensation	32,309.79	34,743.45
Compensation of highest paid Petrobras officer	38,798.87	42,511.80

The total compensation of Petrobras’ key management is set out below:

	2014			2013
	Officers	Board	Total	Officers	Board	Total
Wages and short-term benefits	4.1	0.5	4.6	4.1	0.5	4.6
Social security and other employee-related taxes (*)	1.1	0.1	1.2	1.1	0.1	1.2
Post-employment benefits (pension plan)	0.3	−	0.3	0.3	−	0.3
Variable compensation (**)	1.4	−	1.4	1.7	−	1.7
Total compensation recognized in the statement of income	6.9	0.6	7.5	7.2	0.6	7.8
Total compensation paid	6.5	0.6	7.1	6.1	0.6	6.7
Number of members	7	10	17	7	10	17
(*) The compensation of executive officers and directors is based on legal requirements and guidelines established by the Brazilian Department of Oversight and Governance of State-controlled Companies (Departamento de Coordenação e Governança das Empresas Estatais - DEST). DEST determined that social security and other employee-related taxes were included in the key management compensation proposed at the Annual General Meeting of 2014. Those taxes had been included since 2013, but were not included in the notes to the financial statements.
(**) Key Management personnel variable compensation is based on operational and financial targets set out in a specific program, which are paid in installment payments over four years: 60% payable within 12 months of the end of the period and the remaining 40% allocated on a straight-line basis over the following three years.

In 2014 board members and officers of the consolidated Petrobras group received US$ 30.8 as compensation (US$ 27.6 in 2013).

20.Provision for decommissioning costs

Non-current liabilities	2014	2013
Opening balance	7,133	9,441
Adjustment to provision	2,430	(902)
Payments made	(679)	(506)
Interest accrued	201	199
Others	75	59
Cumulative translation adjustment	(893)	(1,158)
Closing balance	8,267	7,133

F-61

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

21.Taxes

21.1.Income taxes and other taxes

Income taxes	Current assets		Current liabilities
	2014	2013	2014	2013
Taxes in Brazil	1,018	951	139	158
Taxes abroad	45	109	108	123
	1,063	1,060	247	281

Other taxes	Current assets		Non-current assets		Current liabilities
	2014	2013	2014	2013	2014	2013
Current / Deferred ICMS (VAT)	1,772	1,623	787	879	1,275	1,164
Current / Deferred PIS and COFINS (taxes on revenues)	829	2,069	2,983	4,197	295	230
CIDE	13	20	−	−	8	16
Production taxes	−	−	−	−	1,517	2,432
Withholding income taxes	−	−	−	−	486	256
Others	73	151	230	292	281	350
	2,687	3,863	4,000	5,368	3,862	4,448
Taxes abroad	61	48	8	12	202	221
	2,748	3,911	4,008	5,380	4,064	4,669

F-62

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

21.2.Deferred income taxes - non-current

Income taxes in Brazil comprise corporate income tax (IRPJ) and social contribution on net income (CSLL). Brazilian statutory corporate tax rates are 25% and 9%, respectively. The changes in the deferred income taxes are presented as follows:

a)Changes in deferred income taxes

	Property, Plant & Equipment
	Oil and gas exploration costs	Others	Loans, trade and other receivables / payables and financing	Finance leases	Provision for legal proceedings	Tax losses	Inventories	Interest on capital	Others	Total
Balance at January 1, 2013	(12,677)	(3,111)	561	(588)	346	1,109	467	1,050	2,144	(10,699)
Recognized in the statement of income for the year	(2,567)	(1,487)	330	(53)	133	3,481	177	351	(767)	(402)
Recognized in shareholders’ equity	−	−	1,407	53	−	71	−	−	(1,504)	27
Cumulative translation adjustment	1,842	427	(221)	72	(63)	(330)	(77)	(50)	(350)	1,250
Others (*)	(4)	165	(93)	(2)	(7)	480	8	(8)	509	1,048
Balance at December 31, 2013	(13,406)	(4,006)	1,984	(518)	409	4,811	575	1,343	32	(8,776)
Recognized in the statement of income for the year	(2,055)	3,917	401	(42)	182	2,965	(7)	(1,418)	(898)	3,045
Recognized in shareholders’ equity	−	−	1,949	(41)	−	(192)	−	−	1,351	3,067
Cumulative translation adjustment	1,814	302	(441)	86	(75)	(842)	(66)	68	(133)	713
Others (*)	−	(3)	(70)	(77)	10	(51)	1	−	116	(74)
Balance at December 31, 2014	(13,647)	210	3,823	(592)	526	6,691	503	(7)	468	(2,025)
Deferred tax assets										1,130
Deferred tax liabilities										(9,906)
Balance at December 31, 2013										(8,776)
Deferred tax assets										1,006
Deferred tax liabilities										(3,031)
Balance at December 31, 2014										(2,025)
(*) Relates primarily to disposal of interests in investees.

The deferred tax assets will be realized in proportion to the realized in proportion to the realization of the provisions and the final resolution of future events, both of which are based on estimates.

F-63

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

b)Timing of reversal of  deferred income taxes

Management considers that the deferred tax assets will be realized in proportion to the realization of the provisions and the final resolution of future events, both of which are based on estimates.

The estimated schedule of recovery/reversal of net deferred tax assets (liabilities) recoverable (payable) as of December 31, 2014 is set out in the following table:

	Deferred income tax
	Assets	Liabilities
2015	109	13
2016 and thereafter	897	3,018
Recognized deferred tax credits	1,006	3,031
Brazil	215	−
Abroad	3,200	−
Unrecognized deferred tax credits	3,415	−
Total	4,421	3,031

As of December 31, 2014, the Company had tax loss carryforwards from companies abroad, for which no deferred tax assets have been recognized, in the amount of US$ 3,200 (US$ 2,223 as of December 31, 2013) resulting from net operating losses, mainly from oil and gas exploration and production and refining activities in the United States in the amount of US$ 1,833 (US$ 1,680 as of December 31, 2013), as well as Spanish and Dutch companies, in the amount of US$ 882 and US$ 485, respectively.

An aging of the unrecognized tax carryforwards, from companies abroad, by lapse of the applicable statute of limitations is set out below:

Lapse of Statute of Limitations	2016	2017	2018	2019	2020	2021	2022	2023	2024	2025	2026 and onward	Total
Unrecognized deferred tax credits	37	73	155	231	49	448	161	65	84	6	1,891	3,200

21.3.Reconciliation between statutory tax rate and tax expense

A reconciliation between tax expense and the product of “income before income taxes” multiplied by the Brazilian statutory corporate tax rates is set out in the table below:

	2014	2013	2012
Income (loss) before income taxes	(8,824)	13,410	14,493
Nominal income taxes computed based on Brazilian statutory corporate tax rates (34%)	3,000	(4,558)	(4,928)
Adjustments to arrive at the effective tax rate:
·    Tax benefits from the deduction of interest on capital distribution	66	1,306	1,612
·    Different jurisdictional tax rates for companies abroad	559	644	335
·    Tax incentives	26	57	58
·    Tax loss carryforwards (unrecognized tax losses)	(1,289)	(1)	(341)
·    Write-off - overpayments incorrectly capitalized (note 3)	(907)	−	−
·    Non taxable income (deductible expenses), net (*)	(338)	(198)	(559)
·    Tax credits of companies abroad in the exploration stage	(1)	(2)	(2)
·    Others	205	174	263
Income taxes benefit (expense)	1,321	(2,578)	(3,562)
Deferred income taxes	3,045	(402)	(1,266)
Current income taxes	(1,724)	(2,176)	(2,296)
	1,321	(2,578)	(3,562)
Effective tax rate	15.0%	19.2%	24.6%
(*) Includes share of earnings in equity-accounted investees.

F-64

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

22.Employee benefits (Post-Employment)

The balance of employee benefits (post-employment) as of December 31, 2014 and 2013 are set out below:

	2014	2013
Liabilities
Petros Pension Plan	7,874	5,342
Petros 2 Pension Plan	287	121
AMS Medical Plan	9,019	6,999
Other plans	107	111
	17,287	12,573
Current	796	816
Non-current	16,491	11,757
	17,287	12,573

The current balance relates to an estimate of the payments to be made over the next 12 months.

22.1.Petros Plan and Petros 2 Plan

The Company’s post-retirement plans are managed by Fundação Petrobras de Seguridade Social (Petros), which was established by Petrobras as a nonprofit legal entity governed by private law with administrative and financial autonomy.

a)Petros Plan - Fundação Petrobras de Seguridade Social

The Petros Plan was established by Petrobras in July 1970 as a defined-benefit pension plan and currently provides post-retirement benefits for employees of Petrobras and Petrobras Distribuidora S.A., in order to complement government social security benefits. The Petros Plan has been closed to new participants since September 2002.

Petros contracts with an independent actuary to perform an annual actuarial review of its costs using the capitalization method for most benefits. The employers (sponsors) make regular contributions in amounts equal to the contributions of the participants (active employees, assisted employees and retired employees), on a parity basis.

In the event an eventual deficit is determined, participants of the plan and employers (sponsors) shall cover this deficit, pursuant to Brazilian Law (Constitutional Amendment 20/1998 and Complementary Law 109/2001), on the basis of their respective proportions of regular contributions made to the plan during the year in which the deficit arose.

As of December 31, 2014, the balance of the Terms of Financial Commitment (TFC), signed by Petrobras and Petros in 2008 is US$ 3,451, including US$ 205 related to interest expense due in 2015. The TCF are due in 20 years, with 6% p.a. semiannual coupon payments based on the updated balance. The Company holds crude oil and oil products pledged as security for the TFC corresponding to US$ 2,316.

In 2014, salary increases given to active employees pursuant to Petrobras’ Collective Bargaining Agreements of 2004, 2005 and 2006, were included in the pension benefits of retirees as approved by the Executive Council of Fundação Petros.

The employers' expected contributions to the plan for 2015 are US$ 440.

 The duration of the actuarial liability related to the plan, as of December 31, 2014 is 11.49 years.

F-65

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

b)Petros 2 Plan - Fundação Petrobras de Seguridade Social

Petros 2 Plan was established in July 2007 by Petrobras and certain subsidiaries as a variable contribution plan recognizing past service costs for contributions for the period from August 2002 to August 29, 2007. The Petros 2 Plan currently provides post-retirement benefits for employees of Petrobras, Petrobras Distribuidora S.A., Stratura Asfaltos, Termobahia, Termomacaé, Transportadora Brasileira Gasoduto Brasil-Bolívia S.A. – TBG, Petrobras Transporte S.A. – Transpetro and Petrobras Biocombustível. The plan is open to new participants although there will no longer be payments relating to past service costs.

Certain elements of the Petros 2 Plan have defined benefit characteristics, primarily the coverage of disability and death risks and the guarantee of minimum defined benefit and lifetime income. These actuarial commitments are treated as defined benefit components of the plan and are accounted for by applying the projected unit credit method. Contributions paid for actuarial commitments that have defined contribution characteristics are monthly accrued in the statement of income and are intended to constitute a reserve for programmed retirement. The contributions for the portion of the plan with defined contribution characteristics were US$ 345 in 2014.

The defined benefit portion of the contributions has been suspended from July 1, 2012 to June 30, 2015, as determined by the Executive Council of Fundação Petros, based on advice from the actuarial consultants from Fundação Petros. Therefore, the entire contributions are being appropriated in the individual accounts of plan participants.

For 2015 the employers' expected contributions to the defined contribution portion of the plan are US$ 325. The duration of the actuarial liability related to the plan, as of December 31, 2014 is 41.80 years.

22.2.Other plans

The Company also sponsors other pension and health care plans of certain of its Brazilian and international subsidiaries, including plans with defined benefit characteristics abroad, for subsidiaries in Argentina, Japan and other countries. Most of these plans are funded and their assets are held in trusts, foundations or similar entities governed by local regulations.

22.3.Pension Plans assets

Pension plans assets follow a long term investment strategy based on the risks assessed for each different class of assets and provide for diversification, in order to lower portfolio risk. The portfolio profile must comply with the Brazilian National Monetary Council (Conselho Monetário Nacional – CMN) regulations.

Fundação Petros establishes investment policies for 5-year periods, reviewed annually. Petros uses an asset liability management model (ALM) to address net cash flow mismatches of the benefit plans, based on liquidity and solvency parameters, simulating a 30-year period.

Portfolio allocation limits for the period between 2015 and 2019 for the Petros Plan of the Petrobras Group are 30% to 60% in fixed-income securities, 30% to 45% in variable-income securities, 3% to 8% in real estate, 0% to 15% in loans to participants, 4% to 13% in structured finance projects and up to 1% in variable-income securities abroad. Allocation limits for Petros 2 Plan for the same period are: 30% to 90% in fixed-income securities, 5% to 25% in variable-income securities, 0% to 8% in real estate, 0% to 15% in loans to participants, 0% to 10% % in structured finance projects and 0% to 3% in variable-income securities abroad.

F-66

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The pension plan assets by type of asset are set out following:

	2014				2013
Type of asset	Quoted prices in active markets	Unquoted prices	Total fair value	%	Total fair value	%
Fixed income	5,881	1,834	7,715	38%	8,521	37%
Corporate bonds	−	374	374		536
Government bonds	5,881	−	5,881		6,523
Other investments	−	1,460	1,460		1,462
Variable income	8,323	361	8,684	44%	10,499	47%
Common and preferred shares	8,323	−	8,323		10,152
Other investments	−	361	361		347
Structured investments	−	1,601	1,601	7%	1,571	7%
Private equity funds	−	1,427	1,427		1,464
Venture capital funds	−	20	20		29
Real estate Funds	−	154	154		78
Real estate properties	−	1,436	1,436	7%	1,387	6%
	14,204	5,232	19,436	96%	21,978	97%
Loans to participants			715	4%	757	3%
			20,151	100%	22,735	100%

As of December 31, 2014, the investment portfolio included Petrobras’ common and preferred shares in the amount of US$ 108 and US$ 157, respectively, and real estate properties leased by the Company in the amount of US$ 168.

Loans to participants are measured at amortized cost, which is considered to be an appropriate estimate of fair value.

22.4.Medical Benefits: Health Care Plan -Assistência Multidisciplinar de Saúde (“AMS”)

Petrobras, Petrobras Distribuidora S.A., Petrobras Transporte S.A. – Transpetro, Petrobras Biocombustível and Transportador Brasileira Gasoduto Brasil-Bolívia - TBG operate a medical benefit plan for their employees in Brazil (active and retired) and their dependents: the AMS health care plan. The plan is managed by the Company based on a self-supporting benefit assumption and includes health prevention and health care programs. The plan is most significantly exposed to the risk of an increase in medical costs due to new technologies and new types of coverage or to a higher level of usage of medical benefits. The Company continuously improves the quality of its technical and administrative processes, as well as the health programs offered to beneficiaries in order to hedge such risks.

The employees make fixed monthly contributions to cover high-risk procedures and variable contributions for a portion of the cost of the other procedures, both based on the contribution tables of the plan, which are determined based on certain parameters, such as salary levels. The plan also includes assistance towards the purchase of certain medicines in registered drugstores throughout Brazil. There are no health care plan assets. Benefits are paid and recognized by the Company based on the costs incurred by the participants.

The duration of the actuarial liability related to this health care plan, as of December 31, 2014 is 21.18 years.

22.5.Net actuarial liabilities and expenses calculated by independent actuaries and fair value of plans assets

Aggregate information is presented for other plans, whose total assets and liabilities are not material. All plans are unfunded (excess of benefit liabilities over plan assets).

