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

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

for the fiscal year ended December 31, 2013

Commission File Number 001-15106

Petróleo Brasileiro S.A.—Petrobras

(Exact name of registrant as specified in its charter)

Brazilian Petroleum Corporation—Petrobras

(Translation of registrant’s name into English)

The Federative Republic of Brazil

(Jurisdiction of incorporation or organization)

Avenida República do Chile, 65

20031-912 – Rio de Janeiro – RJ –Brazil 

(Address of principal executive offices)

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

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

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class:	Name of each exchange on which registered:
Petrobras Common Shares, without par value*	New York Stock Exchange*
Petrobras American Depositary Shares, or ADSs (evidenced by American Depositary Receipts, or ADRs), each representing two Common Shares	New York Stock Exchange
Petrobras Preferred Shares, without par value*	New York Stock Exchange*
Petrobras American Depositary Shares (as evidenced by American Depositary Receipts), each representing two Preferred Shares	New York Stock Exchange
2.875% Global Notes due 2015, issued by PifCo	New York Stock Exchange
6.125% Global Notes due 2016, issued by PifCo	New York Stock Exchange
3.875% Global Notes due 2016, issued by PifCo	New York Stock Exchange
3.500% Global Notes due 2017, issued by PifCo	New York Stock Exchange
5.875% Global Notes due 2018, issued by PifCo	New York Stock Exchange
7.875% Global Notes due 2019, issued by PifCo	New York Stock Exchange
5.75% Global Notes due 2020, issued by PifCo	New York Stock Exchange
5.375% Global Notes due 2021, issued by PifCo	New York Stock Exchange
6.875% Global Notes due 2040, issued by PifCo	New York Stock Exchange
6.750% Global Notes due 2041, issued by PifCo	New York Stock Exchange
2.000% Global Notes due 2016, issued by PGF	New York Stock Exchange
3.000% Global Notes due 2019, issued by PGF	New York Stock Exchange
4.375% Global Notes due 2023, issued by PGF	New York Stock Exchange
5.625% Global Notes due 2043, issued by PGF	New York Stock Exchange
Floating Rate Global Notes due 2016, issued by PGF	New York Stock Exchange
Floating Rate Global Notes due 2019, issued by PGF	New York Stock Exchange
3.250% Global Notes due 2017, issued by PGF	New York Stock Exchange
4.875% Global Notes due 2020, issued by PGF	New York Stock Exchange
6.250% Global Notes due 2024, issued by PGF	New York Stock Exchange
7.250% Global Notes due 2044, issued by PGF	New York Stock Exchange
Floating Rate Global Notes due 2017, issued by PGF	New York Stock Exchange
Floating Rate Global Notes due 2020, issued by PGF	New York Stock Exchange

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

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

The number of outstanding shares of each class of stock as of December 31, 2013 was:

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

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

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

Yes R  No £ 

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

Yes £  No R 

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

Yes R  No £ 

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

Yes R  No £ 

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

Large accelerated filer  R   Accelerated filer £         Non-accelerated filer £ 

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

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

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 £  Item 18 £ 

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

Yes £  No R 

 

TABLE OF CONTENTS

Page

Forward-Looking Statements		3
Glossary of Petroleum Industry Terms		5
Conversion Table		7
Abbreviations		8
Presentation of Financial and Other Information		9
Presentation of Information Concerning Reserves		10
PART I		10
Item 1.	Identity of Directors, Senior Management and Advisers	10
Item 2.	Offer Statistics and Expected Timetable	10
Item 3.	Key Information	11
Selected Financial Data		11
Risk Factors		13
Item 4.	Information on the Company	22
History and Development		22
Overview of the Group		22
Exploration and Production		24
Refining, Transportation and Marketing		36
Distribution		42
Gas and Power		43
International		50
Biofuels		55
Corporate		56
Organizational Structure		56
Property, Plants and Equipment		58
Regulation of the Oil and Gas Industry in Brazil		58
Health, Safety and Environmental Initiatives		62
Insurance		64
Additional Reserves and Production Information		65
Item 4A.	Unresolved Staff Comments	74
Item 5.	Operating and Financial Review and Prospects	74
Management’s Discussion and Analysis of Financial Condition and Results of Operations		74
Overview		75
Sales Volumes and Prices		76
Effect of Taxes on Our Income		77
Inflation and Exchange Rate Variation		78
Results of Operations		79
Additional Business Segment Information		87
Liquidity and Capital Resources		88
Contractual Obligations		92
Critical Accounting Policies and Estimates		93
Research and Development		95
Trends		97
Item 6.	Directors, Senior Management and Employees	98
Directors and Senior Management		98
Compensation		105
Share Ownership		105
Fiscal Council		106
Audit Committee		106
Other Advisory Committees		107
Ombudsman		107
Employees and Labor Relations		108
Item 7.	Major Shareholders and Related Party Transactions	110
Major Shareholders		110

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TABLE OF CONTENTS (cont.)

Page

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

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FORWARD-LOOKING STATEMENTS

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

·our marketing and expansion strategy;

·our exploration and production activities, including drilling;

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

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

·our liquidity and sources of funding;

·our development of additional revenue sources; and

·the impact, including cost, of acquisitions.

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

·our ability to obtain financing;

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

·global economic conditions;

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

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

·competition; 

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

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

·receipt of governmental approvals and licenses;

·international and Brazilian political, economic and social developments;

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

·the cost and availability of adequate insurance coverage.

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.
Barrels	Standard measure of crude oil volume.
BNDES	The Banco Nacional de Desenvolvimento Econômico e Social (the Brazilian Development Bank)
BSR	Buoyancy supported riser.
Condensate	Light hydrocarbon substances produced with natural gas, which condense into liquid at normal temperature and pressure.
CNPE	The Conselho Nacional de Política Energética (National Energy Policy Council), or CNPE, is an advisory body of the President of the Republic assisting in the formulation of energy policies and guidelines.
CVM	The Comissão de Valores Mobiliários (Securities and Exchange Commission) of Brazil, or CVM.
Deep water	Between 300 and 1,500 meters (984 and 4,921 feet) deep.
Distillation	A process by which liquids are separated or refined by vaporization followed by condensation.
EWT	Extended well test.
Exploration area	A region in Brazil under a regulatory contract without a known hydrocarbon accumulation or with a hydrocarbon accumulation that has not yet been declared commercial.
FPSO	Floating Production, Storage and Offloading Unit.
Heavy (crude) oil	Crude oil with API density less than or equal to 22°.
Intermediate (crude) oil	Crude oil with API density higher than 22° and less than or equal to 31°.
Light (crude) oil	Crude oil with API density higher than 31°.
LNG	Liquefied natural gas.

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LPG	Liquefied petroleum gas, which is a mixture of saturated and unsaturated hydrocarbons, with up to five carbon atoms, used as domestic fuel.
MME	The Ministério de Minas e Energia (Ministry of Mines and Energy) of Brazil.
MPBM	The Ministério do Planejamento, Orçamento e Gestão (Ministry of Planning, Budget and Management) of Brazil.
NGLs	Natural gas liquids, which are light hydrocarbon substances produced with natural gas, which condense into liquid at normal temperature and pressure.
Oil	Crude oil, including NGLs and condensates.
PLSV	Pipe laying support vessel.
Post-salt reservoir	A geological formation containing oil or natural gas deposits located above a salt layer.
Pre-salt reservoir	A geological formation containing oil or natural gas deposits located beneath a salt layer.
Proved reserves	Consistent with the definitions in Rule 4-10(a) of Regulation S-X, proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to December 31, 2013, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced or we must be reasonably certain that we will commence the project within a reasonable time. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
Proved developed reserves	Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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Proved undeveloped reserves	Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Proved undeveloped reserves do not include reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
SS	Semi-submersible unit.
Synthetic oil and synthetic gas	A mixture of hydrocarbons derived by upgrading (i.e., chemically altering) natural bitumen from oil sands, kerogen from oil shales, or processing of other substances such as natural gas or coal. Synthetic oil may contain sulfur or other non-hydrocarbon compounds and has many similarities to crude oil.
TLWP	Tension Leg Wellhead Platform.
Total depth	Total depth of a well, including vertical distance through water and below the mudline.
Ultra-deep water	Over 1,500 meters (4,921 feet) deep.

CONVERSION TABLE

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

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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 have also used our wholly-owned subsidiary Petrobras International Finance Company S.A., or PifCo, as a vehicle to issue notes. We fully and unconditionally guarantee the notes issued by PGF and PifCo, and neither of them is required to file periodic reports with the U.S. Securities and Exchange Commission, or SEC.  See note 38 to our audited consolidated financial statements.

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

Our audited consolidated financial statements as of and for each of the three years ended December 31, 2013, 2012 and 2011 and the accompanying notes contained in this annual report have been presented in U.S. dollars and prepared in accordance with International Financial Reporting Standards, or IFRS, issued by the International Accounting Standards Board, or IASB.  See Item 5. “Operating and Financial Review and Prospects” and Note 2 to our audited consolidated financial statements.  Petrobras applies IFRS in its statutory financial statements prepared in accordance with Brazilian Corporate Law and regulations promulgated by the CVM. 

Our IFRS financial statements filed with the CVM are presented using reais, while the presentation currency of the audited consolidated financial statements included herein is the U.S. Dollar.  The functional currency of Petrobras and all of its Brazilian subsidiaries is the real.  The functional currency of Petrobras Argentina is the Argentine peso, and the functional currency of most of our other entities that operate internationally is the U.S. Dollar.  As described more fully in Note 2.2 to our audited consolidated financial statements, the U.S. dollar amounts for the periods presented have been translated from the real  amounts in accordance with the criteria set forth in IAS 21 – “The effects of changes in foreign exchange rates.”  Based on IAS 21, we have translated all assets and liabilities into U.S. dollars at the exchange rate as of the date of the balance sheet and all accounts in the statement of income and statement of cash flows at the average rates prevailing during the corresponding year.

Unless the context otherwise indicates:

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

·forward-looking amounts, including estimated future capital expenditures and investments, have all been based on our Petrobras 2030 Strategic Plan, approved on February 25, 2014, which covers the period from 2014 to 2030, and on our 2014-2018 Business and Management Plan (“2014-2018 Plan”), and have been projected on a constant basis and have been translated from reais  at an estimated average exchange rate of R$2.23 to U.S.$1.00 in 2014, and the real  strengthening against the U.S. dollar to R$1.92 in the long term, in accordance with our 2014-2018 Plan.  In addition, in accordance with our 2014-2018 Plan, future calculations involving an assumed price of crude oil have been calculated using a Brent crude oil price of U.S.$105.00 per barrel for 2014, declining to U.S.$ 100.00 per barrel in 2017, and to U.S.$95.00 per barrel in the long term, adjusted for our quality and location differences, unless otherwise stated; and

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

PRESENTATION OF INFORMATION CONCERNING RESERVES

Petrobras applies the SEC rules for estimating and disclosing oil and gas reserve quantities included in this annual report.  In accordance with those rules, first adopted by Petrobras at the end of 2009, reserve volumes have been estimated using the average prices calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period and include non-traditional reserves, such as synthetic oil and gas.  In addition, the amended rules also adopted a reliable technology definition that permits reserves to be added based on field-tested technologies. 

DeGolyer and MacNaughton (D&M) used our reserves estimates to conduct a reserves audit of 96% of our net proved crude oil, condensate and natural gas reserves as of December 31, 2013 in certain properties we own in Brazil.  In addition, D&M used its own estimates of our reserves to conduct a reserves evaluation of 100% of the net proved crude oil, condensate, NGL and natural gas reserves as of December 31, 2013 from the properties we operate in Argentina. Furthermore, D&M used our reserves estimates to conduct a reserves evaluation of 100% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2013 in certain properties we operate in the United States. The reserves estimates were prepared in accordance with the reserves definitions in Rule 4-10(a) of Regulation S-X.  All reserves estimates involve some degree of uncertainty. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Operations” for a description of the risks relating to our reserves and our reserve estimates.

On January 15, 2014, we filed reserve estimates for Brazil with the ANP, in accordance with Brazilian rules and regulations, totaling net volumes of 13.5 bnbbl of crude oil and condensate and 14.8 trillion cubic feet of natural gas.  The reserve estimates filed with the ANP were approximately 27.4% higher than those provided herein in terms of oil equivalent. This difference is due to: (i) the ANP requirement to estimate proved reserves through the technical-economical abandonment of production wells, as opposed to limiting reserve estimates to the life of the concession contracts as required by Rule 4-10 of Regulation S-X; and (ii) different technical criteria for booking proved reserves, including the use of  future oil prices projected by Petrobras as opposed to the SEC requirement that the 12-month average price be used to determine the economic producibility of the reserves.

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

PART I

Item 1.    Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2.    Offer Statistics and Expected Timetable

Not applicable.

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Item 3.    Key Information

Selected Financial Data

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

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

BALANCE SHEET DATA

IFRS Summary Financial Data

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

(1)                  Excludes long-term debt.

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

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

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INCOME STATEMENT DATA

IFRS Summary Financial Data

	For the Year Ended December 31,
	2013	2012	2011	2010	2009
	(U.S.$ million, except for share and per share data)
Sales revenues	141,462	144,103	145,915	120,452	91,146
Net income before financial results, profit sharing and income taxes	16,214	16,900	27,285	26,372	22,923
Net income attributable to the shareholders of Petrobras	11,094	11,034	20,121	20,055	15,308
Weighted average number of shares outstanding:
Common	7,442,454,142	7,442,454,142	7,442,454,142	5,683,061,430	5,073,347,344
Preferred	5,602,042,788	5,602,042,788	5,602,042,788	4,189,764,635	3,700,729,396
Net income before financial results, profit sharing and income taxes per:
Common and Preferred shares	1.24	1.30	2.09	2.67	2.61
Common and Preferred ADS	2.48	2.60	4.18	5.34	5.22
Basic and diluted earnings per:
Common and Preferred shares	0.85	0.85	1.54	2.03	1.74
Common and Preferred ADS	1.70	1.70	3.08	4.06	3.48
Cash dividends per(1):
Common shares	0.22	0.24	0.53	0.70	0.59
Preferred shares	0.41	0.48	0.53	0.70	0.59
Common ADS	0.44	0.48	1.06	1.40	1.18
Preferred ADS	0.82	0.96	1.06	1.40	1.18

(1)                  Pre-tax.

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RISK FACTORS

Risks Relating to Our Operations

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

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

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

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

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

The majority of our revenue is derived primarily from sales in Brazil of crude oil and oil products and, to a lesser extent, natural gas.  Changes in crude oil prices typically result in changes in prices for oil products and natural gas.  Historically, international prices for crude oil, oil products and natural gas have fluctuated widely as a result of many global and regional factors.   Volatility and uncertainty in international prices for crude oil, oil products and natural gas may continue. Substantial or extended declines in international crude oil prices may have a material adverse effect on our business, results of operations and financial condition, and the value of our proved reserves.

Our pricing policy in Brazil seeks to align the price of oil and oil products with international prices over the long term, however we do not necessarily adjust our prices for diesel, gasoline and other products to reflect oil price volatility in the international markets or short term movements in the value of the real.  Based on the decisions of the Brazilian federal government, as our controlling shareholder, we have, and may continue to have, periods during which our product prices will not be at parity with international product prices (See “—Risks Relating to Our Relationship with the Brazilian Federal Government—The Brazilian federal government, as our controlling shareholder, may pursue certain macroeconomic and social objectives through us that may have a material adverse effect on us.”).

As a result, when we are a net importer by volume of oil and oil products to meet the Brazilian demand, increases in the price of crude oil in the international markets may have a negative impact on our costs of sales and margins, since the cost to acquire such oil and oil products may exceed the price at which we are able to sell these products in Brazil.  A similar effect occurs when the real  depreciates in relation to the U.S. dollar, as we sell oil and oil products in Brazil in reais  and international prices for crude oil and oil products are set in U.S. dollars. A depreciation of the real  increases our cost of imported oil and oil products, without a corresponding increase in our revenues unless we are able to increase the price at which we sell products in Brazil.

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

Our ability to maintain our long-term growth objectives for oil production, including those defined in our 2014-2018 Plan and our 2030 Strategic Plan, is highly dependent upon our ability to successfully develop our existing reserves and, in the long term, upon our ability to obtain additional reserves.  The development of the sizable reservoirs in deep and ultra-deep waters, including the pre-salt reservoirs that have been assigned to us by the Brazilian federal government, has demanded and will continue to demand significant capital investments.  A primary operational challenge, particularly for the pre-salt reservoirs, will be (i) securing the critical resources that are necessary to meet our production targets, (ii) allocating our resources to build the necessary equipment and deploy such equipment at considerable distances from the shore and (iii) securing a qualified labor force and offshore oil services to develop reservoirs of such size and magnitude in a timely manner.  We cannot guarantee that we will have or will be able to obtain, in the time frame that we expect, sufficient resources necessary to exploit the reservoirs in deep and ultra-deep waters that have been licensed and assigned to us, or that may be licensed to us in the future, including as a result of the enactment of the new regulatory model for the oil and gas industry in Brazil.

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

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

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

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

In order to implement our 2014-2018 Plan, including the development of our oil and natural gas exploration activities in the pre- and post-salt layers and the development of refining capacity sufficient to process increasing production volumes, we will need to raise significant amounts of debt capital in the financial and capital markets, as well as to adjust our product pricing to international levels.  We may not be able to obtain the necessary financing or to adjust our prices in order to implement our 2014-2018 Plan.

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

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

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

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

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

The transfer of oil and gas exploration and production rights to us related to specific pre-salt areas is governed by the Assignment Agreement, which is a contract between the Brazilian federal government, our controlling shareholder, and us. The negotiation of the Assignment Agreement involved significant issues, including (1) the area covered by the assignment of rights, consisting of exploratory blocks; (2) the volume, on a barrel of oil equivalent basis, that we can extract from this area; (3) the price to be paid for the assignment of rights; (4) the terms of any subsequent revision of the contract price and volume; and (5) the terms of the reallocation of volumes among the exploratory blocks assigned to us.

The Assignment Agreement includes provisions for a subsequent revision of the contract terms, including the price we paid for the rights we acquired. The future negotiation with the Brazilian federal government will be conducted in accordance with the terms of the Assignment Agreement and will be based on a number of factors, including assumptions regarding the timing of our oil and gas production, operating and investment costs, and the value of the crude oil at prevailing international prices at the time of the declaration of commerciality of the relevant pre-salt area.  At the time the Assignment Agreement was negotiated, the initial contract price paid by us was based on an assumed Brent oil crude price of approximately U.S.$80 per barrel. Once the revision process is concluded pursuant to the terms of the Assignment Agreement, if the revised contract price is higher than the initial contract price, we will either make an additional payment to the Brazilian federal government or reduce the amount of barrels of oil equivalent subject to the Assignment Agreement. 

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

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

Our activities are subject to a wide variety of federal, state and local laws, regulations and permit requirements relating to the protection of human health, safety and the environment, both in Brazil and in other jurisdictions in which we operate, as well as to evolving industry standards and best practices.  Particularly in Brazil, our oil and gas business is subject to extensive regulation by several governmental agencies, including the ANP, ANEEL, Agência Nacional de Transportes Aquaviários (Brazilian Water Transportation Agency), or ANTAQ and Agência Nacional de Transportes Terrestres (Brazilian Land Transportation Agency), or ANTT. Failure to observe or comply with these laws and regulations could result in penalties that could adversely affect our operations.  In Brazil, for example, we could be exposed to administrative and criminal sanctions, including warnings, fines and closure orders for non-compliance with these environmental, health and safety regulations, which, among other things, limit or prohibit emissions or spills of toxic substances produced in connection with our operations.  Waste disposal and emissions regulations may also require us to clean up or retrofit our facilities at substantial cost and could result in substantial liabilities.  The Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis (Brazilian Institute of the Environment and Renewable Natural Resources, or IBAMA) and the ANP routinely inspect our facilities, and may impose fines, restrictions on operations, or other sanctions in connection with its inspections, including unexpected, temporary shutdowns and delays resulting in decreased production.  In addition, we are subject to environmental laws that require us to incur significant costs to cover damage that a project may cause to the environment.  These additional costs may have a negative impact on the profitability of the projects we intend to implement or may make such projects economically unfeasible.

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

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

We are currently a party to numerous legal proceedings relating to civil, administrative, environmental, labor and tax claims filed against us.  These claims involve substantial amounts of money and other remedies. Several individual disputes account for a significant part of the total amount of claims against us.  See Item 8. “Financial Information—Legal Proceedings” and Note 31 to our audited consolidated financial statements included in this annual report for a description of the legal proceedings to which we are subject.  In the event that claims involving a material amount and for which we have no provisions were to be decided against us, or in the event that the losses estimated turn out to be significantly higher than the provisions made, the aggregate cost of unfavorable decisions could have a material adverse effect on our financial condition and results of operations.  We may also be subject to litigation and administrative proceedings in connection with our concessions and other government authorizations, which could result in the revocation of such concessions and government authorizations.  In addition, our management may be required to direct its time and attention to defending these claims, which could prevent them from focusing on our core business.  Depending on the outcome, certain litigation could result in restrictions on our operations and have a material adverse effect on certain of our businesses.

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

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

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

  As of December 31, 2013, 52% of our total indebtedness consisted of floating rate debt. Additionally, we  have debt maturities that amount to U.S.$52.7 billion during the next five years, a portion of which may be refinanced by issuing new debt.  To the extent that such floating rates rise, or the cost of debt increases when we refinance maturing obligations, we may incur additional expenses. As we refinance our existing debt in the coming years, the mix of our indebtedness may change, specifically as it relates to the ratio of fixed to floating interest rates, the ratio of short-term to long-term debt, and the currencies in which our debt is denominated or to which it is indexed. Such changes may increase our financing expenses.

Furthermore, we decided not to enter into third-party derivative contracts or make other arrangements with third parties to hedge against the risk of an increase in interest rates.  Accordingly, if market interest rates rise, our financing expenses will increase, which could have an adverse effect on our results of operations and financial condition.

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

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

Risks Relating to Our Relationship with the Brazilian Federal Government

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

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

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

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

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

Risks Relating to Brazil

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

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

·exchange rate movements and volatility;

·inflation; 

·financing of government current account deficit;

·price instability;

·interest rates;

·liquidity of domestic capital and lending markets;

·tax policy;

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

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

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

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Risks Relating to Our Equity and Debt Securities

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

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

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

Some of PifCo’s notes are not listed on any securities exchange and are not quoted through an automated quotation system.  PGF’s notes are currently listed both on the New York Stock Exchange and the Luxembourg Stock Exchange and trade on the NYSE Euronext and Euro MTF market, respectively.  PGF can issue new notes that can be listed in markets other than the New York Stock Exchange and the Luxembourg Stock Exchange and traded in markets other than the NYSE Euronext and the Euro MTF market.  We can make no assurance as to the liquidity of or trading markets for PifCo’s notes or PGF’s notes.  We cannot guarantee that the holders of PifCo’s notes or PGF’s notes will be able to sell their notes in the future.  If a market for PifCo’s notes or PGF’s notes does not develop, holders of PifCo’s notes or PGF’s notes may not be able to resell the notes for an extended period of time, if at all.

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

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

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

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

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

Holders of our ADSs may face difficulties in protecting their interests.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Holders in some jurisdictions may not receive payment of gross-up amounts for withholding pursuant to the European Council Directive 2003/48/EC on the taxation of savings income.

Austria and Luxembourg have opted out of certain exchange of information provisions of the European Council Directive 2003/48/EC on the taxation of savings income (the Directive) and are instead, during a transitional period, applying a withholding tax on payments of interest, at a rate of up to 35%, made by a paying agent within those jurisdictions to, or collected by such a paying agent for, an individual beneficial owner resident in other member states of the European Union (EU Member States) or to certain limited types of entities established in other Member States unless the beneficial owner of the interest payments opts for exchange of information as required under the Directive. The Luxembourg government is currently in the process of electing Luxembourg out of the withholding system in favor of automatic exchange of information with effect from January 1, 2015.  Neither we nor the paying agent (nor any other person) would be required to pay additional amounts in respect of the notes as a result of the imposition of withholding tax by any EU Member State or another country or territory which has opted for a withholding system. For more information, see Item 10. “Additional Information—Taxation—Taxation Relating to PifCo’s and PGF’s Notes—European Union Savings Directive.”   An investor should consult a tax adviser to determine the tax consequences of holding PifCo’s or PGF’s notes for such investor.

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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, 2013, the Brazilian federal government owned 28.67% of our outstanding capital stock and 50.26% of our voting shares.  Our common and preferred shares have been traded on the BM&FBOVESPA since 1968 and on the NYSE since 2000.  

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

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

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

Overview of the Group

We are an integrated oil and gas company that is the largest corporation in Brazil and one of the largest companies in Latin America in terms of revenues.  As a result of our legacy as Brazil’s former sole supplier of crude oil and oil products and our deep and continuous commitment to find and develop oil fields in Brazil, our operations account for the majority of Brazil’s oil and gas production, and we hold a large base of proved reserves and a fully developed operational infrastructure.  In 2013, our average domestic daily oil production was 1,931.4mbbl/d, an estimated 90.9% of Brazil’s total oil production.  Over 67.1% (8,419.4 mmboe) of our domestic proved reserves are in large, contiguous and highly productive fields in the offshore Campos Basin, which allows us to optimize our infrastructure and limit our costs of exploration, development and production.  In 45 years of developing Brazil’s offshore basins, we have developed special expertise in deepwater exploration and production, which we exploit both in Brazil and in other offshore oil areas. 

As of December 31, 2013, we had proved developed oil and gas reserves of 7,605.8 mmboe and proved undeveloped reserves of 4,934.5 mmboe in Brazil. The exploration and development of this large reserve base and the new pre-salt areas granted to us by the Brazilian federal government under the Assignment Agreement has demanded, and will continue to demand, significant investments and the rapid growth of our operations.  To support this growth we have ordered the construction of 21 new FPSOs and planned 14 more for the period between 2014 and 2020, and are also making necessary investments in subsea equipment and infrastructure.  

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We operate substantially all of the refining capacity in Brazil.  Most of our refineries are located in southeastern Brazil, within the country’s most populated and industrialized markets and adjacent to the source of most of our crude oil in the Campos Basin.  Our domestic crude distillation capacity of 2,102 mbbl/d and domestic refining throughput of 2,074 mbbl/d are currently below the levels required to meet strong and increasing domestic demand for transportation fuels, particularly gasoline, diesel and jet fuel.  We are currently building two new refining facilities, but the resulting increase in our refining capacity may not fully address domestic demand.  Until there is sufficient refinery capacity to meet such demand, we will continue to import oil and oil products and our planning to build additional refineries.  We are also involved in the production of petrochemicals.  We distribute oil products through our own retail network and to wholesalers.

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

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

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

Our activities are organized into six business segments: 

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

·Refining, Transportation and Marketing: includes refining, logistics, transportation, trading operations, oil products and crude oil exports and imports and petrochemical investments in Brazil;

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

·Gas and Power: transportation and trading of natural gas and LNG, produced in or imported into Brazil, as well as generation and trading of electric power, and the fertilizer business;

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

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

Additionally, we have a Corporate segment that has activities that are not attributed to the other segments, notably those related to corporate financial management, corporate overhead and other expenses, including actuarial expenses related to the pension and medical benefits for retired employees and their dependents.

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

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

Exploration and Production

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

Oil and gas exploration and production activities in Brazil are the largest component of our portfolio.  We have gradually increased production over the past four decades, from 164 mbbl/d of crude oil, condensate and NGLs in Brazil in 1970 to 1,931.4 mbbl/d in 2013.  We aim to grow oil and gas reserves and production sustainably and be recognized for excellence in exploration and production operations.

The primary focus of our exploration and production segment is to:

·Continue to explore and develop the Campos Basin, leveraging the current infrastructure to drill in deeper horizons in existing concessions, including pre-salt reservoirs;

·Explore and develop Brazil’s most promising offshore basin, Santos (gas and light oil), with a particular focus on pre-salt development;

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

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

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

Brazil’s richest oil fields are located offshore, most of them in deep waters.  We have been active in these waters since 1971, when we started exploration in the Campos Basin, and we have become globally recognized as innovators in the technology required to explore and produce hydrocarbons in deep and ultra-deep water.  According to production data from PFC Energy, we operate more production (on a boe basis) from fields in deep and ultra-deep water than any other company.  We focus much of our exploration effort on deepwater drilling, where the discoveries are substantially larger and our technology and expertise create a competitive advantage.

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Historically, our offshore exploration and production activities were focused on post-salt reservoirs, primarily in the Campos Basin.  In recent years, we have made important discoveries in pre-salt reservoirs located in a region of approximately 149,000 km² (36.8 million acres) stretching from the Campos to the Santos Basins, also known as the pre-salt province. Our existing contracts in this area cover 22.2% (approximately 33,100 km² or 8.2 million acres) of the pre-salt areas, including the acreage assigned to us under the Concession Contracts and the Assignment Agreement.  We are also part of the consortium that was granted a concession covering approximately 1,547.8 km² or 0.4 million acres of the Libra field under the Production Sharing Agreement.

In the southern part of the pre-salt province, within the Santos Basin, where the salt layer is thick and the hydrocarbons have been more perfectly preserved, we have made several particularly promising discoveries since 2006, including those made in Blocks BM-S-11 (Lula, formerly Tupi), BM-S-9 (Lapa and Sapinhoá, formerly Carioca and Guará), in the Assignment Agreement area (Búzios and Sul de Lula, formerly Franco and Sul de Tupi) and in Libra, one of the most important discoveries made in the pre-salt area.  In the northern part of the province, within the Campos Basin, we made significant discoveries in 2008 and early 2010 in the area known as Parque das Baleias and in the Barracuda, Albacora, Marlim and Caratinga fields. We are committing substantial resources to develop these pre-salt discoveries, which are located in deep and ultra-deep waters and reservoirs at total depths of up to 7,000 meters (22,965 feet).