F-67

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

a)Changes in the actuarial liabilities, in the fair value of the assets and in the amounts recognized in the statement of financial position

	2014
	Pension plan		Medical Plan	Other plans
	Petros	Petros 2	AMS		Total
Changes in the present value of obligations
Obligations at the beginning of the year	27,804	354	6,999	151	35,308
Interest expense:	3,599	45	969	17	4,630
Term of financial commitment (TFC)	441	−	−	−	441
Actuarial	3,158	45	969	17	4,189
Current service cost	58	33	176	11	278
Contributions paid by participants	164	−	−	−	164
Benefits paid	(1,236)	(10)	(395)	(6)	(1,647)
Remeasurement: Experience (gains) / losses	1,114	158	(350)	7	929
Remeasurement: (gains) / losses - demographic assumptions	(2,022)	(55)	(757)	(6)	(2,840)
Remeasurement: (gains) / losses - financial assumptions	1,966	77	3,645	5	5,693
Others	−	−	−	7	7
Cumulative Translation Adjustment	(3,738)	(59)	(1,268)	(19)	(5,084)
Obligations at the end of the year	27,709	543	9,019	167	37,438
Changes in the fair value of plan assets
Fair value of plan assets at the beginning of the year	22,462	233	−	40	22,735
Interest income	2,863	29	−	4	2,896
Contributions paid by the sponsor (Company)	245	−	396	7	648
Contributions paid by participants	164	−	−	−	164
Receipts from the Term of financial commitment (TFC)	203	−	−	−	203
Benefits Paid	(1,236)	(10)	(395)	(6)	(1,647)
Remeasurement: Return on plan assets exceeding interest income	(2,206)	37	−	4	(2,165)
Others	(1)	−	−	20	19
Cumulative Translation Adjustment	(2,659)	(33)	(1)	(9)	(2,702)
Fair value of plan assets at the end of the year	19,835	256	−	60	20,151
Amounts recognized in the Statement of Financial Position
Present value of obligations	27,709	543	9,019	167	37,438
( -) Fair value of plan assets	(19,835)	(256)	−	(60)	(20,151)
Net actuarial liability as of December 31,	7,874	287	9,019	107	17,287
Changes in the net actuarial liability
Balance as of January 1,	5,342	121	6,999	111	12,573
Remeasurement effects recognized in other comprehensive income	3,264	143	2,538	2	5,947
Costs incurred in the period	794	49	1,155	24	2,022
Contributions paid	(245)	−	(396)	(7)	(648)
Payments related to Term of financial commitment (TFC)	(203)	−	−	−	(203)
Others	1	−	−	(13)	(12)
Cumulative Translation Adjustment	(1,079)	(26)	(1,277)	(10)	(2,392)
Balance as of December 31,	7,874	287	9,019	107	17,287

F-68

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

	2013
	Pension plan		Medical Plan	Other plans
	Petros	Petros 2	AMS		Total
Changes in the present value of obligations
Obligations at the beginning of the year	38,548	789	8,390	182	47,909
Interest expense:	3,373	73	735	20	4,201
Term of financial commitment (TFC)	298	−	−	1	299
Actuarial	3,075	73	735	19	3,902
Current service cost	484	145	192	10	831
Contributions paid by participants	182	−	−	−	182
Benefits paid	(1,155)	(6)	(364)	(10)	(1,535)
Remeasurement: Experience (gains) / losses	1,701	(118)	(1,978)	(2)	(397)
Remeasurement: (gains) / losses - demographic assumptions	323	(31)	2	(5)	289
Remeasurement: (gains) / losses - financial assumptions	(11,215)	(443)	1,066	5	(10,587)
Others	−	22	−	(27)	(5)
Cumulative Translation Adjustment	(4,437)	(77)	(1,044)	(22)	(5,580)
Obligations at the end of the year	27,804	354	6,999	151	35,308
Changes in the fair value of plan assets
Fair value of plan assets at the beginning of the year	27,407	242	−	36	27,685
Interest income	2,461	22	−	4	2,487
Contributions paid by the sponsor (Company)	255	−	364	24	643
Contributions paid by participants	182	−	−	−	182
Receipts from the Term of financial commitment (TFC)	153	−	−	−	153
Benefits Paid	(1,155)	(6)	(364)	(10)	(1,535)
Remeasurement: Return on plan assets exceeding interest income	(3,458)	8	−	3	(3,447)
Others	−	−	−	(13)	(13)
Cumulative Translation Adjustment	(3,383)	(33)	−	(4)	(3,420)
Fair value of plan assets at the end of the year	22,462	233	−	40	22,735
Amounts recognized in the Statement of Financial Position
Present value of obligations	27,804	354	6,999	151	35,308
( -) Fair value of plan assets	(22,462)	(233)	−	(40)	(22,735)
Net actuarial liability as of December 31,	5,342	121	6,999	111	12,573
Changes in the net actuarial liability
Balance as of January 1,	11,141	547	8,390	146	20,224
Remeasurement effects recognized in other comprehensive income	(5,733)	(600)	(910)	(5)	(7,248)
Costs incurred in the period	1,396	218	927	25	2,566
Contributions paid	(255)	−	(364)	(24)	(643)
Payments related to Term of financial commitment (TFC)	(153)	−	−	−	(153)
Others	−	22	−	(14)	8
Cumulative Translation Adjustment	(1,054)	(66)	(1,044)	(17)	(2,181)
Balance as of December 31,	5,342	121	6,999	111	12,573

b)Defined benefit costs

	2014
	Pension Plans		Medical Plan	Other Plans
	Petros	Petros 2	AMS		Total
Service cost	58	33	176	11	278
Interest on net liabilities (assets)	736	16	969	13	1,734
Others	−	−	10	−	10
Net expenses for the year	794	49	1,155	24	2,022
Related to active employees:
Included in the cost of sales	255	26	347	(1)	627
Operating expenses in statement of income	140	22	179	24	365
Related to retirees	399	1	629	1	1,030
Net expenses for the year	794	49	1,155	24	2,022

F-69

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

	2013
	Pension Plans		Medical  Plan	Other Plans
	Petros	Petros 2	AMS		Total
Service cost	484	145	192	10	831
Interest on net liabilities (assets)	912	51	735	16	1,714
Others	−	22	−	(1)	21
Net expenses for the year	1,396	218	927	25	2,566
Related to active employees:
Included in the cost of sales	597	119	267	3	986
Operating expenses in statement of income	355	94	211	20	680
Related to retirees	444	5	449	2	900
Net expenses for the year	1,396	218	927	25	2,566

	2012
	Pension Plans		Medical  Plan	Other Plans
	Petros	Petros 2	AMS		Total
Service cost	(9)	197	146	7	341
Interest on net liabilities (assets)	722	61	892	6	1,681
Others	(8)	26	39	12	69
Net expenses for the year	705	284	1,077	25	2,091
Related to active employees:
Included in the cost of sales	218	124	228	4	574
Operating expenses in statement of income	121	153	180	21	475
Related to retirees	366	7	669	−	1,042
Net expenses for the year	705	284	1,077	25	2,091

c)Sensitivity analysis of the defined benefit plans

The effect of a 100 basis points (bps) change in the assumed discount rate and medical cost trend rate is as set out below:

	Discount Rate				Medical Cost
	Pension Benefits		Medical Benefits		Medical Benefits
	+100 bps	-100 bps	+100 bps	-100 bps	+100 bps	-100 bps
Pension Obligation	(2,632)	3,187	(1,024)	1,260	1,303	(1,075)
Current Service cost and interest cost	(147)	183	(20)	24	53	(44)

F-70

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

d)Significant actuarial assumptions

Assumptions	2014	2013
Discount rate - (real rate)	6.14% (1) / 6.20% (2) / 6.15% (3)	6.56% (1) / 6.65% (2) / 6.58% (3)
Expected Inflation (Brazilian price index - IPCA)	6.50% (1) (2) (3) (4)	5.93% (1) (2) (3)
Nominal discount rate (real rate + inflation)	13.04% (1) / 13.10% (2) / 13.05(3)	12.88% (1) / 12.97% (2) / 12.90% (3)
Expected salary growth - real rate	1.761% (1) / 3.77% (2)	1.981% (1) / 4.044% (2) (5)
Expected salary growth - nominal (real rate + Inflation)	8.37% (1) / 10.52 (2)	8.03% (1) / 10.21% (2)
Medical plan turnover	0.642% p.a. (6)	0.590% p.a. (6)
Pension plan turnover	Null	Null
Expected changes in medical and hospital costs	14.47% to 3.00% p.a. (7)	11.62% to 4.09% p.a. (7)
Mortality table	EX-PETROS 2013 (both genders) (8)	Gender-specific Basic AT 2000, 20% smoothing coefficient (8)
Disability table	TASA 1927 (9)	TASA 1927 (9)
Mortality table for disabled participants	Male AT 49, 10% increasing coefficient (10)	Gender-specific Winklevoss, 20% smoothing coefficient (10)
Age of retirement	Male, 57 years / Female, 56 years (11)	Male, 56 years / Female, 55 years (1) (11) Male, 53 years / Female, 48 years (2)
(1) Petros Plan for Petrobras Group.
(2) Petros 2 Plan.
(3) AMS Plan.
(4) Inflation reflects market projections: 6.30% for 2015 and converging to 3.00% in 2030.
(5) Decreasing rate reaching 3.395% as of 2015.
(6) Average turnover (only of Petrobras, the sponsor) according to age and employment time.
(7) Decreasing rate, converging in 30 years to the long-term expected inflation. Refers only to Petrobras (sponsor) rate.
(8) Except for Petros 2 Plan, for which Female AT 2000 with a 10% smoothing coefficient (2014) and AT 2000 (80% male + 20% female) with a 10% smoothing coefficient (2013) have been used.
(9) Except for Petros 2 Plan, for which Álvaro Vindas disability table has been used.
(10) Except for Petros 2 Plan, for which IAPB 1957 mortality table for disabled participants was used.
(11) Except for Petros Plan 2, for which the Company used the eligibility under the rules of the Brazilian Social Security System (Regime Geral de Previdência Social - RGPS).

In 2014 the Company revised the mortality assumption for its benefits based on new tables. EX-PETROS 2013 general mortality table replaced AT 2000 (which was used to calculate the Company’s actuarial obligation in 2013) for both genders. The EX-PETROS mortality table has two-dimensional characteristics indicating data for mortality by age and for longevity increases. This Table, which is recognized by the actuarial technical bodies, was designed based on extensive data over a long period for the participants of the Petrobras Petros Plan. The independent actuary of Fundação Petrobras used the 2013 position of the EX-PETROS table, which was considered to be the most statistically consistent in the time series, with respect to the population of participants of the Petros plan.

e)Expected maturity analysis of pension and medical benefits

	2014
	Pension Plan		Medical Plan
	Petros	Petros 2	AMS	Other Plans	Total
Up to 1 Year	1,654	13	355	2	2,024
1 To 2 Years	1,614	15	370	2	2,001
2 To 3 Years	1,583	16	381	2	1,982
3 To 4 Years	1,549	17	391	2	1,959
Over 4 Years	21,309	482	7,522	159	29,472
	27,709	543	9,019	167	37,438

22.6.Other defined contribution plans

Petrobras, through its subsidiaries in Brazil and abroad, also sponsors defined contribution pension plans for employees. Contributions paid in 2014, in the amount of US$ 5 were recognized in the statement of income.

F-71

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

22.7.Profit sharing

Profit sharing benefits comply with Brazilian legal requirements and those of the Brazilian Department of Coordination and Governance of State‐Owned Enterprises (DEST), of the Ministry of Planning, Budget and Management, and of the Ministry of Mines and Energy, and are computed based on the consolidated net income attributable to the shareholders of Petrobras.

In March 2014, the Company and the labor unions reached an agreement regarding a new profit sharing regulation, following negotiations started in the context of the 2013/2015 Collective Bargaining Agreement.

Pursuant to the amended rules, profit sharing benefits will be computed based on the results of six corporate indicators, for which annual goals are defined by management (maximum permissible levels of crude oil and oil products spill, lifting cost excluding production taxes in Brazil, crude oil and NGL production in Brazil, feedstock processed - excluding NGL - in Brazil, vessel operating efficiency and percentage of compliance with natural gas delivery schedule).

The results of the six individual goals are factored into a consolidated result that will determine the percentage of the profit to be distributed as a profit sharing benefit to employees.

Pursuant to the amended rules, in the event the Company records a net loss for the period, profit sharing benefit will be one half of the benefit paid in the prior year in addition to half a month’s salary for each employee.

2013 profit sharing benefit

The amended rules were applied to determine profit sharing benefits for the year ended December 31, 2013, which were paid on May 2, 2014, resulting in an additional profit sharing expense of US$ 164, recognized in other expenses.

Based on the consolidated result of the corporate indicators for 2013, a 6.25% distribution was applied to the net income expressed in reais.

2014 profit sharing benefit

In 2014 the annual goals of the six corporate indicators were achieved but the Company reported a net loss. Pursuant to the amended rules, the Company recognized a profit sharing expense of US$ 444.

22.8.Voluntary Separation Incentive Plan

In January 2014, the Company launched a Voluntary Separation Incentive Plan (PIDV), which was developed within the context of its Productivity Optimization Plan (POP) to contribute to the achievement of the goals set out in the Business and Management Plan.

A total of 8,298 employees joined during the enrollment period, which ended on March 31, 2014. Those employees were divided into five categories, which determine when their separation will take place, between 2014 and 2017 based on a knowledge management plan or a management succession plan related to the business processes and activities in which such employees are engaged.

Employees who enrolled in the PIDV had to be aged 55 or more and would have to be eligible to retire under the Brazilian Institute of Social Security (INSS) before the end of the enrollment period (March 31, 2014). Employees who leave any time before the agreed dates are not entitled to the separation program incentives.

F-72

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The plan determines two types of separation incentives: fixed additional payments of ten monthly-salaries, between a floor equivalent to US$ 80 thousand and a cap of equivalent to US$ 265 thousand; variable additional payments between 15% and 25% of a monthly-salary for every month worked after the seventh working month, up to the date of separation.

On March 31, 2014 the Company recognized in other expenses in the statement of income a provision for the estimated charges. The amounts are subject to changes resulting from employees who cancel their requests for voluntary separation, impacts of Collective Bargaining Agreements, which might increase salaries before separation, inflation-indexation of the floor and the cap based on the Brazilian Consumer Price Index (IPCA), as well as variable additional incentives earned by employees.

From April to December 2014, 4,936 separations and 481 cancellations of requests were made for voluntary separation of employees who enrolled in the PIDV. Changes in the provision are set out below:

Opening balance as of March 31,2014	1,059
Revision of provision (*)	21
Separations in the period	(609)
Cumulative translation adjustment	(81)
Closing balance as of December 31, 2014	390
Current	206
Non-current	184
(*) Includes cancellation of requests for voluntary separation, compensation increases and inflation indexation charges of the floor and cap amounts.

23.Shareholders’ equity

23.1.Share capital (net of share issuance costs)

As of December 31, 2014, subscribed and fully paid share capital was US$ 107,380 (US$ 107,371 on December 31, 2013), represented by 7,442,454,142 outstanding common shares and 5,602,042,788 outstanding preferred shares, all of which are registered, book-entry shares with no par value.

Preferred shares have priority on returns of capital, do not grant any voting rights and are non-convertible into common shares.

Capital increase with reserves in 2014

The Shareholders’ Extraordinary General Meeting, held jointly with the Annual General Meeting on April 2, 2014 approved a capital increase through capitalization of a portion of the profit reserve relating to tax incentives, established in 2013 in the amount of US$ 9, pursuant to article 35, paragraph 1, of Ordinance 283/13 of the Ministry for National Integration (Ministro do Estado da Integração Nacional), without issue of new shares (pursuant to article 169, paragraph 1, of the Brazilian Corporation Law - 6,404/76).

Incremental costs directly attributable to the issue of new shares – includes any transaction costs directly attributable to the issue of new shares, net of taxes.

23.2.Change in interest in subsidiaries

Includes any excess of amounts paid/received over the carrying value of the interest acquired/disposed. Changes in ownership interest in subsidiaries that do not result in loss of control of the subsidiary are equity transactions.

F-73

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

23.3.Profit reserves

Legal reserve – represents 5% of the net income for the year, calculated pursuant to article 193 of the Brazilian Corporation Law.

Statutory reserve – is appropriated by applying a minimum of 0.5% of the year-end share capital and is retained to fund technology research and development programs. The balance of this reserve may not exceed 5% of the share capital, pursuant to article 55 of the Company’s bylaws.

Tax incentives reserve – government grants are recognized in the statement of income and are appropriated from retained earnings to the tax incentive reserve in the shareholders’ equity pursuant to article 195-A of Brazilian Corporation Law. This reserve may only be used to offset losses or increase share capital.

The Company recorded a net loss in 2014 and, therefore, the impact of tax incentives in the north and northeast regions of Brazil from Superintendências de Desenvolvimento do Nordeste (SUDENE) and Superintendências de Desenvolvimento da Amazônia (SUDAM) were not allocated to the tax incentives reserve. However, the impact of tax incentives will be allocated to the tax incentives reserve in future periods, pursuant to Chapter I of Law 12,973/14.

Profit retention reserve –appropriates funds intended for capital expenditures, primarily in oil and gas exploration and development activities, included in the capital budget of the Company, pursuant to article 196 of the Brazilian Corporation Law.

The accumulated deficit balance of US$ 7,363 at December 31, 2014 will be allocated to the profit retention reserve.

23.4.Accumulated other comprehensive income

Comprises gains or losses arising from remeasurement of net pension and medical benefits liabilities; cash flow hedges; measurement at fair value of available-for-sale financial assets; and cumulative translation adjustment (CTA), which comprises all exchange differences arising from the translation of the consolidated financial statements from the functional currency (Brazilian Real) into the presentation currency (U.S. dollar).

23.5.Dividends

Shareholders are entitled to receive minimum mandatory dividends (and/or interest on capital) of 25% of the adjusted net income for the year proportional to the number of common and preferred shares, pursuant to Brazilian Corporation Law.

To the extent the Company proposes dividend distributions, preferred shares have priority in dividend distribution, which is based on the highest of 3% of the preferred shares’ net book value, or 5% of the preferred share capital. Preferred shares participate under the same terms as common shares in capital increases resulting from the capitalization of profit reserves or retained earnings.

Dividends – 2013

The Annual General Meeting on April 2, 2014 approved a dividend distribution in the form of interest on capital of US$ 3,970, which corresponds to US$ 0.2227 per common shares and US$ 0.4129 per preferred share (translated into U.S. dollars using the closing rate for 2013). These dividends were paid on April 25, 2014 and the record date was April 2, 2014. Amounts paid were index adjusted based on the SELIC rate from December 31, 2013 to the date of payment.

F-74

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The Board of Directors will not propose a dividend distribution in 2014, as the Company reported a loss for the year ended December 31, 2014.

23.6.Earnings per Share

	2014	2013	2012
Net income (loss) attributable to shareholders of Petrobras	(7,367)	11,094	10,931
Weighted average number of common and preferred shares outstanding	13,044,496,930	13,044,496,930	13,044,496,930
Basic and diluted earnings per common and preferred share (US$ per share)	(0.56)	0.85	0.85

24.Sales revenues

	2014	2013	2012
Gross sales	174,031	172,016	176,714
Sales taxes	(30,374)	(30,554)	(32,611)
Sales revenues (*)	143,657	141,462	144,103
Diesel	42,586	41,435	38,558
Automotive gasoline	23,702	23,470	23,277
Fuel oil (including bunker fuel)	4,357	3,464	2,864
Naphtha	5,622	5,885	5,745
Liquefied petroleum gas	3,729	3,960	4,126
Jet fuel	5,562	5,553	5,862
Other oil products	5,771	5,760	5,958
Subtotal oil products	91,329	89,527	86,392
Natural gas	8,035	7,376	6,580
Ethanol, nitrogen products, renewables and other non-oil products	3,862	4,868	4,027
Electricity, services and others	8,384	4,693	3,498
Total domestic market	111,610	106,464	100,497
Exports	13,930	15,172	22,353
International sales (**)	18,117	19,826	21,253
Sales revenues (*)	143,657	141,462	144,103
(*) Analysis of sales revenues by business segment is set out in note 29.
(**) Sales revenues from operations outside of Brazil, other than exports.

25.Other expenses, net

	2014	2013	2012
Unscheduled stoppages and pre-operating expenses	(1,089)	(923)	(856)
Voluntary Separation Incentive Plan - PIDV (note 22.8)	(1,035)	−	−
Pension and medical benefits - retirees	(1,030)	(900)	(1,042)
Institutional relations and cultural projects	(743)	(821)	(777)
Gains / (losses) on decommissioning of returned/abandoned areas	(443)	58	−
Collective bargaining agreement	(440)	(419)	(444)
E&P areas returned and cancelled projects	(268)	(19)	−
Legal, administrative and arbitration proceedings	(194)	(269)	(716)
Health, safety and environment	(143)	(225)	(289)
Government grants	61	181	385
Gains / (losses) on disposal/write-offs of assets (**)	(213)	1,764	(2)
Reimbursements from E&P partnership operations	360	241	268
Others (*)	(116)	219	167
	(5,293)	(1,113)	(3,306)
(*) In 2014 includes additional profit sharing benefit for 2013, as set out on note 22.7.
(**) Includes a US$ 1,304 gain on disposal of the Company's interest in Petrobras Energia Peru S.A. (note 10.1) and a US$ 1,236 write-off of Premium I and Premium II refineries (note 12.4) in 2014.

F-75

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

26.Costs and Expenses by nature

	2014	2013	2012
Raw material / products for resale	(58,539)	(60,068)	(58,410)
Production taxes	(13,500)	(14,498)	(16,083)
Employee compensation	(13,215)	(12,769)	(12,071)
Depreciation, depletion and amortization	(13,023)	(13,188)	(11,119)
Changes in inventories	(1,181)	1,681	724
Materials, freight, rent, third-party services and other related costs	(23,847)	(23,202)	(24,719)
Allowance for impairment of trade receivables	(2,378)	(73)	(39)
Exploration expenditures written off (incl. dry wells and signature bonuses)	(2,178)	(1,892)	(2,847)
Other taxes	(760)	(780)	(386)
Legal, administrative and arbitration proceedings	(194)	(269)	(716)
Institutional relations and cultural projects	(743)	(821)	(777)
Unscheduled stoppages and pre-operating expenses	(1,089)	(923)	(856)
Health, safety and environment	(143)	(225)	(289)
Impairment of assets	(16,823)	(544)	(137)
Gains / (losses) on disposal/write-offs of assets	(213)	1,764	(2)
E&P areas returned and cancelled projects	(268)	(19)	−
Write-off - overpayments incorrectly capitalized	(2,527)	−	−
Results of decommissioning areas	(443)	58	−
	(151,064)	(125,768)	(127,727)
In the Statement of income
Cost of sales	(109,477)	(108,834)	(108,276)
Selling expenses	(6,827)	(4,904)	(4,927)
General and administrative expenses	(4,756)	(4,982)	(5,034)
Exploration costs	(3,058)	(2,959)	(3,994)
Research and development expenses	(1,099)	(1,132)	(1,143)
Impairment of assets	(16,823)	(544)	(137)
Other taxes	(760)	(780)	(386)
Write-off - overpayments incorrectly capitalized	(2,527)	−	−
Other expenses, net	(5,293)	(1,113)	(3,306)
Profit sharing	(444)	(520)	(524)
	(151,064)	(125,768)	(127,727)

27.Net finance income (expense)

	2014	2013	2012
Foreign exchange gains/(losses) and inflation indexation charges on debt (*)	(561)	(1,603)	(3,327)
Debt interest and charges	(6,734)	(5,491)	(5,152)
Income from investments and marketable securities	1,007	1,278	1,716
Financial result on net debt	(6,288)	(5,816)	(6,763)
Capitalized borrowing costs	3,600	3,921	3,807
Gains (losses) on derivatives, net	337	(181)	(52)
Interest income from marketable securities	(39)	(95)	919
Other finance expense and income, net	(159)	(320)	404
Other foreign exchange gains/(losses) and indexation charges, net	914	(300)	(241)
Finance income (expenses), net	(1,635)	(2,791)	(1,926)
Income	1,949	1,815	3,659
Expenses	(3,923)	(2,673)	(2,016)
Foreign exchange gains/ (losses) and inflation indexation charges, net	339	(1,933)	(3,569)
	(1,635)	(2,791)	(1,926)
(*) Includes debt raised in Brazil (in Brazilian reais) indexed to the U.S. dollar.

28.Supplemental information on statement of cash flows

	2014	2013	2012
Amounts paid/received during the year:
Income taxes paid	853	1,446	1,093
Withholding income tax paid on behalf of third-parties	1,852	1,954	2,045
Capital expenditures and financing activities not involving cash
Purchase of property, plant and equipment on credit	123	209	187
Recognition (reversal) of provision for decommissioning costs	1,999	(629)	5,208

F-76

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

29.Segment Information

Consolidated assets by Business Area - 12.31.2014
	Exploration and Production	Refining, Transportation & Marketing	Gas & Power	Biofuels	Distribution	International	Corporate	Eliminations	Total
Current assets	6,008	14,724	3,979	65	3,481	2,345	24,160	(3,930)	50,832
Non-current assets	145,516	55,314	24,388	1,044	3,740	10,664	8,225	(1,036)	247,855
Long-term receivables	6,729	3,605	1,411	3	1,211	1,848	5,029	(973)	18,863
Investments	200	1,807	524	836	15	2,226	145	−	5,753
Property, plant and equipment	135,671	49,662	22,126	205	2,284	6,058	2,787	(63)	218,730
Operating assets	99,313	40,940	17,868	189	1,730	3,716	2,094	(63)	165,787
Under construction	36,358	8,722	4,258	16	554	2,342	693	−	52,943
Intangible assets	2,916	240	327	−	230	532	264	−	4,509
Total Assets	151,524	70,038	28,367	1,109	7,221	13,009	32,385	(4,966)	298,687
Consolidated assets by Business Area - 12.31.2013*
Current assets	5,902	19,141	3,864	77	2,380	5,089	21,643	(5,441)	52,655
Non-current assets	146,805	73,393	23,839	1,119	4,874	13,034	6,897	(1,193)	268,768
Long-term receivables	6,251	4,411	1,853	2	2,229	1,987	3,168	(1,119)	18,782
Investments	94	2,318	749	895	6	2,511	93	−	6,666
Property, plant and equipment	126,716	66,522	20,882	222	2,350	7,971	3,312	(74)	227,901
Operating assets	90,888	32,636	16,698	205	1,686	3,792	2,312	(74)	148,143
Under construction	35,828	33,886	4,184	17	664	4,179	1,000	−	79,758
Intangible assets	13,744	142	355	−	289	565	324	−	15,419
Total Assets	152,707	92,534	27,703	1,196	7,254	18,123	28,540	(6,634)	321,423
* Beginning in 2014, management of Liquigás (a subsidiary)was allocated to the RTM segment (previously Distribution). Amounts previously reported for 2013 were restated for comparability purposes and the results previously attributable to the Distribution segment are now presented under the RTM segment, pursuant to the management and accountability premise adopted for the financial statements by business segment.

F-77

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Consolidated Statement of Income by Business Area
	Jan-Dec/2014
	Exploration and Production	Refining, Transportation & Marketing	Gas & Power	Biofuels	Distribution	International	Corporate	Eliminations	Total
Sales revenues	65,616	112,320	17,882	266	41,729	13,912	−	(108,068)	143,657
Intersegments	65,116	39,251	1,695	238	1,129	639	−	(108,068)	−
Third parties	500	73,069	16,187	28	40,600	13,273	−	−	143,657
Cost of sales	(35,072)	(115,984)	(15,303)	(311)	(38,495)	(12,829)	−	108,517	(109,477)
Gross profit (loss)	30,544	(3,664)	2,579	(45)	3,234	1,083	−	449	34,180
Income (expenses)	(8,646)	(19,312)	(3,307)	(67)	(2,448)	(1,618)	(5,972)	227	(41,143)
Selling, general and administrative	(440)	(2,762)	(2,551)	(50)	(2,253)	(821)	(2,935)	229	(11,583)
Exploration costs	(2,882)	−	−	−	−	(176)	−	−	(3,058)
Research and development	(548)	(192)	(85)	(15)	(1)	(1)	(257)	−	(1,099)
Other taxes	(52)	(95)	(124)	−	(12)	(111)	(366)	−	(760)
Impairment of assets	(2,133)	(12,782)	(117)	−	−	(1,791)	−	−	(16,823)
Write-off - overpayments incorrectly capitalized	(804)	(1,398)	(266)	−	(9)	(9)	(41)	−	(2,527)
Other expenses, net	(1,787)	(2,083)	(164)	(2)	(173)	1,291	(2,373)	(2)	(5,293)
Income / (loss) before financial results, profit sharing and income taxes	21,898	(22,976)	(728)	(112)	786	(535)	(5,972)	676	(6,963)
Net finance income (expense)	−	−	−	−	−	−	(1,635)	−	(1,635)
Share of earnings in equity-accounted investments	16	120	195	(53)	−	(63)	3	−	218
Profit sharing	(150)	(127)	(20)	(1)	(26)	(10)	(110)	−	(444)
Income / (loss) before income taxes	21,764	(22,983)	(553)	(166)	760	(608)	(7,714)	676	(8,824)
Income taxes	(7,635)	7,569	163	39	(261)	(493)	2,168	(229)	1,321
Net income (loss)	14,129	(15,414)	(390)	(127)	499	(1,101)	(5,546)	447	(7,503)
Net income attributable to:
Shareholders of Petrobras	14,133	(15,405)	(410)	(127)	499	(1,145)	(5,359)	447	(7,367)
Non-controlling interests	(4)	(9)	20	−	−	44	(187)	−	(136)
	14,129	(15,414)	(390)	(127)	499	(1,101)	(5,546)	447	(7,503)

F-78

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Consolidated Statement of Income by Business Area (*)
	Jan-Dec/2013
	Exploration and Production	Refining, Transportation & Marketing	Gas & Power	Biofuels	Distribution	International	Corporate	Eliminations	Total
Sales revenues	68,210	111,665	14,017	388	40,023	16,302	−	(109,143)	141,462
Intersegments	67,096	37,375	1,191	324	995	2,162	−	(109,143)	−
Third parties	1,114	74,290	12,826	64	39,028	14,140	−	−	141,462
Cost of sales	(34,283)	(120,043)	(12,154)	(466)	(36,639)	(14,212)	−	108,963	(108,834)
Gross profit (loss)	33,927	(8,378)	1,863	(78)	3,384	2,090	−	(180)	32,628
Income (expenses)	(4,129)	(3,955)	(1,162)	(69)	(2,048)	(215)	(4,932)	96	(16,414)
Selling, general and administrative	(443)	(3,150)	(1,087)	(55)	(2,048)	(860)	(2,406)	163	(9,886)
Exploration costs	(2,784)	−	−	−	−	(175)	−	−	(2,959)
Research and development	(523)	(242)	(57)	(16)	(2)	(2)	(290)	−	(1,132)
Other taxes	(238)	(166)	(81)	(1)	(15)	(141)	(138)	−	(780)
Impairment of assets	(4)	−	−	−	−	(540)	−	−	(544)
Other expenses, net	(137)	(397)	63	3	17	1,503	(2,098)	(67)	(1,113)
Income / (loss) before financial results, profit sharing and income taxes	29,798	(12,333)	701	(147)	1,336	1,875	(4,932)	(84)	16,214
Net finance income (expense)	−	−	−	−	−	−	(2,791)	−	(2,791)
Share of earnings in equity-accounted investments	2	73	243	(20)	2	174	33	−	507
Profit sharing	(181)	(141)	(23)	(1)	(32)	(14)	(128)	−	(520)
Income / (loss) before income taxes	29,619	(12,401)	921	(168)	1,306	2,035	(7,818)	(84)	13,410
Income taxes	(10,070)	4,243	(230)	51	(443)	(246)	4,087	30	(2,578)
Net income (loss)	19,549	(8,158)	691	(117)	863	1,789	(3,731)	(54)	10,832
Net income attributable to:
Shareholders of Petrobras	19,523	(8,150)	631	(117)	863	1,729	(3,331)	(54)	11,094
Non-controlling interests	26	(8)	60	−	−	60	(400)	−	(262)
	19,549	(8,158)	691	(117)	863	1,789	(3,731)	(54)	10,832
* Beginning in 2014, management of Liquigás (a subsidiary) was allocated to the RTM segment (previously Distribution). Amounts previously reported for 2013 were restated for comparability purposes and the results previously attributable to the Distribution segment are now presented under the RTM segment, pursuant to the management and accountability premise adopted for the financial statements by business segment.

F-79

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Consolidated Statement of Income by Business Area (*)
	Jan-Dec/2012
	Exploration and Production	Refining, Transportation & Marketing	Gas & Power	Biofuels	Distribution	International	Corporate	Eliminations	Total
Sales revenues	74,714	116,826	11,803	455	40,596	17,929	−	(118,220)	144,103
Intersegments	73,871	37,950	1,288	365	878	3,868	−	(118,220)	−
Third parties	843	78,876	10,515	90	39,718	14,061	−	−	144,103
Cost of sales	(33,632)	(130,439)	(9,621)	(488)	(36,915)	(14,538)	−	117,357	(108,276)
Gross profit (loss)	41,082	(13,613)	2,182	(33)	3,681	3,391	−	(863)	35,827
Income (expenses)	(5,438)	(3,837)	(1,080)	(95)	(2,259)	(1,430)	(4,937)	149	(18,927)
Selling, general and administrative	(494)	(3,087)	(967)	(64)	(2,200)	(922)	(2,376)	149	(9,961)
Exploration costs	(3,613)	−	−	−	−	(381)	−	−	(3,994)
Research and development	(540)	(228)	(36)	(34)	(2)	−	(303)	−	(1,143)
Other taxes	(53)	(66)	(57)	(1)	(12)	(111)	(86)	−	(386)
Impairment of assets	(34)	135	(1)	−	−	(237)	−	−	(137)
Other expenses, net	(704)	(591)	(19)	4	(45)	221	(2,172)	−	(3,306)
Income / (loss) before financial results, profit sharing and income taxes	35,644	(17,450)	1,102	(128)	1,422	1,961	(4,937)	(714)	16,900
Net finance income (expense)	−	−	−	−	−	−	(1,926)	−	(1,926)
Share of earnings in equity-accounted investments	(1)	(104)	193	(27)	1	(14)	(5)	−	43
Profit sharing	(178)	(146)	(18)	(1)	(36)	(14)	(131)	−	(524)
Income / (loss) before income taxes	35,465	(17,700)	1,277	(156)	1,387	1,933	(6,999)	(714)	14,493
Income taxes	(12,057)	5,982	(367)	44	(473)	(1,147)	4,213	243	(3,562)
Net income (loss)	23,408	(11,718)	910	(112)	914	786	(2,786)	(471)	10,931
Net income attributable to:
Shareholders of Petrobras	23,406	(11,718)	861	(112)	914	719	(2,565)	(471)	11,034
Non-controlling interests	2	−	49	−	−	67	(221)	−	(103)
	23,408	(11,718)	910	(112)	914	786	(2,786)	(471)	10,931
* Beginning in 2014, management of Liquigás (a subsidiary) was allocated to the RTM segment (previously Distribution). Amounts previously reported for 2012 were restated for comparability purposes and the results previously attributable to the Distribution segment are now presented under the RTM segment, pursuant to the management and accountability premise adopted for the financial statements by business segment.