As of March 31, 2014, we had 147 exploration agreements (covering 96 exploratory blocks and 51 evaluation plans currently underway), corresponding to a gross exploratory acreage of 103,597 km² (25.6 million acres), or a net exploratory acreage of 54,210 km² (13.4 million acres).  We are exclusively responsible for conducting the exploration activities in 38 exploratory blocks and in 17 evaluation plans currently underway.  As of March 31, 2014, we had exploration partnerships with 24 foreign and domestic companies.  We conduct exploration activities under 62 of our 92 partnership agreements. We hold interests ranging from 20% to 100% in the exploration areas under concession or assigned to us.

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

Throughout our history, we have been successful in finding and developing significant oil reservoirs offshore, which has allowed us to achieve economies of scale by spreading the total costs of exploration, development and production over a large base. In 2013, offshore production accounted for 89% of our production and deep water production accounted for 77% of our production in Brazil.  In 2013, we started production from 34 wells.

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

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

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

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

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

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

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

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

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

_____________________

(1) Includes synthetic oil and gas.

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

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

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

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

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·Concession Agreements: ANP grants, from time to time through public auctions open to qualified operators, rights 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 ANP, including the 11th Round, held on May 14, 2013, in which we acquired 34 blocks located in the Foz do Amazonas, Espírito Santo and Barreirinhas 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 the Acre, Paraná, Recôncavo and Sergipe-Alagoas Basins. These concession agreements have in general a term of 27 years or more following the declaration of commerciality, with the possibility of extension by ANP.

·Assignment Agreement (Contrato de Cessão Onerosa):  On September 3, 2010 we entered into an agreement with the Brazilian federal government under which we were assigned exclusive rights to explore and produce oil, natural gas and other fluid hydrocarbons in specified pre-salt areas located in the Santos Basin. The agreement is subject to maximum production of five billion boe over 40 years (extendable for five additional years), of which we have already declared commerciality for 3.18 billion boe on two of the areas (Búzios and Sul de Lula).

·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 Campo de Libra – which has an estimated recoverable volume of between 8 and 12 billion boe) located in the ultra-deep waters of the Santos Basin. On December 2, 2013, we executed the first agreement under this regime. We have a 40% interest in the Libra field, and this agreement has a term of 35 years.

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The following map shows our concession areas in Brazil as of December 2013.

 

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

Main Oil and Gas Producing Fields in Brazil
Basin	Fields	Petrobras %	Type	Fluid(1)
Camamu	Manati	35%	Shallow	Natural Gas
Campos	Albacora	100%	Shallow	Intermediate Oil
		100%	Deepwater	Intermediate Oil
	Albacora Leste	90% 90%	Deepwater Ultra-deepwater	Intermediate Oil Intermediate Oil
	Baleia Azul	100%	Deepwater	Intermediate Oil
	Barracuda	100%	Deepwater	Intermediate Oil
	Cachalote	100%	Deepwater	Intermediate Oil
	Carapeba	100%	Shallow	Intermediate Oil
	Caratinga	100%	Deepwater	Intermediate Oil
	Cherne	100%	Shallow	Intermediate Oil
	Espadarte	100%	Deepwater	Intermediate Oil
	Jubarte	100%	Deepwater	Heavy Oil
	Marimbá	100%	Deepwater	Heavy Oil
	Marlim	100%	Deepwater	Heavy Oil
	Marlim Leste	100%	Deepwater	Intermediate Oil
	Marlim Sul	100% 100%	Deepwater Ultra-deepwater	Intermediate Oil Intermediate Oil
	Namorado	100%	Shallow	Intermediate Oil
	Pampo	100%	Shallow	Intermediate Oil
	Roncador	100%	Ultra-deepwater	Intermediate Oil
	Tartaruga Mestiça	100%	Shallow	Intermediate Oil
	Vermelho	100%	Shallow	Intermediate Oil
	Voador	100%	Deepwater	Heavy Oil
Espírito Santo	Fazenda Alegre Golfinho	100% 100% 100%	Onshore Deepwater Ultra-deepwater	Heavy Oil Intermediate Oil Intermediate Oil
Potiguar	Canto do Amaro	100%	Onshore	Intermediate Oil/Natural Gas Heavy Oil/Natural Gas
	Estreito	100%	Onshore	Heavy Oil
Recôncavo	Aracás Buracica	100% 100%	Onshore Onshore	Light Oil Light Oil
Santos	Baúna	100%	Shallow	Light Oil
	Mexilhão	100%	Shallow	Natural Gas
	Lula	65%	Ultra-deepwater	Intermediate Oil
	Sapinhoá	45%	Ultra-deepwater	Intermediate Oil
	Piracaba	100%	Shallow	Light Oil
	Uruguá	100%	Deepwater	Intermediate Oil/Natural Gas
Sergipe/Alagoas	Carmópolis	100%	Onshore	Intermediate Oil
	Piranema	100%	Deepwater	Intermediate Oil
Solimões	Leste do Urucu	100%	Onshore	Light Oil/Natural Gas
	Rio Urucu	100%	Onshore	Light Oil/Natural Gas

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

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

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Campos Basin

The Campos Basin, which covers approximately 115,000 km² (28.4 million acres), is the most prolific oil and gas basin in Brazil as measured by proved hydrocarbon reserves and annual production.  Since we began exploring this area in 1971, over 60 hydrocarbon accumulations have been discovered, including eight large oil fields in deep water and ultra-deep water.  The Campos Basin is our largest oil- and gas-producing region, producing an average 1,531.1 mbbl/d of oil and 553.8 mmcf/d (14.7 mmm³/d) of associated natural gas from 47 producing fields. During 2013, 75% of our total domestic production came from this basin. In 2013, the proved crude oil and natural gas reserves in the Campos Basin represented 71.7% and 41.3% of our total proved crude oil and natural gas reserves in Brazil, respectively. In 2013, we operated 42 floating production systems and 14 fixed platforms in water depths from 80 to 1,886 meters (262 to 6,188 feet), delivering oil with an average API gravity of 21.9° and maximum basic sediment and water (a measurement of the water and sediment content of flowing crude oil) of 1%.

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

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

Campos Basin Projects

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

Main Campos Basin Development Projects
Field	Unit Type	Production Unit	Crude Oil Nominal Capacity (bbl/d)	Natural Gas Nominal Capacity (mmcf/d)	Water Depth (meters)	Start Up (year)	Notes
Papa-Terra–Module 2	FPSO	P-63	140,000	35.3	1,170	2013	Post-salt
Roncador–Module 3	SS	P-55	180,000	211.9	1,790	2013	Post-salt
Roncador–Module 4	FPSO	P-62	180,000	211.9	1,550	2014	Post-Salt
Parque das Baleias (Baleia Azul, Jubarte, Cachalote, Baleia Anã & Baleia Franca)	FPSO	P-58	180,000	211.9	1,400	2014	Pre and post-salt
Papa-Terra–Module 1	TLWP	P-61	0	0	1,180	2014	Post-salt production processed by P-63

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

                The FPSO P-58 will develop production in the Parque das Baleias area, which encompasses the following fields: Baleia Franca (pre- and post-salt), Cachalote (post-salt), Jubarte (pre- and post-salt), Baleia Azul (pre-salt) and Baleia Anã (post-salt). This unit has an oil production capacity of 180,000 bbl/d and 211.9 mmcf/d (6 mmm³/d)  of natural gas. We own 100% of the oil produced from this unit.

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

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While most of our production in the Campos Basin is from post-salt reservoirs, pre-salt reservoirs in the basin are a growing source of production.  We first began pre-salt oil production in 2008 in the Jubarte field located in the Parque das Baleias region.  We subsequently began producing from the Baleia Franca field in the second half of 2010.  In September 2012, we started a pilot system exclusively dedicated to pre-salt evaluation and production in the Baleia Azul region using the FPSO Cidade de Anchieta, with a capacity to produce 100,000 bbl/d of oil and 123.6 mmcf/d (3.5 mmm³/d) of gas. During 2013, this unit produced an average of almost 90,000 bbl/d. By the end of 2013, the Campos Basin pre-salt area was producing 165.2 mbbl/d, which represents an increase of almost 100% compared to 2012.  Our share of oil from produced from Campos Basin pre-salt reservoirs is 100%.

Maintenance in mature fields

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

Exploration

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

Santos Basin

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

Concession Agreements

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

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

Following Lula, the second field in development in the Santos Basin pre-salt is Sapinhoá (formerly known as Guará) with a total estimated recoverable volume of 2.1 billion boe. Commercial production began in January 2013 through FPSO Cidade de Sao Paulo.  This pilot system has a production capacity of 120,000 bbl/d of oil and natural gas processing of 176.6 mmcf/d (5 mmm³/d). The first production well has been producing over 25,000 bbl/d of oil.  The second well began production in February 2014, with initial production of 36 mbbl/d. This well was the first to produce through a pioneering connecting system, the BSR. The well is located at a water depth of 2,118 meters.

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The third pilot system for the Santos pre-salt is FPSO Cidade de Paraty, located in the Lula field, which started production in June 2013. This FPSO has a capacity of 120,000 bbl/d of oil and 176.6mmcf/d (5 mmm³/d) of natural gas processing.

We currently have two systems performing EWTs in the Santos Basin pre-salt area, the FPSO Cidade de São Vicente and the FPSO Dynamic Producer.

During 2014, two additional systems will be installed: The FPSO Cidade de Ilhabela with a production capacity of 150,000 bbl/d of oil and 211.9 mmcf/d (6 mmm³/d) of gas to be located in the Sapinhoá field. This FPSO is currently in Brazil on the shipyard Brasa for modules integration and is expected to start operating during the second half of 2014. The second FPSO to be installed is Cidade de Mangaratiba, with a production capacity of 150,000 bbl/d of oil and 282.5 mmcf/d (8 mmm³/d) of gas to be located in Iracema. This FPSO is currently undergoing a module integration at the Brasfels shipyard, in Brazil.

 We continue to concentrate our efforts on gathering information about the pre-salt reserves through EWTs and testing drilling technologies to improve efficiency and to plan the definitive design of production platforms.

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

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

Assignment Agreement (Contrato de Cessão Onerosa)

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

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

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Production Sharing Agreement (Contrato de Partilha de Produção)

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

Santos Basin Projects

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

Field	Unit Type	Production Unit	Crude Oil Nominal Capacity (bbl/d)	Natural Gas Nominal Capacity (mmcf/d)	Water Depth (meters)	Start Up (year)	Notes
Bauna & Piracaba (BM-S-40)	FPSO	Cidade de Itajai	80,000	70.6	200	2013	Post-salt
Sapinhoá Pilot (Guará)	FPSO	Cidade de São Paulo	120,000	176.6	2,141	2013	Pre-salt
Lula (Northeast) Pilot	FPSO	Cidade de Paraty	120,000	176.6	2,200	2013	Pre-salt
Sapinhoá Norte	FPSO	Cidade de Ilha Bela	150,000	211.9	2,100	2014	Pre-salt Concession
Iracema Sul	FPSO	Cidade de Mangaratiba	150,000	282.5	2,100	2014	Pre-salt Concession
Iracema Norte	FPSO	Cidade de Itaguaí (Z1)	150,000	282.5	2,100	2015	Pre-salt Concession
Lula Alto	FPSO	Cidade de Maricá	150,000	211.9	2,100	2016	Pre-salt Concession
Lula Central	FPSO	Cidade de Saquarema	150,000	211.9	2,100	2016	Pre-salt Concession
Lula Sul	FPSO	P-66	150,000	211.9	2,100	2016	Pre-salt Concession
Búzios 1	FPSO	P-74	150,000	247.2	2,100	2016	Assignment Agreement
Lapa	FPSO	Cidade de Caraguatatuba	100,000	176.6	2,100	2016	Pre-salt Concession
Lula Norte	FPSO	P-67	150,000	211.9	2,100	2016	Pre-salt Concession
Búzios 2	FPSO	P-75	150,000	247.2	2,100	2016	Assignment Agreement
Lula Extremo Sul	FPSO	P-68	150,000	211.9	2,100	2017	Pre-salt Concession
Lula Oeste	FPSO	P-69	150,000	211.9	2,100	2017	Pre-salt Concession
Búzios 3	FPSO	P-76	150,000	247.2	2,100	2017	Assignment Agreement
Iara Horst	FPSO	P-70	150,000	211.9	2,100	2017	Pre-salt Concession
Búzios 4	FPSO	P-77	150,000	247.2	2,100	2017	Assignment Agreement
NE Tupi	FPSO	P-72	150,000	211.9	2,100	2018	Pre-salt Concession
Iara NW	FPSO	P-71	150,000	211.9	2,100	2018	Pre-salt Concession
Carcará	FPSO	TBD	150,000	282.5	2,100	2018	Pre-salt Concession
Entorno de Iara	FPSO	P-73	150,000	211.9	2,100	2018	Assignment Agreement

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

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

Espírito Santo Basin

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

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

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

Sergipe-Alagoas Basin

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

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

Other Basins

We produce hydrocarbons and hold exploration acreage in 20 other basins in Brazil.  While our onshore production is primarily in mature fields, we plan to sustain and slightly increase production from these fields in the future by using enhanced recovery methods.  In 2013, production from these other basins amounted to 167.7 mbbl/d of oil and 316.2 mmcf/d (8.4 mmm³/d) of natural gas.

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

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Critical Resources in Exploration and Production

We seek to develop and retain the critical resources that are necessary to meet our production targets.  Drilling rigs are an important resource for our exploration and production operations and substantial lead time is required when fleet expansion is needed. When we discovered the pre-salt, in 2006, our activities were constrained by the availability of rigs, but our subsequent efforts to lease additional rigs have eliminated this constraint. Whereas in 2008 we only had three rigs capable of drilling in water deeper than 2,000 meters (6,560 feet), we had 40 as of December 31, 2013. We believe that we now have sufficient rigs to meet our long-term production targets, although we will continue to  evaluate our drilling requirements and will adjust our fleet size as needed.

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

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

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

Refining, Transportation and Marketing

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

We are an integrated company with a dominant market share in our home market.  We own and operate 12 refineries in Brazil, with a total net distillation capacity of 2,102 mbbl/d, and are one of the world’s largest refiners.  As of December 31, 2013, we operated substantially all of Brazil’s total refining capacity.  We supplied almost all of the refined product needs of third-party wholesalers, exporters and petrochemical companies, in addition to the needs of our Distribution segment.  We operate a large and complex infrastructure of pipelines, terminals and a shipping fleet to transport oil products and crude oil to domestic and export markets.  Most of our refineries are located near our crude oil pipelines, storage facilities, refined product pipelines and major petrochemical facilities, facilitating access to crude oil supplies and end-users.

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

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

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

Refining

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

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

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

* Consider oil and NGLs processing (fresh feedstock)

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

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

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

·Increase residue conversion; and

·Reduce the environmental impact of our refining operations.

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

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

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

Major Refinery Projects

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

·Complexo Petroquímico do Rio de Janeiro—Comperj, an integrated refining and petrochemical complex.  We broke ground in 2008, and began construction in 2010.  The 165 mbbl/d refining operation is scheduled to start up in 2016, and as of December 31, 2013, we have completed approximately 66.3% of construction and invested U.S.$7.6 billion; and

·Abreu e Lima - RNEST, a refinery in Northeastern Brazil is designed to process 230 mbbl/d of crude oil to produce 162 mbbl/d of low sulfur diesel (10 ppm) as well as LPG, naphtha, bunker fuel and petroleum coke.  We expect operations to come on stream in the last quarter of 2014, and as of December 31, 2013, we have completed approximately 84.3% of construction and invested U.S.$14.8 billion.

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

·Premium I in the State of Maranhão is being designed to process 24° API heavy crude oil, maximize production of low sulfur diesel, and produce LPG, naphtha, low sulfur kerosene, bunker fuel and petroleum coke.  This refinery will be built in two phases of 300 mbbl/d each; and

·Premium II in the State of Ceará will have a processing capacity of 300 mbbl/d and will follow the same specifications as Premium I. 

The Premium facilities will be able to reduce costs and achieve efficiencies through simplification and standardization of the projects.

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The following tables summarize our domestic output of oil products and consolidated sales by product for the last three years.

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

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

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

Delivery Commitments 

We sell crude oil through long-term and spot-market contracts.  Our long-term contracts specify the delivery of fixed and determinable quantities, subject to a price negotiation with third parties on a delivery-by-delivery basis. We are committed through long-term contracts to deliver a total of approximately 240 mbbl/d in 2014.  We believe our domestic proved reserves will be sufficient to allow us to continue to deliver all contracted volumes.  For 2014, approximately 75% of our exported crude oil will be committed to meeting our contractual delivery commitments to third parties.

Imports and Exports

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

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

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

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

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

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

Logistics and Infrastructure for oil and oil products

We own and operate an extensive network of crude oil and oil products pipelines in Brazil that connect our terminals, refineries and other primary distribution points.  On December 31, 2013, our onshore and offshore, crude oil and oil products pipelines extended 19,313 km (9,525 miles).  We operate 27 marine storage terminals and 21 other tank farms with nominal aggregate storage capacity of 64 mmbbl.  Our marine terminals handle an average 10,019 tankers and oil barges annually.  We are working in partnership with other companies to develop and expand Brazil’s ethanol pipeline and logistics network.

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

Three new oil tankers were delivered to Transpetro in 2013. Another 39 vessels are scheduled to be delivered between 2014 and 2020, all of which will be built in Brazilian shipyards.  In addition, Transpetro has contracted 20 convoys (each composed of four barges and one pushboat) for biofuel transportation on the Tietê-Paraná waterway.

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

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

Petrochemicals

Our petrochemicals operations provide an outlet for our growing production volumes of gas and other refined products, which increase their value and provides substitute for products that are otherwise imported.  Our strategy is to operate in an integrated manner with the other businesses of Petrobras, preferably through partnerships with other companies.

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

	mmt/y (nominal capacity)	Petrobras interest (%)
Braskem(1):
Ethylene	3.95	36.20
Polyethylene	3.03
Polypropylene	3.95
DETEN Química S.A.:
LAB(1)	0.22	27.88
LABSA(1)	0.08
METANOR S.A./COPENOR S.A.:
Methanol	0.08	34.54
Formaldehyde	0.09
Hexamine	0.01
FCC Fábrica Carioca de Catalisadores S.A.:
Catalysts	0.04	50.00
Additives	0.01
PETROQUÍMICASUAPE COMPLEX(2):
Purified Terephthalic Acid - PTA	0.70	100.00
Polyethylene Terephthalate - PET	0.45
Polymer and Polyester filament textiles	0.24
PETROCOQUE S.A.:
Calcined petroleum coke	0.50	50.00
________________________

(1)Feedstock for the production of biodegradable detergents.

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

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

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

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

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

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

Distribution   

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

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

The primary focus of our Distribution segment is to:

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

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

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

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

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Most Petrobras Distribuidora stations are owned by franchisees that use the Petrobras Distribuidora brand name under license and purchase exclusively from us; we also provide franchisees with technical support, training and advertising.  We own 632 of the Petrobras Distribuidora stations and are required by law to subcontract the operation of these owned stations to third parties.  We believe that our market share position is supported by a strong Petrobras Distribuidora brand image and by the remodeling of service stations and addition of lubrication centers and convenience stores.

Our wholesale distribution of oil products and biofuels under the Petrobras Distribuidora brand to commercial and industrial customers accounts for 55% of the total Brazilian wholesale market. Our customers include aviation, transportation and industrial companies, as well as utilities and government entities.

Our LPG distribution business - Liquigas Distribuidora - held a 22.7% market share and ranked second in LPG sales in Brazil in 2013, according to the ANP.

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

Gas and Power

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

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

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

·Add value by monetizing Petrobras’ natural gas resources;

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

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

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

As a result of our efforts to develop the market, natural gas in 2012 supplied 11.5% of Brazil’s total energy needs, compared to 3.7% in 1998, and is projected to supply 16% of Brazil’s total energy needs by 2022, according to Empresa de Pesquisa Energética, a branch of the MME.  

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Natural Gas

We have three principal markets for natural gas:

·Industrial, commercial and retail customers;

·Thermoelectric generation; and

·Consumption by our refineries and fertilizer plants.

Natural gas consumption in Brazil by industrial, commercial and retail customers in 2013 was 40.9 mmm³/d, representing a decrease of only 0.4% compared to 2012.  This small decrease is attributable mainly to Brazil’s low economic growth.  Natural gas consumption in the power generation industry increased 73% from 2012 to 2013 due to unfavorable rainfall, which reduced the reservoir storage levels of Brazilian hydroelectric power plants.  Natural gas consumption by refineries and fertilizer plants increased by 3%.  

As a result of a multi-year infrastructure development program in pipelines network that was completed in 2011, we now have an integrated system centered around two main, interlinked pipeline networks that allow us to deliver natural gas from our main offshore natural gas producing fields in the Santos, Campos and Espírito Santo Basins, as well as from three LNG terminals, and a gas pipeline connection with Bolivia. 

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

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

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

We also own and operate four natural gas processing plants.   

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

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

Principal Natural Gas Local Distribution Holdings
Name	State	Group Interest %	Average Gas Sales in 2013 (mmm3/d)	Customers(1)
CEG RIO	Rio de Janeiro	37.41	9.1	38,888
BAHIAGAS	Bahia	41.50	4.5	23,354
GASMIG	Minas Gerais	40.00	4.1	1,484
PETROBRAS DISTRIBUIDORA	Espírito Santo	100.00	3.0	27,386
___________________________

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

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

Supply and Sales of Natural Gas in Brazil, mmm3/d
	2013	2012	2011
Sources of natural gas supply
Domestic production	40.8	39.5	34.1
Imported from Bolivia	30.5	27.0	27.1
LNG	14.5	8.4	1.6
Total natural gas supply	85.9	74.9	62.8
Sales of natural gas
Sales to local gas distribution companies(1)	38.6	39.3	39.8
Sales to gas-fired power plants	26.0	16.6	8.2
Total sales of natural gas	64.6	55.9	48.0
Internal consumption (refineries, fertilizer and gas-fired power plants)(2)	20.8	18.5	14.8
Revenues (U.S.$ billion)(3)	9.0	8.1	5.9
________________________

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

(2)                  Includes gas used in the transport system.

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

Long-Term Natural Gas Commitments

When we began construction of the Bolivia-Brazil pipeline in 1996, we entered into a long-term Gas Supply Agreement, or GSA, with the Bolivian state-owned company Yacimientos Petrolíferos Fiscales Bolivianos, or YPFB, to purchase certain minimum volumes of natural gas at prices linked to the international fuel oil price through 2019, after which the agreement may be extended until all contracted volume has been delivered. 

On December, 19, 2009, Petrobras and YPFB signed the fourth amendment to the GSA, which provides for annual additional payments to YPFB for liquids contained in the natural gas purchased by Petrobras through the GSA. As of February 2010, Petrobras has paid all obligations owed for 2007, but YPFB did not meet the condition precedent necessary to receive additional payments for the subsequent years (after 2007).  Petrobras and YPFB have been negotiating several aspects of the GSA, including payments for liquids contained in the natural gas purchased in the subsequent years (after 2007). As a result of this ongoing negotiation, Petrobras may agree to make additional payments in exchange for certain compensations to be agreed by YPFB, but it is currently not possible to provide any specific payment estimates for subsequent years. As a result, we have not considered them in our contractual GSA obligations forecast.

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Our volume obligations under the ship-or-pay arrangements entered into with Gás Transboliviano (GTB) and Transportadora Brasileira Gasoduto Bolivia-Brasil (TBG) were generally designed to match our gas purchase obligations under the GSA through 2019.  The tables below show our contractual commitments under these agreements for the five-year period from 2014 through 2018.

	2014	2015	2016	2017	2018
Purchase commitments to YPFB
Volume obligation (mmm3/d)(1)	24.06	24.06	24.06	24.06	24.6
Volume obligation (mmcf/d)(1)	850.00	850.00	850.00	850.00	850.00
Brent crude oil projection (U.S.$)(2)	100.00	100.00	100.00	100.00	95.00
Estimated payments (U.S.$ million)(3)	2,730.08	2,591.10	2,574.50	2,569.80	2,467.30
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)	139.14	139.82	140.51	141.21	141.21
Ship-or-pay contract with TBG
Volume commitment (mmm3/d)(4)	35.28	35.28	35.28	35.28	35.28
Volume commitment (mmcf/d)	1,246.09	1,246.09	1,246.09	1,246.09	1,246.09
Estimated payments (U.S.$ million)(5)	524.21	564.24	527.97	530.03	532.50

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

(2)                  Brent price forecast based on our 2030 Strategic Plan.

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

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

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

Gas Sales Contracts

We sell our gas primarily to local gas distribution companies and to gas fired plants generally based on standard take-or-pay, long-term supply contracts. This represents 74% 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 2013, we renegotiated some existing long-term natural gas sales contracts with local distribution company of natural gas in order to promote adjustments tailored to specific market demands, encompassing term extensions for some contracts, prolonging our natural gas sales portfolio.  We continued offering contracts for short-term volumes through electronic auctions.

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The table below shows our future gas supply commitments from 2014 to 2018, including sales to both local gas distribution companies and gas-fired power plants.

Future Commitments under Natural Gas Sales Contracts, mmm3/d	2014	2015	2016	2017	2018
To local gas distribution companies:
Related parties(1)	20.48	21.48	22.52	22.77	23.23
Third parties	17.00	17.13	17.27	17.27	17.27
To gas-fired power plants:
Related parties(1)	6.37	2.49	2.41	2.44	2.43
Third parties	7.93	7.58	7.39	7.48	7.37
Total(2)	51.79	48.68	49.59	49.96	50.30
Estimated contract revenues (U.S.$ billion)(3)(4)	6.2	6.2	6.3	6.3	6.2

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

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

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

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

Short-Term Natural Gas Sales

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

Since October 2012 we have revised the auction so that one short-term contract will regulate all operations of sales during an one-year period.   On average, 4.4 mmm³/d of natural gas were sold under short-term contracts in 2009, with volumes reaching 7.8 mmm³/d in 2010, 6.7 mmm³/d in 2011 and 6.6 mmm³/d in 2012.  In 2013, the average volumes of natural gas delivered under this short-term agreement was 0.7 mmm³/d, with a delivery record of 3.1 mmm³/d in August 2013.

Fertilizers

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

Our fertilizer plants in Bahia and Sergipe produce ammonia and urea for the Brazilian market. In June 2013, Petrobras acquired a fertilizer nitrogen plant located in Araucária, Parana, from Vale Fertilizantes S.A. This plant has the capacity to produce 700,000 t/y of urea and 50,000 t/y of ammonia.

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

Ammonia and Urea (ton)
	2013	2012	2011
Ammonia	205,029	229,575	240,665
Urea	1,071,827	848,000	831,462
Revenues (U.S.$ million)(1)	621	571	605

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

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We are currently building two additional facilities to expand our fertilizer business:

•              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, expected to start up in September 2014; and

•              UFN V, with the capacity to produce 519,000 t/y of ammonia from 1.3 mmm³/d of natural gas, expected to start up in April 2017;

Power

Brazilian electricity needs are mainly supplied by hydroelectric power plants (85,657 MW of installed capacity), which account for 68% 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 2013 was 125,774 MW. Of this total, 6,547.6 MW (or 5.2%) was available from 21 thermoelectric plants we operate. These plants are designed to supplement power from the hydroelectric  power plants.  

In 2013, hydroelectric power plants in Brazil generated 47,318 MWavg, which corresponded to 75% of Brazil’s total electricity needs (62,824 MWavg). Hydroelectric generation capacity is supplemented by other sources of energy (wind, coal, nuclear, fuel oil, diesel oil and natural gas).  Total electricity generated by these sources averaged 12,750 MW in 2013, of which our thermoelectric power plants contributed 4,043 MWavg, as compared to 2,699 MWavg in 2012 and 653 MWavg in 2011.  In 2013, we invested U.S.$245.64 million in our power business segment.

Electricity Sales and Commitments for Future Generation Capacity

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

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

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

For the year of 2013, the commercial capacity certified by MME for all thermoelectric power plants controlled by us was of  4,366 MWavg, although our total  generating capacity was 6,547.6 MWavg in 2013. Of the total 4,583 MWavg of commercial capacity available (capacidade comercial disponível or  lastro) for sale in 2013, approximately 39% was sold as standby availability in auctions and approximately 53% was  committed under bilateral contracts and self-production.

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

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Our future commitments under bilateral contracts and self-production are of 2,394 MWavg in 2014, 2,367 MWavg in 2015 and 2,386 MWavg in 2016.  The agreements will run off gradually, with the last contract expiring in 2028.  As existing bilateral contracts run-off, we will sell our remaining certified commercial capacity under short and medium-term bilateral contracts,  in new auctions to be conducted by MME or in the spot market. 

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

Installed Power Capacity, Certified Commercial Capacity
	2010	2011	2012	2013	2014	2015
Installed power capacity and utilization
Installed capacity (MW)	5,277	5,806	6,235	6,548	7,161	7,161
Certified commercial capacity (MWavg)	3,619	3,777	4,146	4,366	4,236	4,382
Purchases (MWavg)	234	214	292	217	207	200
Commercial capacity available (Lastro) (MWavg)	3,853	3,991	4,438	4,583	4,443	4,582

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)
	2013	2012	2011
Total sale commitments	4,247	4,438	3,991
Bilateral contracts	2,056	2,318	2,000
Self-production	393	423	395
Auctions to distribution companies	1,798	1,697	1,596
Generation volume	3,983	2,699	653
Revenues (U.S.$ million)(1)	5,173	3,755	2,366

(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 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
	2013	2012	2011
	(U.S.$ million)
International:
Sales revenues	16,302	17,929	16,956
Income (loss) before income taxes	2,035	1,933	2,117
Property, plant and equipment	7,971	10,882	9,871
Capital expenditures and investments	2,368	2,572	2,631

In addition to Brazil, we have operations in 17 countries, encompassing all phases of the energy business.  The primary focus of our international operations is:

·Oil and gas exploration and production, particularly in Latin America, Africa and United States;

·Maintenance of the natural gas supply from Bolivia to meet the Brazilian market demand;

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·Increase the operational efficiency of our international distribution segment; and

·Maintenance of the operational integrity and the optimization of the operations of our refining assets.