F-80

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Statement of Income - breakdown of International Business Area
	Jan-Dec/2014
	Exploration & Production	Refining, Transportation & Marketing	Gas & Power	Distribution	Corporate	Eliminations	Total
Statement of income
Sales revenues	3,000	7,406	490	5,167	23	(2,174)	13,912
Intersegments	1,234	1,528	34	2	15	(2,174)	639
Third parties	1,766	5,878	456	5,165	8	−	13,273
Income before financial results, profit sharing and income taxes	185	(556)	71	96	(327)	(4)	(535)
Net income (loss) attributable to shareholders of Petrobras	(413)	(474)	92	82	(428)	(4)	(1,145)
	Jan-Dec/2013
	Exploration & Production	Refining, Transportation & Marketing	Gas & Power	Distribution	Corporate	Eliminations	Total
Statement of income
Sales revenues	4,134	8,633	556	5,223	7	(2,251)	16,302
Intersegments	2,382	1,982	37	7	5	(2,251)	2,162
Third parties	1,752	6,651	519	5,216	2	−	14,140
Income before financial results, profit sharing and income taxes	2,030	(22)	66	105	(303)	(1)	1,875
Net income (loss) attributable to shareholders of Petrobras	1,644	(12)	68	92	(62)	(1)	1,729
	Jan-Dec/2012
	Exploration & Production	Refining, Transportation & Marketing	Gas & Power	Distribution	Corporate	Eliminations	Total
Statement of income
Sales revenues	5,369	8,989	601	5,184	−	(2,214)	17,929
Intersegments	3,834	2,194	38	16	−	(2,214)	3,868
Third parties	1,535	6,795	563	5,168	−	−	14,061
Income before financial results, profit sharing and income taxes	2,438	(407)	132	73	(291)	16	1,961
Net income (loss) attributable to shareholders of Petrobras	1,317	(400)	121	70	(403)	14	719
	Exploration & Production	Refining, Transportation & Marketing	Gas & Power	Distribution	Corporate	Eliminations	Total
Total assets - breakdown of International Business Area
At 12.31.2014	9,623	1,861	472	940	1,230	(1,117)	13,009
At 12.31.2013	13,656	2,652	602	1,085	1,970	(1,842)	18,123

F-81

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

30.Provisions for legal proceedings

30.1.Provisions for legal proceedings, contingent liabilities and not provisions for legal proceedings

The Company has recognized provisions for the best estimate of the costs of proceedings for which it is probable that an outflow of resources embodying economic benefits will be required and that can be reasonably estimated. These proceedings are mainly comprised of labor claims, tax proceedings related to withholding income tax over proceeds from notes issued abroad, losses and damages proceedings resulting from the cancellation of an assignment of excise tax (IPI) credits to a third party and fishermen seeking indemnification from the Company for a January 2000 oil spill in the State of Rio de Janeiro.

Provisions for legal proceedings, are set out below:

Non-current liabilities	12.31.2014	12.31.2013
Labor claims	717	569
Tax claims	104	94
Civil claims	666	545
Environmental claims	40	26
Other claims	13	12
	1,540	1,246

	12.31.2014	12.31.2013
Opening Balance	1,246	1,265
New provisions, net	766	415
Payments made	(314)	(249)
Accruals and charges	66	77
Others	(8)	(57)
Cumulative translation adjustment	(216)	(205)
Closing Balance	1,540	1,246

Judicial deposits made in connection with legal proceedings are set out in the table below according to the nature of the corresponding lawsuits:

Non-current assets	12.31.2014	12.31.2013
Labor	928	882
Tax	1,006	1,002
Civil	663	529
Environmental	80	83
Others	5	8
	2,682	2,504

Contingent liabilities for which the likelihood of loss is considered to be possible are not recognized as liabilities in the financial statements but are disclosed, unless the expected outflow of resources embodying economic benefits is considered remote.

The estimated contingent liabilities for legal proceedings at December 31, 2014 for which the likelihood of loss is considered to be possible are set out in the table below.

F-82

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Nature	Estimate
Tax	36,992
Civil - General	3,896
Labor	4,661
Civil - Environmental	1,499
Others	2
	47,050

A brief description of the nature of the main contingent liabilities (tax, civil, environmental and labor) for which the likelihood of loss is considered to be possible are set out in the table below.

Description of tax matters	Estimate
Plaintiff: Secretariat of the Federal Revenue of Brazil
1) Failure to withhold and pay income tax (IRRF) and Contribution of Intervention in the Economic Domain (CIDE) on remittances for payment of platform charters.
Current status: This claim involves lawsuits in different administrative and judicial stages, in which the Company is taking legal actions to ensure its rights.	7,929
2) Failure to pay tax on financial operations (IOF) over intercompany loans entered into with, PifCo, Brasoil and BOC in 2007, 2008, 2009 and 2010.
Current status: Awaiting the hearing of an appeal at the administrative level.	2,689
3) Deduction from taxable income of profits of subsidiaries and associates domiciled abroad in 2005, 2006, 2007, 2008, 2009 and 2010.
Current status: Awaiting the hearing of an appeal at the administrative level.	2,547
4) Failure to withhold and pay income tax withheld (IRRF) on remittances for payment of crude oil imports.
Current status: This claim involves lawsuits in different administrative and judicial stages, in which the Company is taking legal actions to ensure its rights.	1,918
5) Deduction from taxable income of expenses from Petros Plan renegotiation and penalties.
Current status: Awaiting the hearing of an appeal at the administrative level.	1,858
6) Deduction from taxable income (income tax - IRPJ and social contribution - CSLL) of development costs.
Current status: This claim involves a lawsuit in administrative stage, in which the Company is taking legal actions to ensure its rights.	1,757
7) Tax credits applied were disallowed due to failure to comply with an ancillary tax obligation.
Current status: Awaiting the hearing of an appeal at the administrative level.	1,736
8) Failure to pay Contribution of Intervention in the Economic Domain (CIDE) on imports of naphtha.
Current status: This claim is being discussed at the administrative level.	1,328
9) Failure to pay social security contributions over contingent bonuses paid to employees.
Current status: This claim involves lawsuits in administrative stages, in which the Company is taking legal actions to ensure its rights.	821
10) Deduction from taxable income (income tax - IRPJ and social contribution - CSLL) of various employee benefits and pension benefits (PETROS) expenses in 2007 and 2008.
Current status: This claim is being disputed at the administrative level, involving three administrative proceedings.	744
11) Failure to pay Contribution of Intervention in the Economic Domain (CIDE) from March 2002 to October 2003 on transactions with fuel retailers and service stations protected by judicial injunctions determining that fuel sales were made without gross-up of such tax.
Current status: This claim involves lawsuits in different administrative and judicial levels, in which the Company is taking legal actions to ensure its rights.	634
Plaintiff: State of São Paulo Finance Department
12) Dispute over VAT (ICMS) levied on a drilling rig import – temporary admission in the state of São Paulo and clearance in the state of Rio de Janeiro and related fines for breach of ancillary tax obligations.
Current status: This claim involves lawsuits in administrative stages, in which the Company is taking legal actions to ensure its rights.	1,813
Plaintiff: States of AM, BA, DF, ES, PA, PE and RJ Finance Departments
13) Dispute over VAT (ICMS) levied on crude oil and natural gas sales attributable to alleged differences in beginning inventory and ending inventory.

F-83

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Current status: This claim involves lawsuits in different administrative and judicial levels, in which the Company is taking legal actions to ensure its rights.	1,151
Plaintiff: State of Rio de Janeiro Finance Department
14) VAT (ICMS) levied on dispatch of liquid natural gas (LNG) without issuance of tax document by the main establishment.
Current status: This claim involves lawsuits in different administrative stages, in which the Company is taking legal actions to ensure its rights.	1,323
15) Dispute over VAT (ICMS) levied on jet fuel sales, as Decree 36,454/2004 was declared unconstitutional.
Current status: This claim involves lawsuits in administrative stages, in which the Company is taking legal actions to ensure its rights.	758
Plaintiff: Municipal governments of the cities of Anchieta, Aracruz, Guarapari, Itapemirim, Marataízes, Linhares, Vila Velha, Vitória and Maragogipe.
16) Alleged failure to withhold and pay tax on services provided offshore (ISSQN) in some municipalities located in the State of Espírito Santo. Petrobras withheld and paid these taxes to the municipalities where the respective service providers were established, in accordance with Complementary Law 116/03.
Current status: This claim involves lawsuits in different judicial stages, in which the Company is taking legal actions to ensure its rights.	846
Plaintiff: State SP, RS and SC Finance Departments
17) Three States challenged VAT (ICMS) paid to the State of MS on imports of natural gas.
Current status: This claim involves lawsuits in different administrative and judicial stages, as well as three civil lawsuits in the Supreme Court.	799
Plaintiff: States of Rio de Janeiro and Sergipe Finance Departments
18) VAT (ICMS) credits were allegedly applied improperly on the purchase of drilling rig bits and chemical products used in formulating drilling fluid.
Current status: This claim involves lawsuits in different judicial stages, in which the Company is taking legal actions to ensure its rights.	396
19) Other tax matters	5,945
Total tax matters	36,992

Description of civil matters	Estimate
Plaintiff: Agência Nacional de Petróleo, Gás Natural e Biocombustíveis - ANP
1) Legal and administrative disputes on differences in special participation charges and royalties paid in several fields. In addition, the Brazilian Oil, Natural Gas and Biofuels Agency (ANP) is claiming fines for alleged non-compliance with minimum exploratory programs and alleged irregularities in platform measurement systems.
Current status: This claim involves proceedings in different administrative and judicial stages, in which the Company is taking legal actions to ensure its rights.	1,557
Plaintiff: Refinaria de Petróleo de Manguinhos S.A.
2) Lawsuit seeking to recover damages for alleged anti-competitive practices with respect to gasoline and other oil products (Diesel and LPG) sales in the domestic market.
Current status: This claim is in judicial stage and was ruled for the plaintiff in the first stage. The Company is taking legal actions to ensure its rights. The Brazilian Antitrust regulator (CADE) has analyzed this claim and did not consider the Company's practices anti-competitive.	497
3) Other civil matters	1,842
Total for civil matters	3,896

F-84

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Description of environmental matters	Estimate
Plaintiff: Ministério Público Federal, Ministério Público Estadual do Paraná
AMAR - Associação de Defesa do Meio Ambiente de Araucária e IAP - Instituto Ambiental do Paraná
1) Legal proceeding related to specific performance obligations, indemnification and compensation for damages related to an environmental accident that occurred in the State of Paraná on July 16, 2000.
Current status: The court partially ruled in favor of the plaintiff, however both parties (the plaintiff and the Company) filed an appeal.	783
2) Other environmental matters	716
Total for environmental matters	1,499

Description of labor matters	Estimate
Plaintiff : Sindipetro of Espírito Santo, Rio de Janeiro, Bahia, Minas Gerais and São Paulo.
1) Class actions requiring a review of how the minimum compensation based on the employee's position and work schedule (Remuneração Mínima por Nível e Regime - RMNR) is computed.
Current status: The Company filed with the Superior Labor Court a collective bargaining agreement seeking to interpret the collective bargaining agreement clause questioned before the Labor Courts.	1,187
Plaintiff : Sindipetro of Norte Fluminense and Sindipetro do Estado da Bahia
2) Class Actions regarding wage underpayments to certain employees due to alleged changes in the methodology used to factor overtime into the calculation of paid weekly rest, allegedly computed based on ratios that are higher than those established by Law No. 605/49.
Current status: The Company has appealed a decision with respect to the claim filed by Sindipetro/BA and awaits judgment by the Superior Labor Court. The Company has filed an appeal in the Superior Labor Court to overturn a decision with respect to the claim filed by Sindipetro Norte Fluminense (NF) and awaits judgment.	437
Plaintiff : Sindipetro of Norte Fluminense – SINDIPETRO/NF
3)The plaintiff claims Petrobras to pay overtime for standby work time exceeding 12-hours per day. It also claims that Petrobras must respect a 12-hour limit per workday, subject to a daily fine.
Current status: Awaiting the Superior Labor Court to judge appeals filed by both parties.	381
4) Other labor matters	2,656
Total for labor matters	4,661

30.2.Class actions and other related proceedings

Between December 8, 2014 and January 7, 2015, five putative securities class action complaints were filed against the Company in the United States District Court for the Southern District of New York (SDNY). These actions were consolidated on February 17, 2015 (the “Consolidated Securities Litigation”). The Court appointed a lead plaintiff, Universities Superannuation Scheme Limited (“USS”), on March 4, 2015. USS filed a consolidated amended complaint on March 27, 2015 that purports to be on behalf of investors who: (i) purchased or otherwise acquired Petrobras securities traded on the NYSE or pursuant to other transactions in the U.S. during the period January 22, 2010 and March 16,2015, inclusive (the “Class Period”), and were damaged thereby; (ii) purchased or otherwise acquired the 2012 Notes pursuant to the 2009 Registration Statement, or the 2013 Notes or 2014 Notes pursuant to the 2012 Registration Statement and were damaged thereby; and (iii) purchased or otherwise acquired Petrobras securities on the Brazilian stock exchange during the period January 22, 2010 and March 19,2015, who also purchased or otherwise acquired Petrobras securities traded on the NYSE or pursuant to other transactions in the U.S. during the same period.

The consolidated amended complaint alleges, among other things, that in the Company’s press releases, filings with the SEC and other communications, the Company made materially false and misleading statements and omissions regarding the value of its assets, the amounts of the Company’s expenses and net income, the effectiveness of the Company’s internal controls over financial reporting, and the Company’s anti-corruption policies, due to alleged corruption purportedly in connection with certain contracts, which allegedly artificially inflated the market value of the Company’s securities.

F-85

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

In addition, to date, three complaints have been filed by individual investors in the Southern District of New York consisting of allegations similar to those in the consolidated amended complaint. Those individual actions have been consolidated with the Consolidated Securities Litigation for pre-trial purposes.

The plaintiffs have not specified an amount of alleged damages in the actions. Because these actions are in their early stages, the possible loss or range of losses, if any, arising from the litigation cannot be estimated. The Company has engaged a U.S. firm as legal counsel and intends to defend vigorously against the allegations made in the context of these actions.

30.3.Contingent assets

30.3.1.Legal proceeding in the United States - P-19 and P-31 platforms

In 2002, Braspetro Oil Service Company (Brasoil) and Petrobras obtained a favorable decision  in related lawsuits filed before U.S. courts by the insurance companies United States Fidelity & Guaranty Company and American Home Assurance Company in which they were seeking to obtain (since 1997 and regarding Brasoil) a judicial order exempting them from their payment obligations under the performance bond related to platforms P- 19 and P-31 platforms, and seeking reimbursement from Petrobras for any amounts for which they could ultimately be held liable in the context of the execution proceedings of such performance bond.

On July 21, 2006, the U.S. courts issued an executive decision, conditioning the payment of the amounts owed to Brasoil on a definitive dismissal of the legal proceedings involving identical claims that were ongoing before Brazilian courts.

In August 2014, Brasoil and Petrobras signed an out-of-court agreement with the U.S. insurance companies, which provides for the closure of all lawsuits and judicial executions filed in Brazilian and foreign courts. The agreement resulted in a US$ 295 gain, of which US$ 72 had been previously recognized, and therefore, a US$ 223 gain was recognized in other income in 2014.

30.3.2.Recovery of PIS and COFINS

The Company filed civil lawsuits against the Federal Government claiming to recover, through offsetting, amounts paid as taxes on finance income and foreign exchange variation gains (PIS) in the period between February 1999 and November 2002 and COFINS between February 1999 and January 2004 claiming that paragraph 1 of article 3 of Law 9,718/98 is unconstitutional.

On November 9, 2005, the Federal Supreme Court declared this paragraph to be unconstitutional.

On November 18, 2010, the Superior Court of Justice upheld the claim filed by Petrobras in 2006 to recover the COFINS for the period from January 2003 to January 2004. Petrobras then recognized the amount of US$ 290 as recoverable taxes.

The Company recognized US$ 957 as recoverable taxes in September 2014 (US$ 360 in other income and US$ 597 in finance income) for the lawsuit filed in 2005 to recover PIS and COFINS taxes overpaid on finance income in the period from February 1999 to December 2002, after its right to recover those taxes has been definitely recognized and the amounts and documents necessary to request judicial payment were presented.

As of December 31, 2014, the Company had non-current receivables of US$ 1,030 related to PIS and COFINS, which are inflation indexed and awaiting settlement, are set out in the table below.

F-86

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

	12.31.2014
COFINS - January 2003 to January 2004	290
PIS / COFINS - February 1999 to November 2002	957
Inflation indexation	24
Cumulative translation adjustment	(241)
Non-current receivables	1,030

31.Commitment to purchase  natural gas

On August 18, 2014, Petrobras reached an agreement with Yacimientos Petrolíferos Fiscales Bolivianos (YPFB) to settle controversies regarding several aspects of the Bolivian natural gas import contract to supply the Brazilian domestic market (GSA). This agreement sets out payment schedules and compensations for both parties to resolve different interpretations of the GSA, and includes a contract to secure Bolivian natural gas supply to for a thermoelectric power plant - UTE Cuiabá through December 2016.

As of December 31, 2014, the total amount of agreement (GSA) for the 2015 to 2019 period is approximately 54.92 billion cubic meters (m³) of natural gas (equivalent to 30.08 cubic meters (m³) per day) and corresponds to a total value of US$ 10.09 billion.

The agreement resulted in a net charge to income of US$ 383, of which US$ 438 was recognized in cost of sales, partially offset by a US$ 55 gain in other income.

32.Collateral for crude oil exploration concession agreements

The Company has granted collateral to the Brazilian Agency of Petroleum, Natural Gas and Biofuels (Agência Nacional de Petróleo, Gás Natural e Biocombustíveis -ANP) in connection with the performance of the Minimum Exploration Programs established in the concession agreements for petroleum exploration areas in the total amount of US$ 2,467 of which US$ 1,881 are still in force at December 31, 2014, net of commitments that have been undertaken. The collateral comprises crude oil from previously identified producing fields, pledged as security, amounting to US$ 1,512 and bank guarantees of US$ 369.