International Upstream Activities

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

In 2013, our net production outside Brazil averaged 127.2mbbl/d of crude oil and NGLs and 560.4 mmcf/d (15.9 mmm³/d) of natural gas, representing 9.2% of our total production on a barrels of oil equivalent basis.  During 2013, our capital expenditures and investments for international exploration and production totaled U.S.$2.1 billion, representing 7.2% of our total exploration and production capital spending.

International Activities by Region and Country

In addition to exploring for and producing oil, our international activities include refining, 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, Peru, Paraguay and Uruguay.  In 2013, our average net production from South America (outside of Brazil) was 167.2 mboe/d, or 76% of our international production compared to 188.2 mboe/d, or 75% of our international production in 2012.  Reserves in the region represent 64% 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 525.0 mmcf/d (14.9 mmm³/d) of natural gas in 2013, or 94% of our international production.

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, El Tordillo and La Tapera – Puesto Quiroga fields, and our main gas production is concentrated in the El Mangrullo, Río Neuquém fields in the Neuquém 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 Puesto Hernandez field to YPF for U.S.$ 40.7 million. Through our interest in PESA, we own the Bahia Blanca Refinery, with a capacity of 30.5 mbbl/d, and stakes in the Refinor/Campo Duran Refinery and in two petrochemical plants in Argentina.  We also own 268 retail service stations, three electric power plants, Pichi Picún Leufú (hydrogeneration), Genelba (gas powered combined cycle) and Genelba Plus (gas powered), as well as interest 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.

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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 44.5% interest in Transierra S.A., which owns the Yacuiba-Rio Grande gas pipeline (Gasyrg) linking the San Alberto, San Antonio and Itaú fields to the BTB pipeline.

In Chile, our assets comprise 253 service stations, the distribution and sales of fuel at airports and a lubricant plant.

In Colombia, we sold our subsidiary Petrobras Colombia Limited (PEC) to Perenco, for a total amount of U.S.$380 million, including interests in onshore producing blocks and the pipelines Colombia and Alto Magdalena, with a capacity of 14,950 bpd and 9,180 bpd, respectively. The conclusion of this transaction is subject to customary conditions precedent, including approval by the National Agency of Hydrocarbons (ANH). 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 101 service stations and a lubricant plant.

In Paraguay, our assets comprise 166 service stations, the distribution and sales of fuel at two airports and an LPG refueling plant.

In Peru, we sold our subsidiary Petrobras Energia Peru to China National Petroleum Corporation in November 2013 for U.S.$2.6 billion, including stakes in three blocks (Lote X, 57 and 58). The conclusion of this transaction is subject to the approval of both the Chinese and Peruvian governments and compliance with the procedures set out under the joint operating agreement executed in connection with the operation of blocks Lote X, 57 and 58.  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.

In Uruguay, we sold our interests in offshore exploration blocks 3 and 4, located in the Punta del Este Basin to Shell in October 2013 for U.S.$17 million. The conclusion of this transaction is subject to customary conditions precedent, including the approval of the Uruguayan Government. We have no other upstream portfolio in the country. See note 10 to our audited consolidated financial statements. We have fuel distribution operations, including 88 service stations, and we also market marine products, fertilizers, asphalt and aviation products and distribution. Our gas segment includes two gas distribution companies in Uruguay, namely Distribuidora de Gas Montevideo S.A (with retail sales in Montevideo), in which we still hold a 100% equity interest, and Conecta S.A. (with national commercial sales), in which we hold a 55% equity interest. In May 2013, we signed an agreement with Administración Nacional de Combustibles, Alcoholes y Portland (ANCAP) to sell 50% of our equity interest in Distribuidora de Gas Montevideo S.A for a total amount of U.S.$7.5 million. The conclusion of this transaction is subject to customary conditions precedent, including the approval of the Uruguayan Government.  See “—Gas and Power”.

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North America

In the United States, we focus on deepwater fields in the Gulf of Mexico.  As of December 31, 2013, we held interests in 139 offshore blocks, 102 of which we operate.  Our production in the United States during 2013 was originated mainly from the Cascade, Chinook and Coulumb 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 a FPSO.  Other assets include the Saint Malo and Lucius blocks, which are currently in the development stage, and Tiber, among others, which are currently in the exploratory stage. During 2013, we farmed-out interests in several blocks, including some in Gila, Coulomb, for (i) a total amount of U.S.$294 million and (ii) interests in exploratory blocks near the Tiber block, where we already have a stake. See note 10 to our audited consolidated financial statements. We also own 100% of the Pasadena Refining System Inc., or PRSI, and 100% of PRSI’s related trading company - PRSI Trading, LLC. The refinery has a capacity of 100 mbbl/d.

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 announced a joint venture with BTG Pactual to jointly explore oil and gas opportunities in Africa, involving substantially all of our exploration and production assets in Africa. This joint venture, which will be our primary vehicle to explore such opportunities in Africa, was formed upon the acquisition by BTG Pactual of 50% of the shares issued by Petrobras Oil & Gas B.V. (PO&G), a wholly owned subsidiary of Petrobras International Braspetro B.V (PIBBV), for U.S.$1,548 billion.

Once PO&G’s corporate restructuring is concluded, our joint venture operations will involve the branch of PIBBV located in Angola, the branches of PO&G located in Benin, Gabon and Namibia, as well as PIBBV’s subsidiaries Brasoil Oil Services Company (Nigeria) Ltd., Petroleo Brasileiro Nigeria Ltd. and Petrobras Tanzania Ltd. See note 10 to our audited consolidated financial statements.

The assets of our joint venture with BTG Pactual include:

In Angola, our production from Block 2, which we do not operate, as well the blocks  6/06, 18/06 and 26, which are all 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, Block 2714A, which is in an exploratory phase;

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 capacity of 100 mbbl/d, which currently produces refined products such as gasoline, diesel, fuel oil and jet fuel.

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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, 2013.

		Main International Exploration and Production Assets in Development
Countries		Main projects in development	Phase	Operated by	Petrobras interest (%)
South America
1	Argentina(1)	Sierra Chata El Tordillo Santa Cruz I Oeste 25 de Mayo – Medanito Rio Neuquen Santa Cruz I El Mangrullo Entre Lomas Puesto Hernández(6)	Production Production Production Production Production Production Production Production Production	Petrobras Partner Petrobras Petrobras Petrobras Petrobras Petrobras Petrobras Petrobras	46 36 50 100 100 71 100 77 38.45
2	Bolivia(2)	San Alberto San Antonio Itaú	Production Production Production	Petrobras Petrobras Petrobras	35 35 30
3	Colombia	Guando(6) Yalea(6) Espinal(6) Balay 1(6) Tayrona Cebucan(6)	Production Production Production Development Exploration Exploration	Petrobras Partner Petrobras Petrobras Petrobras Petrobras	15 50 33 45 40 50
4	Peru	Lote 10(6) Lote 57(6) Lote 58(6)	Production Development Exploration	Petrobras Partner Petrobras	100 46.16 100
5	Uruguay	Block 3(6)  Block 4(6)	Exploration Exploration	Partner Petrobras	40 40
6	Venezuela(3)	Oritupano-Leona Acema La Concepción Mata	Production Production Production Production	Partner Partner Partner Partner	22 34 36 34
North America
7	Mexico(4)	Cuervito Fronterizo	Production Production	Petrobras Petrobras	45 45
8	U.S.	Cascade Chinook Cottonwood St. Malo Tiber Lucius	Production Production Production Development Exploration Development	Petrobras Petrobras Petrobras Partner Partner Partner	100 66.67 100 25 20 9.6
Africa
9	Angola(5)	Block 2/85 Block 6/06 Block 18/06 Block 26	Production Exploration Exploration Exploration	Partner Petrobras Petrobras Petrobras	27.5 40 30 40
10	Benin(5)	Block 4	Exploration	Partner	35
11	Gabon(5)	Ntsina Marin Mbeli Marin	Exploration Exploration	Partner Partner	50 50
12	Namibia(5)	2714A	Exploration	Petrobras	30

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13	Nigeria(5)	Akpo Agbami Egina Egina South Preowei	Production Production Development Exploration Exploration	Partner Partner Partner Partner Partner	20 12.5 20 20 20
14	Tanzania(5)	Block 6 Block 8	Exploration Exploration	Petrobras Petrobras	38 50

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

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

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

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

(5)            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.

(6)            Assets recently sold to third parties.See Item 4. “Information on the Company- International Activities by Region and Country”.

Biofuels

Biofuels Key Statistics
	2013	2012	2011
	(U.S.$ million)
Biofuel:
Sales revenues	388	455	320
Income (loss) before income taxes	(168)	(156)	(151)
Property, plant and equipment	222	255	285
Capital expenditures	143	147	294

Brazil is a global leader in the use and production of biofuels.  Today, 83.1% of new light vehicles sold in Brazil have flexfuel capability, and service stations offer a choice of 100% ethanol and an ethanol/gasoline blend.

Biodiesel

Since January 2010, all diesel fuel sold in Brazil is required to have at least 5% biodiesel.  We supply 20% of Brazil’s biodiesel 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), Brazil’s third largest sugarcane processor, Nova Fronteira Bioenergia S.A. (Nova Fronteira) and Bambuí Bioenergia S.A. (Bambuí Bioenergia), we also have presence in the whole ethanol production chain in the production and distribution of ethanol and selling the exceeding electricity generated from sugarcane bagasse burn. We have all necessary infrastructure for the distribution and export of ethanol. In 2013, we invested approximately U.S.$104.3 million (R$225.1 million) in Guarani, increasing our interest to 39.6% from 35.8%. 

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Through our affiliated companies Bambuí Bioenergia, Nova Fronteira and Guarani, we also own ethanol plants situated in the States of Minas Gerais, São Paulo and Goiás and also an ethanol plant in Mozambique, Africa. These affiliated companies’ total milling in the 2013/2014 harvest amounted to 25.5 mmt of sugarcane, and the total ethanol and sugar production capacity of our affiliate companies amounted to 18.2 mbbl/d and 1.6 mmt respectively compared to 14.2 mbbl/d and 1.6 mmt respectively in the 2012/2013 harvest. These affiliated entities sold 936 GWh of exceeding electricity generated during the 2013/2014 harvest. 

In 2013, we exported 733 mbbl/y of ethanol, 4.0% of Brazil’s total ethanol exports, compared to 545 mbbl/y of ethanol in 2012.  In addition, we also increased the volume of ethanol bought outside of Brazil, which reached a volume of 712 mbbl/y. 

Corporate

Corporate Key Statistics
	2013	2012	2011
	(U.S.$ million)
Corporate:
Income (loss) before income taxes	(7,818)	(6,999)	(5,003)
Property, plant and equipment	3,312	3,204	3,022
Capital expenditures and investments	547	747	729

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, 2013, we had 30 direct subsidiaries and two direct joint operations as listed below. 27 are entities incorporated under the laws of Brazil and five are incorporated abroad (including PifCo).  As set out in notes 10 and 38 to our audited consolidated financial statements, on February 12, 2014, PGF acquired all of PifCo’s outstanding shares. We also have indirect subsidiaries (including Petrobras Argentina S.A. and 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 equity interest.

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PETROBRAS
BRAZIL	ABROAD
Petrobras Distribuidora S.A.	Petrobras Netherlands B.V. - PNBV
Petrobras Gás S.A. - Gaspetro	Petrobras International Braspetro - PIB BV
Petrobras Transporte S.A. - Transpetro	Petrobras International Finance Company - PifCo
Petrobras Logística de Exploração e Produção S.A. - PB-LOG	Braspetro Oil Services Company - Brasoil
Companhia Integrada Têxtil de Pernambuco S.A. - Citepe	Cordoba Financial Services GmbH
Petrobras Biocombustível S.A. - PBIO
Companhia Locadora de Equipamentos Petrolíferos S.A. - CLEP
Companhia Petroquímica de Pernambuco S.A. - PetroquímicaSuape
Liquigás Distribuidora S.A.
Araucária Nitrogenados S.A.
Termomacaé Ltda.
Termoaçu S.A.
INNOVA S.A. ( * )
5283 Participações Ltda.
Breitener Energética S.A.
Termobahia S.A.
Termoceará Ltda.
Arembepe Energia S.A.
Petrobras Comercializadora de Energia Ltda. - PBEN
Baixada Santista Energia S.A.
Fundo de Investimento Imobiliário RB Logística - FII
Energética Camaçari Muricy I Ltda.
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. (**)
(*) Classified as assets held for sale as of December 31, 2013, as set out in note 10 to our audited consolidated financial statements.
(**) Joint operations.

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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.

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 such time 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 2013, we paid this tax on 18 of our fields, namely Albacora, Albacora Leste, Barracuda, Baúna, Cachalote, Canto do Amaro, Caratinga, Carmópolis, Jubarte, Leste do Urucu, Lula, Manati, Marlim, Marlim Leste, Marlim Sul, Rio Urucu, Roncador and Ostra (operated by Shell); 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 billion boe. 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. “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 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.  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 were granted exclusivity in these pipelines for 10 years.  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, which 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.

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.

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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.  Also in 2002, the Brazilian federal government established an excise tax on the sale and import of crude oil, oil products and natural gas products (Contribuição de Intervenção no Domínio Econômico, Contribution for Intervention in the Economic Sector, or CIDE) which is currently at 0% tax rate for gasoline, diesel, ethanol and other products. The Brazilian federal government has periodically used CIDE as a tool to maintain price stability to end consumers, primarily by decreasing the CIDE rate when we increase our prices to reflect higher international prices and vice versa.  In 2009, 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, according to previously established criteria, for the use of new gas transport pipelines subject to the authorization regime.

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.  At the federal level, our offshore activities and those that involve more than one Brazilian state are subject to the regulatory authority of the Conselho Nacional doMeio Ambiente (National Council for the Environment, or CONAMA) and 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. Under Brazilian law, there is strict 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.

We are subject to a number of administrative and legal proceedings relating to environmental matters.  See Item 8. “Financial Information—Legal Proceedings.” and Note 31 to our audited consolidated financial statements included in this annual report for a description of the legal and administrative proceedings to which we are subject.

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In 2013, we invested approximately U.S.$1,540 million in environmental projects, compared to approximately U.S.$1,498 in 2012 and U.S.$1,625 million in 2011.  These investments were primarily directed at reducing emissions and wastes resulting 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 emergency situations.

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 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 system;

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

Our efforts to address health, safety and environmental concerns and ensure compliance with environmental regulations involved an investment of approximately U.S.$2.6 billion (R$5.7 billion) in 2013. They included 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:  

·A HSE management system which 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 connected with new oil and gas production and other transportation and logistical  aspects of our operations.

·A strategic goal seeking to maximize energy efficiency and reduce greenhouse gases emission intensity, which was approved by our board of executive officers in November 2010 along with a set of performance indicators with targets to monitor progress with respect to this new challenge.  Our objective is to reach excellence levels in the oil and gas industry and to contribute to business sustainability.

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·The HSE and Energy Efficiency in Investments project, which began in 2011 and aim at identifying opportunities, risks as well as ensuring the integration of health, safety, environment and energy efficiency (HSEE) aspects throughout the life cycle of new investment projects. Given the high volume of investments planned for the coming years, the project will benefit from the opportunity to increase our HSEE performance with lower marginal costs, contributing to the reduction of losses, to operational continuity and to a lower exposure to penalties and liabilities.

Every investment project is evaluated to confirm its compliance with all HSE requirements and adoption of the best HSE practices throughout the project’s life cycle.  In addition, we conduct more extensive environmental studies for new projects when required by applicable environmental legislation.

We are committed to reduce greenhouse gas emission intensity from our processes and products. In recent years, our optimization efforts aimed at improving natural gas recovery have ensured a consistent reduction in the volume of gas flared. Gas flaring in 2013 was reduced by 11.3% compared to 2012 and by 62% compared to 2009. The natural gas recovery rate is currently 93%.

Furthermore, by investing U.S.$21.8 million (R$47.1 million) in energy efficiency projects, in addition to other investments in optimization and reliability, complemented by the introduction of changes in operational procedures, we were able to save an amount of energy equivalent to 3.4 mboe/d in 2013.  

Environmental Remediation Plans and Procedures

As part of our environmental plans, procedures and efforts, we have developed detailed response and remediation contingency plans to be implemented in the event of an oil spill or leak from our offshore operations.  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.  We also have stockpiles of the equipment needed to quickly and effectively contain offshore spills or leaks, including over 234 miles of containment and absorbent booms, 500 different oil skimmers, around 60,000 gallons of oil dispersants and 453 oil pumps.  Petrobras has 45 dedicated oil spill recovery vessels (OSRVs) fully equipped for oil spill control and firefighting, as well as 271 additional support and recovery boats and barges available to fight offshore oil spills and leaks 24 hours a day, seven days a week.

We created 10 environmental protection centers in strategic areas in which we operate throughout Brazil in order to ensure rapid and coordinated response to onshore or offshore oil spills.  These regional facilities are supported by 14 local advanced bases dedicated to oil spill prevention, control and response.  Our environmental protection centers and their advanced bases would be mobilized in the event of a spill or leak at one of our offshore operations.  Each of our local and regional response centers is self-sufficient and available to respond either individually or jointly together with neighboring facilities depending on the severity and scale of the emergency.

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 the resources available through that network as well. As a member of OSRL, we 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.  The Brazilian base opened in March 2014, and the capping and containment equipment to be stationed there is currently being manufactured, with major component deliveries scheduled for July 2014.

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In 2013, we conducted 11 emergency drills of regional and national 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 spill 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 2013 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 2013, we had oil spills totaling 1,176 barrels of crude oil, compared to 2,436 barrels of crude oil in 2012, 1,471 barrels of crude oil in 2011 and 4,200 barrels of crude oil in 2010.

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 also do not maintain coverage for our wells for all of our Brazilian operations.  Although we do not insure most of our pipelines, we have insurance against damage or loss to third parties resulting from specific incidents, as well as oil pollution.  We also maintain coverage for risks associated with cargo, hull and machinery risk.  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 17 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 and 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 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.

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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, 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 do not maintain control-of-well insurance for our domestic operations onshore and offshore Brazil.  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.

The premium for renewing our domestic property risk insurance policy for an 18-month period commencing December 2013 was U.S.$100.8 million.  This represented a nominal increase of 4% considering the same preceding 18-month period.  The insured value of our assets, in the same period, increased by 6.3% to U.S.$160.4 billion.  The premium average rate for the period was 0.06%, remaining stable relative to the previous period.  Since 2001, our risk retention has increased and our deductibles may reach U.S.$80 million in certain cases.

Additional Reserves and Production Information

Production of crude oil and natural gas in Brazil is divided into onshore and offshore production, comprising 11% and 89% of total production in Brazil, respectively.  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 2013, the Campos Basin produced an average 1,531.1 mbbl/d of oil and 553.8 mmcf/d (14.7 mmm³/d) of associated natural gas, comprising 75% 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. 

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On December 31, 2013, our estimated proved reserves of crude oil, condensate and natural gas in Brazil totaled 12.5 bnbbl of oil equivalent, including 10.7 bnbbl of crude oil and condensate and 299.2 bnm³ (11.3 tcf) of natural gas.  As of December 31, 2013, our domestic proved developed crude oil and condensate reserves represented 61% of our total domestic proved crude oil and condensate reserves, and our domestic proved developed natural gas reserves represented 58% of our total domestic proved natural gas reserves.  Total domestic proved crude oil and condensate reserves increased at an average annual rate of 4% in the last five years, and total natural gas proved reserves increased at an average annual rate of 4% 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 Securities and Exchange Commission.  

Internal Controls over Proved Reserves

The reserves 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 reserves estimates by supervising and providing technical support to Regional Reserves Coordinators (Coordenadores de Reservas Regionais, or CRRs) who are responsible for preparing the reserves estimates.  Our CRRs and CRCs have degrees in geophysics, geology, petroleum engineering, accounting and economics and are trained internally and abroad in international reserves estimates seminars.  CRCs are responsible for compliance with Securities and Exchange Commission rules and regulations, consolidating and auditing the reserves estimation process. The technical person primarily responsible for overseeing the preparation of our domestic reserves is a member of the SPE, with 24 years of experience in the field and has been with Petrobras for 30 years.  The technical person primarily responsible for overseeing the preparation of our international reserves has eight years of experience in the field, a doctorate in reservoir engineering and has been with Petrobras for 34 years. Our reserves estimates are presented to our board of executive officers and submitted to the board of directors for final approval.

DeGolyer and MacNaughton (D&M) used our reserves estimates to conduct a reserves audit of 96% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2013 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, 2013 from the properties we operate in Argentina.  Furthermore, D&M used our reserves estimates to conduct a reserves evaluation of 100% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2013 in certain properties we operate in the United States. The reserves estimates were prepared in accordance with the reserves definitions 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-91. 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.

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Changes in Proved Reserves

During 2013, we added 1,217.5 mmboe to our proved reserves, excluding synthetic oil and synthetic gas, while we sold some of our interests in fields with proved reserves amounting to 118.1 mmboe, including (i) all of the interests we had in the Abalone, Argonauta, Náutilus and Ostra fields in Brazil, (ii) all of the interests we had in the Coulomb and Stones fields in the United States and (iii) half of our interests in the Agbami, Akpo and Egina fields located in Nigeria. Since we no longer control the Nigerian entities directly responsible for our operations there, Nigerian reserves are no longer included in our consolidated reserves. As a result of these additions and dispositions, our proved reserves increased in 2013 by 1,099.4 mmboe. Considering a production of 861.1 mmboe in 2013, our net increase of proved reserves was 238.3 mmboe. This volume production do not take into account the production of Extended Well Texts (EWTs) in exploratory blocks in Brazil, the production of synthetic oil and synthetic gas and the production in Bolivia since the Bolivian Constitution prohibits the disclosure and registration of its reserves.

At year-end 2013 compared to year-end 2012, we added a net total of 204.8 mmboe to our proved undeveloped reserves company‐wide. Thus, we had a total of 5,267.0 mmboe of proved undeveloped reserves company‐wide at December 31, 2013, compared to 5,062.2 mmboe of proved undeveloped reserves company-wide at December 31, 2012.

In Brazil, the net increase in our proved undeveloped reserves in 2013 compared to 2012 is derived from the 836.1 mmboe of extensions and discoveries mainly in the pre-salt areas of Santos and Campos Basins, the increase of 322.5 mmboe of technical revisions to previous estimates and the increase of 117.5 mmboe of improved recovery.  This net increase to our proved undeveloped reserves in Brazil was partially offset by the reduction of 83.3 mmboe from economic revisions to previous estimates and the reduction of 28.4 mmboe from sales of mineral in situ. In addition, we converted a net total of 960.6 mmboe of our proved undeveloped reserves to proved developed reserves in Brazil in 2013, mainly through the drilling of several wells in existing production fields and the start of operation of production units in the basins of Santos and Campos.

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

                In 2013, we invested a total of U.S.$18.2 billion in development projects (of which approximately 92% (U.S.$16.7 billion) was invested in Brazil) and converted a total of 1,021.6 mmboe of proved undeveloped reserves to proved developed reserves, approximately 94% (960.6 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 and deep and ultra-deep water infrastructure and 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 5,267.0 mmboe of proved undeveloped reserves company-wide at year‐end 2013, approximately 3% (142.2 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 developments projects, particularly in Brazil, and constraints in the capacity of our existing infrastructure.

The majority of the 142.2 mmboe of our proved undeveloped reserves that have remained undeveloped for five years or more consist of reserves in the Santos and Campos Basins, for which we are making investments to develop necessary infrastructure.

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The following tables set forth our production of crude oil, natural gas, synthetic oil and synthetic gas by geographic area in 2013, 2012 and 2011:   

	Hydrocarbon Production by Geographic Area
	2013					2012					2011
	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)	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)	268.2	‒	105.3	‒	285.8	262.8	‒	101.4	‒	279.7	297.9	‒	115.6	‒	317.2
Other	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	1,721.1	2.8	1,075.5	1.4	1,903.3
Total Brazil	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	2,019.0	2.8	1,191.1	1.4	2,220.5
International:
South America (outside of Brazil)	70.2	‒	546.7	‒	161.4	76.4	‒	629.9	‒	181.4	77.4	‒	569.4	‒	172.3
North America	11.8	‒	11.9	‒	13.8	9.0	‒	18.8	‒	12.1	2.2	‒	11.1	‒	4.0
Africa	25.9	‒	0.0	‒	25.9	51.8	‒	-	‒	51.8	57.6	‒	-	‒	57.6
Total International	107.9	‒	558.7	‒	201.1	137.3	‒	648.7	‒	245.4	137.2	‒	580.5	‒	233.9
Total consolidated production	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	2,156.2	2.8	1,771.6	1.4	2,454.4
Equity and non-consolidated affiliates:(3)
South America (outside of Brazil)	5.5		1.7	‒	5.8	6.4	‒	2.4	‒	6.8	7.7	‒	3.5	‒	8.3
Africa	13.8	‒	0.0	‒	13.8	‒	‒	‒	‒	‒	‒	‒	‒	‒	‒
Worldwide production	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	2,163.9	2.8	1,775.1	1.4	2,462.7

_____________

(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, 2013. 

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	6,509.3	6,578.9	7,605.8	8.8	11.8	10.7	7,616.5
International
South America (outside of Brazil)	86.0	368.4	147.4	‒	‒	‒	147.4
North America	46.2	9.9	47.9	‒	‒	‒	47.9
Africa	‒	‒	‒	‒	‒	‒	‒
Total International	132.2	378.3	195.3	‒	‒	‒	195.3
Total consolidated proved developed reserves	6,641.5	6,957.2	7,801.1	8.8	11.8	10.7	7,811.8
Equity and non-consolidated affiliates
South America (outside of Brazil)	12.4	14.9	14.9	‒	‒	‒	14.9
Africa	37.3	15.7	40.0	‒	‒	‒	40.0
Total non-consolidated proved developed reserves	49.7	30.6	54.9	‒	‒	‒	54.9
Total proved developed reserves	6,691.2	6,987.8	7,856.0	8.8	11.8	10.7	7,866.7
Proved undeveloped:
Brazil	4,149.1	4,712.7	4,934.5	‒	‒	‒	4,934.5
International
South America (outside of Brazil)	80.1	690.1	195.1	‒	‒	‒	195.1
North America	77.0	123.1	97.5	‒	‒	‒	97.5
Africa	-	-	-	‒	‒	‒	-
Total International	157.1	813.2	292.6	‒	‒	‒	292.6
Total consolidated proved undeveloped reserves	4,306.2	5,525.9	5,227.1	‒	‒	‒	5,227.1
Equity and non-consolidated affiliates
South America (outside of Brazil)	8.8	26.4	13.2	‒	‒	‒	13.2
Africa	25.9	4.9	26.7	‒	‒	‒	26.7
Total non-consolidated proved undeveloped reserves	34.7	31.3	39.9	‒	‒	‒	39.9
Total proved undeveloped reserves	4,340.9	5,557.2	5,267.0	‒	‒	‒	5,267.0
Total proved reserves (developed and undeveloped)	11,032.1	12,545.1	13,123.1	8.8	11.8	10.7	13,133.7

_____________

(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 2013, 2012 and 2011:  

Total Proved Developed and Undeveloped Reserves (consolidated entities only)
	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, 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*	(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
Reserves quantity information for the year ended December 31, 2011
January 1, 2011	10,723.8	11,881.8	12,704.1	7.4	12.0	9.4	12,713.5
Revisions of previous estimates	613.6	998.3	780.0	2.4	3.3	2.9	783.0
Improved recovery	8.0	0.3	8.1	‒	‒	‒	8.1
Purchases of minerals in situ	‒	‒	‒	‒	‒	‒	‒
Extensions and discoveries	168.6	277.7	214.9	‒	‒	‒	214.9
Production	(739.8)	(790.3)	(871.5)	(1.2)	(1.9)	(1.5)	(873.0)
Sales of minerals in situ	‒	‒	‒	‒	‒	‒	‒
December 31, 2011	10,774.2	12,367.8	12,835.5	8.6	13.4	10.8	12,846.3

____________

Natural gas production volumes used in this table are the net volumes withdrawn from Petrobras’ 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’ 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.

*This line represents the amount of proved reserves excluded this year 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 expiry before 2025 with respect to our Brazilian onshore and offshore operations. In Argentina, we have some concessions that will expire within the next three years. Although we are working for the obtainment of extensions in some of these concessions, our booked reserves do not include any volumes after the expiration dates. 

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, 2013.   

Gross and Net Productive Wells and Gross and Net Developed and Undeveloped Acreage
	As of December 31, 2013
	Oil		Natural gas		Synthetic oil		Synthetic gas
Gross and net productive wells:(1)	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Consolidated subsidiaries
Brazil	8,138	8,134	251	245	‒	‒	‒	‒
International
South America (outside of Brazil)	5,726	4,567	392	280	‒	‒	‒	‒
North America	9	7	5	2	‒	‒	‒	‒
Africa	3	1	-	‒	‒	‒	‒	‒
Total international	5,738	4,575	397	282	‒	‒	‒	‒
Total consolidated	13,876	12,709	648	527	‒	‒	‒	‒
Equity and non-consolidated affiliates:
South America (outside of Brazil)	166	47	‒	‒	‒	‒	‒	‒
Africa	37	3	‒	‒	‒	‒	‒	‒
Total gross and net productive wells	14,079	12,759	648	527	‒	‒	‒	‒

	As of December 31, 2013
	Oil		Natural gas		Synthetic oil		Synthetic gas
	(in acres)
Gross and net developed acreage:	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Brazil	4,255,411.6	3,948,929.9	398,195.8	381,441.7	1,346.0	1,346.0	‒	‒
International
South America (outside of Brazil)	1,644,047.0	1,354,031.8	1,886,402.6	1,239,095.3	‒	‒	‒	‒
North America	14,229.9	10,483.5	3,271.6	1,765.7	‒	‒	‒	‒
Africa	‒	‒	‒	‒	‒	‒	‒	‒
Total international	1,658,276.9	1,364,515.3	1,889,674.3	1,240.861.0	‒	‒	‒	‒
Total consolidated	5,913,688.5	5,313,445.2	2,287,870.0	1,622,302.7	1,346.0	1,346.0	‒	‒
Equity and non-consolidated affiliates:
South America (outside of Brazil)	312,859.3	75,652.5	18,970.3	6,156.7	‒	‒	‒	‒
Africa	374,636.8	27,505.4	‒	‒	‒	‒	‒	‒
Total non-consolidated	687,496.1	103,157.9	18,970.3	6,156.7	‒	‒	‒	‒
Total gross and net developed acreage	6,601,184.6	5,416,603.1	2,306,840.3	1,628,459.4	1,346.0	1,346.0	‒	‒

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	As of December 31, 2013
	Oil		Natural gas		Synthetic oil		Synthetic gas
	(in acres)
Gross and net undeveloped acreage:	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Brazil	1,067,251.0	930,955.8	253,899.8	252,120.3	‒	‒	‒	‒
International
South America (outside of Brazil)	380,663.4	249,337.6	2,083,723.1	1,157,138.9	‒	‒	‒	‒
North America	16,545.9	7,697.5	9,686.8	4,220.9	‒	‒	‒	‒
Africa	‒	‒	‒	‒	‒	‒	‒	‒
Total international	397,209.3	257,035.1	2,093,409.9	1,161,359.8	‒	‒	‒	‒
Total consolidated	1,464,460.3	1,187,990.9	2,347,309.7	1,413,480.1	‒	‒	‒	‒
Equity and non-consolidated affiliates:
South America (outside of Brazil)	197,885.8	50,805.2	44,893.6	14,679.2	‒	‒	‒	‒
Africa	269,937.6	24,170.0	‒	‒	‒	‒	‒	‒
Total non-consolidated	467,823.4	74,975.2	44,893.6	14,679.2	‒	‒	‒	‒
Total gross and net undeveloped acreage	1,932,283.7	1,262,966.1	2,392,203.3	1,428,159.3	‒	‒	‒	‒
__________________ (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.

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
	2013	2012	2011
Net productive exploratory wells drilled:
Consolidated subsidiaries:
Brazil	67.55	44.7	31.9
South America (outside of Brazil)	3.5	4.0	3.3
North America	‒	1.1	0.6
Africa	‒	‒	0.2
Other	‒	‒	‒
Total consolidated subsidiaries	71.05	49.8	36.0
Equity and non-consolidated affiliates:
South America (outside of Brazil)	‒	0.4	‒
Africa	‒	‒	‒
Total productive exploratory wells drilled	71.05	50.2	36.0
Net dry exploratory wells drilled:
Consolidated subsidiaries:
Brazil	16.75	42.2	50.8
South America (outside of Brazil)	0.8	3.0	0.9
North America	0.9	0.5	‒
Africa	‒	0.7	0.5
Other	‒	‒	‒
Total consolidated subsidiaries	18.45	46.4	52.2
Equity and non-consolidated affiliates:
South America (outside of Brazil)	0.5	‒	‒
Africa	‒	‒	‒
Total dry exploratory wells drilled	18.95	46.4	52.2
Total number of net wells drilled	90.0	96.6	88.2
Net productive development wells drilled:
Consolidated subsidiaries:
Brazil	399.73	355.1	228.0
South America (outside of Brazil)	57.7	239.9	194.2

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North America	2.5	1.8	‒
Africa	‒	0.6	0.4
Other	‒	‒	‒
Total consolidated subsidiaries	459.93	597.4	422.6
Equity and non-consolidated affiliates:
South America (outside of Brazil)	1.5	2.4	3.0
Africa	0.6	‒	‒
Total productive development wells drilled	462.03	599.8	425.6
Net dry development wells drilled:
Consolidated subsidiaries:
Brazil	6	1	0.5
South America (outside of Brazil)	‒	‒	‒
North America	‒	‒	‒
Africa	‒	‒	‒
Other	‒	‒	‒
Total consolidated subsidiaries	6.0	1	0.5
Equity and non-consolidated affiliates:
South America (outside of Brazil)	‒	‒	0.2
Total dry development wells drilled	6.0	1	0.7
Total number of net wells drilled	468.03	600.8	426.3

The following table summarizes the number of wells in the process of being drilled as of December 31, 2013.  For more information about our on-going 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, 2013
	Year-end 2013
	Gross	Net
Wells Drilling
Consolidated Subsidiaries:
Brazil	52.0	46.04
International:
South America (outside of Brazil)	1.0	0.7
North America	‒	‒
Africa	‒	‒
Others	‒	‒
Total International	1.0	0.7
Total consolidated production	53.0	46.74
Equity and non-consolidated affiliates:
South America (outside of Brazil)	1.0	0.6
Africa	‒	‒
Total wells drilling	54.0	47.34

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The following table sets forth our average production 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 2013
Average production prices
Oil, per barrel	98.19	82.82	99.29	107.88	97.72	108.75
Natural gas, per thousand cubic feet(1)	7.90	3.88	3.97	‒	7.36	‒
Synthetic oil, per barrel	99.54	‒	‒	‒	99.54	‒
Synthetic gas, per thousand cubic feet	8.24	‒	‒	‒	8.24	‒
Average production costs, per barrel – total	17.26	17.29	30.79	6.93	17.22	9.40
During 2012
Average production 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
During 2011
Average production prices
Oil, per barrel	102.24	74.03	107.02	114.65	101.52	89.40
Natural gas, per thousand cubic feet(1)	8.83	3.16	4.72	‒	8.27	‒
Synthetic oil, per barrel	98.94	‒	‒	‒	98.94	‒
Synthetic gas, per thousand cubic feet	7.42	‒	‒	‒	7.42	‒
Average production costs, per barrel – total	13.08	12.61	12.43	6.29	12.89	14.57

(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 in 2011 and 2012. For 2013, this information includes operations in Africa (PO&G), as set out in note 10 to our audited consolidated financial statements.

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, 2013,  2012 and 2011 has been prepared in accordance with IFRS issued by the IASB. For more information, see “Presentation of Financial and Other Information” and Note 2 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-6 of this annual report.

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Overview

We earn income from:

·domestic sales, which consist of sales of oil products (such as 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 profit of investees, foreign exchange variation and inflation indexation gains on financial instruments.

Our expenses include:

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

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

·research and development 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:

·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);

·related 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;

·fluctuations in the real  vs. U.S. dollar exchange rates and, to a lesser degree, other currencies, as set out in note 34.2.2(c) to our audited consolidated financial statements; and

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

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Sales Volumes and Prices

The profitability of our operations in any particular accounting period is related to the sales volume of, and prices for, 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 2013 totaled 1,384,616 thousand barrels of crude oil equivalent, representing U.S.$141,462 million in sales revenues, compared to 1,385,917 thousand barrels of crude oil equivalent, representing U.S.$144,103 million in sales revenues in 2012, and 1,355,309 thousand barrels of crude oil equivalent, representing U.S.$145,915 million in sales revenues in 2011.

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 we do not adjust our prices for gasoline, diesel and certain other oil products to reflect short-term volatility in the international markets.  As a result, our downstream margins may be significantly different than those of other integrated international oil companies within a given financial reporting period due to material rapid or sustained increases or decreases in the international price of crude oil and oil products, or in the real  vs. U.S. dollar exchange rate.

The average prices of Brent crude, an international benchmark oil, were approximately U.S.$108.66 per barrel in 2013, U.S.$111.58 per barrel in 2012 and U.S.$111.27 per barrel in 2011.  In December 2013, Brent crude oil prices averaged U.S.$110.81 per barrel. However, due to the devaluation of the real  throughout the year of 2013, the average price of the Brent crude, when expressed in reais, went from R$217.47 per barrel during 2012 to R$234.52 per barrel during 2013.

In November 2011, we announced price increases at the refinery gate (the wholesale price we sell to distributors) of 10% for gasoline and 2% for diesel to partially adjust to higher international oil product prices. During 2012, we announced further price increases at the refinery gate totaling 7.8% for gasoline and 10.2% for diesel when compared to December 31, 2011 prices. During 2013, we announced further price increases at the refinery gate totaling 10.9% for gasoline and 19.6% for diesel when compared to December 31, 2012 prices.

                In November 2013, our board of directors announced the following principles and objectives for our diesel and gasoline pricing policy:

·Ensure that our indebtedness and leverage ratios return to the limits established under our 2013 - 2017 Business and Management Plan no later than December 2015, considering the growth of our oil production and the application of our diesel and gasoline pricing policy;

·Achieve, in a compatible time period, an alignment between Brazilian and international diesel and gasoline prices; and

·Prevent transferring the volatility of diesel and gasoline international prices to the domestic consumer.

During 2013, approximately 75.3% of our sales revenues were derived from sales of oil products, natural gas and other products in Brazil, compared to 69.7% in 2012 and 67.8% in 2011. 

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	For the Year Ended December 31,
	2013			2012			2011
	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	359,266	115.30	41,435	343,063	112.39	38,558	321,106	123.09	39,524
Automotive gasoline	215,419	109.00	23,470	208,695	111.54	23,277	178,471	122.96	21,945
Fuel oil (including bunker fuel)	35,588	97.30	3,464	30,896	92.71	2,864	29,813	97.81	2,916
Naphtha	62,520	94.10	5,885	60,331	95.23	5,745	61,034	94.18	5,748
Liquefied petroleum gas	84,281	47.00	3,960	81,992	50.32	4,126	81,636	59.85	4,886
Jet fuel	38,751	143.30	5,553	38,896	150.72	5,862	37,010	148.71	5,504
Other oil products	74,068	77.80	5,760	72,969	81.67	5,959	68,780	98.83	6,797
Subtotal oil products	869,893	102.90	89,527	836,842	103.20	86,393	777,849	112.30	87,320
Natural gas (boe)	149,277	49.40	7,376	130,544	50.41	6,580	110,042	51.80	5,701
Ethanol, nitrogen products, renewables and other non-oil products	33,346	146.00	4,868	30,369	132.60	4,027	31,413	141.56	4,447
Electricity, services and others	−	−	4,693	‒	‒	3,498	‒	‒	1,473
Total domestic market	1,052,516	−	106,464	997,755	‒	100,497	919,305	‒	98,941
Exports	144,111	105.30	15,172	203,234	109.99	22,353	231,086	106.66	24,649
International sales	187,989	105.50	19,826	184,928	114.92	21,253	204,919	108.95	22,325
Total international market	332,100	−	34,998	388,162	‒	43,606	436,004	‒	46,974
Consolidated sales revenues	1,384,616	−	141,462	1,385,917	‒	144,103	1,355,309	‒	145,915

(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 principal 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 25% and a social contribution tax at an effective rate of 9%, the standard corporate tax rate in Brazil. 

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

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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 5.91% in 2013, 5.84% in 2012 and 6.50% in 2011 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, including an increase in finance expenses, as part of our indebtedness is inflation-indexed.

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 prevailing throughout the year, the U.S. dollar depreciated against the real  each year, except for 2009. In 2013, the U.S. dollar appreciated 10.4% against the real, compared to an appreciation of 14.3% in 2012 and a depreciation of 5.1% in 2011.

 Fluctuations in exchange rate have multiple effects in 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 upon our margins, is affected by our pricing policy in Brazil.  When the real appreciates against the U.S. dollar and we do not adjust our price in Brazil, our margins generally improve. When the real  depreciates against the U.S. dollar and we do not adjust our prices in Brazil, margins generally decline.

                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 32.2.2(c) to our audited consolidated financial statements provides further information about our foreign exchange exposure related to assets and liabilities.

                Effective mid-May 2013 we 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 the Company’s 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 permits that gains and losses arising from the effect of changes in the foreign currency exchange rate on the hedging instruments not be immediately recognized as profits or losses, but rather in other comprehensive income in shareholder’s equity and then reclassified from equity to profit or loss in the periods during which the hedged transactions occur. See notes 3.3.6 and 34.2.2 to our audited consolidated financial statements for further information about our cash flow hedge.

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To the extent that our indebtedness in long-term debt obligations denominated in U.S. dollars continues to increase, we will only be able to create additional cash flow hedging relationships with such additional debt if we are capable of increasing our production, and subsequently, our highly probable future monthly export revenues in U.S. dollars.

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 prices at which we sell our crude oil, oil products and natural gas and the relationship of those prices to 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.

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 Society of Petroleum Engineers (SPE) criteria, which are the criteria we apply to analyze our operating results:

	2013	2012	2011
Crude oil and NGL production (mbbl/d):
Brazil	1,931	1,980	2,022
International	109	139	140
Non-consolidated international production(1)	19	7	8
Total crude oil and NGL production	2,059	2,126	2,170
Change in crude oil and NGL production	(3.2)%	(2.0)%	0.6%
Average sales price for crude (U.S.$/barrel):
Brazil	98.19	104.60	102.24
International	89.86	94.37	91.37
Natural gas production (mmcf/d) (2):
Brazil	2,336	2,250	2,130
International	546	582	582
Total natural gas production	2,882	2,832	2,712
Change in natural gas production (sold only)	1.8%	4.4%	5.9%
Average sales price for natural gas (U.S.$/mcf) (2):
Brazil	7.90	8.08	8.83
International	3.51	3.00	2.88
Year-end exchange rate (reais/U.S.$)	2.34	2.04	1.88
Appreciation (depreciation) during the year(3)	(14.8)%	(8.5)%	(12.6)%
Average exchange rate for the year (reais/U.S.$)	2.16	1.96	1.67
Appreciation (depreciation) during the year(4)	(10.4)%	(14.3)%	5.1%
Inflation rate (IPCA)	5.9%	5.8%	6.5%

(1)                  Non-consolidated companies in Venezuela and, as from June 2013, companies in Africa, as set out in note 10 to our audited consolidated financial statements.

(2)                  Amounts were converted from bbl to cubic feet in accordance with the following scale: 1 bbl = 6 cubic feet.

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

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

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Virtually all of our revenues and expenses for our Brazilian operations are denominated and payable in Brazilian reais. When the U.S. dollar strengthens relative to the Brazilian real, as it did in 2013 and 2012 (with an appreciation of 10.4% and 14.3% 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 comparisons between our results of operations in 2013 and in 2012, and between our results of operations in 2012 and 2011, 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, 2013, for more information about the translation of real  amounts into U.S. dollars.

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 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.$108,254 million from U.S.$107,534 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 imports 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;

·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 in 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 Operating Income and Expenses

The 47% decrease in our net other operating expenses in 2013 when compared to 2012 (U.S.$ 2,237 million vs. U.S.$4,185 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 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 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 3.3.6 and 34.2.2 (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 3.2 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	(8,162)	(11,718)	(30) %
Gas and Power	631	861	(27)%
Biofuel	(117)	(112)	4%
Distribution	876	914	(4)%
International	1,729	719	140%
Corporate(2)	(3,331)	(2,565)	30%
Eliminations	(55)	(471)	(88)%
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 inactive participants.

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

Refining, Transportation and Marketing (RTM) purchases crude oil from E&P and imports oil to blend with our domestic oil.  Additionally, RTM purchases oil products in the international markets to meet excess product demand in the domestic market.  Those purchases are made at international prices, either from E&P or from international markets, and the products are sold in Brazil at a price that we expect will converge to international prices in the long run. For some of our products, mainly gasoline, diesel and residential LPG, however, the prices in Brazil can lag the international markets.

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). 

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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.

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 4% 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, however 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 PRODESIN, our 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 30 to our audited consolidated financial statementsfor further information regarding our business segments.

Results of Operations—2012 compared to 2011

Sales Revenues

Sales revenues decreased by 1% to U.S.$144,103 million in 2012 compared to U.S.$145,915 million in 2011. This decrease was principally a result of the appreciation of the U.S. dollar against the Brazilian real. 

Excluding foreign currency exchange effects, local currency sales revenues increased by 15%, driven by:

· Higher domestic prices for oil products due to increased gasoline and diesel prices and to the impact of the appreciation of the U.S. dollar against the Brazilian real  on oil products (mainly jet fuel) that were adjusted to reflect international prices; and

·An 8% increase in domestic sales volumes, mainly attributable to the increase of sales volumes of gasoline (17%), diesel (6%), jet fuel (5%) and natural gas (17%), partially offset by lower crude oil exports volumes due to higher feedstock processed and to the lower crude oil production.

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Cost of Sales

Cost of sales increased by 8%  to U.S.$107,534 million in 2012 compared to U.S.$99,595 million in 2011.

Excluding foreign currency exchange effects, local currency cost of sales increased by 26%, driven by:  

·An 8% increase in domestic sales volumes of oil products, mainly met by higher import volumes;

·Higher crude oil and oil products import costs due to higher import volumes, as well as higher production costs;

·Higher depreciation, depletion and amortization costs due to the operational start-up of new facilities;

Selling Expenses

Selling expenses decreased by 8% to U.S.$4,927 million in 2012 compared to U.S.$5,346 million in 2011 due to the appreciation of the U.S. dollar against the Brazilian real.  

Excluding foreign currency exchange effects, selling expenses increased by 7% in 2012 compared to 2011, primarily as a result ofhigher freight costs driven by the increase of sales volumes.

Administrative and General Expenses

Administrative and general expenses decreased by 2% to U.S.$5,034 million in 2012 compared to U.S.$5,161 million in 2011.

Excluding foreign currency exchange effects, administrative and general expenses increased by 14% in 2012 compared to 2011. This increase was principally a result of higher employee compensation expenses arising from the 2011 and 2012 Collective Bargaining Agreements, a larger workforce and increased third-party technical services.

Exploration Costs

Exploration costs increased by 52% to U.S.$3,994 million in 2012 compared to U.S.$2,630 million in 2011. This increase was primarily attributable to higher write-offs of dry or sub-commercial wells.

Research and Development Expenses

Research and development expenses decreased by 21% to U.S.$1,143 million in 2012 compared to U.S.$1,454 million in 2011. This decrease was principally a result of the appreciation of the U.S. dollar. Excluding foreign currency exchange effects, R&D expenses decreased by 8%, due to lower costs with the submarine water-oil separation project (SSAO) in 2012.

Other Operating Income and Expenses, Net

Other operating expenses, net increased by 5% to U.S.$4,185 million in 2012 compared to U.S.$3,984 million in 2011. This increase was principally a result of higher costs due to increased losses on legal and administrative proceedings.

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Net finance income (expense)

Net finance expense reachedU.S.$1,926 million in 2012, compared to a net finance income of U.S.$76 million in 2011.  This decrease was principally a result of the effect of the appreciation of the U.S. dollar against the real over a higher net debt.

Non-Controlling Interests

Non-controlling interests decreased to U.S.$103 million in 2012 compared to U.S.$129 million in 2011. 

Net Income (Loss) by Business Segment

We measure performance at the segment level on the basis of net income.  The following is a discussion of the net income of our six business segments at December 31, 2012, compared to December 31, 2011.

	Year Ended December 31,
	2012(1)	2011(1)	Percentage Change
	(U.S.$ million)		(%)
Exploration and Production	23,406	24,326	(3.8)
Refining, Transportation and Marketing	(11,718)	(5,718)	104.9
Gas and Power	861	1,862	(53.8)
Biofuel	(112)	(95)	17.9
Distribution	914	774	18.1
International	719	1,179	(39.0)
Corporate(2)	(2,565)	(721)	255.8
Eliminations	(471)	(1,486)	(68.3)
Net income	11,034	20,121	(45.2)
__________

(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 inactive participants.

Exploration and Production

Exploration and Production net income decreased by 3.8% due to the appreciation of the U.S. dollar against the real.  

Excluding foreign currency exchange effects, local currency net income on exploration and production increased by 12%, due to increased domestic crude oil prices (sales/transfer), reflecting the depreciation of the real  against the U.S. dollar and lower impairment charges. These effects were partially offset by lower production levels, higher maintenance and repair costs related to wells, freight costs for oil platforms, depreciation of equipment and production taxes due to the start-up of new systems/wells, as well as by higher write-offs of dry or sub-commercial wells mainly drilled between 2009 and 2012 (at higher costs), especially in areas of new exploratory frontiers.

The spread between the average domestic oil price (sale/transfer) and the average Brent price diminished from US$9.03/bbl in 2011 to US$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.

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Refining, Transportation and Marketing

  Refining, Transportation and Marketing, or RTM, purchases crude oil from E&P and imports oil to blend with our domestic oil.  Additionally, RTM purchases oil products in the international markets to meet excess product demand in the domestic market.  RTM acquires crude oil and oil products at the international price, either from E&P or from international markets, and sells products in Brazil at a price that we expect will equal international prices in the long run. For some of our products, principally gasoline, diesel and residential LPG, however, the prices in Brazil can lag the international markets.

Our RTM segment net losses increased by 104.9% due to the impact of the appreciation of the U.S. dollar on crude oil costs (acquisition/transfer) and oil product costs (imports), and also due to higher oil product import volumes (mainly gasoline and diesel). These effects were partially offset by an increase of 7% in export sales prices and a 5% increase in oil product outputs. Excluding foreign currency exchange effects, domestic sales prices increased by 11% in 2012.

Gas and Power

Our Gas and Power segment net income decreased by 53.8% due to lower margins on natural gas sales, driven by the impact of the appreciation of the U.S. dollar on LNG import costs and higher LNG imports volumes to meet the domestic thermoelectric increased demand, and also by the positive impact of tax credits in 2011 (U.S.$554 million). These effects were partially offset by higher average electricity prices and increased sales volumes, attributable to lower water reservoir levels at the hydroelectric power plants located in Brazil, driven by lower rainfall levels in all Brazilian regions.

Biofuel

Our biofuel operations net losses increased by 17.9% due to the negative results of invested companies in the ethanol sector and by an increase in research and development expenses, mainly related to second generation ethanol. The net losses on biofuel operations in 2012 were partially offset by the positive effect of the changes in biodiesel auction rules in the fourth quarter of 2011.

Distribution

Our Distribution segment net income increased by 18.1% mainly due to an increase in sales margins in 2012 compared with 2011. Our gross margins improved in 2012 because we did not experience the negative factors that affected our margins in 2011, mainly related to losses resulting from the sale of inventory due to the volatility of the ethanol prices, and to a 4% increase in sales volumes, as well as improved operational efficiency.

The Distribution segment accounted for 38.1% of the sales volume of the national fuel distribution market in 2012, compared to 39.2% in 2011.

International

Our International segment net income decreased by 39% mainly due to impairment losses (that amounted to U.S.$225 million)  in the Pasadena refinery in the United States.

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Additional Business Segment Information  

Additional selected financial data by business segment for 2013, 2012 and 2011 is set out below:

	For the Year Ended December 31,
	2013	2012	2011
	(U.S.$ million)
Exploration and Production
Sales revenues to third parties(1)(2)	1,114	843	516
Intersegment net revenues	67,096	73,871	73,601
Total sales revenues(2)	68,210	74,714	74,117
Net income (loss)(3)	19,523	23,406	24,326
Capital expenditures and investments	27,566	21,959	20,405
Property, plant and equipment	126,716	102,779	90,633
Refining, Transportation and Marketing
Sales revenues to third parties(1)(2)	72,948	78,760	80,484
Intersegment sales revenues	38,103	37,950	38,146
Total sales revenues(2)	111,051	116,710	118,630
Net income (loss)(3)	(8,162)	(11,718)	(5,718)
Capital expenditures and investments	14,243	14,745	16,133
Property, plant and equipment	66,200	63,463	54,629
Gas and Power
Sales revenues to third parties(1)(2)	12,826	10,515	8,434
Intersegment sales revenues	1,191	1,288	1,304
Total sales revenues(2)	14,017	11,803	9,738
Net income (loss)(3)	631	861	1,862
Capital expenditures and investments	2,716	2,113	2,293
Property, plant and equipment	20,882	21,585	21,968
Biofuel
Sales revenues to third parties(1)(2)	64	90	32
Intersegment sales revenues	324	365	288
Total sales revenues(2)	388	455	320
Net income (loss)(3)	(117)	(112)	(95)
Capital expenditures and investments	143	147	294
Property, plant and equipment	222	255	285
Distribution
Sales revenues to third parties(1)(2)	40,370	39,834	43,270
Intersegment sales revenues	995	878	731
Total sales revenues(2)	41,365	40,712	44,001
Net income (loss)(3)	876	914	774
Capital expenditures and investments	514	666	679
Property, plant and equipment	2,672	2,733	2,510
International
Sales revenues to third parties(1)(2)	14,140	14,061	13,179
Intersegment sales revenues	2,162	3,868	3,777
Total sales revenues(2)	16,302	17,929	16,956
Net income (loss)(3)	1,729	719	1,179
Capital expenditures and investments	2,368	2,572	2,631
Property, plant and equipment	7,971	10,882	9,871

(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 are for capital expenditures, dividend payments and repayment of debt.  In 2013, we met these requirements with internally generated funds, long-term debt, short-term debt, divestments and also by a reduction in our marketable securities.  In 2014, our major cash needs are for our budgeted capital expenditures, the announced dividends for the year ended December 31, 2013 of U.S.$3,970 million as well as principal and interest payments of U.S.$12,283 million on our long-term debt. 

Financing Strategy

The objective of our financing strategy is to fund the capital expenditures needed to achieve the targets set forth in our 2014-2018 Plan, released on February 25, 2014. The 2014-2018 Plan calls for expenditures of U.S.$220.6 billion during that period, of which U.S.$206.8 billion is for projects already being implemented or under a bidding process, and the remaining U.S.$13.8 billion is for the portfolio under evaluation with projects that are still in the planning phase of development and subject to further approvals by our management.  

In order to reach the targets set forth in our 2014-2018 Plan, we will 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, supplier financing and bank financing. We plan to maintain our current debt maturity profile.

In 2013, a portion of our funding requirements was met by the disposal of assets through our divestment program (PRODESIN). Proceeds from disposals of assets amounted to U.S.$3,820 million in 2013, and we expect to receive additional proceeds in 2014 from transactions pending completion.  See note 10 to our audited consolidated financial statements for further information regarding such disposals of assets.

For 2014, we intend to meet our funding requirements through a combination of new debt from a broad range of traditional funding sources, including international debt capital markets, export credit agencies, non-Brazilian government development banks, the BNDES, and Brazilian and international commercial banks, drawing down our year-end cash balances and existing credit facilities. As of April 30, 2014, we have financed part of our needs (in a total amount of U.S.$21.3 billion) from various funding sources, including commercial banks, capital markets and development banks (such as BNDES).

Government Regulation

We are required to submit our annual capital expenditures budget (Plano de Dispêndio Global, or PDG) to the Brazilian Ministry of Planning, Budget and Management, and the MME.  Following review by these agencies, 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 Brazilian Ministry of Planning, Budget and Management 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 issuing medium and long-term debt, we and our Brazilian subsidiaries must also obtain the approval of the National Treasury Secretariat.  Borrowings that exceed the approved budgeted amount for any year also require approval of the Brazilian Senate.  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.

However, the issuance of debt by our non-Brazilian subsidiaries, including PifCo and PGF, is not subject to registration with the Central Bank or approval by the National Treasury Secretariat. All issuances of medium and long-term notes and debentures require the approval of our board of directors.

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Sources of Funds

Our Cash Flow

In 2013, the resources needed to fund our capital expenditures (U.S.$45,163 million) and payment of dividends (U.S.$2,656 million) were met by cash flow from operations (U.S.$26,289 million), net proceeds from long-term financing (U.S.$16,021 million), cash provided by the disposal of assets (U.S.$3,820 million), as well as a reduction in our balance of government bonds with maturities of more than 90 days (U.S.$6,334 million).

Net cash provided by operating activities in 2013 increased by 4% in local currency (excluding the foreign currency translation effect), as a result of increases in diesel and gasoline prices in the domestic market during 2013 and the increase in outputs of refined products (6%), which contributed to a reduction in oil product import volumes. These effects were partially offset by the impact of the depreciation of the real  on import costs and by lower crude oil export volumes. When translated into U.S. dollars, cash provided by operations decreased from U.S.$27,888 million in 2012 to U.S.$26,289 million in 2013.

Proceeds from long-term financing, net of repayments, totaled U.S.$16,021 million in 2013, an increase of U.S.$6,935 million when compared to 2012. The principal sources of long-term financing were the issuance of six series of U.S. dollar bonds totaling approximately U.S.$11 billion in the international capital markets in May 2013, and long-term financing from foreign and Brazilian financial institutions.

Proceeds from disposals of assets throughout 2013 totaled U.S.$3,820 million. These divestments were the result of our PRODESIN divestment program, with the majority of the proceeds coming from the disposal of 50% of our interest in operations in Africa (through the formation and partial sale of a joint venture combining our African assets) and the disposal of our interest in block BC-10, located in Brazil.

The uses of cash were primarily for capital expenditures and investments in operating units, which totaled U.S.$45,163 million in 2013 compared to U.S.$40,706 million in 2012. Higher expenditures in E&P (U.S.$5,200 million), including U.S.$2.6 billion related to acquisition costs of rights over the Libra block in the pre-salt area, were largely responsible for the increase.

Payment of dividends during 2013 totaled U.S.$2,656 million.

As of December 31, 2013, our balance of cash and cash equivalents amounted to U.S.$15,868 million, compared to U.S.$13,520 million as of December 31, 2012. Our balance of government bonds with maturities of more than 90 days decreased from U.S.$10,212 million as of December 31, 2012 to U.S.$3,878 million as of December 31, 2013.

Short-Term Debt

Our outstanding short-term debt serves mainly to support our working capital and our imports of crude oil and oil products. As of December 31, 2013, our total short-term debt amounted to U.S.$3,654 million and the current portion of our long-term debt amounted to U.S.$3,118 million, compared to U.S.$3,666 million and U.S.$2,795 million as of December 31, 2012, respectively.

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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.$106,235 million as of December 31, 2013, compared to U.S.$88,484 million as of December 31, 2012.  This increase was primarily due to funding from the domestic and international banking markets and from the issuance of U.S. dollar denominated bonds. These financial resources will be used primarily for the development of projects related to oil and gas production, for the construction of vessels and pipelines, as well as for the construction and expansion of industrial plants.  See note 17 to our audited consolidated financial statements for a breakdown of our debt by source and other information.