33.Risk management

The Company is exposed to a variety of risks arising from its operations, including price risk (related to crude oil and oil products prices), foreign exchange rates risk, interest rates risk, credit risk and liquidity risk. It manages risks through a corporate policy established by its officers.

The objective of the overall risk management policy is to support the achievement of the Company’s strategic goals through an adequate resource allocation and an appropriate balance between growth, return on investments and risk exposure level, which can arise from its normal activities or from the context within which the Company operates.

A summary of the positions held by the Company and recognized in other current assets and liabilities as of December 31, 2014, as well as the amounts recognized in the statement of income and other comprehensive income and the guarantees given is set out following:

F-87

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

	Statement of Financial Position
	Notional value		Fair value Asset Position (Liability)		Maturity
	12.31.2014	12.31.2013	12.31.2014	12.31.2013
Derivatives not designated for hedge accounting
Future contracts - total (*)	(4,314)	10,224	70	(20)
Long position/Crude oil and oil products	84,544	52,267	−	−	2015
Short position/Crude oil and oil products	(88,858)	(42,043)	−	−	2015
Options - total (*)	(594)	−	0.7	−
Call/Crude oil and oil products	(364)	−	(0.4)	−
Put/Crude oil and oil products	(230)	−	1.1	−	2015
Forward contracts - total			2	(1)
Long position/Foreign currency forwards (ARS/USD)	USD 10		(1)	−	2015
Short position/Foreign currency forwards (BRL/USD)	USD 249	USD 17	3	(1)	2015
Swap
Interest – Euribor / Fixed rate	EUR 5	EUR 10	−	(0.6)	2015
Derivatives designated for hedge accounting
Swap - total			(42)	(9)
Foreign currency / Cross-currency Swap	USD 298	USD 298	(22)	11	2016
Interest – Libor / Fixed rate	USD 419	USD 440	(20)	(20)	2020
Total recognized in the Statement of Financial Position			30.7	(30.6)
(*) Notional value in thousands of bbl

	Gains (losses) recognized in the statement of income (*)			Gains (losses) recognized in the Shareholders’ Equity (**)			Guarantees given as collateral
	2014	2013	2012	2014	2013	2012	12.31.2014	12.31.2013
Commodity derivatives	368	(105)	(103)	−	−	−	6	143
Foreign currency derivatives	(20)	(39)	41	10	10	7	−	−
Interest rate derivatives	(11)	−	(1)	(1)	11	(9)	−	−
Embedded derivative - ethanol	−	(37)	10	−	−	−	−	−
	337	(181)	(53)	9	21	(2)	6	143
Cash flow hedge on exports (***)	(702)	(303)	−	(5,741)	(5,923)	−	−	−
	(365)	(484)	(53)	(5,732)	(5,902)	(2)	6	143
(*) Amounts recognized in finance income in the period.
(**) Amounts recognized as other comprehensive income in the period.
(***) Using non-derivative financial instruments as designated hedging instruments, as set out note 33.3.

A sensitivity analysis for the different types of market risks, to which the Company is exposed, based on the derivative financial instruments held as of December 31, 2014 is set out following:

Financial Instruments	Risk	Probable Scenario*	Stressed Scenario (∆ of 25%)	Stressed Scenario (∆ of 50%)
Derivatives not designated for hedge accounting
Future contracts	Crude oil and oil products - price changes	70	(71)	(212)
Forward contracts	Foreign currency - depreciation R$ x USD	(20)	(60)	(120)
Forward contracts	Foreign currency - appreciation argentine peso x USD	−	(3)	(5)
Swap	Interest - Euribor decrease	−	−	−
Options	Crude oil and oil products - price changes	1	−	(3)
		51	(134)	(340)
Derivatives designated for hedge accounting
Swap		(1)	102	305
Debt	Foreign currency - appreciation JPY x USD	1	(102)	(305)
Net effect		−	−	−
Swap		5	(1)	(1)
Debt	Interest - LIBOR increase	(5)	1	1
Net effect		−	−	−
(*) On February 27, 2015, the probable scenario was computed based on the following risks: R$ x U.S. Dollar - an 8.36% depreciation of the Real; Japanese Yen x U.S. Dollar - a 0.03% depreciation of the Japanese Yen; Peso x U.S. Dollar - a 2.00% depreciation of the Peso; LIBOR Forward Curve - a 0.35% increase throughout the curve; EURIBOR Forward Curve - a 0.15% decrease throughout the curve.

F-88

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

33.1.Risk management of price risk (related to crude oil and oil products prices)

Petrobras preferably does not use derivative instruments to hedge exposures to commodity price cycles related to products purchased and sold to fulfill operational needs. Derivatives are used as hedging instruments to manage the price risk of certain short-term commercial transactions.

33.2.Foreign exchange risk management

Petrobras seeks to identify and manage foreign exchange rate risks based on an integrated analysis of natural hedges, to benefit from the correlation between income and expenses. The Company’s short-term risk management involves choosing the currency in which to hold cash, such as the Brazilian Real, U.S. dollar or other currency. The risk management strategy involves the use of derivative instruments to hedge certain liabilities, minimizing foreign exchange rate risk exposure.

a)Cash Flow Hedge involving the Company’s highly probable future exports

The Company designates hedging relationships to account for the effects of the existing natural hedge between a portion of its long-term debt obligations (denominated in U.S. dollars) and its U.S. dollar denominated exports and to properly recognize that hedge in its financial statements.

Individual hedging relationships were designated in a one-to-one proportion, meaning that a portion of the total monthly exports will be the hedged transaction of an individual hedging relationship, hedged by a portion of the company’s long-term debt (which has an average maturity of approximately 6.1 years).

The principal amounts, fair value as of December 31, 2014, and a schedule of the timing of the losses recognized in other comprehensive income (shareholders’ equity) to be recycled to the statement of income, as of December 31, 2014, based on a R$/USD 2.6562 exchange rate, are set out below:

Hedging Instrument	Hedged Transactions	Nature of the Risk	Maturity Date	Principal Amount (US$ million)	Carrying amount as of December 31, 2014 (R$ million)
Non-Derivative Financial Instruments	Portion of Highly Probable Future Monthly Export Revenues	Foreign Currency – Real vs U.S. Dollar Spot Rate	January 2015 to June 2023	50,858	135,088

Changes in the principal amount (in US$ million)
Amounts designated as of December 31, 2013	40,742
New hedging instruments designated	22,330
Exports affecting profit or loss	(5,764)
Principal repayments / amortization	(6,450)
Amounts designated as of December 31, 2014	50,858

A schedule of the timing of the losses recognized in other comprehensive income (shareholders’ equity) to be recycled to the statement of income as of December 31, 2014 is set out below:

	Consolidated
	12.31.2014
	2015	2016	2017	2018	2019	2020	2021	2022	2023	Total
Expected reclassification	(1,278)	(1,452)	(1,642)	(1,569)	(1,391)	(924)	(769)	(884)	(132)	(10,041)

F-89

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

b)Cash flow hedges involving swap contracts – Yen x Dollar

The Company has a cross currency swap to fix in U.S. dollars the payments related to bonds denominated in Japanese yen and does not intend to settle these contracts before the maturity. The relationship between the derivative and the bonds was designated for cash flow hedge accounting.

c)Sensitivity analysis for foreign exchange risk on financial instruments

A sensitivity analysis is set out below, showing the probable scenario for foreign exchange risk on financial instruments, computed based on external data along with stressed scenarios (a 25% and a 50% change in the foreign exchange rates), except for assets and liabilities of foreign subsidiaries, when transacted in a currency equivalent to their respective functional currencies.

Financial Instruments	Exposure at 12.31.2014	Risk	Probable Scenario (*)	Stressed Scenario (∆ of 25%)	Stressed Scenario (∆ of 50%)
Assets	2,594		217	648	1,297
Liabilities	(61,299)	Dollar/Real	(5,123)	(15,325)	(30,649)
Cash flow hedge on exports	50,858		4,250	12,714	25,429
	(7,847)		(656)	(1,963)	(3,923)
Liabilities (**)	(651)	Yen/Dollar	−	(163)	(325)
Assets	6	Euro/Real	−	2	3
Liabilities	(2,589)		−	(647)	(1,295)
	(2,583)		−	(645)	(1,292)
Assets	6,878	Euro/Dollar	(781)	1,719	3,439
Liabilities	(13,866)		1,575	(3,467)	(6,933)
	(6,988)		794	(1,748)	(3,494)
Assets	4	Pound	−	1	2
Liabilities	(727)	Sterling/Real	(54)	(182)	(363)
	(723)		(54)	(181)	(361)
Assets	1,763	Pound	(37)	441	882
Liabilities	(3,787)	Sterling/Dollar	80	(947)	(1,894)
	(2,024)		43	(506)	(1,012)
Assets	274	Peso/Dollar	6	69	137
Liabilities	(765)		(15)	(191)	(382)
	(491)		(9)	(122)	(245)
	(20,656)		118	(5,165)	(10,327)
(*) On 27/02/15, the probable scenario was computed based on the following risks: Real x Dollar – an 8.36% depreciation of the Real / Yen x Dollar – a 0.03% depreciation of the Yen / Peso x Dollar: a 2.00% depreciation of the Peso/ Euro x Dollar: a 7.70% depreciation of the Euro / Pound Sterling x Dollar: a 0.87% depreciation of the Pound Sterling. The probable scenario was determined based on the spot foreign exchange rates (PTAX selling rates) reported by the Central Bank of Brazil on February 27, 2015.
(**) A portion of the foreign currency exposure is hedged by a cross-currency swap.

33.3.Interest rate risk management

The Company considers that interest rate risk does not create a significant exposure and therefore, preferably does not use derivative financial instruments to manage interest rate risk, except for specific situations encountered by certain subsidiaries of Petrobras.

F-90

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

33.4.Capital management

The Company’s objectives when making its financial decisions is to achieve an adequate capital management and indebtedness level in order to safeguard its ability to continue as a going concern, adding value to its shareholders and investors. Its main sources of funding have been cash provided by its operating activities, debt issuance in the international capital markets, loan agreements with commercial banks and cash provided by asset disposals (divesting). The duration of the Company’s debt matches the maturity of its capital expenditures (an average maturity of approximately 6 years).

Net debt is calculated as total debt (short-term debt and long-term debt) less cash, cash equivalents and government bonds and time deposits with maturities higher than three months. Adjusted EBITDA is calculated by adding back net finance income (expenses), income taxes, depreciation/amortization, share of earnings in equity-accounted investments, impairment charges and write-off of overpayments incorrectly capitalized to net income. Net total capitalization is calculated by adding net debt to shareholders’ equity. These measures are not defined by the International Financial Reporting Standards – IFRS (non-GAAP measures) and should neither be considered in isolation or as substitutes for profit, indebtedness and cash flow provided by operating activities as defined by the IFRS, nor be compared to those measures of other companies.

	2014	2013
Total debt (current and noncurrent)	132,158	114,325
Cash and cash equivalents	(16,655)	(15,868)
Government securities and time deposits (maturity of more than three months)	(9,302)	(3,878)
Net debt	106,201	94,579
Net debt/(net debt+shareholders' equity)	48%	39%
Adjusted EBITDA	24,966	29,426
Net debt/Adjusted EBITDA ratio	4.25	3.21

Undertaking capital expenditures in the oil and gas industry is financial-capital intensive and involves long-term maturity. Thus cash used in investing activities may exceed cash provided by operating activities during certain periods. Cash provided by operating activities may be negatively affected if oil prices remain at the current level for a significant period of time. Thus the Company’s financial ratios may be negatively affected during the period when there is no cash flows provided by the operations of its ongoing capital expenditures or when changes resulting from a revision of the Company’s Business and Management Plan – BMP are being implemented.

In addition, the recently revised divestment plan for the 2015 to 2016 period (projecting divestments of US$ 13.7 billion) is part of the Company's financial planning, aimed at reducing leverage, preserving cash and prioritizing capital expenditures, primarily in oil and gas production in Brazil in highly productive and profitable areas.

However, this divestment portfolio is dynamic and the occurrence of the transactions depend on business conditions, market conditions and the Company’s continuing assessment of its businesses.

33.5.Credit risk

Credit risk management in Petrobras aims at reconciling the need for minimizing risk (of not collecting receivables or financial deposits) and maximizing the result of commercial and financial transactions, through efficient credit analysis, granting and management based on quantitative and qualitative parameters that are appropriate for each market segment in which the Company operates.

The commercial credit portfolio is very diversified and comprises clients from the domestic market and from foreign markets. Credit granted to financial institutions is spread among “investment grade” international banks rated by international rating agencies and highly-rated Brazilian banks.

F-91

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

33.5.1.Credit quality of financial assets

a)Trade and other receivables

Most of the company’s customers have no credit agency ratings. Thus, credit commissions assess creditworthiness and define credit limits, which are regularly monitored, based on the client’s main activity, commercial relationship and credit history with Petrobras, solvency, financial situation and external market assessment of the customer.

b)Other financial assets

Credit quality of cash and cash equivalents, as well as marketable securities is based on external credit ratings provided by Standard & Poor’s, Moody’s and Fitch. The credit quality of those financial assets, that are neither past due nor have been impaired, are set out below:

	Cash and cash equivalents		Marketable securities
	2014	2013	2014	2013
AAA	21	23	−	−
AA	100	7	−	−
A	8,145	4,959	20	−
BBB	1,501	62	91	−
AAA.br	5,221	9,926	9,282	3,979
AA.br	926	462	−	−
Others	741	429	39	37
	16,655	15,868	9,432	4,016

33.6.Liquidity risk

Liquidity risk is represented by the possibility of a shortage of cash or other financial assets in order to settle the Company’s obligations on the agreed dates and is managed by the Company based on policies such as: centralized cash management, in order to optimize the level of cash and cash equivalents held and to reduce working capital; a minimum cash level to ensure that the need of cash for investments and short-term obligations is met even in adverse market conditions; increasing the number of investors in the domestic and international markets through funding opportunities, developing a strong presence in the international capital markets and searching for new funding sources, including new markets and financial products.

This strategy is currently is being achieved, for example, by seeking funding in the Asian market. The Company intends to use different funding sources (banking market, Export Credit Agencies - ECAs and capital markets) in 2015 to obtain the necessary funding to repay debt and fund its capital expenditures. In addition, the Company’s divestment program (of US$ 13.7 billion) will contribute to its funding needs.

A maturity schedule of the Company’s finance debt (undiscounted), including face value and interest payments is set out following:

Maturity	2015	2016	2017	2018	2019	2020 and thereafter	Balance at December 31, 2014	Balance at December 31, 2013
	16,042	18,499	16,842	22,351	27,506	78,464	179,704	155,175

F-92

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

33.7.Insurance (unaudited)

The Company’s insurance strategy involves acquiring insurance to cover risks that may produce material impacts and also to cover risks that are subject to compulsory insurance coverage (pursuant to legal or contractual requirements). The remaining risks are self-insured and Petrobras intentionally assumes the entire risk by abstaining from contracting insurance. The Company assumes a significant portion of its risk, by entering into insurance policies that have deductibles that may reach an amount equivalent to US$ 20.

The Company’s risk assumptions for insurance are not part of the audit scope of the financial statements audit and therefore were not examined by independent auditors.

The main information concerning the insurance coverage outstanding at December 31, 2014 is set out below:

Assets	Types of coverage	Amount insured
Facilities, equipment inventory and products inventory	Fire, operational risks and engineering risks	182,746
Tankers and auxiliary vessels	Hulls	3,800
Fixed platforms, floating production systems and offshore drilling units	Oil risks	38,741
Total		225,287

Petrobras does not have loss of earnings insurance or insurance related to well control, automobiles and pipeline networks in Brazil.

34.Fair value of financial assets and liabilities

Fair values are determined based on market prices, when available, or, in the absence thereof, on the present value of expected future cash flows. The fair values of cash and cash equivalents, short term debt and other non-current assets and liabilities are the same as or do not differ significantly from their carrying amounts.

The hierarchy of the fair values of the financial assets and liabilities, recorded on a recurring basis, is set out below:

-Level 1 inputs: are the most reliable evidence of fair value, quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity can access at the measurement date.

-Level 2 inputs: are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

-Level 3 inputs: are unobservable inputs for the asset or liability.

F-93

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

	Fair value measured based on
	Level I	Level II	Level III	Total fair value recorded
Assets
Marketable securities	2,711	−	−	2,711
Commodity derivatives	70.7	−	−	70.7
Foreign currency derivatives	−	2	−	2
Balance at December 31, 2014	2,781.7	2	−	2,783.7
Balance at December 31, 2013	3,895	10	−	3,905
Liabilities
Foreign currency derivatives	−	(22)	−	(22)
Interest derivatives	−	(20)	−	(20)
Balance at December 31, 2014	−	(42)	−	(42)
Balance at December 31, 2013	(20)	(20.6)	−	(40.6)

There are no material transfers between levels.

The estimated fair value for the Company’s long term debt as of December 31, 2014, computed based on the prevailing market rates is set out in note 17.

35.Subsequent events

Moody’s review of Petrobras’s global ratings

On February 24, 2015, Moody’s downgraded Petrobras’s bonds credit rating in the U.S. market. Petrobras lost its investment grade rating.

According to Moody´s, the downgrade of Petrobras’s rating reflects increasing concern about corruption investigations and liquidity pressures that might result from delays in delivering audited financial statements. In addition, Moody's expects that the Company will be challenged to make meaningful reduction in its debt level over the next several years and expects the Company to take longer than previously expected to achieve planned leverage reductions.

The Company has no covenants which are affected by the credit rating downgrades or require maintenance of an investment grade rating.

Closure of refining activities in Japan

In February 2015, Petrobras initiated a plan for closure of the refining activities in Okinawa, Japan. The plan will provide for the closure of the Nansey Sekiyu (NSS) refinery and the Company will work together with the Japanese Ministry of Economy, Trade and Industry (METI).

Disposal of assets in Argentina

On March 30, 2015, Petrobras Argentina S.A., PESA, disposed of its interest in assets located in the Austral basin in Santa Cruz to Compañía General de Combustibles S.A. (CGC) for US$ 101.

Financing agreements in the banking market

On April 1, 2015, Petrobras Global Trading BV – PGT, an indirect subsidiary of Petrobras entered into a US$ 3.5 billion line of credit for 10 years with China Development Bank Corporation – CDB.

F-94

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

On April 9, 2015, Petrobras Distribuidora S.A. (a wholly-owned subsidiary of Petrobras) entered into a R$ 4.5 billion (US$ 1.5 billion) working capital loan agreement with Banco do Brasil, due March 2021.

On April 17, 2015, the Company announced the approval of the following financing agreements:

-5-year standby credit line with Caixa Econômica Federal of R$ 2 billion (US$ 0.8 billion);

-5-year standby credit line with Bradesco of R$ 3 billion (US$ 1.2 billion);

-Cooperation agreement with Standard Chartered for an oil production platform sale and leaseback transaction of US$ 3 billion for 10 years.

36.Information Related to Guaranteed Securities Issued by Subsidiaries

36.1.Petrobras Global Finance B.V. (PGF)

Petróleo Brasileiro S.A. - Petrobras fully and unconditionally guarantees the debt securities issued by Petrobras Global Finance B.V. (PGF), a 100-percent-owned finance subsidiary of Petrobras. There are no significant restrictions on the ability of Petrobras to obtain funds from PGF.

36.2.Petrobras International Finance Company – PifCo

In the past, Petrobras used its former wholly-owned subsidiary Petrobras International Finance Company S.A., or PifCo, as a vehicle to issue notes that it fully and unconditionally guaranteed. PGF acquired all of the outstanding shares of Petrobras International Finance Company S.A. (PifCo) on February 12, 2014 and on December 29, 2014, PifCo merged into PGF, and PGF assumed PifCo’s obligations under all outstanding notes originally issued by PifCo, which continue to benefit from Petrobras’ full and unconditional guarantee.

F-95

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

In accordance with Codification Topic 932 - Extractive Activities – Oil and Gas, this section provides supplemental information on oil and gas exploration and production activities of the Company. The information included in items (i) through (iii) provides historical cost information pertaining to costs incurred in exploration, property acquisition and development, capitalized costs and results of operations. The information included in items (iv) and (v) presents information on Petrobras’ estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

Beginning in 1995, the Federal Government of Brazil undertook a comprehensive reform of the country’s oil and gas regulatory system. On November 9, 1995, the Brazilian Constitution was amended to authorize the Federal Government to contract with any state or privately owned company to carry out the activities related to the upstream and downstream segments of the Brazilian oil and gas sector. This amendment eliminated Petrobras’ effective monopoly. The amendment was implemented by the Oil Law, which liberated the fuel market in Brazil beginning January 1, 2002.

The Oil Law established a regulatory framework ending Petrobras’ exclusive agency and enabling competition in all aspects of the oil and gas industry in Brazil. As provided in the Oil Law, Petrobras was granted the exclusive right for a period of 27 years to exploit the petroleum reserves in all fields where the Company had previously commenced production. However, the Oil Law established a procedural framework for Petrobras to claim exclusive exploratory (and, in case of success, development) rights for a period of up to three years with respect to areas where the Company could demonstrate that it had “established prospects”. To perfect its claim to explore and develop these areas, the Company had to demonstrate that it had the requisite financial capacity to carry out these activities, alone or through financing or partnering arrangements.

The international geographic area includes activities in South America, which includes Argentina, Colombia and Ecuador; North America, which includes Mexico and the United States of America; and others, comprised of Turkey. The equity-accounted investments are comprised of the operations of Petrobras Oil and Gas B.V. (PO&G) in Namibia and Nigeria, as well as Venezuelan companies involved in exploration and production activities.

F-96

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

i) Capitalized costs relating to oil and gas producing activities

The following table summarizes capitalized costs for oil and gas exploration and production activities with the related accumulated depreciation, depletion and amortization, and asset retirement obligation assets:

	Consolidated entities							Equity Method Investees
	Brazil	South America	North America	Africa	Others	International	Total	Total
December 31, 2014
Unproved oil and gas properties	9,298	72	673	−	−	745	10,043	9
Proved oil and gas properties	96,520	2,007	4,247	−	−	6,254	102,774	4,542
Support Equipment	79,497	1,181	78	−	3	1,262	80,759	26
Gross Capitalized costs	185,315	3,260	4,998	−	3	8,261	193,576	4,577
Depreciation, depletion and amortization	(46,691)	(1,753)	(1,274)	−	(3)	(3,030)	(49,721)	(1,819)
Net capitalized costs	138,624	1,507	3,724	−	−	5,231	143,855	2,758
December 31, 2013
Unproved oil and gas properties	21,261	826	685	22	−	1,533	22,794	−
Proved oil and gas properties	82,389	2,410	5,907	−	−	8,317	90,706	3,972
Support Equipment	81,436	360	(274)	(15)	4	75	81,511	1
Gross Capitalized costs	185,086	3,596	6,319	7	4	9,926	195,012	3,973
Depreciation, depletion and amortization	(44,626)	(2,045)	(948)	−	(4)	(2,997)	(47,623)	(1,455)
Net capitalized costs	140,460	1,551	5,370	7	1	6,929	147,389	2,518
December 31, 2012
Unproved oil and gas properties	48,255	705	1,641	1,500	25	3,871	52,126	−
Proved oil and gas properties	60,651	3,950	3,572	2,467	−	9,989	70,640	491
Support Equipment	74,411	1,499	2	26	7	1,534	75,945	−
Gross Capitalized costs	183,317	6,154	5,215	3,994	32	15,394	198,711	491
Depreciation, depletion and amortization	(43,283)	(3,013)	(625)	(1,415)	(3)	(5,056)	(48,339)	(170)
Net capitalized costs	140,034	3,141	4,590	2,579	29	10,338	150,372	321

F-97

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

ii) Costs incurred in oil and gas property acquisition, exploration and development activities

Costs incurred are summarized below and include both amounts expensed and capitalized:

	Consolidated entities							Equity Method Investees
	Brazil	South America	North America	Africa	Others	International (*)	Total	Total
December 31, 2014
Acquisition costs:
Proved	−	89	−	−	−	89	89	−
Unproved	54	−	−	−	−	−	54	−
Exploration costs	5,455	122	135	15	−	272	5,727	−
Development costs	18,158	546	418	−	−	964	19,122	638
Total	23,667	757	552	15	−	1,325	24,992	638
December 31, 2013
Acquisition costs:
Proved	−	−	−	−	−	−	−	−
Unproved	2,791	−	−	−	−	−	2,791	−
Exploration costs	6,814	183	397	1	1	582	7,396	−
Development costs	16,732	673	1,138	282	2	2,095	18,827	237
Total	26,337	856	1,535	283	3	2,677	29,014	237
December 31, 2012
Acquisition costs:
Proved	−	−	−	−	−	−	−	−
Unproved	−	−	−	−	−	−	−	−
Exploration costs	5,670	282	601	86	1	970	6,640	−
Development costs	16,217	877	1,036	285	60	2,258	18,475	19
Total	21,887	1,159	1,637	371	61	3,228	25,115	19
(*) The assets classified as held for sale in 2013 were disposed of in 2014.

(iii) Results of operations for oil and gas producing activities

The Company’s results of operations from oil and gas producing activities for the years ended December 31, 2014, 2013 and 2012 are shown in the following table. The Company transfers substantially all of its Brazilian crude oil and gas production to the Refining, Transportation & Marketing segment in Brazil. The prices calculated by the Company’s model may not be indicative of the price the Company would have realized had this production been sold in an unregulated spot market. Additionally, the prices calculated by the Company’s model may not be indicative of the future prices to be realized by the Company. Gas prices used are those set out in contracts with third parties.

Production costs are lifting costs incurred to operate and maintain productive wells and related equipment and facilities, including operating employees’ compensation, materials, supplies, fuel consumed in operations and operating costs related to natural gas processing plants.

Exploration expenses include the costs of geological and geophysical activities and non-productive exploratory wells. Depreciation and amortization expenses relate to assets employed in exploration and development activities. In accordance with Codification Topic 932 – Extractive Activities – Oil and Gas, income taxes are based on statutory tax rates, reflecting allowable deductions. Interest income and expense are excluded from the results reported in this table.

F-98

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

(iii) Results of operations for oil and gas producing activities

	Consolidated entities							Equity Method Investees
	Brazil	South America	North America	Africa	Others	International	Total	Total
December 31, 2014
Net operation revenues:
Sales to third parties	500	847	919	−	−	1,766	2,266	676
Intersegment	65,116	1,234	−	−	−	1,234	66,350	1,394
	65,616	2,081	919	−	−	3,000	68,616	2,071
Production costs	(27,397)	(998)	(227)	−	−	(1,225)	(28,622)	(579)
Exploration expenses	(2,882)	(28)	(142)	(15)	−	(185)	(3,067)	(280)
Depreciation, depletion and amortization	(7,675)	(352)	(558)	−	−	(910)	(8,585)	(174)
Impairment of oil and gas properties	(2,133)	(87)	(1,585)	(6)	−	(1,678)	(3,811)	(74)
Other operating expenses	(2,827)	1,059	(112)	2	113	1,063	(1,764)	(8)
Results before income tax expenses	22,702	1,675	(1,705)	(20)	113	64	22,766	954
Income tax expenses	(7,719)	(490)	(4)	−	17	(477)	(8,196)	(653)
Results of operations (excluding corporate overhead and interest costs)	14,983	1,186	(1,709)	(20)	130	(413)	14,570	301
December 31, 2013
Net operation revenues:
Sales to third parties	1,114	1,033	513	206	−	1,752	2,866	546
Intersegment	67,096	1,708	−	674	−	2,382	69,478	762
	68,210	2,742	513	879	−	4,134	72,344	1,308
Production costs	(26,465)	(1,420)	(177)	(65)	−	(1,663)	(28,128)	(197)
Exploration expenses	(2,784)	(61)	(88)	(28)	(3)	(180)	(2,964)	(2)
Depreciation, depletion and amortization	(7,814)	(519)	(322)	(89)	−	(931)	(8,745)	(263)
Impairment of oil and gas properties	(4)	1	(14)	(560)	−	(573)	(577)	−
Other operating expenses	(1,345)	(256)	(75)	(50)	1,748	1,367	22	−
Income before income tax expenses	29,798	486	(162)	86	1,744	2,154	31,952	847
Income tax expenses	(10,131)	(141)	(2)	(367)	(1)	(510)	(10,642)	(348)
Results of operations (excluding corporate overhead and interest costs)	19,667	345	(164)	(281)	1,744	1,644	21,311	498
December 31, 2012
Net operation revenues:
Sales to third parties	843	1,148	19	368	−	1,535	2,378	186
Intersegment	73,871	1,659	290	1,886	−	3,834	77,705	−
	74,714	2,807	309	2,254	−	5,369	80,083	186
Production costs	(27,094)	(1,360)	(40)	(178)	−	(1,578)	(28,672)	(154)
Exploration expenses	(3,613)	(176)	(48)	(81)	(56)	(361)	(3,974)	−
Depreciation, depletion and amortization	(6,528)	(476)	(177)	(191)	(1)	(845)	(7,373)	(79)
Impairment of oil and gas properties	(34)	−	−	(16)	−	(16)	(50)	−
Other operating expenses	(1,801)	(152)	(113)	176	(42)	(131)	(1,932)	−
Income before income tax expenses	35,644	643	(69)	1,964	(99)	2,438	38,082	(47)
Income tax expenses	(12,119)	(150)	−	(929)	1	(1,078)	(13,197)	14
Results of operations (excluding corporate overhead and interest costs)	23,525	493	(69)	1,035	(98)	1,360	24,885	(33)

F-99

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

(iv) Reserve quantities information

The Company’s estimated net proved oil and gas reserves and changes thereto for the years 2014, 2013 and 2012 are shown in the following table. Proved reserves are estimated by the Company’s reservoir engineers in accordance with the reserve definitions prescribed by the Securities and Exchange Commission.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is done by means not involving a well.

In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.

Bolivian proved reserves were not classified as such in 2010 due to the new Bolivian Constitution, which restricts the disclosure of estimated reserves for properties under its authority. The initial balance of Bolivian proved reserves for 2010 is adjusted under the line item “Revisions of previous estimates”.

F-100

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

(iv) Reserve quantities information

A summary of the annual changes in the proved reserves of oil is as follows (in millions of barrels):

	Consolidated Entities							Equity Method Investees
Proved developed and undeveloped reserves	Brazil	South America	North America	Africa	International**	Synthetic Oil	Total	Total
Reserves at December 31, 2011	10,411.2	191.2	53.7	118.1	363.0	8.6	10,782.8	29.6
Revisions of previous estimates	69.7	(2.6)	23.5	22.4	43.3	0.7	113.7	(3.0)
Extensions and discoveries	424.4	11.4	−	−	11.4	−	435.8	−
Improved Recovery	324.6	0.6	−	18.7	19.3	−	343.9	−
Production for the year	(690.7)	(25.2)	(3.3)	(19.0)	(47.5)	(1.0)	(739.1)	(2.3)
Reserves at December 31, 2012	10,539.2	175.4	74.0	140.2	389.6	8.3	10,937.1	24.3
Transfers by loss of control*	−	−	−	(140.2)	(140.2)	−	(140.2)	140.2
Revisions of previous estimates	(110.0)	13.4	21.9	−	35.4	1.3	(73.4)	1.8
Extensions and discoveries	818.3	−	33.0	−	33.0	−	851.4	−
Improved Recovery	124.2	−	−	−	−	−	124.2	−
Sales of reserves	(42.3)	−	(1.5)	−	(1.5)	−	(43.8)	(65.4)
Production for the year	(671.0)	(22.8)	(4.3)	−	(27.1)	(0.8)	(698.9)	(16.5)
Reserves at December 31, 2013	10,658.4	166.0	123.1	(0.0)	289.2	8.8	10,956.4	84.5
Revisions of previous estimates	629.3	(3.2)	5.3	−	2.1	0.2	631.6	(1.1)
Extensions and discoveries	267.7	3.0	1.6	−	4.6	−	272.3	−
Improved Recovery	−	0.5	−	−	0.5	−	0.5	−
Sales of reserves	−	(104.4)	(0.1)	−	(104.5)	−	(104.5)	−
Purchases of reserves	−	22.9	−	−	22.9	−	22.9	−
Production for the year	(704.6)	(18.3)	(10.0)	−	(28.3)	(1.1)	(734.0)	(11.3)
Reserves at December 31, 2014	10,850.9	66.5	119.9	(0.0)	186.5	7.9	11,045.2	72.1
*Amounts transferred from consolidated entities to equity-method entities, as the Company ceased to consolidate PO&G.
** In 2013 includes 105 million barrels related to assets classified as held for sale.
Apparent differences in the sum of the numbers are due to rounding off.

F-101

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

(iv) Reserve quantities information

A summary of the annual changes in the proved reserves of natural gas is as follows (in billions of cubic feet):

	Consolidated Entities							Equity Method Investees
Proved developed and undeveloped reserves	Brazil	South America	North America	Africa	International**	Synthetic Gas	Total	Total
Reserves at December 31, 2011	11,067.0	1,189.6	71.9	39.3	1,300.8	13.4	12,381.2	43.5
Revisions of previous estimates	373.4	(18.3)	2.7	6.2	(9.4)	1.8	365.8	5.2
Extensions and discoveries	275.8	19.6	−	−	19.6	−	295.4	−
Improved Recovery	(624.3)	0.8	−	−	0.8	−	(623.5)	−
Production for the year	(747.3)	(108.0)	(6.9)	−	(114.9)	(1.9)	(864.1)	(0.9)
Reserves at December 31, 2012	10,344.6	1,083.7	67.7	45.5	1,196.9	13.3	11,554.8	47.8
Transfers by loss of control*	−	−	−	(45.5)	(45.5)	−	(45.5)	45.5
Revisions of previous estimates	(291.2)	75.2	2.6	−	77.8	(0.1)	(213.5)	(8.0)
Extensions and discoveries	1,113.0	−	80.4	−	80.4	−	1,193.4	−
Improved Recovery	916.0	−	−	−	−	−	916.0	−
Sales of reserves	(17.3)	−	(13.4)	−	(13.4)	−	(30.7)	(22.8)
Purchases of reserves	0.4	−	−	−	−	−	0.4	−
Production for the year	(773.8)	(100.4)	(4.4)	−	(104.8)	(1.4)	(880.0)	(0.6)
Reserves at December 31, 2013	11,291.7	1,058.5	132.9	0.0	1,191.4	11.8	12,494.8	61.9
Revisions of previous estimates	468.0	25.5	46.1	−	71.6	0.1	539.7	(14.4)
Extensions and discoveries	216.0	42.1	6.0	−	48.1	−	264.1	−
Improved Recovery	−	10.8	−	−	10.8	−	10.8	−
Sales of reserves	−	(351.7)	(0.1)	−	(351.8)	−	(351.8)	−
Purchases of reserves	−	47.1	−	−	47.1	−	47.1	−
Production for the year	(805.4)	(101.5)	(4.9)	−	(106.4)	(1.4)	(913.2)	(0.6)
Reserves at December 31, 2014	11,170.3	730.8	180.0	0.0	910.8	10.6	12,091.5	46.9
*Amounts transferred from consolidated entities to equity-method entities, as the Company ceased to consolidate PO&G.
** In 2013 includes 363 billion cubic feet related to assets classified as held for sale.
Apparent differences in the sum of the numbers are due to rounding off.