Included in these figures at December 31, 2013 are the following international debt issues:

Notes(*)/(**)	Carrying amount as of December 31, 2013
	(U.S.$ million)
PifCo’s 2.875% Global Notes due 2015	1,247
PifCo’s 2.150% Japanese Yen Bonds due 2016(1)	328
PifCo’s 3.875% Global Notes due 2016	2,494
PifCo’s 6.125% Global Notes due 2016	878
PGF’s 2.000% Global Notes due 2016	1,244
PGF’s Floating Rate Global Notes due 2016(2)	998
PifCo’s 3.500% Global Notes due 2017	1,741
PESA’s 5.875% Notes due 2017	300
PifCo’s 4.875% Global Notes due 2018(3)	1,710
PifCo’s 5.875% Global Notes due 2018	1,741
PifCo’s 8.375% Global Notes due 2018	573
PifCo’s 7.875% Global Notes due 2019	2,781
PGF’s 3.000% Global Notes due 2019	1,984
PGF’s 3.250% Global Notes due 2019(4)	1,781
PGF’s Floating Rate Global Notes due 2019(5)	1,496
PifCo’s 5.750% Global Notes due 2020	2,479
PifCo’s 5.375% Global Notes due 2021	5,326
PifCo’s 5.875% Global Notes due 2022(6)	820
PGF’s 4.250% Global Notes due 2023(7)	948
PGF’s 4.375% Global Notes due 2023	3,452
PifCo’s 6.250% Global Notes due 2026(8)	1,134
PGF’s 5.375% Global Notes due 2029(9)	725
PifCo’s 6.875% Global Notes due 2040	1,471
PifCo’s 6.750% Global Notes due 2041	2,372
PGF’s 5.625% Global Notes due 2043	1,710

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

(**) On January 14, 2014, PGF issued four tranches of notes totaling U.S.$5.09 billion (after expenses) (€3.05 billion and £600 million aggregate principal amounts of guaranteed senior notes) and on March 17, 2014, PGF issued six tranches of notes totaling U.S.$8.5 billion (after expenses).

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

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

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

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

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

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

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

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Off Balance Sheet Arrangements

As of December 31, 2013, 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.

Uses of Funds

Capital Expenditures and Investments

We invested a total of U.S.$48,097 million in 2013, a 12% increase, when compared to our investments of U.S.$42,949 million in 2012. Our investments in 2013 were primarily directed toward increasing oil and gas production, as well as modernizing and expanding our refineries. Of our total capital expenditures in 2013, U.S.$27,566 million was invested in exploration and development projects in Brazil.

The following table sets forth our consolidated capital expenditures for each of our business segments for 2013, 2012 and 2011:

	For the Year Ended December 31
	2013	2012	2011
	(U.S.$ million)
Exploration and Production	27,566	21,959	20,405
Refining, Transportation and Marketing	14,243	14,745	16,133
Gas and Power	2,716	2,113	2,293
Biofuel	143	147	294
Distribution	514	666	679
International
Exploration and Production	2,126	2,347	2,340
Refining, Transportation and Marketing	156	131	189
Gas and Power	26	5	31
Distribution	52	72	58
Others	8	17	13
Corporate	547	747	729
Total	48,097	42,949	43,164

On February 25, 2014, we announced our 2014-2018 Plan, which contemplates total budgeted capital expenditures of U.S.$220.6 billion from 2014 to 2018, U.S.$206.8 billion of which is for projects already being implemented or under a bidding process, while U.S.$13.8 billion is for the portfolio under evaluation with projects that are still in the planning phase of development and subject to further approvals by our management.   

We expect that U.S.$153.9 billion of the capital expenditures in our 2014-2018 Plan will be directed towards exploration and production segment in Brazil, totaling U.S.$162.9 billion when also considering our activities abroad. Our capital expenditure budget for 2014, including our project financings, is U.S.$42.4 billion.

We plan to meet our budgeted capital expenditures primarily through internally generated cash, issuances in the international capital markets, structured facilities and project finance loans, commercial bank loans, divestments 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.

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Dividends

For 2013, our board of directors approved the payment of dividends, in the form of interest on capital (before withholding income taxes), in the total amount of R$9,301 million (U.S.$3,970 million, when expressed at the exchange rate on the balance sheet date). This amount is equivalent to R$0.5217 (U.S.$0.2227) per common share, R$0.9672 (U.S.$0.4129) per preferred share, R$1.0434 (U.S.$0.4454) per common ADS and R$1.9344 (U.S.$0.8257) per preferred ADS.  Dividends for 2013 represent a total of 41.85% of our adjusted net income in reais  (adjusted in accordance with Brazilian Corporation Law) and their distribution was approved by our annual general shareholders’ meeting on April 2, 2014. Interest on capital was distributed to our shareholders on April 25, 2014.

For more information on our dividend policy, including a description of the minimum preferred 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.

Contractual Obligations

The following table summarizes our outstanding contractual obligations and commitments at December 31, 2013:

	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)	114,236	8,001	19,958	24,730	61,547
Finance lease obligations	89	9	15	17	48
Decommissioning costs	7,133	-	221	60	6,852
Total balance sheet items	121,458	8,010	20,194	24,807	68,447
Other long-term contractual commitments
Natural gas ship-or-pay	3,184	541	1,046	1,062	535
Service contracts	56,407	25,138	19,763	6,299	5,208
Natural gas supply agreements(3)	12,056	2,259	4,124	3,940	1,734
Operating leases	52,091	14,683	16,081	8,107	13,219
Purchase commitments	19,779	7,532	8,473	2,784	990
Total other long-term commitments	143,518	50,153	49,486	22,192	21,687
Total	264,976	58,164	69,680	46,999	90,134

(1)                Excludes U.S.$35,308 million related to our pension and medical benefits obligations, which are partially funded by U.S.$22,735 million in plan assets and U.S.$7,133 million related to our provision for decommissioning costs. Information on employees’ postretirement benefit plans (including the expected maturity analysis of pension and medical benefits, set out in note 22.5 (c) to our audited consolidated financial statements) and on the provision for decommissioning costs are set forth in notes 22 and 20, respectively, to our audited consolidated financial statements.

(2)                Includes accrued interest, short-term debt and long-term debt (current and noncurrent portions).

(3)                Amounts assume that the counterparty would not fulfill certain precedent conditions in the agreement.

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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 4 to our audited consolidated financial statements (comprising oil and gas reserves, depreciation and impairment; pension and other post-retirement obligations; contingent liabilities and provisions; derivative financial instruments and hedge accounting). Additional information about our accounting policies and new amendments and standards are provided in notes 3 and 5 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 dismantling of areas and environmental remediation, as well as impairment testing of refining assets and pension and medical benefits.

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.

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.

In 2013, our provision for decommissioning costs decreased by U.S.$2.30 billion as a result of our annual revision and of payments made for decommissioning.

We reviewed and revised our estimated costs associated with well abandonment and the demobilization of oil and gas production areas. As a result, for 2013, there was a U.S.$0.9 billion decrease in the amounts related to the revision of the provision, attributable to:

a)  a U.S.$1.63 billion decrease attributable to an increase in our risk-adjusted discount rate (from 2.31% p.a. at December 31, 2012 to 3.03% p.a. at December 31, 2013) used for discounting future obligations to present value; and

b) a U.S.$0.7 billion decrease attributable to revised abandonment estimates, which incorporate recent technologies and procedures in the industry, including the adoption of the light workover technique to abandon part of offshore wells.

Those effects were partially offset by a U.S.$1.21 billion increase attributable to the devaluation of the real  in relation to the U.S dollar (from R$2.0435 on December 31, 2012 to R$2.3426 on December 31, 2013).

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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.

For more information about the annual changes in the decommissioning provisions, please refer to note 20 to our audited consolidated financial statements.

Impairment Testing of Refining Assets

                Value in use is the method used in the impairment testing of our refining assets, which are included in a single cash generating unit (“CGU”) comprising all of our refineries and associated assets, terminals and pipelines 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. All decisions concerning this CGU (operation, investments, and market strategy) seek to maximize the value of the whole system and not to improve the results of each constituent part. Pipelines and terminals are also an interdependent portion of the refining assets, in order to supply the market.

                The assessment of the value in use of an asset involves the use of estimates on uncertain assumptions, such as future production curves, future commodity prices, sales revenues growth, operating margins, discount rates, foreign exchange rates, inflation rates and investments required for carrying out projects. No impairment charges were recognized for 2013.

                The key assumptions on which we based our cash flow projections to determine the value in use of our refining CGU were derived from our business and management plan, and are described following:

                · estimated average exchange rate of R$2.23 to U.S.$1.00 in 2014 (converging to R$1.87 vs. U.S.$1.00 in the long term);

                · Brent crude oil price of U.S.$105 for 2014, declining to U.S.$95 in the long term;

                · domestic sales volumes growth based on projected Brazilian and global G.D.P growth;

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

                · pre-tax discount rate derived from our weighted average cost of capital (reviewed annually).

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

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

For more detailed information about our impairment policies, please refer to Notes 3.10, 4.2 and 14 to our audited consolidated financial statements as of December 31, 2013.

Pension and other post-retirement benefits

                We currently provide post-retirement benefits to our employees mainly through Petros and Petros 2 pension plans and AMS health care plan, as well as other plans sponsored by our Brazilian and International subsidiaries, as described in note 22 to our audited consolidated financial statements.

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                Changes in actuarial assumptions, including changes in the discount rate used, may significantly impact our pension obligations. Our pension and medical obligations decreased from U.S.$47,909 million as of December 31, 2012 to U.S.$35,308 million as of December 31, 2013, mainly due to a U.S.$10.6 billion impact of the remeasurement of financial assumptions (which resulted mainly from an increase in our nominal discount rate).

                Our nominal discount rates (before adjustments for inflation) for our pension plans Petros and Petros 2, and for our health care plan (AMS) are determined based on a weighted average of the Brazilian Government inflation-indexed Bonds (NTN-B), for our post-retirement benefits obligations duration. Long-term NTN-B interest rates increased from a 2.58% - 4.06% range in 2012 to a 5.96% - 6.73% range in 2013, resulting from an increase in the Brazilian target domestic interest rate (SELIC), which strongly affects NTN-Bs.

                The increase in our nominal discount rates from 9.35%, 9.35% and 9.42% in 2012 to 12.88%, 12.97% and 12.90% in 2013, respectively for each pension and health care plans, followed an increase in the aforementioned Brazilian interest rates in Brazil, as well as an increase in short term inflation projections from 5.42% in 2012 to 5.93% in 2013, based on a higher expected inflation in Brazil.

                 See note 22.5(c) to our audited consolidated financial statements for a sensitivity analysis of the impact of a 100 basis point change in actuarial assumptions over our post-retirement benefits obligations.

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 spend 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 2013, we spent U.S.$1,132 million on research and development, equivalent to 0.8% of our sales revenues, while in 2012, we spent U.S.$1,143 million, equivalent to 0.8% of our sales revenues, and in 2011, we spent U.S.$1,454 million, equivalent to 1.0% of our sales revenues.

Our research and development activities focus on three main goals:

(1)           Expansion of our current businesses through the:

(a) discovery of new exploratory frontiers through comprehensive, basin-scale geological and geophysical investigations of Brazilian frontier areas, both onshore and offshore, and implementation of innovative seismic processing and inversion algorithms;

(b) enhancement of oil and gas final recovery by the use of innovative sea water, CO₂ and polymer injection systems;

(c) enhancement of the pre-salt production systems and its reservoirs’ final recovery by intensive usage of compact subsea solutions, injection systems and the capacity enhancement of the new pre-salt FPSO units;

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(d) development of new or enhanced subsea production systems and equipment for deep and ultra-deep waters based on compact subsea oil/water/gas separation, sea floor produced water re-injection, improved gas-lift technology, sea floor oil boosting and gas compression and a new generation of electrical submersible pumps;

(e) optimization and development of drilling and production solutions for unconventional reservoirs, shale gas, gas hydrates, coal bed methane, tight gas and shale oil, by geophysical investigations of the Brazilian onshore frontier areas and well design optimization through cost effective and currently available technologies;

(f) optimization of our natural gas logistics and final usage, through the development of solutions for offshore and stranded gas, such as chemical conversion, compression and subsea to shore, and the optimization of our onshore assets;

(g) application of available up-to-date logistic technologies to improve our integrated offshore operations;

(h) optimization of the Brazilian oil and derivatives supply and the exportation of oil and its derivatives;

(i) development of technologies and mixing devices to optimize the refining processes for pre-salt oils, such as desalter operation; and

(j) development of technologies to enhance the flexibility of middle distillates or gasoline, in order to meet market demands;

(2)           Providing a mix of products compatible with the energy demands of the future through the:

(a) development of new fuels, lubricants and special product formulations such as podium diesel and podium gasoline;

(b) development of low sulfur fuels such as Diesel S-10 and Gasoline S-50, with additional quality improvements by the introduction of new benefits such as lower engine pollutant emissions, cleaner engine parts and higher oxidation stability;

(c) development of new technologies for petrochemical activities such as catalyst systems for polypropylene and ethylene production from olefins and polystyrene and polyester (raw materials and polymers) from both fossil and renewable sources;

(d) optimization of our ammonia and urea production plants through advanced real-time process control optimization and development of new technologies for urea based fertilizers and ruminant feedstock, through mixed fertilizer formulations with micronutrients;

(e) development of competitive second generation biofuel production processes, which use residual biomass as feedstock, through biochemical and thermochemical routes such as pyrolysis and gasification; and

(f) optimization of our thermoelectric power plants, with emphasis on operation and maintenance cost reduction, and research and development on renewable energy technologies, such as concentrated solar, photovoltaic and wind power;

(3)           Ensuring that our activities are environmentally sustainable. We aim throughout our entire business to:

(a) reduce water consumption and the volume and toxicity of wastewater discharges, by the selection and development of new chemical products and formulations and by water re-use increase through an extensive portfolio of primary, secondary and tertiary treatment routes;

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(b) reduce our emissions of air pollutants, CO₂ and other greenhouse gases based on intensive re-injection of CO₂ into our production reservoirs, selection and development of technologies for pollutants abatement and carbon capture storage and sequestration;

(c) increase the energy efficiency of our processes and products through research and development in combustion, heat transfer processes and advanced thermal cycles;

(d) prevent and mitigate the environmental impact of our activities through extensive offshore research in deepwater biodiversity characterization and the development of innovative operation standards; and

(e) ensure the integrity, safety and reliability of all our industrial facilities, by the development and implementation of new materials and process equipment, online process and equipment integrity monitoring and diagnosis, inspection techniques, new process tuning systems, advanced control tools, real-time optimization and simulators for design and process analysis.

In the three-year period ended December 31, 2013, our research and development operations were awarded 97 patents in Brazil and 139 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 1966.  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, 2013, this facility had 1,959 employees, 91.3% 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 2013, 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

We plan to continue expanding all segments of operations in our target markets in accordance with our 2014-2018 Plan.  In support of this goal, we plan total capital expenditures of U.S.$220.6 billion over 2014-2018, U.S.$206.8 billion of which is for projects already being implemented or under a bidding process, while U.S.$13.8 billion is for the portfolio under evaluation with projects that are still in the planning phase of development and subject to further approvals by our management.  Of this total, approximately 70% is in the exploration and production segment (Brazil and abroad), where constant investment in exploration and development is needed to exploit newly discovered resources and offset natural declines in production from existing fields as they mature. 

We expect that the demand for oil products in Brazil will continue to increase driven primarily by economic growth and the increase in purchasing power of the population. In recent years, we met this incremental growth in demand by increasing imports of oil and oil products, as our oil production and our refining capacity was not sufficient to meet the increased demand. This increase in imports increased our cost of sales and decreased our margins in recent years, because we have not adjusted our domestic prices enough to reflect the higher cost of oil and oil products and the devaluation of the real.  We expect that our refining capacity expansion currently being implemented and our oil production growth will reduce our need to import oil and gas products to meet domestic demand, although as domestic demand continues to increase, we will need to consider whether to further expand our refining capacity.

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The price we realize for the oil we export is determined by international oil prices, although we generally sell our oil at a discount to Brent and other light oil benchmark prices because it is heavier and thus more expensive to refine.  In 2013, oil price trends were affected by political unrest in the Middle East and in North Africa as well as by fluctuations in macroeconomic conditions, primarily in Europe.  The Brent benchmark price experienced lower variation in 2013 as compared to 2012, with a minimum price of U.S.$96.79/bbl, a maximum price of U.S.$119.34/bbl and an average price of U.S.$108.66/bbl, the third-highest nominal Brent yearly average price ever recorded.  The economic outlook and continuing political turmoil in the Middle East and in North Africa will remain the key determinants of oil price trends in the short term.  A fast-paced recovery coupled with slow supply-side response can result in higher prices in the medium term.  On the other hand, if economic recovery expectations are not met, especially those regarding non-OECD (Organization for Economic Cooperation and Development) economies and there is an increase of the oil production in the U.S. (more supply of unconventional oil), oil prices may drop below current levels.  In addition, recent geopolitical concerns may persist, potentially driving prices higher in the short term.

For the 2014 to 2018 period, we plan to continue to focus on increasing our refining throughput and our capacity to refine heavier crudes.  The refining expansion program currently underway may improve our refining margins, since the new refineries will be able to process a heavier crude slate with lower costs while having a higher yield of middle distillate products  (primarily of diesel and jet fuel) with higher potential demand and growth margins. 

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.  The guidance provided by our board of directors is instrumental in this review process. For the 2014-2018 period, we have retained the targets for our net-debt-to-equity ratio in the range of 25% to 35%. For more information about our capital management, see note 34.3 to our audited consolidated financial statements.

Item 6.  Directors, Senior Management and Employees

Directors and Senior Management

Directors

Our board of directors is composed of a minimum of five and up to 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  threshold is 5%. Thus, shareholders representing 5% of our voting capital may demand the adoption of a cumulative voting procedure.

Specifically, pursuant to Law No. 12,353 and Act No. 026, an employee representative chosen by our active employees must be a member of our board of directors.

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Furthermore, our bylaws enable (i) minority preferred shareholders that together hold at least 10% of the total capital stock (excluding the controlling shareholders) to elect and remove one member to our board of directors; (ii) minority common shareholders to elect 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.  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, dated May 28, 2003, 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 under the cumulative vote procedure, the removal of any board member by an extraordinary meeting of shareholders will result in the removal of all 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
Guido Mantega(1)	April 7, 1949	Chair	March 2015	Esplanada dos Ministérios – Bloco P 5th. floor Brasília – DF Zip-code: 70.048-900
Maria das Graças Silva Foster(1)	August 26, 1953	Director	March 2015	Avenida República do Chile, no. 65 23rd. floor Rio de Janeiro – RJ Zip-code: 20.031-912
Miriam Aparecida Belchior(1)	February 5, 1958	Director	March 2015	Esplanada dos Ministérios – Bloco K 7th. floor Brasília – DF Zip-code: 70.040-906
Francisco Roberto de Albuquerque(1)	May 17, 1937	Director	March 2015	Alameda Carolina, no. 594 Itú – SP Zip Code: 13.306-410
Márcio Pereira Zimmermann(1)	July 1, 1956	Director	March 2015	Esplanada dos Ministérios – Bloco U Room 705 Brasília – DF Zip-code: 70.065-900
Luciano Galvão Coutinho(1)	September 29, 1946	Director	March 2015	Av. República do Chile, no. 100 22th. floor Rio de Janeiro – RJ Zip-code: 20.031-917
Sergio Franklin Quintella(1)	February 21, 1935	Director	March 2015	Praia de Botafogo, no. 190 12th. floor Rio de Janeiro – RJ Zip-code: 22.250-900
Mauro Gentile Rodrigues da Cunha(3)	November 6, 1971	Director	March 2015	Rua Joaquim Floriano, no. 1,120 – 10th. floor, Cj 101 – Itaim Bibi São Paulo – SP Zip-code: 04534-004
José Guimarães Monforte(2)	July 6, 1947	Director	March 2015	Rua dos Pinheiros, 870 – 20th. floor, Cj 201/202 – Pinheiros São Paulo – SP Zip Code: 05422-001
Sílvio Sinedino Pinheiro(4)	June 25, 1951	Director	March 2015	Avenida República do Chile, no. 330 12nd. floor Rio de Janeiro – RJ Zip-code: 20.031-170

(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.

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Guido Mantega—Mr. Mantega has been the Chairman of the boards of directors of Petrobras and Petrobras Distribuidora S.A. since March  2010, and he has served on both boards since April  2006. He was a member of the Remuneration and Succession Committee of our board of directors (RS Committee) from October 2007 to April  2010.  He has been Brazil’s Minister of Finance since March  2006,  after serving as the president of the Banco Nacional de Desenvolvimento Econômico e Social – BNDES (the Brazilian Development Bank) and as Brazil’s Minister of Planning, Budget and Management.  He is a member of the Conselho de Desenvolvimento Econômico e Social—CDES (the Economic and Social Development Council), an advisory body to the Brazilian federal government. He received a bachelor’s degree in economics from the Faculdade de Economia, Administração e Contabilidade—FEA (the School of Economy, Administration and Accounting) at the Universidade de São Paulo - USP (the University of São Paulo), and a Ph.D. in development sociology from the Faculdade de Filosofia, Letras e Ciências Humanas—FFLCH (the School of Philosophy, Literature and Human Sciences) at USP.  He completed specialized studies at the Institute of Development Studies—IDS at the University of Sussex, England in 1977.  As Brazil’s Minister of Finance, his duties include the representation of the Brazilian government with the G-20, BRICS, Mercosul, IMF and World Bank; international roadshows to promote foreign investments in Brazil; and summits involving the President of the Republic of Brazil, Dilma Rousseff, acting as her advisor. 

Maria das Graças Silva Foster—Ms. Foster has been our Chief Executive Officer since February  2012 and our Chief International Officer since July  2012.  She is also a member of our board of directors and the boards of directors of Petrobras Distribuidora S.A., Petrobras Biocombustível S.A. and Petrobras Oil&Gas – POG-BV.  Ms. Foster is also chairperson of the Health, Safety and Environment Committee of our board of directors (the HSE Committee), and she has been the chairperson of the boards of directors of Petrobras Transporte S.A. - Transpetro since March 2012, and Petrobras Gás S.A. - Gaspetro since February 2012.  From September 2007 to February 2012, she served as Petrobras’ Chief Gas & Power Officer and from December 2007 to March 2012, as the CEO of Gaspetro. From May 2006 to September 2007, Ms. Foster was the CEO and the CFO of Petrobras Distribuidora S.A.. Ms. Foster has been a member of the board of directors of Gaspetro since October 2007. She has also served as a director of Transpetro from March 2003 to September 2005 and from November 2007 to the present. Ms. Foster was also a member of the board of directors of Transportadora Associada de Gás S.A. - TAG from October 2007 to March 2008, Transportadora Brasileira Gasoduto Bolívia-Brasil (TBG) from March 2003 to September 2005 and Braskem S.A. - Braskem from October 2005 to April 2012. Ms. Foster was also the chairperson of the board of directors of Liquigás Distribuidora S.A. (Liquigás), the CEO and Investor Relations Executive Officer of Petrobras Química S.A. - Petroquisa, and  Petrobras’ Executive Manager for Petrochemicals and Fertilizers. She has also had various roles in the Brazilian government, including the position of Secretary of Petroleum, Natural Gas and Renewable Fuels of the Ministério das Minas e Energia - MME (the Ministry of Mines and Energy) from January 2003 to September 2005. In the private sector, she has been a member of the board of directors of Instituto Brasileiro de Petróleo Gás e Biocombustíveis – IBP (Brazilian Petroleum, Gas and Biofuels Institute) since October 2006 and has been its president since March 2012. She holds a degree in chemical engineering from the Universidade Federal Fluminense – UFF (the Fluminense Federal University), a master’s degree in chemical engineering and a post-graduate degree in nuclear engineering from the Universidade Federal do Rio de Janeiro - UFRJ (the Federal University of Rio de Janeiro) and an MBA in economics from the Fundação Getulio Vargas - FGV (Getulio Vargas Foundation). 

                Miriam Aparecida Belchior—Ms. Belchior has been a member of our board of directors since July  2011, and she is also member of the board of directors of Petrobras Distribuidora S.A.. She  is a member of the HSE Committee of our board of directors. Ms. Belchior has been  Brazil’s Minister of Planning, Budget and Management since January 2011. She was the Articulation and Monitoring Sub-head of the Chief of Staff, responsible for connecting government actions and monitoring strategic projects from 2003 to 2010. She served as Executive Secretary for the Programa de Aceleração do Crescimento—PAC (the Growth Acceleration Program) in 2007 and became its General Coordinator in April 2010. Ms. Belchior is an engineer and holds a master’s degree in public administration and government from FGV. She previously served as a professor with the Fundação para Pesquisa e Desenvolvimento da Administração, Contabilidade e Economia —FUNDACE (the Foundation for Research and Development of Administration, Accounting and Economics) and the Universidade de São Marcos (the University of São Marcos).

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Francisco Roberto de Albuquerque—Mr. de Albuquerque has been member of our board of directors since April  2007, and he is also a member of the board of directors of Petrobras Distribuidora S.A.  He has been a member of the Audit Committee and the RS Committee of our board of directors since April 2007, and October  2007, respectively.  He earned a bachelor’s degree in military sciences from the Academia Militar das Agulhas Negras—AMAN (the Agulhas Negras Military Academy) in Resende, in the State of Rio de Janeiro, in 1958 and in economics from the Faculdade de Ciências Econômicas de São Paulo (the São Paulo College of Economic Sciences) at Fundação Álvares Penteado (Álvares Penteado Foundation) in 1968, a master’s degree in military sciences from the Escola de Aperfeiçoamento de Oficiais—EsAO (the Advanced Military School) in 1969, and a Ph.D. in military sciences from the Escola de Comando e Estado-Maior do Exército—ECEME (the Military Officer Training School) in Rio de Janeiro in 1977.

Márcio Pereira Zimmermann—Mr. Zimmermann has been member of our board of directors since March  2010, and he is also a member of the board of directors of Petrobras Distribuidora S.A.  He has been the President of the  RS Committee of our board of directors since April 2010.  Mr. Zimmermann is currently the Executive Secretary (Deputy Minister) of the MME, where he previously served as Minister, Executive Secretary and Secretary for Energy Planning and Development.  Mr. Zimmermann is also the Chairman of the board of directors of Centrais Elétricas Brasileiras—Eletrobras, where he previously served as Engineering Executive Officer, and the Chairman of the board of directors of Furnas Centrais Elétricas S.A.  He has been a member of the Conselho Nacional de Política Energética—CNPE (National Energy Policy Council) since February 2009.  He was also the Energy Production and Commercialization Executive Officer and Technical Executive Officer of Eletrosul Centrais Elétricas S.A. and the Research and Development Executive Officer of Centro de Pesquisas de Energia Elétrica—CEPEL (Electrical Energy Research Center).  Mr. Zimmermann holds a bachelor’s degree in electrical engineering from the Pontifícia Universidade Católica do Rio Grande do Sul – PUC-RS (the Pontifical Catholic University of Rio Grande do Sul), a post-graduate degree in power systems engineering from the Universidade Federal de Itajubá – UNIFEI (the Federal University of Itajubá), and a master’s degree in electrical engineering from the Pontifícia Universidade Católica do Rio de Janeiro – PUC-Rio (the Pontifical Catholic University of Rio de Janeiro).

Luciano Galvão Coutinho—Mr. Coutinho has been member of our board of directors since April 2008, and he is also 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  USP and a bachelor’s degree in economics from USP.

Sergio Franklin Quintella—Mr. Quintella has been member of our board of directors since April 2009, and he is also member of the board of directors of Petrobras Distribuidora S.A.  He has been member of the Audit Committee of our board of directors since November 2009 and was appointed as its president  in November  2011. He is vice president of FGV and member of the board of directors of Oi S.A. since September 2005 and April 2012, respectively.  He was member of the board of directors of BNDES from 1975 to 1980, member of Conselho Monetário Nacional – CMN (National Monetary Council) from 1985 to 1990, and president of the Tribunal de Contas (Court of Auditors) of the State of Rio de Janeiro from 1993 to 2005.  Mr. Quintella holds a bachelor’s degree in civil engineering from PUC-Rio, a bachelor’s degree in economics from the Faculdade de Economia do Rio de Janeiro (the College of Economics of Rio de Janeiro) and a post-graduate degree in economic engineering from the Escola Nacional de Engenharia (the National Engineering School).  He also holds a master’s degree in business from IPSOA Institute, in Turin, Italy and graduated from the Advanced Management Program at Harvard Business School.  Mr. Quintella is currently member of the council of PUC-Rio. 

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Mauro Gentile Rodrigues da Cunha—Mr. Cunha has been member of our board of directors since April 2013,  and he is also member of the board of directors of Petrobras Distribuidora S.A. He has been member of the Audit Committee of our board of directors since May 2013.  Mr. Cunha is currently the President of the Associação de Investidores no Mercado de Capitais - AMEC (the Capital Markets Investors’ Association), a position which  he  has held since April 2012.  He  has also been member of the board of directors of Companhia Energética de São Paulo – CESP and Trisul S.A. since April 2013.  He has spent much of his career advising and consulting on corporate governance and asset management, holding different positions in companies such as Opus Gestão de Recursos, Mauá Investimentos, Franklin Templeton  Investimentos (Brasil) Ltda, Morgan Stanley Asset Management and Deutsche Morgan Grenfell, among others. Mr. Cunha has been a Chartered Financial Analyst since 1997, and he holds an MBA from the University of Chicago, as well as a bachelor’s degree in Economics from PUC-Rio.  

                José Guimarães Monforte - Mr. Monforte has been a member of our board of directors since April 2014, and he is also a member of the board of directors of Petrobras Distribuidora S.A. Mr. Monforte has spent most of his career working on financial and capital markets matters in both Brazilian and international institutions. During his career, Mr. Monforte has held different positions in a number of companies, including Grupo Banespa from 1972 to 1979, and Merrill Lynch, Brazil from 1979 to 1987, where he was the first chief executive officer. From 1987 to 1996, Mr. Monforte was the officer responsible for Citibank’s Private Banking and Investment Banking in Brazil and was vice president of the Associação Nacional de Bancos de Investimento (the National Association of Investment Banks), vice president of the Board of Caixa de Liquidação of the São Paulo Commodities Exchange and a member of committees of the São Paulo Stock Exchange; the two Exchanges merged to  become BM&F BOVESPA S.A. Mr. Monforte was executive president of VBC Energia from 1996 to 1997, which during his leadership acquired Companhia Paulista de Força e Luz - CPFL, now CPFL Energia S.A.. From 1998 to 2007 he was president and organizer of Janos Participações, which was formed to manage the assets of the controlling shareholders of Natura Cosméticos S.A., a Brazilian cosmetics company whose initial public offering has become a successful model for Brazilian capital markets. Mr. Monforte is highly-regarded for Brazilian corporate governance matters, and he has been a member of several boards of directors in Brazil and abroad. He also was the Chairman of the board of directors of the Instituto Brasileiro de Governança Corporativa (The Brazilian Institute of Corporate Governance) from 2004 to 2008.  He earned a bachelor’s degree in economics from Universidade Católica de Santos (Catholic University of Santos).