F-102

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

(iv) Reserve quantities information

	2014				2013				2012
	Crude Oil	Synthetic Oil	Natural Gas	Synthetic Gas	Crude Oil	Synthetic Oil	Natural Gas	Synthetic Gas	Crude Oil	Synthetic Oil	Natural Gas	Synthetic Gas
	(millions of barrels)		(billions of cubic feet)		(millions of barrels)		(billions of cubic feet)		(millions of barrels)		(billions of cubic feet)
Net proved developed reserves:
Consolidated Entities
Brazil	7,002.7	7.9	6,661.0	10.6	6,509.3	8.8	6,578.9	11.8	6,397.5	8.3	6,811.5	13.3
South America	52.0	−	358.2	−	86.0	−	368.4	−	96.5	−	414.1	−
North America	63.6	−	146.2	−	46.2	−	9.9	−	21.2	−	25.2	−
Africa	−	−	−	−	−	−	−	−	77.8	−	35.8	−
International	115.6	−	504.3	−	132.2	−	378.3	−	195.5	−	475.1	−
Total Consolidated Entities	7,118.3	7.9	7,165.4	10.6	6,641.6	8.8	6,957.3	11.8	6,593.0	8.3	7,286.6	13.3
Nonconsolidated Entities
South America	9.4	−	15.7	−	12.4	−	14.9	−	12.7	−	14.6	−
Africa	30.8	−	14.4	−	37.3	−	15.7	−	−	−	−	−
International	40.2	−	30.1	−	49.8	−	30.5	−	12.7	−	14.6	−
Total Nonconsolidated Entities	40.2	−	30.1	−	49.8	−	30.5	−	12.7	−	14.6	−
Total Consolidated and Nonconsolidated Entities	7,158.5	7.9	7,195.5	10.6	6,691.4	8.8	6,987.8	11.8	6,605.7	8.3	7,301.2	13.3

Net proved undeveloped reserves:
Consolidated Entities
Brazil	3,848.2	−	4,509.2	−	4,149.1	−	4,712.7	−	4,141.7	−	3,533.0	−
South America	14.6	−	372.5	−	80.1	−	690.1	−	78.9	−	669.5	−
North America	56.4	−	33.8	−	77.0	−	123.1	−	52.8	−	42.5	−
Africa	−	−	−	−	−	−	−	−	62.4	−	9.8	−
International	71.0	−	406.3	−	157.1	−	813.2	−	194.1	−	721.8	−
Total Consolidated Entities	3,919.2	−	4,915.5	−	4,306.2	−	5,525.9	−	4,335.8	−	4,254.8	−
Nonconsolidated Entities
South America	8.6	−	11.9	−	8.8	−	26.4	−	11.6	−	33.2	−
Africa	23.3	−	4.9	−	25.9	−	4.9	−	−	−	−	−
International	31.9	−	16.8	−	34.7	−	31.3	−	11.6	−	33.2	−
Total Nonconsolidated Entities	31.9	−	16.8	−	34.7	−	31.3	−	11.6	−	33.2	−
Total Consolidated and Nonconsolidated Entities	3,951.1	−	4,932.3	−	4,340.8	−	5,557.2	−	4,347.4	−	4,288.0	−
Apparent differences in the sum of the numbers are due to rounding off.

F-103

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

(v) Standardized measure of discounted future net cash flows relating to proved oil and gas quantities and changes therein

The standardized measure of discounted future net cash flows, related to the above proved oil and gas reserves, is calculated in accordance with the requirements of Codification Topic 932 – Extractive Activities – Oil and Gas. Estimated future cash inflows from production in Brazil and international segments are computed by applying the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indicators, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and are applied to estimated future pre-tax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10% mid-period discount factors. This discounting requires a year-by-year estimate of when the future expenditures will be incurred and when the reserves will be produced.

F-104

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

The valuation prescribed under Codification Topic 932 – Extractive Activities – Oil and Gas requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of Petrobras’ future cash flows or the value of its oil and gas reserves.

	Consolidated entities						Equity Method Investees
	Brazil	South America	North America	Africa	International**	Total	Total
As of December 31, 2014
Future cash inflows	1,080,516	7,164	11,334	−	18,498	1,099,014	6,282
Future production costs	(469,252)	(3,743)	(3,687)	−	(7,430)	(476,682)	(1,904)
Future development costs	(70,098)	(1,195)	(2,351)	−	(3,547)	(73,644)	(1,613)
Future income tax expenses	(188,740)	(618)	(408)	−	(1,026)	(189,766)	(920)
Undiscounted future net cash flows	352,427	1,608	4,888	−	6,495	358,922	1,846
10 percent midyear annual discount for timing of estimated cash flows*	(178,720)	(526)	(1,582)	−	(2,108)	(180,828)	(553)
Standardized measure of discounted future net cash flows	173,707	1,082	3,306	−	4,388	178,094	1,292
As of December 31, 2013
Future cash inflows	1,134,383	16,770	12,071	−	28,841	1,163,225	8,724
Future production costs	(469,442)	(8,742)	(3,484)	−	(12,226)	(481,668)	(3,051)
Future development costs	(72,675)	(2,146)	(2,795)	−	(4,942)	(77,617)	(1,927)
Future income tax expenses	(205,938)	(1,693)	(169)	−	(1,862)	(207,800)	(1,221)
Undiscounted future net cash flows	386,328	4,189	5,622	−	9,811	396,139	2,524
10 percent midyear annual discount for timing of estimated cash flows*	(197,760)	(1,435)	(2,288)	−	(3,723)	(201,483)	(820)
Standardized measure of discounted future net cash flows	188,569	2,754	3,335	−	6,088	194,657	1,704
As of December 31, 2012
Future cash inflows	1,107,784	18,010	7,318	15,682	41,010	1,148,794	4,155
Future production costs	(458,630)	(8,822)	(1,676)	(3,105)	(13,603)	(472,233)	(2,880)
Future development costs	(58,197)	(2,245)	(2,002)	(3,785)	(8,032)	(66,229)	(177)
Future income tax expenses	(204,258)	(2,010)	−	(3,166)	(5,176)	(209,434)	(405)
Undiscounted future net cash flows	386,699	4,933	3,640	5,626	14,199	400,898	693
10 percent midyear annual discount for timing of estimated cash flows*	(198,081)	(1,733)	(1,174)	(1,872)	(4,779)	(202,860)	(282)
Standardized measure of discounted future net cash flows	188,618	3,200	2,466	3,754	9,420	198,038	411
*Semiannual capitalization
**In 2013 includes the amount of US$ 1,758 related to assets classified as held for sale.

F-105

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

(v)          Standardized measure of discounted future net cash flows relating to proved oil and gas quantities and changes therein

	Consolidated entities							Equity Method Investees
	Brazil	South America	North America	Africa	Others	International	Total	Total
Balance at January 1, 2014	188,569	2,754	3,335		−	6,088	194,657	1,704
Sales and transfers of oil and gas, net of production cost	(38,212)	(652)	(700)	−	−	(1,352)	(39,563)	(952)
Development cost incurred	18,158	546	418	−	−	964	19,122	638
Net change due to purchases and sales of minerals in place	−	(1,092)	106	−	−	(985)	(985)	−
Net change due to extensions, discoveries and improved recovery less related costs	7,197	182	−	−	−	182	7,379	−
Revisions of previous quantity estimates	16,764	(28)	213	−	−	185	16,949	(30)
Net change in prices, transfer prices and in production costs	(33,371)	(255)	(397)	−	−	(652)	(34,023)	(547)
Changes in estimated future development costs	(11,824)	(361)	38	−	−	(323)	(12,147)	(116)
Accretion of discount	18,857	132	343	−	−	475	19,331	176
Net change in income taxes	7,570	(114)	(94)	−	−	(208)	7,363	86
Timing		−	19	−	−	19	19	(29)
Other - unspecified		(30)	25	−	−	(6)	(6)	362
Balance at December 31, 2014	173,707	1,082	3,306	−	−	4,388	178,094	1,292

F-106

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

	Consolidated entities							Equity Method Investees
	Brazil	South America	North America	Africa	Others	International**	Total	Total
Balance at January 1, 2013	188,618	3,200	2,466	3,755	−	9,421	198,039	411
Transfers by loss of control*	−	−	−	(3,755)	−	(3,755)	(3,755)	3,755
Sales and transfers of oil and gas, net of production cost	(33,988)	(1,159)	(398)	−	−	(1,557)	(35,545)	(735)
Development cost incurred	16,732	656	165	282	2	1,105	17,837	237
Net change due to purchases and sales of minerals in place	(1,008)	272	(116)	−	−	157	(851)	(1,878)
Net change due to extensions, discoveries and improved recovery less related costs	33,171	−	673	−	−	673	33,844	−
Revisions of previous quantity estimates	(4,075)	28	936	−	−	963	(3,112)	84
Net change in prices, transfer prices and in production costs	(9,710)	(370)	303	(282)	(2)	(351)	(10,061)	(416)
Changes in estimated future development costs	(19,155)	(404)	(346)	−	−	(750)	(19,905)	(86)
Accretion of discount	18,862	447	271	−	−	718	19,579	251
Net change in income taxes	(877)	189	(12)	−	−	176	(701)	272
Timing		(3)	(654)	−	−	(657)	(657)	−
Other - unspecified		(102)	46	−	−	(56)	(56)	(192)
Balance at December 31, 2013	188,569	2,754	3,335	−	−	6,088	194,657	1,704
*Amounts transferred from consolidated entities to equity-method entities, as the Company ceased to consolidate PO&G.
** Includes the amount of US$ 1,758 related to assets classified as held for sale.

F-107

 

Petróleo Brasileiro S.A. – Petrobras

Supplementary information on Oil and Gas Exploration and Production (unaudited)

(Expressed in millions of US Dollars, unless otherwise indicated)

	Consolidated entities						Equity Method Investees
	Brazil	South America	North America	Africa	International	Total	Total
Balance at January 1, 2012	192,396	3,446	1,133	3,465	8,044	200,440	445
Sales and transfers of oil and gas, net of production cost	(47,822)	(1,241)	(67)	(1,721)	(3,029)	(50,851)	(116)
Development cost incurred	16,217	759	538	285	1,642	17,859	19
Net change due to purchases and sales of minerals in place	−	−	−	−	−	−	−
Net change due to extensions, discoveries and improved recovery less related costs	17,855	180	1,017	1,372	2,569	20,424	40
Revisions of previous quantity estimates	3,410	246	(59)	1,774	1,961	5,371	(58)
Net change in prices, transfer prices and in production costs	(6,848)	84	114	(341)	(203)	(7,051)	(138)
Changes in estimated future development costs	(8,958)	(823)	(380)	(1,058)	(2,261)	(11,219)	(114)
Accretion of discount	19,240	485	130	344	959	20,199	67
Net change in income taxes	3,129	154	−	(100)	54	3,183	1
Timing	−	(37)	54	−	17	17	−
Other - unspecified	−	(54)	(15)	(265)	(334)	(334)	265
Balance at December 31, 2012	188,619	3,199	2,465	3,755	9,419	198,038	411

F-108

EX-8.1

 

Exhibit 8.1

Subsidiaries	Total Capital	Voting Capital	Country of Incorporation	Activity
Petrobras Netherlands B.V. - PNBV	100.00%	100.00%	Netherlands	E&P
Petrobras Distribuidora S.A. – BR	100.00%	100.00%	Brazil	Distribution
Transportadora Associada de Gás S.A. – TAG	100.00%	100.00%	Brazil	Gas & Power
Petrobras Transporte S.A. – Transpetro	100.00%	100.00%	Brazil	RT&M
Petrobras Logística de Exploração e Produção S.A. - PB-LOG	100.00%	100.00%	Brazil	E&P
Petrobras Gás S.A. – Gaspetro	100.00%	100.00%	Brazil	Gas & Power
Petrobras International Braspetro - PIB BV (i)	88.12%	88.12%	Netherlands	International
Petrobras Biocombustível S.A.	100.00%	100.00%	Brazil	Biofuels
Companhia Integrada Têxtil de Pernambuco S.A. - CITEPE	100.00%	100.00%	Brazil	RT&M
Liquigás Distribuidora S.A.	100.00%	100.00%	Brazil	RT&M
Termomacaé Ltda.	99.99%	99.99%	Brazil	Gas & Power
Companhia Petroquímica de Pernambuco S.A. - PetroquímicaSuape	100.00%	100.00%	Brazil	RT&M
Araucária Nitrogenados S.A.	100.00%	100.00%	Brazil	Gas & Power
Breitener Energética S.A.	93.66%	93.66%	Cayman Islands	Gas & Power
Braspetro Oil Services Company - Brasoil	100.00%	100.00%	Brazil	Corporate
Petrobras Comercializadora de Energia Ltda. - PBEN	99.91%	99.91%	Brazil	Gas & Power
Termobahia S.A.	98.85%	98.85%	Brazil	Gas & Power
Arembepe Energia S.A.	100.00%	100.00%	Brazil	Gas & Power
5283 Participações Ltda.	100.00%	100.00%	Brazil	International
Baixada Santista Energia S.A.	100.00%	100.00%	Brazil	Gas & Power
Energética Camaçari Muricy I Ltda.	100.00%	100.00%	Brazil	Gas & Power
Fundo de Investimento Imobiliário RB Logística - FII	99.00%	99.00%	Brazil	E&P
Termomacaé Comercializadora de Energia Ltda	100.00%	100.00%	Brazil	Gas & Power
Cordoba Financial Services GmbH	100.00%	100.00%	Austria	Corporate
Petrobras Negócios Eletrônicos S.A. - E-Petro	99.95%	99.95%	Brazil	Corporate
Downstream Participações Ltda.	99.99%	100.00%	Brazil	Corporate
Joint Operations	Total Capital	Voting Capital	Country of Incorporation	Activity
Fábrica Carioca de Catalizadores S.A. - FCC	50.00%	50.00%	Brazil	RT&M
Ibiritermo S.A.	50.00%	50.00%	Brazil	Gas & Power
Consolidated Structured entities	Total Capital	Voting Capital	Country of Incorporation	Activity
Charter Development LLC – CDC	0.00%	0.00%	U.S.A	E&P
Companhia de Desenvolvimento e Modernização de Plantas Industriais – CDMPI	0.00%	0.00%	Brazil	RT&M
PDET Offshore S.A.	0.00%	0.00%	Brazil	E&P
Fundo de Investimento em Direitos Creditórios Não-padronizados do Sistema Petrobras	0.00%	0.00%	Brazil	Corporate
Fundo de Investimento em Direitos Creditórios Padronizados do Sistema Petrobras	0.00%	0.00%	Brazil	Corporate

____________________________________________________________________________

(i) 5283 Participações Ltda holds an 11.88% interest in PIB BV and, therefore, PIB BV is a wholly-owned subsidiary.

EX-12.1

Exhibit 12.1

CERTIFICATION PURSUANT TO RULES 13a-14(a) AND 15d-14(a) AS ADOPTED

UNDER SECTION 302 OF THE SARBANES-OXLEY ACT

I, Aldemir Bendine, certify that:

1.      I have reviewed this annual report on Form 20-F of Petróleo Brasileiro S.A. – PETROBRAS (the “Company”);

2.      Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.      Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

4.      The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:

(a)      Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)      Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)      Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)      Disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting; and

5.      The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions):

(a)      All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

(b)      Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.

	/s/ Aldemir Bendine
Date: May 15, 2015	Aldemir Bendine
	Chief Executive Officer

CERTIFICATION PURSUANT TO RULES 13a-14(a) AND 15d-14(a) AS ADOPTED

UNDER SECTION 302 OF THE SARBANES-OXLEY ACT

I, Ivan de Souza Monteiro, certify that:

1.      I have reviewed this annual report on Form 20-F of Petróleo Brasileiro S.A. – PETROBRAS (the “Company”);

2.      Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.      Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

4.      The Company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:

(a)      Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)      Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)      Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)      Disclosed in this report any change in the Company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting; and

5.      The Company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions):

(a)      All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

(b)      Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.

	/s/ Ivan de Souza Monteiro
Date: May 15, 2015	Ivan de Souza Monteiro
	Chief Financial Officer and Chief Investor Relations Officer

EX-13.1

Exhibit 13.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT

Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), the undersigned officer of Petróleo Brasileiro S.A. - PETROBRAS (the “Company”), does hereby certify, to such officer’s knowledge, that:

The Annual Report on Form 20-F for the year ended December 31, 2014 of the Company fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Form 20-F fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Aldemir Bendine
Date: May 15, 2015	Aldemir Bendine
	Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT

Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), the undersigned officer of Petróleo Brasileiro S.A. - PETROBRAS (the “Company”), does hereby certify, to such officer’s knowledge, that:

The Annual Report on Form 20-F for the year ended December 31, 2014 of the Company fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Form 20-F fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Ivan de Souza Monteiro
Date: May 15, 2015	Ivan de Souza Monteiro
	Chief Financial Officer and Chief Investor Relations Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-15.1

 

Exhibit 15.1

Consent of Independent Registered Public Accounting Firm 

We hereby consent to the incorporation by reference in the Registration Statement on Form F-3 (No. 333-183618) of Petróleo Brasileiro S.A. - Petrobras of our report dated May 15, 2015 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Annual Report on Form 20-F.

/s/ PricewaterhouseCoopers Auditores Independentes

PricewaterhouseCoopers Auditores Independentes

Rio de Janeiro - Brazil

May 15, 2015

EX-15.2

 

Exhibit 15.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

April 29, 2015

Petróleo Brasileiro S.A.
Av. República do Chile 330

9th Floor – Centro

CEP 20031-170
Rio de Janeiro – RJ-Brazil

Ladies and Gentlemen:

We hereby consent to the references to DeGolyer and MacNaughton as set forth under the headings “Presentation of Information Concerning Reserves,” “Item 4. Information on the Company–Additional Reserves and Production Information–Internal Controls over Proved Reserves,” and “Item 19–Exhibits” in the Annual Report on Form 20‑F of Petróleo Brasileiro S.A.—Petrobras (Petrobras) for the year ended December 31, 2014 (the Annual Report). We further consent to the inclusion of our three third-party letter reports dated April 29, 2015 (our Reports), as Exhibit 99.1 in the Annual Report. The first third-party letter report dated April 29, 2015, contains our opinions regarding a comparison of estimates prepared by us with those furnished to us by Petrobras of the net proved crude oil, condensate, natural gas, and oil-equivalent reserves as of December 31, 2014, of certain properties owned by Petrobras in Brazil and offshore from Brazil. The second third-party letter report dated April 29, 2015, contains our independent estimates of the net proved crude oil, natural gas liquids, natural gas, and oil-equivalent reserves as of December 31, 2014, of certain properties owned by Petrobras in Argentina. The third third-party letter report dated April 29, 2015, contains our opinions regarding a comparison of estimates prepared by us with those furnished to us by Petrobras of the net proved crude oil, condensate, natural gas, and oil-equivalent reserves as of December 31, 2014, of certain properties owned by Petrobras in the United States Gulf of Mexico.

 

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We further consent to the references to our firm as set forth in the Registration Statement on Form F-3, Registration Nos. 333-183618, 333-183618-01, and 333-183618-02 of Petróleo Brasileiro S.A.—Petrobras, Petrobras Global Finance B.V., and Petrobras International Finance Company, under the heading “Experts,” and to the incorporation by reference to the other references to our firm contained in the Annual Report of Petrobras on Form 20-F for the year ended December 31, 2014, under the headings “Presentation of Information Concerning Reserves,” “Item 4. Information on the Company–Additional Reserves and Production Information–Internal Controls over Proved Reserves,” and “Item 19–Exhibits,” and to the inclusion of our Reports as Exhibit 99.1 in the Annual Report.

Very truly yours,

/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716

EX-99.1

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

April 29, 2015

Petróleo Brasileiro S.A.

Av. República do Chile 330

9th Floor – Centro

CEP 20031-170

Rio de Janeiro – RJ-Brazil

Ladies and Gentlemen:

Pursuant to your request, we have conducted a reserves audit of the net proved crude oil, condensate, and natural gas reserves, as of December 31, 2014, of certain properties in which Petróleo Brasileiro S.A. (Petrobras) has represented that it owns an interest. The properties are located in Brazil and offshore from Brazil. This audit was completed on April 29, 2015. Petrobras has represented that these properties account for 96.5 percent on a net equivalent barrel basis of Petrobras’ net proved reserves as of December 31, 2014, and that the net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a)   (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided to us by Petrobras that it represents to be Petrobras’ estimates of the net reserves, as of December 31, 2014, for the same properties as those which we audited. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Petrobras.

Reserves estimates included herein are expressed as net reserves as represented by Petrobras. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2014. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Petrobras after deducting all interests owned by others.

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Estimates of oil, condensate, and natural gas reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Petrobras personnel, from Petrobras files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Petrobras with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

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Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. In such cases, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production‑decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Natural gas quantities estimated herein are marketable gas. Marketable gas is defined as the total gas to be produced from the reservoirs after reduction for injection, flare, and shrinkage resulting from field separation and processing. Gas reserves are expressed at a temperature base of 20 degrees Celsius and at a pressure base of 1 atmosphere. Condensate reserves estimated herein are those to be recovered by conventional lease separation. Oil and condensate reserves estimates included in this report are expressed in terms of 42 United States gallons per barrel.

Definition of Reserves

Petroleum reserves estimated by Petrobras included in this report are classified as proved. Only proved reserves have been audited for this report. Reserves classifications used by Petrobras in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

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Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

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(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence

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using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be 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.

(iii) Under no circumstances shall estimates for undeveloped reserves be 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, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs. Prices and costs were provided in United States dollars (U.S.$):

Oil and Condensate Prices

Petrobras has represented that the oil and condensate prices were based on a reference price, 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, unless prices are defined by contractual arrangements. Petrobras supplied differentials by field to a Brent reference price of U.S.$100.93 per barrel and the prices were held constant thereafter. The volume-weighted average adjusted price attributable to estimated proved reserves for the fields that were audited was U.S.$93.62 per barrel. These prices were not escalated for inflation.

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Natural Gas Prices

Petrobras has represented that the natural gas prices were based on a 12-month average price, 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, unless prices are defined by contractual arrangements. The volume-weighted average adjusted price for the fields that were audited was U.S.$8.63 per thousand cubic feet (Mcf). This price was based on contract prices and a 12‑month average regulation price from the Brazilian National Petroleum Agency (ANP) of U.S.$9.68 per Mcf. The ANP regulation prices were provided by Petrobras and are the prices disclosed by the ANP to upstream operators for payment of royalties and taxes. These prices were not escalated for inflation.

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Petrobras, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2014, estimated oil and gas reserves.

Petrobras has represented that estimated net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves of the SEC. Petrobras represents that its estimates of the net proved reserves attributable to these properties, which represent 96.5 percent of Petrobras’ reserves on a net equivalent basis, are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe):

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	Estimated by Petrobras Net Proved Reserves as of December 31, 2014
	Oil and Condensate (MMbbl)	Natural Gas (Bcf)	Oil Equivalent (MMboe)
Reviewed by DeGolyer and MacNaughton
Brazil
Total Proved	10,497.4	9,908.0	12,262.0
Note: Gas is converted to oil equivalent using an energy equivalent factor of 5,615 cubic feet of gas per 1 barrel of oil equivalent.

In our opinion, the information relating to estimated proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

In comparing the detailed net proved reserves estimates prepared by us and by Petrobras, we have found differences, both positive and negative, resulting in an aggregate difference of 4.03 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by Petrobras on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by us.

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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Petrobras. Our fees were not contingent on the results of our audit. This letter report has been prepared at the request of Petrobras. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

	Submitted, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716
[SEAL]	/s/ Thomas C. Pence, P.E. Thomas C. Pence, P.E. Senior Vice President DeGolyer and MacNaughton

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Thomas C. Pence, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Petrobras dated April 29, 2015, and that I, as Senior Vice President, was responsible for the preparation of this letter report.

2.That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 32 years of experience in oil and gas reservoir studies and evaluations.

/s/ Thomas C. Pence, P.E.

Thomas C. Pence, P.E.

Senior Vice President

DeGolyer and MacNaughton

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

April 29, 2015

Petróleo Brasileiro S.A.

Av. República do Chile 330

9th Floor – Centro

CEP 20031-170

Rio de Janeiro – RJ-Brazil

Ladies and Gentlemen:

Pursuant to your request, we have conducted a reserves evaluation of the net proved crude oil, natural gas liquids (NGL), and natural gas reserves, as of December 31, 2014, of certain properties in Argentina in which Petróleo Brasileiro S.A. (Petrobras) has represented that it owns an interest. This evaluation was completed on April 29, 2015. Petrobras has represented that these properties account for 100 percent on a net equivalent barrel basis of Petrobras’ net proved reserves in fields operated by Petrobras in Argentina as of December 31, 2014. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Petrobras.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2014. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Petrobras after deducting all interests owned by others.

Estimates of oil, NGL, and natural gas reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject

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to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this evaluation were obtained from reviews with Petrobras personnel, from Petrobras files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Petrobras with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. In such

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cases, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production‑decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Natural gas volumes estimated herein are marketable gas at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.969 pounds per square inch absolute (psia). Marketable gas is defined as the total gas to be produced from the reservoirs after reduction for injection, flare, and shrinkage resulting from field separation and processing, but before reduction for fuel usage.

NGL volumes estimated herein include condensate, C₅₊, and liquefied petroleum gas (LPG), which is composed of propane and butane fractions. LPG reserves are converted from barrels to metric tons at 11.65 barrels per metric ton. LPG and C₅₊ reserves are the result of low temperature plant processing. Condensate reserves estimated herein are those to be obtained by normal separator recovery.

Oil and NGL reserves estimated in this report are expressed in terms of 42 United States gallons per barrel. Oil reserves estimated herein are those to be recovered by normal field separation.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs

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consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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(i) Reserves on undrilled acreage shall be 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.

(ii) Undrilled locations can be 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.

(iii) Under no circumstances shall estimates for undeveloped reserves be 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, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs. Prices and costs were provided in United States dollars (U.S.$):

Oil, Condensate, and LPG Prices

Petrobras has represented that the oil, condensate, and LPG prices were based on two reference 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. Petrobras provided 12-month average prices by property, based on differentials to the Medanito and Maria Ines reference prices of U.S.$80.40 and U.S.$76.50 per barrel, respectively. The volume-weighted average adjusted price attributable to estimated proved reserves was U.S. $78.12 per barrel for crude oil, condensate

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and C₅₊ and U.S.$25.45 per barrel for LPG (U.S.$296.4 per metric ton). These prices were not escalated for inflation.

Natural Gas Prices

Petrobras has represented that the natural gas prices are defined by contractual arrangements. The volume-weighted average adjusted product price attributable to estimated proved gas reserves was U.S.$3.61 per thousand cubic feet. These prices were not escalated for inflation.

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Petrobras, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2014, estimated proved oil and gas reserves.

Our estimates of Petrobras’ net proved reserves attributable to the reviewed properties are based on the definition of proved reserves of the SEC and are as follows, expressed in millions of barrels (MMbbl), millions of cubic feet (MMcf), and millions of barrels of oil equivalent (MMboe):

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	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2014
	Oil and NGL (MMbbl)	Natural Gas (MMcf)	Oil Equivalent (MMboe)
Argentina
Total Proved	52.262	693,830	167.900
Notes: 1. Gas is converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. 2. Of the 52.262 MMbbl net proved oil and NGL reserves, 2.881 MMbbl is LPG. 3. Net reserves include the 77-percent consolidated interest owned by Petrobras Argentina S.A. and Petrolera Entre Lomas S.A. in the Entre Lomas, Bajada del Palo, and Aqua Amarga fields. This consolidated interest includes a 30.08-percent minority interest not owned by the company. Of the 167.900 MMboe net proved reserves, 15.318 MMboe is owned by minority interests.

In our opinion, the information relating to estimated proved reserves of oil, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-6 through 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Petrobras. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Petrobras. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

	Submitted, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716
[SEAL]	/s/ Thomas C. Pence, P.E. Thomas C. Pence, P.E. Senior Vice President DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Thomas C. Pence, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Petrobras dated April 29, 2015, and that I, as Senior Vice President, was responsible for the preparation of this letter report.

2.That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 32 years of experience in oil and gas reservoir studies and evaluations.

/s/ Thomas C. Pence, P.E.

Thomas C. Pence, P.E.

Senior Vice President

DeGolyer and MacNaughton

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

April 29, 2015

Petróleo Brasileiro S.A.

Av. República do Chile 330

9th Floor – Centro

CEP 20031-170

Rio de Janeiro – RJ-Brazil

Ladies and Gentlemen:

Pursuant to your request, we have conducted a reserves audit of the net proved crude oil, condensate, and natural gas reserves, as of December 31, 2014, of certain properties in which Petróleo Brasileiro S.A. (Petrobras) has represented that it owns an interest. The properties are located in the United States Gulf of Mexico. This audit was completed on April 29, 2015. Petrobras has represented that these properties account for 100 percent on a net equivalent barrel basis of Petrobras’ net proved reserves in fields operated by Petrobras in the United States Gulf of Mexico as of December 31, 2014, and that the net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided to us by Petrobras that it represents to be Petrobras’ estimates of the net reserves, as of December 31, 2014, for the same properties as those which we audited. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by Petrobras.

Reserves estimates included herein are expressed as working-interest and net reserves as represented by Petrobras. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2014. Working-interest reserves are defined as that portion of gross reserves attributable to the interests of Petrobras after deducting all interests owned by others. Net reserves are defined as working-interest reserves after deductions for royalties.

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Estimates of oil, condensate, and natural gas reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Petrobras personnel, from Petrobras files, from records on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by IHS Global Inc.; Copyright 2014 IHS Global Inc. In the preparation of this report we have relied, without independent verification, upon such information furnished by Petrobras with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

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Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. In such cases, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production‑decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Natural gas quantities estimated herein are marketable gas. Marketable gas is defined as the total gas to be produced from the reservoirs after reduction for injection flare and shrinkage resulting from field separation and processing. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base of the state in which the interest is located. Condensate reserves estimated herein are those to be recovered by conventional lease separation. Oil and condensate reserves estimates included in this report are expressed in terms of 42 United States gallons per barrel.

Definition of Reserves

Petroleum reserves estimated by Petrobras included in this report are classified as proved. Only proved reserves have been audited for this report. Reserves classifications used by Petrobras in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual

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arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not

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limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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(i) Reserves on undrilled acreage shall be 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.

(ii) Undrilled locations can be 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.

(iii) Under no circumstances shall estimates for undeveloped reserves be 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, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs. Prices and costs were provided in United States dollars (U.S.$):

Oil and Condensate Prices

Petrobras has represented that the oil and condensate prices were based on a reference price, 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, unless prices are defined by contractual arrangements. Petrobras provided differentials by field to a 12‑month average West Texas Intermediate reference price of U.S.$94.42 per barrel for the Cottonwood field and a Maya reference price of $87.39 per barrel for the Cascade and Chinook fields and the prices were held constant thereafter.

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The volume-weighted average adjusted product price attributable to estimated proved reserves audited herein was U.S.$90.88 per barrel. These prices were not escalated for inflation.

Natural Gas Prices

Petrobras has represented that the natural gas prices were based on a reference price, 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, unless prices are defined by contractual arrangements. The gas prices were calculated for each property using differentials to the Henry Hub reference price of U.S.$4.48 million British thermal units (MMBtu). The volume‑weighted average adjusted product price attributable to estimated proved reserves was U.S.$5.29 per thousand cubic feet. These prices were not escalated for inflation.

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Petrobras, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2014, estimated oil and gas reserves.

Petrobras has represented that its estimated working-interest and net proved reserves attributable to the reviewed properties are based on the definition of proved reserves of the SEC. Petrobras has represented that its estimates of the working‑interest and net proved reserves attributable to these properties, which represent 100 percent of Petrobras’ United States Gulf of Mexico operated reserves

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on a net equivalent basis, are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by Petrobras Proved Reserves as of December 31, 2014
	Oil and Condensate (Mbbl)	Natural Gas (MMcf)	Oil Equivalent (Mboe)
Reviewed by DeGolyer and MacNaughton
United States Gulf of Mexico
Working-Interest Reserves (before royalties)
Total Proved	74,344	36,855	80,487
Net Reserves (working-interest reserves after royalties)
Total Proved	70,120	32,755	75,579
Note: Gas is converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

In our opinion, the information relating to estimated proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

In comparing the detailed net proved reserves estimates prepared by us and by Petrobras, we have found differences, both positive and negative, resulting in an aggregate difference of 4.4 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by Petrobras on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by us.

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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Petrobras. Our fees were not contingent on the results of our audit. This letter report has been prepared at the request of Petrobras. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

	Submitted, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716
[SEAL]	/s/ Thomas C. Pence, P.E. Thomas C. Pence, P.E. Senior Vice President DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Thomas C. Pence, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1.That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Petrobras dated April 29, 2015, and that I, as Senior Vice President, was responsible for the preparation of this letter report.

2.That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 32 years of experience in oil and gas reservoir studies and evaluations.

[SEAL] /s/ Thomas C. Pence, P.E. Thomas C. Pence, P.E. Senior Vice President DeGolyer and MacNaughton