                Sílvio Sinedino Pinheiro—Mr. Sinedino has been a member of our board of directors since April 2014, and he is the representative of our employees. Mr. Sinedino previously served as a member of our board of directors from March 2012 to April 2013, when he was also a representative of our employees. He has been a member of Petros’ Board of Advisors since 2013.  He is also the current president of AEPET - Associação dos Engenheiros da Petrobras (Petrobras’ Association of Engineers). From 2002 to 2005, he was an officer of the Sindicato dos Petroleiros do Estado do Rio de Janeiro—Sindipetro-RJ (Oil Workers’ Union of the State of Rio de Janeiro).  He is a systems analyst at Petrobras and develops seismic processing software for our E&P segment.  Mr. Sinedino holds a bachelor’s degree in electrical engineering from PUC-Rio as well as master’s degrees in computer science and in business administration, both from the Instituto Alberto Luiz Coimbra de Pós-Graduação e Pesquisa em Engenharia–COPPE (the Alberto Luiz Coimbra Institute of Post-Graduate Studies and Research in Engineering) of UFRJ.

Executive Officers

Our board of executive officers, composed of the Chief Executive Officer (CEO) and six executive officers, is responsible for our day-to-day management.  Our executive officers are Brazilian nationals and reside in Brazil.  Under our bylaws, the board of directors elects the executive officers, including the CEO, and must consider personal qualification, knowledge and specialization in electing executive officers to their respective areas.  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.  Six of our current executive officers are experienced Petrobras career managers, engineers or technicians.

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

Name	Date of Birth	Position	Current Term
Maria das Graças Silva Foster	August 26, 1953	Chief Executive Officer and Chief International Officer	March 2017
Almir Guilherme Barbassa	May 19, 1947	Chief Financial Officer and Chief Investor Relations Officer	March 2017
José Antonio De Figueiredo	January 1, 1956	Chief Engineering, Technology and Procurement Officer	March 2017
José Miranda Formigli Filho	March 30, 1960	Chief Exploration and Production Officer	March 2017
José Carlos Cosenza	April 23, 1951	Chief Downstream Officer	March 2017
José Alcides Santoro Martins	August 28, 1954	Chief Gas and Power Officer	March 2017
José Eduardo de Barros Dutra	April 11, 1957	Chief Corporate and Services Officer	March 2017

                Maria das Graças Silva Foster—Ms. Foster has been our Chief Executive Officer since February 13, 2012.  For biographical information regarding Ms.  Foster, see “—Directors.” 

Almir Guilherme Barbassa—Mr. Barbassa has been our Chief Financial Officer and Chief Investor Relations Officer since July 2005.  Mr. Barbassa joined Petrobras in 1974 and has worked in several financial and planning capacities, both in Brazil and abroad.  Mr. Barbassa has served as Petrobras’ corporate finance and treasury manager, and he has also served at various times as financial manager and chairman of Petrobras subsidiaries that carry out international financial activities.  Mr. Barbassa is also a member of the board of directors of Braskem.  In addition, he was an economics professor at Universidade Católica de Petrópolis (Petrópolis Catholic University) and Faculdades Integradas Bennett (Bennett University) from 1973 to 1979.  Mr. Barbassa holds a master’s degree in economics from FGV.  

                José Antonio De Figueiredo—Mr. Figueiredo has been our Chief Engineering, Technology & Procurement Officer since May 2012.  Mr. Figueiredo joined Petrobras in 1979 and has held various management positions at Petrobras’ research center and engineering department before being appointed as General Manager of our E&P and Shipbuilding Projects in February 2001, E&P-Southeast Area Executive Manager in 2003, Services Executive Manager at E&P segment in February 2012 and Engineering Executive Officer in May 2012.  Mr. Figueiredo holds a degree in electronic engineering from UFRJ and an MBA in business management from FGV. 

José Miranda Formigli Filho—Mr. Formigli Filho has been our Chief Exploration and Production Officer since February 2012.  Mr. Formigli Filho graduated in civil engineering from the Instituto Militar de Engenharia—IME, with a specialization in petroleum engineering and has an MBA in advanced business management from UFRJ—COPPEAD.  He is a member of the Society of Petroleum Engineers (SPE) and the Society for Underwater Technology (SUT).  In Petrobras’ E&P segment, he has managed offshore activities and has been the Production Manager of the Campos Basin, Marlim Field Asset Manager, Services Executive Manager and Production Engineering Executive Manager.  From May 2008 through January 2012, Mr. Formigli Filho was the Executive Manager of Pre-Salt Development.

                José Carlos Cosenza—Mr. Cosenza has been our Chief Downstream Officer since April 2012.  Mr. Cosenza joined Petrobras in 1976 and worked as Production Manager at REFAP (Refinaria Alberto Pasqualini), General Manager at both REPAR (Refinaria do Paraná) and REPLAN (Refinaria de Paulínia) and was the Chief Executive Officer of Petrobras Argentina and Petrobras Uruguay.  He was the Vice President of the expansion project of Pasadena Refinery in the U.S. and Executive Manager of Refining.  Mr. Cosenza holds a degree in chemical engineering from UFRGS.

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José Alcides Santoro Martins—Mr. Santoro Martins has been our Chief Gas and Power Officer since February 2012.  Mr. Santoro Martins holds a bachelor’s degree in civil engineering from USP.  He has been at Petrobras for 34 years and has held various management positions, as well as being a board member of different subsidiaries of the Company.  He is also Chief Executive Officer of Gaspetro since March 2012.  He was the Chief Executive Officer of Termobahia S.A. from September 2008 to March 2012, of Termoceará Ltda., Termomacaé Ltda. and Sociedade Fluminense de Energia Ltda. from October 2008 to April 2012, of Fafen Energia S.A. from September 2008 to December 2011; of Termorio S.A. from August 2008 to December 2011; and of UTE Bahia I Camaçari Ltda. from September 2008 to December 2011.  He was also Director for Oil, Gas and Biofuels at the Empresa de Pesquisa Energética - EPE (Energy Research Company) from May 2005 to June 2006 and Technology Director at the Center for Gas & Renewable Energy Technology—CTGAS-ER from February 2004 to May 2005.  Mr. Santoro is the Chairman of the board of TAG and a member of the board of directors of Gaspetro, Transpetro and Braskem.

José Eduardo de Barros Dutra—Mr. Dutra has been our Chief Corporate and Services Officer since March 2012.  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.  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 post of director of Petrobras and director of Petrobras Distribuidora S.A.  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.

Compensation

For 2013, the aggregate amount of compensation we paid to all members of the board of directors and executive officers was approximately U.S.$5.5 million. At December 31, 2013 we had seven executive officers and ten board members. See note 19.4 to our audited consolidated financial statements for further information regarding compensation of our employees and officers.

In addition, the members of the board and the executive officers receive certain additional benefits generally provided to our employees and their families, such as medical assistance and payment of educational expenses.  Our executive officers also receive supplementary social security benefits.

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

Share Ownership

As of March 31, 2014, the members of our board of directors, our executive officers, the members of our Fiscal Council, and close members of their families, as a group, beneficially held a total of 31,505 common shares and 222,117 preferred shares of our company.  Accordingly, on an individual basis, and as a group, our directors, executive officers, Fiscal Council members, and close members of their families beneficially owned less than one percent of any class of our shares.  The shares held by our directors, executive officers, Fiscal Council members, and close members of their families 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, Fiscal Council members, or close members of their families holds any options to purchase common shares 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 the 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 the Fiscal Council:

Name	Year of First Appointment
Marcus Pereira Aucélio	2012
Edson Freitas de Oliveira	2002
Ricardo de Paula Monteiro	2008
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 things:

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

·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;

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·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 Miriam Aparecida Belchior, Sergio Franklin Quintella and Luciano Galvão Coutinho.  All members of our Audit Committee satisfy the independence requirements set forth in Rule 10A-3 under the Exchange Act.

Other Advisory Committees

Our Board of Directors has two additional advisory committees: the Comitê de Remuneração e Sucessão (Remuneration and Succession Committee) and the Comitê de Segurança, Meio Ambiente e Saúde (Safety, Environmental and Health Committee).

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 administration, which includes Petrobras.  In April 2012, Petrobras’ CEO, Ms. Maria das Graças Foster, appointed the General Ombudsman as the authority responsible for implementing this law within the Company. Now, the General Ombudsman's Office has to perform new tasks, such as ensuring compliance with the rules on access to information by the public, monitoring the implementation of this law and submitting periodic reports to the Board of Directors, as well as making recommendations and providing guidance to Petrobras’ business units with respect to the enforcement of the law.

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Employees and Labor Relations

We attract and retain valuable employees by offering competitive compensation and benefits, merit-based promotions and a profit-sharing plan.  In accordance with Brazilian law, total profit-sharing payments to employees are limited to 25% of the amount of proposed dividends for the year.

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

	As of December 31,
	2013	2012	2011
Petrobras employees:
Parent company	62,692	61,878	58,950
Subsidiaries	15,903	15,547	15,453
Abroad	7,516	7,640	7,515
Total Petrobras Group	86,111	85,065	81,918
Parent company by level:
High school	39,005	38,660	36,923
College	23,115	22,614	21,366
Maritime employees	572	604	661
Total parent company	62,692	61,878	58,950
Parent company by region:
Southeastern Brazil	43,309	42,186	40,674
Northeastern Brazil	14,651	15,022	14,625
Other locations	4,732	4,670	3,651
Total parent company	62,692	61,878	58,950

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

	2013	2012	2011
	(U.S.$ million)
Salaries	8,184.1	7,989.4	8,055.4
Employee training	196.1	256.3	249.6
Profit-sharing distributions	520.0	524.0	867.0

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 2013, we signed a new collective bargaining agreement, incorporating negotiations under both economic and social clauses. Under this agreement, employees received a 6.09% cost of living increase, reflecting an adjustment for inflation in 2013, as measured by the Índice Nacional de Preços ao Consumidor Amplo, or IPCA, a real wage increase of up to 2.33%, and a one-time payment of 100% of monthly remuneration, or R$7,200.00, whichever is higher.

Knowledge Transfer Initiatives

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

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                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 to this program. Voluntary separation of employees under this program must achieve the following results: (i) adjust company personnel to its 2014-2018 Plan; achieve company interests in line with employees’ expectations, (iii) preserve existing knowledge within the company and (iv) permit the development of leadership succession plans.

                The target group of this voluntary separation incentive program are Petrobras’ employees that have 55 years old or more, regardless of their position in Petrobras and that would be eligible to retire under the Social Security National Institute (INSS) rules until the end of incentive program enrollment period (March 31, 2014).

Employees Internal Relocation Program - Mobiliza

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

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 96.75% 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 amount 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 2013, 2012 and 2011:

	2013	2012	2011
	(U.S.$ million)
Total benefits paid – Pension and Medical Plans	1,535	1,544	1,595
Total contributions – Pension and Medical Plans(1)	825	871	892
Actuarial liabilities(2)	12,573	20,224	15,818

(1)Includes contributions by sponsors and employees.

(2)Obligations for unfunded Pension and Medical Plans. Amounts restated for 2011 due to the adoption of amendments to IAS 19, as set out in note 2.3 to our audited consolidated financial statements.

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On August 9, 2002, the Petros Plan stopped admitting new participants and since 2003 we have been engaged in complex negotiations with representatives of the 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.

On July 1, 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 2013, contributions paid by Petrobras and its subsidiaries (sponsors) to the pension and medical plans amounted U.S.$643 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 3.16, 4.3 and 22 to our audited consolidated financial statements for more information about our Employee Benefits.

                Effective for annual periods beginning on January 1, 2013, amendments to IAS 19 – “Employee benefits” eliminated the option to defer actuarial gains and losses (corridor approach) and require net interest to be calculated by applying the discount rate used for measuring the obligation to the net benefit asset or liability. See note 2.3 to our audited consolidated financial statements for further information about amounts restated due to the adoption of amendments to IAS 19.

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 March 31, 2014, there were 7,442,454,142 outstanding common shares and 5,602,042,788 outstanding preferred shares. The ratio of our common and preferred shares to ADRs is two shares to one ADR.  As of March 31, 2014, approximately 24.81% of our preferred shares and approximately 20.43% of our common shares were held of record in the United States directly or in the form of ADSs.

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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 special voting rights, other than the right to always 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 March 31, 2014, 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	0.00	3,740,470,811	28.67
BNDES	734,202,699	9.87	161,596,958	2.89	895,799,657	6.87
BNDES Participações S.A.—BNDESPar.	11,700,392	0.16	1,341,348,766	23.95	1,353,049,158	10.37
Caixa de Previdência dos Funcionários do Banco do Brasil — PREVI	12,673,903	0.17	353,699,725	6.31	366,373,628	2.81
Other Brazilian public sector entities	2,321,932	0.03	670,082	0.01	2,992,014	0.02
All members of the board of directors, executive officers and members of our fiscal council (21 persons)	31,505	0.00	222,117	0.00	253,622	0.00
Others	2,941,052,900	39.51	3,744,505,140	66.84	6,685,558,040	51.26
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 require the approval of our board of directors, and must follow the conditions of an arms-length transaction and market practices 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 which 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, which transaction 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.

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.”

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Brazilian Federal Government

We have engaged, and expect to continue to engage, in numerous transactions in the ordinary course of business with our controlling shareholder, the Brazilian federal government, and with other companies controlled by it, including financing and banking, asset management and other transactions with banks and other entities controlled by the Federal Government.  The above-mentioned transactions amounted to a net liability of U.S.$19,189 million as of December 31, 2013. 

As of December 31, 2013, we had a receivable (the Petroleum and Alcohol Account) from the Brazilian federal government, our controlling shareholder, of U.S.$357 million.  For further information, see note 19.3 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, 2013, the value of these marketable securities that has been directly acquired and held by us amounted to U.S.$6,247 million. 

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 subject to numerous legal proceedings relating to civil, tax, labor, corporate and environmental issues arising in the normal course of our business.  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 31 to our audited consolidated financial statements included in this annual report, and that description is incorporated by reference under this Item.

Additionally, in January 2014, the Secretariat of the Federal Revenue of Brazil issued a tax assessment (auto de infração) against us amounting to approximately R$1,442.6 million (U.S.$615.5 million) in relation to an alleged non-payment of social security contributions due over benefits given to certain of our employees from January 2009 to December 2011. This claim is being discussed at the administrative level.  We believe that the chances of loss are possible, but not probable, and accordingly we have not established any provision.

Internal Commissions

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

On March 31, 2014, our internal commission established to evaluate bribery allegations involving SBM Offshore confirmed that it found no internal evidence to support such allegations.

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We currently have a number of internal commissions in place that were set up in certain instances to evaluate past transactions mentioned in public press reports, including: (i) a commission formed on March 24, 2014 to evaluate aspects of the Pasadena refinery acquisition; (ii) a commission formed on April 11, 2014 to evaluate our contracts with our service provider EcoGlobal; (iii) a commission formed on April 14, 2014 to evaluate our contracts with our service provider Astro Marítima Navegação S.A.; and (iv) 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. Each of these internal commissions has between 30 and 60 days to complete its work. Based on the information that is currently available, we do not believe that the findings of any of these internal commissions would have a material effect on our financial statements.

Dividend Distribution

The tables 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,
	2013	2012	2011
	(U.S.$ million)
Total amounts paid	2,656	3,272	6,422

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. “Additional Information—Memorandum and Articles of Incorporation—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 sharesand preferred 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
2008	62.30	20.21	52.51	16.89	75.19	14.94	63.51	12.56
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
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
September 2013	17.95	15.90	19.16	16.78	16.37	13.60	17.58	14.35
Fourth quarter	20.34	15.57	21.44	16.78	17.90	13.34	18.79	14.33
October 2013	19.54	16.83	20.43	17.93	17.45	15.32	18.37	16.50
November 2013	20.34	17.73	21.44	18.66	17.90	15.78	18.79	16.41
December 2013	16.57	15.57	17.63	16.78	14.20	13.34	15.05	14.33
2014:
First quarter	15.82	12.02	16.75	12.57	13.32	10.27	13.96	10.68
January 2014	15.82	13.64	16.75	14.70	13.32	11.21	13.96	11.90
February 2014	14.03	12.90	14.96	13.59	11.67	10.78	12.50	11.37
March 2014	15.01	12.02	15.78	12.57	13.18	10.27	13.90	10.68

BM&FBOVESPA

As of December 31, 2013, Petrobras’ common and preferred shares represented approximately 8.9% of the total market capitalization of the BM&FBOVESPA and Petrobras was the second most actively traded company of the BM&FBOVESPA.  At December 31, 2013, the aggregate market capitalization of the 379 companies listed on the BM&FBOVESPA was approximately U.S.$1,031 billion and the ten largest companies represented approximately 51.2% 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.  With limited exceptions, non-Brazilian holders may only trade on the BM&FBOVESPA in accordance with the requirements of Resolution No. 2,689 of the CMN.  Resolution No. 2,689 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 Central Bank of Brazil and the CVM.  In addition, Resolution No. 2,689 requires non-Brazilian holders to restrict their securities trading to transactions on Brazilian stock exchanges or qualified over-the-counter markets.  With limited exceptions, non-Brazilian holders may not transfer the ownership of investments made under Resolution No. 2,689 to other non-Brazilian holders through a private transaction. See Item 10. “Additional Information - Exchange Controls” for further information.

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Item 10.   Additional Information

Memorandum and Articles of Incorporation

General

We are a publicly traded company duly registered with the CVM under identification number 951-2.  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 its derivatives, 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.

Qualification of Directors

Law No. 12,431/2011, amended the Brazilian Corporate Law by eliminating the previous requirement that only shareholders of a company may be appointed to its board of directors.  Therefore, directors are no longer required to be shareholders of the company, but the 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 directly or indirectly a majority of the voting rights include a director on the board of directors that is a representative elected by the company’s employees, such director to be elected 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 profits for the preceding fiscal year are to be allocated.  The Brazilian Corporate Law defines net profits as net income after income taxes and social contribution taxes for such fiscal year, net of any accumulated losses from prior fiscal years and any amounts allocated to employees’ and management’s participation in our profits.  In accordance with the Brazilian Corporate Law, the amounts available for dividend distribution or payment of interest on capital equals net profits less any amounts allocated from such net profits to the legal reserve.

We are required to maintain a legal reserve, to which we must allocate 5% of net profits 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.

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

·first, a percentage of net profits 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 profits in a given year, this excess may be allocated to an unrealized revenue reserve.  The Brazilian Corporate Law defines realized net profits as the amount of net profits 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 profits 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 shareholders’ 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 profit 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 profits, 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 profits 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, 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.

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.

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Payment of Dividends and Interest on Capital

We are required by the Brazilian Corporate Law and by our bylaws 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 pro rata 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 profits) 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.

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

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.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 our bylaws, our preferred shares generally 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;

·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 profits for payment of the mandatory dividend and allocation to the various reserve accounts;

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·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 canceling 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;

·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;

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·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 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 with 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.

Our preferred shares will acquire voting rights if we fail to pay the minimum dividend to which such shares are entitled for three consecutive fiscal years.  The voting right shall continue until payment has been made.  Preferred shareholders also obtain the right to vote if we enter into a liquidation process.

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.

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.

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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, a shareholder has the right to withdraw his or her equity interest from the company and to receive payment for the portion of shareholder’s equity attributable to his or her 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.

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.

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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;

·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.

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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.

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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.

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 things, 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. 2,689 may buy and sell securities on the BM&FBOVESPA without obtaining a separate certificate of registration for each transaction.

In addition, Annex V to Resolution No. 1,289 of the CMN,  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.

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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.

Material Contracts

Assignment Agreement (Contrato de Cessão Onerosa)

On September 3, 2010, we entered into an agreement with the Brazilian federal government, 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 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.

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.

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 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.

Contingent Block

We may request that the Brazilian federal government grant us the right to perform the activities set forth in the minimum work program in the contingent block within four years from the date of the Assignment Agreement, and provided that it is proved, based on oil and gas industry best practices, that the total volume recoverable in the other blocks is less than the maximum volume initially provided by the Assignment Agreement.

The activities set forth in the minimum work program for the contingent block must be performed within the term of the exploration phase. At any time, in case we or the Brazilian federal government identify the possibility of producing the maximum volume initially provided for in the Assignment Agreement in the other blocks, we will be required to return the contingent block to the Brazilian federal government immediately.

Revision

The Assignment Agreement is subject to a revision process. We will notify the Brazilian federal government and the ANP ten months before the date expected for the declaration of commerciality of each area covered by the agreement, in order to initiate the revision process, which will begin immediately after the declaration of commerciality of each field in each of the blocks. The revision process will be concluded when we issue our last declaration of commerciality, based on each area’s revised prices and volumes, for all the areas subject to the Assignment Agreement. The contingent block will also be subject to the revision process if we request to the Brazilian federal government the right to perform the activities set forth in the minimum work program within this block.

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

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, where we may agree to return one or more of the areas covered by the Assignment Agreement. 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:  the date of the Declaration of Commerciality in accordance with the terms of the Assignment Agreement.  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 revision date (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.

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·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.

·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 equivalent 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 Brazilian Central Bank) 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 will end upon the declaration of commerciality of each respective reservoir discovered in each area covered by the Assignment Agreement. We will have four years, which may be extended for an additional two-year period, to comply with the minimum work program and other ANP-approved activities as set forth in 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, we are required to undertake a minimum work program, as specified in the Assignment Agreement. We may perform other activities outside the scope of the minimum work program, provided that such activities are approved by the ANP.

The ANP will impose fines on us for delays in the performance of the minimum work program. If the delay is less than 24 months, the fine will correspond to the amount of such non-performed activities, proportional to the number of outstanding days. If the delay is greater than 24 months, then the fine will be equal to twice the amount of the activities of the minimum work program for the relevant block.

Reallocation of Volumes

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.

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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.

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 shall indicate a representative to 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.

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.

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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.

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 includes, 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.

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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.“Regulation of the Oil and Gas Industry in Brazil - Production-Sharing Contract Regime for Unlicensed Pre-Salt and Potentially Strategic Areas”.

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 ANP (of which R$50 million was paid to PPSA) as a signing bonus for the execution of the Production Sharing Agreement. Under the terms of the Production Sharing Agreement, the Libra Consortium will share with the Brazilian government “profit oil” produced in exchange for the right to explore and produce oil and gas in the Libra block. The government share of profit oil will be 41.625%, varying with the price 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 billion boe.

                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.

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, as approved by PPSA and the Operating Committee, 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.

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Phases

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

Exploration phase.  This phase comprises the appraisal 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 and in other circumstances described 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 seek and 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 the exploration 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.

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.

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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.

·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.

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

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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 register their investment under Law No. 4,131/1962 or CMN Resolution No. 2,689. Registration under CMN Resolution No. 2,689 affords favorable tax treatment to foreign investors who are not resident in a tax haven, as defined by Brazilian tax laws. See “—Taxation Relating to Our ADSs and Common and Preferred Shares—Brazilian Tax Considerations.”

Under CMN Resolution No. 2,689, 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. 2,689, the definition of foreign investor includes individuals, legal entities, mutual funds and other collective investment entities, domiciled or headquartered abroad.

Under CMN Resolution No. 2,689, a foreign investor must:

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

·appoint an authorized custodian in Brazil for its investments;

·register as a foreign investor with the CVM; and

·register its foreign investment with the Central Bank of Brazil.

Securities and other financial assets held by CMN Resolution No. 2,689 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. 2,689 must be carried out in the stock exchanges or through organized over-the-counter markets licensed by the CVM, except for transfers resulting from a corporate reorganization or occurring upon the death of an investor by operation of law or will.

Holders of ADSs who have not registered their investment with the Central Bank of Brazil could be adversely affected by delays in, or refusals to grant, any required government approval for conversions of payments made in reais and remittances abroad of these converted amounts.

Annex V of CMN Resolution No. 2,689 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.  Following the closing of an international offering, the electronic certificate of registration will be amended by the depositary with respect to the ADSs sold in the international offering and will be maintained by the Brazilian custodian for the relevant shares on behalf of the depositary.

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In the event that a holder of ADSs exchanges such ADSs for the underlying shares, the holder will be entitled to continue to rely on such electronic registration for five business days after the exchange.  Thereafter, unless the relevant shares are held pursuant to Resolution No. 2,689 by a duly registered investor, or a holder of the relevant shares applies for and obtains a new certificate of registration from the Central Bank of Brazil, the holder may not be able to convert into foreign currency and to remit outside Brazil the proceeds from the disposition of, or distributions with respect to, the relevant shares, and the holder, if not registered under Resolution No. 2,689, will be subject to 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 may invest in the preferred or common shares under Resolution No. 2,689 or under Law No. 4,131/1962.  The rules of Resolution No. 2,689 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 Resolution No. 2,689, 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 the foreign investment; (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 Resolution No. 2,689 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, securities trading is restricted to transactions carried out in the stock exchanges or organized over-the-counter markets licensed 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. However, in accordance with recent regulations enacted by the Brazilian federal government a withholding income tax rate of 15% (or 25% for beneficiaries domiciled in tax haven jurisdictions) may be imposed over the amount of dividends paid by us exceeding our “taxable profits” (as defined by Law 11,941/2009) as accrued from fiscal year 2008 to fiscal year 2014. This new regulation had no impact on the distribution of dividends that we have made (or will make) with respect to our profits accrued from fiscal year 2008 to fiscal year 2013. For the profits we will accrue during fiscal year 2014, if the amount of dividends we pay to our shareholders exceeds our “taxable profits” (as defined by Law 11,941/2009), then the holders of our preferred or common shares may be subject to withholding income tax over such exceeding amounts. These recent regulations shall be necessarily approved by the Brazilian Congress in order to remain effective and may be subject to amendments. We continue to review the scope and legality of this new regulation.

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 as 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 Resolution No. 2,689 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 20% (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.”

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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.

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 Resolution No. 2,689; and (ii) any other non-Brazilian holder, including non-Brazilian holders who invest in Brazil not in accordance with Resolution No. 2,689 (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 Resolution No. 2,689 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.”

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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 Resolution No. 2,689 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 Resolution No. 2,689 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.

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 Resolution No. 2,689 will continue to apply in the future.

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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 20%. 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 20%; (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; or (iii) does not tax or that taxes foreign source income at a maximum rate lower than 20%; 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.

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, depending on the respective conditions, at a rate of 6%, except for foreign exchange transactions in connection with (i) investments in variable income carried out in the Brazilian stock, commodities and/or future exchanges (except for derivatives with predetermined income), (ii) acquisitions of stock of Brazilian publicly traded companies in a public offer, and (iii) subscriptions of stock of Brazilian publicly traded companies, which are 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 Resolution No. 2,689. 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 has been reduced from 1.5% to zero, as of December 24, 2013.

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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 Resolution No. 2,689, or by the depositary representing such holder, is eligible for registration with the Central Bank of Brazil; such registration (the amount so registered being called registered capital) 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 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 greatest number of such shares were sold on the day of withdrawal; or

(b)   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 withdrawal.

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, the average of such average quoted rates on the same 15 dates used to determine the average price of preferred or common shares).

A non-Brazilian holder of preferred or common shares may experience delays in effecting such registration, which 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.”

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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) the Company 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 the Company’s audited financial statements and relevant market and shareholder data, the Company believes that it should not be treated as a PFIC for U.S. federal income tax purposes with respect to its 2012 or 2013 taxable year. In addition, based on the Company’s audited financial statements and its current expectations regarding the value and nature of its assets, the sources and nature of its income, and relevant market and shareholder data, the Company does not anticipate becoming a PFIC for its 2014 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 the Company 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.

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Taxation Relating to PifCo’s and PGF’s Notes

The following summary contains a description of material Brazilian, Dutch, Luxembourg, European Union and U.S. federal income tax considerations that may be relevant to the purchase, ownership, and disposition of PifCo’s and 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, Luxembourg, Brazil and the United States.

This summary is based on the tax laws of The Netherlands, Luxembourg, 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; and

·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; and

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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

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.

Luxembourg Taxation

Luxembourg Withholding Tax on Interest

Under Luxembourg tax law, there is no Luxembourg withholding tax on payments of interest except in very specific circumstances.

By a law dated as of June 21, 2005 (the "2005 Directive Law"), Luxembourg has implemented the Directive regarding the taxation of savings income.

In essence, under the 2005 Directive Law, which has been in effect since July 1, 2005, Luxembourg levies a 35% withholding tax on payments of interest (or other similar income) paid by an economic operator (a “paying agent” within the meaning of the Directive) within its jurisdiction to or for an individual as well, in some cases, to specific forms of organizations, such as partnerships, respectively resident or established in another EU Member State or in certain dependent or associated territories, unless such individual (the beneficiary of the interest payments) agrees to an exchange of information between the tax authorities of Luxembourg and the relevant EU Member State regarding the payment of interest (or similar income) it received.

However, on March 18, 2014, the Luxembourg Minister of Finance submitted to the parliament a bill of law (“Bill”) amending the Law. The Bill implements the automatic exchange of information on savings income under the Directive starting January 1, 2015. Until that date, Luxembourg will continue to apply the existing withholding tax system on savings (unless the individual (i.e., the beneficiary of the interest payments) agrees to an exchange of information between tax authorities).

Taxation of the Noteholders

Noteholders (corporate or individuals) who are non-residents of Luxembourg and who have neither a permanent establishment, a permanent representative nor a fixed base of business in Luxembourg with which the holding of the notes is connected are not liable for any Luxembourg income tax, whether they receive payments of principal, payments of interest (including accrued but unpaid interest), payments received upon redemption or repurchase of the notes.

Luxembourg Tax on the Disposal of Notes

Noteholders who are non-residents of Luxembourg and who have neither a permanent establishment, a permanent representative nor a fixed base of business in Luxembourg with which the holding of the notes is connected are not liable for any Luxembourg income tax, whether or not they realize capital gains on the sale of any notes.

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Miscellaneous

There is no Luxembourg registration tax, stamp duty or any other similar tax or duty payable in Luxembourg by noteholders as a consequence of the issuance of the notes, nor will any of these taxes be payable as a consequence of a subsequent transfer, repurchase or redemption of the notes.

                There is no Luxembourg value-added tax (VAT) payable in respect of payments in consideration for the issuance of the notes or in respect of the payment of interest or principal under the notes or the transfer of the notes.

No Luxembourg inheritance taxes are levied on the transfer of the notes upon death of a noteholder in cases where the deceased was not a resident of Luxembourg for inheritance tax purposes. No Luxembourg gift tax will be levied on the transfer of the notes by way of gift unless the gift is recorded in a deed passed in front of a Luxembourg notary or otherwise registered in Luxembourg.

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 dependent upon the conclusion of certain other agreements by certain other non-EU countries to information exchange relating to interest and other similar income), Luxembourg and Austria will (unless during that period they elect 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 Luxembourg government is currently in the process of electing Luxembourg out of the withholding system in favor of automatic exchange of information with effect from January 1, 2015.

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 a withholding system applying in the case of Switzerland).

The European Commission has proposed certain amendments to the Directive, which may, if implemented, amend and broaden the scope of the requirement described above. 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 PifCo or 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 20% 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 except 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’ reports and other information at the offices of the New York Stock Exchange, 11 Wall Street, New York, New York 10005, on which Petrobras’ 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’ 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 the non-receipt of sales made and amounts invested, deposited or guaranteed by financial institutions.

We adopt the practice of integrated risk management according to which management focuses not on the individual risks of operations or business units, but takes a wider view of the consolidated corporation, capturing possible natural hedges where available. For the management of market risk, financial structural actions are taken through the proper management of capital and indebtedness of the company rather than 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 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.  Our exposure on these contracts is limited to the difference between contract value and market value on the volumes hedged. See note 34 to our audited consolidated financial statements for more information about our commodity derivative transactions. 

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The following table sets forth a sensitivity analysis demonstrating the net change in fair value of a 10% adverse change in the price of the underlying commodity as of December 31, 2013, which is a 10% increase in the price of the underlying commodity for options, futures and swaps.

	Petrobras
Outstanding as of December 2013	Quantity	Fair Value(1)	+10% Sensitivity
	(mbbl)	(U.S.$ million)	(U.S.$ million)
Options:
Buy contracts	4,069
Sell contracts	4,069
		0	0
Futures:
Buy contracts	52,267
Sell contracts	42,043
		-20.32	-137.34
Swaps:
Receive variable/pay fixed	0
Receive fixed/pay variable	0
		0	0

(1)     Fair value represents an estimate of gain or loss that would be realized if contracts were settled at the balance sheet date.

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 2013 and 2012, including short-term and long-term debt.   

	Total Debt Portfolio
	2013	2012
	(%)
Real-denominated:
Fixed rate	3.1	0.6
Floating rate	16.9	19.7
Sub-total	20.0	20.3
U.S.dollar-denominated:
Fixed rate	37.2	41.0
Floating rate	34.4	29.8
Sub-total	71.6	70.8
Other currencies:
Fixed rate	8.0	8.0
Floating rate	0.4	0.9
Sub-total	8.4	8.9
Total	100.0	100.0
Floating rate debt:
Real-denominated	16.9	19.7
Foreign currency-denominated	34.9	30.7
Fixed rate debt:
Real-denominated	3.1	0.6
Foreign currency denominated	45.1	49.0
Total	100.0	100.0
U.S. dollars	71.6	70.8
Euro	5.6	5.5
GBP	1.6	2.0
Japanese Yen	1.2	1.4
Brazilian reais	20.0	20.3
Total	100.0	100.0

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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 Certificado de Depósito Interbancário (Interbank Deposit Certificate, or CDI) and in the Taxa de Juros de Longo Prazo (Brazilian long-term interest rate, or TJLP), as fixed by the CMN.

We do not currently utilize derivative instruments to manage our exposure to interest rate fluctuation.  We have been considering 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 is limited to the balance sheet and derives principally from the incidence of non-real denominated obligations in our debt portfolio.  See Item 5. “Operating and Financial Review and Prospects—Inflation and Exchange Rate Variation.”

Our foreign currency risk management strategy includes the use of derivative instruments to protect against foreign exchange rate volatility, which may impact the value of certain of our obligations.

Information regarding expected maturity dates and currency, the principal cash flows and related average interest rates of our debt obligations is set out in note 17 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, 2013, the gross aggregate amount of such reimbursements was approximately U.S.$40 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

Evaluation of 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, 2013.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.  Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as of December 31, 2013 were 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’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining effective internal control over financial reporting and for its assessments 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 Audit Committee and our Chief Executive Officer and 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.

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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 the 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.

Our management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on such assessment and criteria, the Company’s management has concluded that Company’s internal control over financial reporting was effective as of December 31, 2013. On May 14, 2013, COSO published an updated Internal Control - Integrated Framework (2013) and related illustrative documents. As of December 31, 2013, the company is utilizing the original framework published in 1992. The transition period for adoption of the updated framework ends on December 15, 2014.

The effectiveness of our internal control over financial reporting as of December 31, 2013, has been audited by PricewaterhouseCoopers Auditores Independentes, an independent registered public accounting firm, as stated in their report which appears herein.

Changes in Internal Controls

Our management has not identified any changes in its internal control over financial reporting during the fiscal year ended December 31, 2013, that has materially affected or is reasonably likely to materially affect its internal control over financial reporting.

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. Sérgio Franklin Quintella is the Audit Committee financial expert and he is independent, as defined in 17 CFR 240.10A-3.

Item 16B.    Code of Ethics

We guide our business and our relations with third parties 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 was renamed to Petrobras System Code of Ethics in 2002.

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 the 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 since then, has 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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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, 2013 and December 31, 2012:

	Year Ended December 31,
	2013	2012
	(U.S.$ thousand)
Audit fees	8,316	7,357
Audit-related fees	80	207
Tax fees	253	172
Total fees	8,648	7,736

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), subsidiary audits (IFRS and Brazilian GAAP, among others) and review of periodic documents filed with the SEC.  In 2013, audit fees include fees billed by PricewaterhouseCoopers Auditores Independentes, in the amount of U.S.$517 thousand, related to the audit of the 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 2013 and 2012.

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 for 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, Miriam Aparecida Belchior, Luciano Galvão Coutinho and Sergio Franklin Quintella, 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 satisfy the other requirements of Exchange Act Rule 10A-3.

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Item 16E.    Purchases of Equity Securities by the Issuer and Affiliated Purchasers

During the fiscal year ended December 31, 2013, 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’ 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’ 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’ directors are non-management directors. The internal regulation of Petrobras’ 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’ 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’ 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’ 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’ 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) 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 or Code of Good Practices are permitted. Both documents are available on Petrobras’ 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-103, incorporated herein by reference.

Item 19.    Exhibits

No.	Description
1.1	Amended Bylaws of Petróleo Brasileiro S.A.-Petrobras.
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	Eleventh 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 2.875% Global Notes due 2015 (incorporated by reference to Exhibit 4.8 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	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)).
2.25	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)).
2.26	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)).
2.27	Guaranty for the 2.875% Global Notes due 2015, dated as of February 6, 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 and Petrobras International Finance Company, furnished to the Securities and Exchange Commission on February 6, 2012 (File Nos. 001-15106 and 001-33121)).
2.28	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)).
2.29	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)).
2.30	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)).
2.31	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)).
2.32	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)).
2.33	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)).
2.34	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)).
2.35	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).
2.36	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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2.37	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))
2.38	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))
2.39	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)).
2.40	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)).
2.41	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)).
2.42	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)).
2.43	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)).
2.44	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)).
2.45	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)).
2.46	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)).
2.47	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)).
2.48	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)).
2.49	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)).
2.50	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)).
2.51	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)).
2.52	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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2.53	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)).
2.54	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)).
2.55	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)).
2.56	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)).
2.57	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)).
2.58	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)).
2.59	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)).
2.60	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)).
2.61	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)).
2.62	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)).
2.63	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)).
2.64	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)).
2.65	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)).
2.66	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)).
2.67	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)).
2.68	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)).

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2.69	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)).
2.70	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)).
2.71	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)).
2.72	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)).
2.73	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)).
2.74	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)).
2.75	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)).
2.76	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)).
2.77	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)).
	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.
2.78	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.
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’ 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 Petrolíferos Fiscales Bolivianos-YPFB (together with and English version) (incorporated by reference to Exhibit 10.2 to Petrobras’ 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 KPMG.
15.3	Consent letter of DeGolyer and MacNaughton.
99.1	Third Party Reports of DeGolyer and MacNaughton.

166

 

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 April 30, 2014.

Petróleo Brasileiro S.A.—PETROBRAS

                                                                                                              By:    /s/ Maria das Graças Silva Foster                          

Name: Maria das Graças Silva Foster
    Title:   Chief Executive Officer and Chief

             International Officer

By:    /s/ Almir Guilherme Barbassa                               
      Name: Almir Guilherme Barbassa
      Title: Chief Financial Officer and Chief Investor

Relations Officer

167

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated financial statements at

December 31, 2013, 2012 and 2011 with

report of independent registered

public accounting firm

 

Petróleo Brasileiro S.A. – Petrobras

Contents

Report of Independent Registered Public Accounting Firm		F-3
Consolidated Statement of Financial Position		F-6
Consolidated Statement of Income		F-7
Consolidated Statement of Comprehensive Income		F-8
Consolidated Statement of Cash Flows		F-9
Consolidated Statement of Changes in Shareholders’ Equity		F-10
Notes to the financial statements		F-11
1.	The Company and its operations	F-11
2.	Basis of preparation	F-11
3.	Summary of significant accounting policies	F-13
4.	Critical accounting policies: key estimates and judgments	F-24
5.	New standards and interpretations	F-27
6.	Cash and cash equivalents	F-30
7.	Marketable securities	F-30
8.	Trade and other receivables	F-30
9.	Inventories	F-31
10.	Acquisitions, disposal of assets and legal mergers	F-32
11.	Investments	F-37
12.	Property, plant and equipment	F-40
13.	Intangible assets	F-41
14.	Impairment	F-43
15.	Exploration for and evaluation of oil and gas reserves	F-45
16.	Trade payables	F-46
17.	Finance debt	F-47
18.	Leases	F-50
19.	Related parties	F-50
20.	Provision for decommissioning costs	F-53
21.	Taxes	F-53
22.	Employee benefits (Post-Employment)	F-57
23.	Profit sharing	F-64
24.	Shareholders’ equity	F-64
25.	Sales revenues	F-66
26.	Other operating expenses, net	F-67
27.	Expenses by nature	F-67
28.	Net finance income (expense)	F-68
29.	Supplemental information on statement of cash flows	F-68
30.	Segment Information	F-69
31.	Provisions for legal proceedings, contingent liabilities and contingent assets	F-74
32.	Natural Gas Purchase Commitments	F-79
33.	Collateral in connection with concession agreements for petroleum exploration	F-79
34.	Risk management and derivative instruments	F-79
35.	Fair value of financial assets and liabilities	F-87
36.	Insurance	F-88
37.	Subsequent events	F-89
38.	Information Related to Guaranteed Securities Issued by Subsidiaries	F-90
Supplementary information on Oil and Gas Exploration and Production (unaudited)		F-91

 

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 and 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, 2013, and December 31, 2012, and the results of their operations and their cash flows for the years ended December 31, 2013, and December 31, 2012, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013 based on criteria established in Internal Control - Integrated Framework  (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 the accompanying Management’s Report on Internal Control over Financial Reporting. 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.

We also have audited the adjustments to the 2011 financial statements to retrospectively apply the change in accounting for employee benefit plans for the revisions to IAS 19 Employee Benefits as described in Note 2.3. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2011 consolidated financial statements of the Company other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2011 consolidated financial statements taken as a whole.

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.

F-3 

 

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, February 25, 2014

/s/ PricewaterhouseCoopers Auditores Independentes

PricewaterhouseCoopers Auditores Independentes

CRC 2SP000160/O-5 “F” RJ

Marcos Donizete Panassol

Contador CRC 1SP155975

F-4 

 

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

Petróleo Brasileiro S.A. – Petrobras

Rio de Janeiro - RJ

We have audited, before the effects of the adjustments to retrospectively apply the change in accounting described in Note 2.3, the accompanying consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows of Petróleo Brasileiro S.A. – Petrobras and subsidiaries (“the Company”) for the year ended  December 31, 2011. The 2011 financial statements before the effects of the adjustments described in note 2.3 are not presented herein. The 2011 consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the 2011 financial statements, before the effects of the adjustments to retrospectively apply the change in accounting described in note 2.3, present fairly, in all material respects, the consolidated results of the Company’ operations and their cash flows for the year ended December 31, 2011, in conformity with International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB).

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively apply the change in accounting described in note 2.3, which include the disclosure of the January 1, 2012 balance sheet and, accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were audited by a successor auditor.

/s/ KPMG Auditores Independentes
KPMG Auditores Independentes

Rio de Janeiro, Brazil

March 30, 2012

F-5 

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statement of Financial Position

December 31, 2013, 2012 and January 1, 2012 (In millions of US Dollars)

Assets	Note	12.31.2013	12.31.2012 (*)	01.01.2012 (*)	Liabilities	Note	12.31.2013	12.31.2012 (*)	01.01.2012 (*)
Current assets					Current liabilities
Cash and cash equivalents	6	15,868	13,520	19,057	Trade payables	16	11,919	12,124	11,863
Marketable securities	7	3,885	10,431	8,961	Current debt	17	8,001	7,479	10,067
Trade and other receivables, net	8.1	9,670	11,099	11,756	Finance lease obligations	18.1	16	18	44
Inventories	9	14,225	14,552	15,165	Income taxes payable	21.1	281	345	263
Recoverable income taxes	21.1	1,060	1,462	2,018	Other taxes payable	21.2	4,669	5,783	5,584
Other recoverable taxes	21.2	3,911	4,110	4,830	Dividends payable	21.2	3,970	3,011	2,067
Advances to suppliers		683	927	740	Payroll, profit sharing and related charges		2,052	2,163	2,528
Other current assets		946	1,550	2,065	Pension and medical benefits	22	816	788	761
		50,248	57,651	64,592	Others		2,429	2,359	3,187
							34,153	34,070	36,364
Assets classified as held for sale	10.3	2,407	143	−	Liabilities on assets classified as held for sale	10.3	1,073	−	−
		52,655	57,794	64,592			35,226	34,070	36,364
Non-current assets					Non-current liabilities
Long-term receivables					Non-current debt	17	106,235	88,484	72,718
Trade and other receivables, net	8.1	4,532	4,441	3,253	Finance lease obligations	18.1	73	86	98
Marketable securities	7	131	176	3,064	Deferred income taxes	21.3	9,906	11,976	12,558
Judicial deposits	31	2,504	2,696	2,080	Pension and medical benefits	22	11,757	19,436	15,057
Deferred income taxes	21.3	1,130	1,277	787	Provisions for legal proceedings	31	1,246	1,265	1,088
Other tax assets	21.2	5,380	5,223	4,912	Provision for decommissioning costs	20	7,133	9,441	4,712
Advances to suppliers		3,230	3,156	3,141	Others		724	772	1,231
Others		1,875	1,887	1,725
		18,782	18,856	18,962			137,074	131,460	107,462
					Total liabilities		172,300	165,530	143,826
					Shareholders' equity	24
Investments	11.2	6,666	6,106	6,530	Share capital		107,371	107,362	107,355
Property, plant and equipment	12.1	227,901	204,901	182,918	Additional paid in capital		395	349	316
Intangible assets	13.1	15,419	39,739	43,412	Profit reserves		75,689	67,238	60,142
		268,768	269,602	251,822	Accumulated other comprehensive income (loss)		(34,928)	(14,235)	3,503
					Attributable to the shareholders of Petrobras		148,527	160,714	171,316
					Non-controlling interests		596	1,152	1,272
					Total Equity		149,123	161,866	172,588
Total Assets		321,423	327,396	316,414	Total liabilities and shareholder's equity		321,423	327,396	316,414
(*) Amounts restated, as set out in note 2.3.
The Notes form an integral part of these Financial Statements.

F-6 

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statement of Income

December 31, 2013, 2012 and 2011 (In millions of US Dollars, unless otherwise indicated)

	Note	2013	2012	2011
Sales revenues	25	141,462	144,103	145,915
Cost of sales		(108,254)	(107,534)	(99,595)
Gross profit		33,208	36,569	46,320
Income (expenses)
Selling expenses		(4,904)	(4,927)	(5,346)
General and Administrative expenses		(4,982)	(5,034)	(5,161)
Exploration costs		(2,959)	(3,994)	(2,630)
Research and development expenses		(1,132)	(1,143)	(1,454)
Other taxes		(780)	(386)	(460)
Other operating expenses, net	26	(2,237)	(4,185)	(3,984)
		(16,994)	(19,669)	(19,035)
Net income before financial results, profit sharing and income taxes		16,214	16,900	27,285
Finance Income		1,815	3,659	3,943
Finance Expenses		(2,673)	(2,016)	(1,424)
Foreign exchange and inflation indexation charges		(1,933)	(3,569)	(2,443)
Net finance income (expense)	28	(2,791)	(1,926)	76
Share of profit / gains on interest in equity-accounted investments		507	43	230
Profit sharing	23	(520)	(524)	(867)
Net income before income taxes		13,410	14,493	26,724
Income taxes	21.4	(2,578)	(3,562)	(6,732)
Net income		10,832	10,931	19,992
Net income (loss) attributable to:
Shareholders of Petrobras		11,094	11,034	20,121
Non-controlling interests		(262)	(103)	(129)
		10,832	10,931	19,992
Basic and diluted earnings per weighted-average of common and preferred share in U.S. dollars	24.6	0.85	0.85	1.54
The Notes form an integral part of these Financial Statements.

F-7 

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statement of Comprehensive Income

December 31, 2013, 2012 and 2011 (In millions of US Dollars)

	2013	2012 (*)	2011 (*)
Net income	10,832	10,931	19,992
Actuarial gains / (losses) on defined benefit pension plans	7,248	(4,693)	(1,807)
Deferred income tax	(2,153)	1,533	710
Cumulative translation adjustments	(20,397)	(14,049)	(21,859)
	(15,302)	(17,209)	(22,956)
Items that may be reclassified subsequently to profit or loss:
Unrealized gains / (losses) on available-for-sale securities
Recognized in shareholders' equity	1	498	81
Reclassified to profit or loss	(43)	(714)	8
Deferred income tax	15	72	(30)
	(27)	(144)	59
Unrealized gains / (losses) on cash flow hedge
Recognized in shareholders' equity	(6,265)	(3)	(33)
Reclassified to profit or loss	312	7	5
Deferred income tax	2,030	1	−
	(3,923)	5	(28)
Share of other comprehensive income of equity-accounted investments	(236)	−	6
	(4,186)	(139)	37
Other comprehensive income (loss):	(19,488)	(17,348)	(22,919)
Total Comprehensive income (loss)	(8,656)	(6,417)	(2,927)
Shareholders of Petrobras	(8,263)	(6,136)	(2,773)
Non-controlling interests	(393)	(281)	(154)
Total comprehensive income (loss)	(8,656)	(6,417)	(2,927)
(*) Amounts restated, as set out in note 2.3.
The Notes form an integral part of these Financial Statements.

F-8 

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statement of Cash Flows

December 31, 2013, 2012 and 2011 (In millions of US Dollars)

	2013	2012	2011
Cash flows from Operating activities
Net income attributable to the shareholders of Petrobras	11,094	11,034	20,121
Adjustments for:
Non-controlling interests	(262)	(103)	(129)
Share of (profit) loss of equity-accounted investments	(507)	(43)	(230)
Depreciation, depletion and amortization	13,188	11,119	10,535
Impairment charges on property, plant and equipment and other assets	1,125	880	1,056
Exploration expenditures written off	1,892	2,847	1,480
(Gains) / losses on disposal / write-offs of non-current assets	(1,764)	2	527
Foreign exchange variation, indexation and finance charges	3,167	4,308	3,799
Deferred income taxes, net	402	1,266	3,599
Pension and medical benefits (actuarial expense)	2,566	2,091	1,730
Decrease / (Increase) in assets
Trade and other receivables, net	(1,142)	(1,522)	(2,326)
Inventories	(2,128)	(1,864)	(5,035)
Other assets	(212)	(1,990)	(2,537)
Increase/(Decrease) in liabilities
Trade payables	1,108	1,039	2,455
Taxes payable	(1,517)	(151)	(1,991)
Pension and medical benefits	(796)	(735)	(837)
Other liabilities	75	(290)	1,481
Net cash provided by operating activities	26,289	27,888	33,698
Cash flows from Investing activities
Capital expenditures	(45,110)	(40,802)	(41,377)
Investments in investees	(199)	(146)	(336)
Receipts from disposal of assets (divestment)	3,820	276	−
Investments in marketable securities	5,718	2,051	6,683
Dividends received	146	241	411
Net cash (used in) investing activities	(35,625)	(38,379)	(34,619)
Cash flows from Financing activities
Acquisition of Non-controlling interest	(70)	255	27
Proceeds from long-term financing	39,542	25,205	23,951
Repayment of principal	(18,455)	(11,347)	(8,750)
Repayment of interest	(5,066)	(4,772)	(4,574)
Dividends paid	(2,656)	(3,272)	(6,422)
Net cash provided by financing activities	13,295	6,069	4,232
Effect of exchange rate changes on cash and cash equivalents	(1,611)	(1,115)	(1,909)
Net increase/ (decrease) in cash and cash equivalents	2,348	(5,537)	1,402
Cash and cash equivalents at the beginning of the year	13,520	19,057	17,655
Cash and cash equivalents at the end of the year	15,868	13,520	19,057
The Notes form an integral part of these Financial Statements.

F-9 

 

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statement of Changes in Shareholders’ Equity

December 31, 2013, 2012 and 2011 (In millions of US Dollars)

		Additional paid in capital		Accumulated other comprehensive income			Profit Reserves
	Share Capital	Incremental costs attributable to the issue of new shares	Change in interest in subsidiaries	Cumulative translation adjustment	Actuarial gains (losses) on defined benefit plans	Other comprehensive income and deemed cost	Legal	Statutory	Tax incentives	Profit retention	Retained earnings	Shareholders' equity attributable to shareholders	Non-controlling interests	Total shareholders' equity
Balance at January 1, 2011 (*)	107,341	(279)	286	30,130	(3,343)	215	5,806	571	698	39,342	(82)	180,685	1,839	182,524
Capital increase with reserves	14								(14)			−		−
Realization of deemed cost						(6)					6	−		−
Change in interest in subsidiaries			309									309	(292)	17
Net income											20,121	20,121	(129)	19,992
Other comprehensive income				(22,433)	(1,097)	37					599	(22,894)	(25)	(22,919)
Appropriations:
Allocation of net income							1,006	537	43	12,235	(13,821)	−		−
Dividends											(6,905)	(6,905)	(121)	(7,026)
Balance at December 31, 2011 (*)	107,355	(279)	595	7,697	(4,440)	246	6,812	1,108	727	51,577	(82)	171,315	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				(14,434)	(3,160)	(139)					563	(17,170)	(178)	(17,348)
Appropriations:
Allocation of net income							552	537	9	6,005	(7,103)	−		−
Dividends											(4,499)	(4,499)	(109)	(4,608)
Balance at December 31, 2012 (*)	107,362	(279)	628	(6,737)	(7,600)	102	7,364	1,645	729	57,582	(82)	160,713	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				(21,597)	5,095	(4,186)					1,331	(19,357)	(131)	(19,488)
Distributions:												−
Allocation of net income							555	537	9	7,277	(8,378)	−		−
Dividends											(3,970)	(3,970)	(61)	(4,031)
	107,371	(279)	674	(28,334)	(2,505)	(4,089)	7,919	2,182	729	64,859	−	148,527	596	149,123
Balance at December 31, 2013	107,371		395			(34,928)					75,689	148,527	596	149,123
(*) Amounts restated, as set out in note 2.3.
The Notes form an integral part of these Financial Statements.

F-10 

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

December 31, 2013 and 2012 (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 any other correlated 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

The consolidated financial information has been prepared and is 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.

The 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 detailed in the accounting policies set out below.

The annual consolidated financial information was approved and authorized for issue by the Company’s Board of Directors in a meeting held on February 25, 2014.

2.2.Functional and presentation currency

The functional currency of Petrobras and all Brazilian subsidiaries is the Brazilian Real. The functional currency of most of the 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 into the presentation currency 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 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 or valuation where items are remeasured. All exchange rate 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 in the consolidated statements of changes in shareholders’ equity.

The cumulative translation adjustments were set to nil at January 1, 2009 (the date of transition to IFRS).

2.3.Prior period restatements

The Statements of Financial Position as of December 31, 2012 and January 1, 2012 have been restated for comparative purposes, including the following effects:

F-11 

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

a)Amendments to IAS 19 – “Employee benefits”

Effective for annual periods beginning on January 1, 2013, amendments to IAS 19 – “Employee benefits” eliminated the option to defer actuarial gains and losses (corridor approach) and requires net interest to be calculated by applying the discount rate used for measuring the obligation to the net benefit asset or liability.

The impact of such amendments, for the year ended December 31, 2012 is: an increase in the Company’s net actuarial liability of US$10,161 (US$6,179 at January 1, 2012), as well as a corresponding decrease in deferred tax liabilities of US$2,988 (US$1,657 at January 1, 2012) and a decrease of US$7,173 in the shareholders’ equity (US$4,522 at January 1, 2012).

b)Offsetting deferred income taxes

Deferred income tax assets were offset against deferred income tax liabilities by the Company, considering the balance of deferred income taxes of each of the consolidated subsidiaries. The impact of such change for the year ended December 31, 2012 was a decrease of US$ 4,249 in noncurrent assets and liabilities (US$ 3,500 at January 1, 2012).

Those restatements had no significant impact on the Company’s profit or loss or cash flows.

The effects of such changes in the statement of financial position, statement of changes in shareholders’ equity and statement of comprehensive income, for comparative purposes, are set out following:

	12.31.2012				01.01.2012
Statement of Financial Position	As presented (*)	(a) Impact of IAS 19 amendment	(b) Offsetting Deferred Income Taxes	Restated	As presented (*)	(a) Impact of IAS 19 amendment	(b) Offsetting Deferred Income Taxes	Restated
Non-current assets
Deferred income taxes	5,526	−	(4,249)	1,277	4,287	−	(3,500)	787
Non-current liabilities
Pension and medical benefits	9,275	10,161		19,436	8,878	6,179		15,057
Deferred income taxes	19,213	(2,988)	(4,249)	11,976	17,715	(1,657)	(3,500)	12,558
Shareholders' equity
Other comprehensive income (loss)	(7,144)	(7,091)	−	(14,235)	7,943	(4,440)	−	3,503
Retained earnings (profit reserves)	67,320	(82)		67,238	60,224	(82)	−	60,142
(*) As presented for the period ended December 31, 2012.

	12.31.2012		12.31.2011		01.01.2011
Statement of Shareholders' Equity	Actuarial gains (losses) on defined benefit plans	Retained earnings	Actuarial gains (losses) on defined benefit plans	Retained earnings	Actuarial gains (losses) on defined benefit plans	Retained earnings
Other comprehensive income
As presented (*)	−	−	−	−	−	−
Restated	(7,600)	−	(4,440)	−	(3,343)	−
Retained earnings
As presented (*)	−	−	−	−	−	−
Restated	−	(82)	−	(82)	−	(82)
(*) As presented for the period ended December 31, 2012.

	2012		2011
Statement of comprehensive income	As presented (*)	Restated	As presented (*)	Restated
Other comprehensive income
Actuarial gains (losses) on defined benefit plans	−	(4,693)	−	1,807
Deferred income taxes on actuarial gains (losses)	−	1,533	−	(710)
(*) As presented for the period ended December 31, 2012.

F-12

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

3.Summary of significant accounting policies

The accounting policies set out below have been consistently applied to all periods presented in these consolidated financial statements.

3.1.Basis of consolidation

 The consolidated financial statements include the financial information of Petrobras and the entities it controls (its subsidiaries). 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 the Company.

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.

F-13

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The entities and structured entities set out following are consolidated:

	Equity capital - Subscribed, paid in and voting %
Subsidiaries	2013	2012
Petrobras Distribuidora S.A. - BR and its subsidiaries	100.00	100.00
Braspetro Oil Services Company - Brasoil and its subsidiaries (i)	100.00	100.00
Petrobras International Braspetro B.V. - PIBBV and its subsidiaries (i) (ii)	100.00	100.00
Petrobras Comercializadora de Energia Ltda. - PBEN (iii)	100.00	100.00
Petrobras Negócios Eletrônicos S.A. – E-PETRO (iv)	100.00	100.00
Petrobras Gás S.A. - Gaspetro and its subsidiaries	99.99	99.99
Petrobras International Finance Company - PifCo (i)	100.00	100.00
Petrobras Transporte S.A. - Transpetro and its subsidiaries	100.00	100.00
Downstream Participações Ltda.	99.99	99.99
Petrobras Netherlands B.V. - PNBV and its subsidiaries (i)	100.00	100.00
5283 Participações Ltda.	100.00	100.00
Fundo de Investimento Imobiliário RB Logística - FII	99.00	99.00
Baixada Santista Energia S.A.	100.00	100.00
Sociedade Fluminense de Energia Ltda. – SFE (vi)	−	100.00
Termoaçu S.A. (vii) (viii)	100.00	−
Termoceará Ltda.	100.00	100.00
Termomacaé Ltda.	100.00	100.00
Termomacaé Comercializadora de Energia Ltda.	100.00	100.00
Termobahia S.A.	98.85	98.85
Ibiritermo S. A. (x)	50.00	50.00
Petrobras Biocombustível S.A.	100.00	100.00
Refinaria Abreu e Lima S.A. (vi)	−	100.00
Companhia Locadora de Equipamentos Petrolíferos S.A. – CLEP	100.00	100.00
Comperj Participações S.A. (vi)	−	100.00
Comperj Estirênicos S.A. (vi)	−	100.00
Comperj MEG S.A. (vi)	−	100.00
Comperj Poliolefinas S.A. (vi)	−	100.00
Cordoba Financial Services Gmbh - CFS and its subsidiary (i)	100.00	100.00
Breitener Energética S.A. and its subsidiaries	93.66	93.66
Cayman Cabiunas Investment CO. (ix)	−	100.00
Innova S.A.	100.00	100.00
Companhia de Desenvolvimento de Plantas Utilidades S.A. - CDPU (v)	−	100.00
Companhia de Recuperação Secundária S.A. - CRSEC (vi)	−	100.00
Arembepe Energia S.A.	100.00	100.00
Energética Camaçari Muricy S.A.	100.00	71.60
Companhia Integrada Têxtil de Pernambuco S.A. - Citepe	100.00	100.00
Companhia Petroquímica de Pernambuco S.A. - PetroquímicaSuape	100.00	100.00
Petrobras Logística de Exploração e Produção S.A. - PB-LOG	100.00	100.00
Liquigás S.A.	100.00	100.00
Araucária Nitrogenados S.A. (vii)	100.00	−
Fábrica Carioca de Catalizadores S.A. - FCC (viii) (x)	50.00	−
(i) Foreign-incorporated companies with non-Brazilian Real consolidated financial statements.
(ii) 11.87% interest of 5283 Participações Ltda.
(iii) 0.09% interest of Petrobras Gás S.A. - Gaspetro.
(iv) 0.05% interest of Downstream.
(v) Companies merged into Comperj Participações S.A.
(vi) Companies merged into Petrobras
(vii) Acquisition of control (business combination).
(viii) Equity-method accounted investee in 2012.
(ix) Extinguished company
(x) Joint operation

F-14

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

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
Nova Transportadora do Nordeste S.A. - NTN	Brazil	Gas & Power
Nova Transportadora do Sudeste S.A. - NTS	Brazil	Gas & Power
Fundo de Investimento em Direitos Creditórios Não-padronizados do Sistema Petrobras	Brazil	Corporate
(i) Foreign-Incorporated Companies with non-Brazilian Real consolidated financial statements.

Petrobras has no equity interest in the structured entities above, and control is not determined by voting rights, but by the power the Company has over the relevant operating activities of such entities.

3.2.Business segment reporting

The information related to the operating segments (business areas) of the Company 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.

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 between the areas using methods based on market parameters.

Information for each business area is presented as defined by the current organizational structure. The Company operates under the following segments:

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, our 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 (RT&M): 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 stations 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 mainly the activities of Petrobras Distribuidora, 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.

F-15

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

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.

3.3.Financial instruments

3.3.1.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.

3.3.2.Marketable securities

Marketable securities comprise investments in debt or equity securities. These instruments are initially measured at fair value and are classified and subsequently measured as set out below:

-Fair value through profit or loss - includes securities purchased and held for trading in the short term. These instruments are subsequently measured at fair value with changes recognized in profit or loss.

-Held-to-maturity - includes securities with fixed or determinable payments, for which management has the ability and intent to hold until maturity. These instruments are subsequently measured at amortized cost using the effective interest rate method.

-Available-for-sale – includes securities that are either designated in this category or not classified as fair value through profit or loss or held-to-maturity securities. These instruments are subsequently measured at fair value. Subsequent changes in fair value are recognized within other comprehensive income, in the shareholders’ equity and reclassified to profit or loss when securities are derecognized.

Subsequent changes attributable to interest, foreign exchange, and inflation are recognized in profit or loss for all categories, when applicable.

3.3.3.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 credit losses and impairment.

The Company recognizes a provision 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. Such evidence includes insolvency, defaults or a significant probability of a debtor filing for bankruptcy.

3.3.4.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.

3.3.5.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.

F-16

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Gains or losses arising from changes in fair value are recognized in profit or loss as finance income (finance expense), unless the derivative is qualified and designated for hedge accounting.

3.3.6.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 which 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.

In hedging relationships which qualify for fair value hedge accounting, the gain or loss from remeasuring the hedging instrument at fair value is recognized in profit or loss.

In hedging relationships which qualify for cash flow hedge accounting, the Company designates derivative financial instruments and long-term debt (non-derivative financial instruments) and gains or losses relating to the effective portion of the hedge are recognized within other comprehensive income, in the shareholders’ equity and recycled to profit or loss in the periods when the hedged item affects profit or loss. The gains or losses relating to the ineffective portion are recognized in profit or loss.

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 profit or loss.

3.4.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, liquid natural gas (LNG), fertilizers and biofuels, stated at the lower of the average cost, and their net realizable value.

Crude oil and liquid natural gas (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, other than raw material, 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.

F-17

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

3.5.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 is not control or joint control over those polices.

A joint arrangement is an arrangement over which two or more parties have joint control. 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.

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 assets, liabilities and related income and expenses. In addition, the Company recognizes its share of the sales revenue and expenses and the joint assets and joint liabilities.

3.6.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 profit or loss 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 an additional paid-in capital.

Goodwill arising from investments in associates and joint ventures without change of control is accounted for as part of these investments. It is measured by the excess of the consideration transferred over the interest in the fair value of the net assets.

3.7.Oil and Gas exploration and development expenditures

The costs incurred in connection with the exploration, appraisal, development and production of oil and 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 oil and natural gas (capitalized acquisition costs) are initially capitalized.

-Costs directly associated with exploratory wells pending determination of proved reserves are capitalized within property, plant and equipment. Exploratory wells that have found oil and gas reserves, but those reserves cannot be classified as proved, 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.

F-18

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

-Costs related to exploratory wells drilled in areas of unproved reserves are expensed when determined to be dry or non-economical (did not encounter potentially economic oil and gas quantities).

-Costs related to the construction, installation and completion of infrastructure facilities, such as platforms, pipelines, drilling of development wells and other related costs incurred in connection with the development of proved reserve areas and successful exploratory wells are capitalized within property, plant and equipment.

3.8.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, adjusted during hyperinflationary periods, as well as by the present value of the estimated cost of dismantling and removing the asset and restoring the site and reduced by accumulated depreciation and impairment losses.

Expenditures on major maintenance of industrial units and vessels are capitalized if the recognition criteria are met. Expenditures comprise: replacement of certain assets or parts of assets, equipment assembly services, as well as other related costs. Such maintenance occurs, on average, every four years. Capitalized expenditures are depreciated on a straight line basis based on the estimated time of the maintenance cycle.

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 life or by applying the unit-of-production method to the related assets.

Except for assets with a useful life 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, as set out below:

i) Depreciation (amortization) of oil and gas producing properties, including related equipment and facilities is computed based on a unit-of-production basis over the proved developed oil and gas reserves, applied on a field by field basis; and

ii) Amortization of amounts paid for obtaining concessions for exploration of oil and natural gas of producing properties, such as signature bonus (capitalized acquisition costs) 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 is depreciated on a straight line basis. See note 12 for further information about the estimated useful life by class of assets.

3.9.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) and 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”); public service concessions; trademarks; patents; software and goodwill.

F-19

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Signature bonuses paid for obtaining concessions for exploration of oil and natural gas and amounts related to the Assignment Agreement are initially capitalized within intangible assets and are transferred to property, plant and equipment upon the declaration of commerciality.

Signature bonuses and amounts related to the Assignment Agreement 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.

3.10.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 comprises a comparison of the carrying amount of an individual asset or a cash-generating unit with its recoverable amount. Whenever the recoverable amount of the unit is less than the carrying amount of the unit, 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 weighted average cost of capital post-tax (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 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 on a field by field basis.

Reversal of previously recognized impairment losses is permitted for assets other than goodwill.

3.11.Leases 

Leases that transfer substantially all the risks and rewards incidental to ownership of the leased item are recognized as finance leases.

F-20

 

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 amounts equal to the fair value of the lease property or, if lower, to the present value of the minimum lease payments, each 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 all the risks and rewards, 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.

3.12.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 management 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 past the period to complete the sale by more than one year if the delay is caused by events or circumstances beyond the entity’s control and there is sufficient evidence of the commitment to the plan to sell the asset.

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.

3.13.Decommissioning costs

Decommissioning costs are future obligations to perform environmental restoration, dismantle and remove a facility as it terminates 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 (associated with the obligation) 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.

A corresponding provision is recognized as a liability. Unwinding of the discount is recognized as a financial 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 when a field is declared to be commercial, 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.

F-21

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

3.14.Provisions 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 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.

3.15.Income taxes

Income tax expense for the period comprises current and deferred tax.

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 as of December 31, 2007.

a)Current income taxes

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.

Taxable profit differs from accounting profit due to certain adjustments required by tax regulations.

b)Deferred income taxes

Deferred tax is 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 temporary deductible differences 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 shall be 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.

3.16.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 independent actuary, 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.

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 profit or loss; 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, changes to, or withdraw 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.

F-22

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

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.

Remeasurements of the net defined benefit liability (asset), recognized in other comprehensive income, comprise: (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).

Actuarial assumptions include demographical and financial assumptions, medical costs estimates, as well as historical data related to expenses incurred and employee contributions.

The Company also contributes amounts to defined contribution plans, that are expensed when incurred and are computed based on a percentage over salaries.

3.17.Share Capital and Stockholders’ Compensation

Share capital comprises common shares and preferred shares. Incremental costs directly attributable to the issue of new shares are classified as additional paid in capital and shown (net of tax) in shareholders’ equity as a deduction from the proceeds.

Preferred shares have priority on returns of capital and dividends, which are based on the higher amount of 3% over the net book value of shareholders equity for preferred shares, or 5% of the share capital for preferred shares. Preferred shares do not grant any voting rights; are non-convertible into common shares and participate under the same terms as common shares, in capital increases resulting from the capitalization of reserves and profits.

Dividend distribution comprises dividends and interest on capital determined in accordance with the limits defined in the Company’s bylaws.

Interest on capital is a form of dividend distribution which is deductible for tax purposes in Brazil.  Tax benefits from the deduction of interest on capital are recognized in profit or loss.

3.18.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 are recognized as revenue in profit or loss 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 thereafter are transferred to profit or loss over the useful life of the asset on a straight-line basis.

3.19.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 reliably measured. 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.

F-23

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

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 and 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.

4.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, revenues 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.

4.1.Oil and gas reserves

Oil and gas reserves are estimated based on economic, geological and engineering information, such as well logs, pressure data and fluid sample core data and are used as the basis for calculating unit-of-production depreciation rates and for impairment assessments.

These estimates require the application of judgment and are reviewed at least annually and 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 prices and costs that are used in the estimation of reserves. Revisions can also result from significant changes in development strategy or production equipment and facility capacity.

Oil and gas reserves include both proved and unproved reserves. 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 and operating conditions (i.e., prices and costs as of the date the estimate is made). 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 and represented 59.9% of the total proved reserves of the Company as of December 31, 2013.

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.

F-24

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Other information about reserves is presented as supplementary information.

a)Oil and gas reserves: depreciation, amortization and depletion

Depreciation, amortization and depletion 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 and depletion recognized in profit or loss 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 expense, while an increase in reserves would reduce depreciation.

See notes 3.8 and 12 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 3.10. In general, analyses are based on proved reserves and probable reserves. The percentage of probable reserves that the Company includes in cash flows does not exceed the Company’s past success ratios in developing probable reserves.

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.

The Company, typically, does not view temporarily low oil prices as a trigger event for conducting impairment tests. 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. Accordingly, any impairment tests that the Company performs make use of its long-term price assumptions used in its planning and budgeting processes and its capital investment decisions, which are considered reasonable estimates, given market indicators and experience.

Lower future oil and gas prices, 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 3.8, 12 and 14 for more detailed information about oil and natural gas exploration and development assets.

4.2.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 following 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.

F-25

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

-Downstream CGU’s: i) Refining assets 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 complement and are an interdependent portion of the refining assets, to supply the market; ii) Petrochemical CGU: petrochemical plants from PetroquímicaSuape and Citepe; iii) Transportation CGU: the transportation CGU is comprised of the vessel fleet of Transpetro.

-Gas & Power CGU’s: i) Natural gas CGU: comprised of natural gas pipelines, natural gas processing plants and fertilizers and nitrogen products plants; and ii) Power CGU: thermoelectric power generation plants.

-Distribution CGU: comprised of the distribution assets related to the operations of Petrobras Distribuidora S.A. and Liquigás Distribuidora S.A..

-Biofuels CGU’s: i) Biodiesel CGU: group of assets that compose the biodiesel plants. The CGU reflects an integrated view of the biodiesel plants and is defined based on the production planning and operation process, considering domestic market conditions, the capacity of each plant, as well as the results of biofuels auctions and raw materials supply; ii) Ethanol CGU: comprised of investments in associates and joint ventures in the ethanol sector.

-International CGU: i) International Exploration and production CGU: oil and natural gas producing properties comprised of a group of exploration and development assets outside of Brazil; ii) Other operations of the international business segment: smallest identifiable group of assets that generates largely independent cash inflows.

Investments in associates and joint ventures including goodwill are individually tested for impairment.

See notes 3.10 and 14 for more detailed information about impairment.

4.3. 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 rate curve and an equivalent real interest rate that matches the duration of the pension and health care obligations with the 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 for the last five years, which are used to set a starting point for the curve, which decreases gradually in 30 years, converging to a general 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.

4.4.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, based on legal advice and management’s best estimates.

F-26

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

See note 31 for more detailed information about contingencies and legal proceedings.

4.5.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 regulation have 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. Notwithstanding, the timing and amounts of future cash flows are subject to significant uncertainty.

See notes 3.14 and 20 for more detailed information about the decommissioning provisions.

4.6.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 inflation indices.

See notes 3.3.5 and 34 for more detailed information about derivative financial instruments.

4.7.Hedge accounting

Identifying hedging relationships between hedged items and hedging instruments (derivative financial instruments and 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.

See notes 3.3.6 and 34 for more detailed information about hedge accounting.

5.New standards and interpretations

a)IASB – International Accounting Standards Board

During 2013, new standards and amendments to standards and interpretations were issued by the International Accounting Standards Board (IASB) effective for annual periods beginning on January 1, 2013, none of which had a significant effect on the consolidated financial statements for 2013, except for amendments to IAS 19 - Employee Benefits (CPC 33 - R1):

F-27

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

·The effects of the adoption of amendments to IAS 19 – “Employee benefits” are set out in note 2.3.

·Amendment to IAS 1 - ‘Presentation of financial statements’, regarding other comprehensive income requires for entities to group items presented in ‘other comprehensive income’ (OCI) on the basis of whether they are potentially recycled to profit or loss subsequently.

·IFRS 10 "Consolidated Financial Statements" - defines principles and requirements for the preparation and presentation of consolidated financial statements when an entity controls one or more entities. Establishes the concept of control as the basis for consolidation and sets out how to apply the principle of control to identify whether an investor controls an investee and therefore must consolidate the investee.

·IFRS 11 - “Joint Arrangements” - establishes principles for disclosure of financial statements of entities that are parties of joint agreements. There are two types of joint arrangement: joint operations and joint ventures. Joint operations arise where a joint operator has rights to the assets and obligations relating to the arrangement and hence accounts for its interest in assets, liabilities, revenue and expenses. Joint ventures arise where the joint operator has rights to the net assets of the arrangement and hence equity accounts for its interest. Proportional consolidation of joint ventures is no longer allowed.

·IFRS 12 - “Disclosure of Interests in Other Entities” - Consolidates all the requirements of disclosures that an entity should carry out when participating in one or more entities, including joint arrangements, associates and structured entities.

·IFRS 13 - “Fair Value Measurement” – provides a precise definition of fair value, as well as a source of fair value measurement and disclosure. Does not extend the use of fair value accounting but provides guidance on how it should be applied where its use is already required or permitted by other standards.

·Amendments to IFRS 7- “Financial Instruments: Disclosures” – regarding offsetting financial assets and financial liabilities - establishes disclosure requirements for compensation agreements of financial assets and liabilities.

·IAS 28 (revised 2011) - "Associates and joint ventures" - Includes the requirements for joint ventures, as well as associates, to be accounted for by the equity method, following the issue of IFRS 11.

A number of new standards and amendments to standards and interpretations issued by the International Accounting Standards Board (IASB) are not effective for 2013, as set out below. They have not been adopted in preparing these financial statements at December 31, 2013.

Standards	Brief Description	Effective Date
IFRS 9, "Financial instruments" and Amendments	IFRS 9 retains but simplifies the mixed measurement model and establishes two primary measurement categories for financial assets: amortized cost and fair value.	January 1, 2018
	The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset.
	The guidance in IAS 39 on impairment of financial assets and hedge accounting continues to apply.
	IFRS 9 includes the new hedge accounting requirements

F-28

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

IFRIC 21, "Levies"	IFRIC 21 is an interpretation of IAS 37, Provisions, Contingent Liabilities and Contingent Assets. IFRIC 21 addresses when an entity should recognize a liability to pay a government levy (other than income taxes). The Interpretation clarifies that the obligating event that gives rise to a liability to pay a levy is the activity described in the relevant legislation that triggers the payment of the levy.	January 1, 2014
Amendment to IAS 36 - "Impairment of assets" on recoverable amount disclosures.	This amendment addresses the disclosure of information about the recoverable amount of impaired assets. The amendments clarify that the scope of those disclosures is limited to the recoverable amount of impaired assets that is based on fair value less costs of disposal. The amendments are required to be applied retrospectively.	January 1, 2014

None of the amendments and new standards listed above is expected to have a significant effect on the financial statements.

b)Brazilian Tax Law

On November 11, 2013 the Brazilian government issued Provisional Measure No. 627, which:

-introduces changes to corporate income taxes (including income tax - IRPJ and social contribution on profits - CSLL), as well as changes to social contributions on revenues (including PIS/PASEP and COFINS);

-repeals the transitional tax regime (RTT), which was introduced by Federal Law No. 11,941 on May 27, 2009;

-revises the rules related to share of profits earned by foreign subsidiaries (FS) of Brazilian entities subject to corporate income taxes (IRPJ and CSLL) in Brazil;

-introduces changes to Federal Law No. 12,865/2013, which reopened the federal tax amnesty and refinancing program (REFIS da crise), which was introduced by Federal Law No. 11,941/2009, for tax debts claimed by the Brazilian Internal Revenue Service (Receita Federal do Brasil) and the Office of the Attorney-General of the National Treasury (Procuradoria Geral da Fazenda Nacional - PGFN);

This Provisional Measure is under consideration by the National Congress (Congresso Nacional) and is thus subject to amendment before it can be enacted into law. A number of clarifying regulations must be issued by the Brazilian Internal Revenue Service.

The Company has assessed the effects that these changes could produce and, based on the current text of the Provisional Measure, estimates no material impacts on the 2013 consolidated financial statements.

F-29

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

6.Cash and cash equivalents

	2013	2012
Cash at bank and in hand	951	990
Short-term financial investments
- In Brazil
Single-member funds (Interbank Deposit) and other short-term deposits	3,493	8,329
Other investment funds	53	208
	3,546	8,537
- Abroad	11,371	3,993
Total short-term financial investments	14,917	12,530
Total cash and cash equivalents	15,868	13,520

Short-term financial investments in Brazil comprise single-member (exclusive) funds mainly holding Brazilian Federal Government Bonds and short-term financial investments abroad comprised of time deposits and other short-term fixed income instruments from highly-ranked financial institutions.

Those investments have maturities of three months or less and therefore are considered cash and cash equivalents.

7.Marketable securities

	2013	2012
Trading securities	3,878	10,222
Available-for-sale securities	17	239
Held-to-maturity securities	121	146
	4,016	10,607
Current	3,885	10,431
Non-current	131	176

Trading securities refer mainly to investments in government bonds that have maturities of more than 90 days. These assets are classified as current assets due to the expectation of their realization in the short term.

8.Trade and other receivables

8.1.Trade and other receivables, net

	2013	2012
Trade receivables
Third parties	9,847	10,785
Related parties (Note 19)
Investees	658	780
Receivables from the electricity sector	2,156	1,937
Petroleum and alcohol accounts -Federal Government	357	409
Other receivables	2,590	3,081
	15,608	16,992
Provision for impairment of trade receivables	(1,406)	(1,452)
	14,202	15,540
Current	9,670	11,099
Non-current	4,532	4,441

F-30

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

8.2.Changes in the provision for impairment of trade receivables

	2013	2012	2011
Opening balance	1,452	1,487	1,609
Additions (*)/ (**)	217	300	283
Write-offs (*)	(69)	(203)	(220)
Cumulative translation adjustment	(194)	(132)	(185)
Closing balance	1,406	1,452	1,487
Current	800	854	898
Non-current	606	598	589
(*) Includes exchange differences arising from translation of the provision for impairment of trade receivables in companies abroad.
(**) Amounts recognized in profit or loss as selling expenses.

8.3.Trade and other receivables overdue - Third parties

	2013	2012
Up to 3 months	692	769
From 3 to 6 months	159	156
From 6 to 12 months	362	181
More than 12 months	1,643	1,587
	2,856	2,693

9.Inventories 

	2013	2012
Crude Oil	5,849	5,149
Oil Products	4,985	5,880
Intermediate products	924	972
Natural Gas and LNG (*)	401	302
Biofuels	158	282
Fertilizers	26	12
	12,343	12,597
Materials, supplies and others	1,935	2,000
	14,278	14,597
Current	14,225	14,552
Non-current	52	45
(*) Liquid Natural Gas

Consolidated inventories are presented net of a US$ 88 allowance reducing inventories to net realizable value (US$ 90 in 2012), mainly due to the volatility of international prices of crude oil and oil products. The amounts recognized in profit or loss as other operating expenses are set out in note 26.

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$ 2,976  (US$ 2,923 in 2012), as set out in note 22.

F-31

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

10.Acquisitions, disposal of assets and legal mergers

10.1.Acquisition of assets

Araucária Nitrogenados S.A.

On June 1, 2013, Petrobras assumed control over Araucária Nitrogenados S.A. (FAFEN-PR), under an agreement to acquire all shares of the company executed with Vale S.A. on December 18, 2012. The transaction was approved by the Brazilian Antitrust Authority (Conselho Administrativo de Defesa Econômica – CADE) on May 15, 2013.

The transaction price consideration was US$ 234 and will be paid to Vale through lease income from mineral rights for properties owned  by Petrobras in Sergipe. The assessment of the fair value of assets and liabilities is ongoing and will be completed within 12 months from the date Petrobras assumed control of the investee. A US$ 76 gain on bargain purchase has been recognized in profit or loss, as gains on interest in investees, based on a preliminary assessment of the fair value of assets acquired and liabilities assumed (US$ 310). Provisional amounts recognized may be adjusted during the measurement period.

Termoaçu

On May 14, 2013, Petrobras entered into a contractual arrangement with Neoenergia to acquire its 23.13% interest in the share capital of Termoaçu.

Petrobras increased its interest in Termoaçu to 100% upon the completion of the transaction, which was subject to: the approval by Agência Nacional de Energia Elétrica – ANEEL, obtained on June 14, 2013, consent of Conselho Administrativo de Defesa Econômica – CADE, obtained on July 17, 2013, as well as the arbitral award, regarding the performance of the sales and purchase agreement, awarded by the Arbitral Tribunal on August 14, 2013. The total consideration paid, after price adjustments, was US$74.

10.2.Disposal of assets

Brasil PCH

On June 14, 2013, Petrobras entered into an agreement with Cemig Geração e Transmissão S.A. (which further 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 the voting stock, for a consideration of US$304, excluding contractual price adjustments.

On February 14, 2014, the remaining conditions precedent for this transaction were concluded for a total amount of US$ 297, including contractual price adjustments.

Due to the pending conditions precedent for conclusion of this transaction as of December 31, 2013, the assets and associated liabilities were classified as held for sale.

Formation of joint venture to operate in Exploration and Production (E&P) in Africa

On June 14, 2013, the Board of Directors of Petrobras approved the agreement between Petrobras International Braspetro B.V. (PIBBV), a subsidiary of Petrobras, and BTG PactuaI E&P B.V, a subsidiary of Banco BTG PactuaI S.A., to form a joint venture to operate in the exploration and production of oil and gas in Africa, comprised of assets in Angola, Benin, Gabon, Namibia, Nigeria and Tanzania.

BTG PactuaI E&P B.V. acquired 50% of the joint-venture shares of Petrobras Oil & Gas B.V. (PO&G), previously held by PIBBV, for the total amount of US$ 1,548, including US$ 36 received as an advance for the disposal of assets in Angola and Tanzania. The transaction was concluded on June 28, 2013 and the Company recognized a US$877 gain before taxes in other operating income (expenses), as set out below:

F-32

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Proceeds from disposal	1,512
Carrying amount	(797)
Gain on disposal of assets (*)	715
Fair value measurement of uplift on retained interest	715
	1,430
Impairment of assets in Angola and Tanzania (**)	(553)
Total gain on contribution of assets to joint venture	877
(*) Gain on disposed assets, other than Angola and Tanzania
(**) Impaired to reduce carrying amounts to fair value less cost of disposal

As the Angola and Tanzania portions of the transaction are subject to approval by their respective governments, the carrying amount of the assets located in those countries was classified as held for sale.

The partnership’s investment in PO&G was classified as a joint venture, and was therefore unconsolidated, reflecting the corporate structure and the terms of the shareholders' agreement, signed on June 28, 2013.

Companhia Energética Potiguar

On August 16, 2013, Petrobras entered into an agreement with Global Participações Energia S.A. to dispose of its 20% interest in the voting capital of Companhia Energética Potiguar for US$ 10, after contractual price adjustments.

The approval by Conselho Administrativo de Defesa Econômica – CADE was obtained on September 25, 2013 and the transaction was concluded on October 31, 2013.

Coulomb field – USA

On August 16, 2013, the Board of Directors of Petrobras approved the disposal by Petrobras America Inc., a subsidiary of Petrobras International Braspetro B.V. (PIBBV), of its 33% interest in the Coulomb field, located at the Mississippi Canyon block 613 (MC 613) for US$ 184. Shell Offshore Inc., operator and holder of a 67% interest in the field, exercised its purchase right of first refusal.

After the price adjustment established in the farm-out agreement and the costs associated with the asset, a gain of US$ 121, net, was recognized when the transaction was concluded, on September 27, 2013.

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. (Innova) to Videolar S.A. and its controlling shareholder, at a consideration of US$ 369, subject to price adjustment before the transaction is concluded.

The transaction was approved in a Shareholders’ Extraordinary General Meeting held on September 30, 2013 and its conclusion is subject to certain conditions, including the approval by Conselho Administrativo de Defesa Econômica – CADE.

Due to the pending conditions precedent for conclusion of this transaction, on December 31, 2013 the assets and associated liabilities involved in this transaction were classified as held for sale.

F-33

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

BC-10 Block - Parque das Conchas

On August 16, 2013, the Board of Directors of Petrobras approved the disposal of the total interest in the Parque das Conchas offshore project (BC-10 block), representing 35% of the joint venture and 35% of Tambá BV – an equipment supplier, for a consideration of US$ 1.54 billion.

The agreement with Sinochem Group established certain conditions precedent to the conclusion of the sale, including the right of first refusal of the parties in the joint venture and the approval of the transaction by  Conselho Administrativo de Defesa Econômica (CADE) and Agência Nacional de Petróleo, Gás e Biocombustíveis (ANP).

On September 17, 2013 Shell and ONGC Videsh exercised their rights of first refusal to purchase a 23% and a 12% interest, respectively.

After approval by ANP and CADE, the assets were disposed of on December 30, 2013. The transaction resulted in a US$ 446 gain for the Company.

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. (PIBBV), to Perenco Colombia Limited, for a consideration of US$ 380, subject to price adjustment before the closing of the transaction.

The transaction is subject to customary conditions precedent, including its approval by the Agência Nacional de Hidrocarburos – ANH.

Due to the pending conditions precedent for conclusion of this transaction, at December 31, 2013 the assets and associated liabilities involved in the transaction were classified as held for sale.

Exploration Blocks - Uruguai

On October 4, 2013, the Board of Directors of Petrobras approved the disposal to Shell of a 40% interest that Petrobras Uruguay Servicios y Operaciones S.A. – PUSO, a subsidiary of Petrobras Uruguay S.A. de Inversión had in Bizoy S.A. and Civeny S. A., for a consideration of US$ 18. Bizoy S.A. and Civeny S.A. held exploration blocks 3 and 4, respectively, located in the Punta Del Este Basin, in Uruguai.

The transaction is subject to certain conditions precedent, mainly the approval by Administración Nacional de Combustibles Alcohol y Portland (ANCAP).

Due to the pending conditions precedent for conclusion of this transaction, the assets and associated liabilities involved in the transaction were classified as held for sale.

Petrobras Energia  Peru S.A.

On November 13, 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 Internacional Braspetro BV – PIB BV to China National Petroleum Corporation (CNPC), for US$ 2,669, subject to price adjustment until the transaction is concluded.

The transaction is subject to certain conditions precedent, including approval by the Chinese and Peruvian governments, as well as compliance with the procedures under their "Joint Operating Agreement (JOA)", where applicable.

F-34

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Due to the pending conditions precedent for the conclusion of this transaction, the assets and corresponding liabilities related to the transaction objects were classified as held for sale.

10.3.Assets classified as held for sale

Assets classified as held for sale and associated liabilities, classified under the Company’s current assets and current liabilities are comprised of the following items and business segments:

	Consolidated
	2013						2012
	Exploration and Production (*)	Refining, Transport. & Marketing	Gas & Power	International	Others	Total	Total
Assets classified as held for sale
Property, plant and equipment	50	125	−	1,605	−	1,780	143
Trade receivables	−	104	−	32	−	136	−
Inventories	−	78	−	43	−	121	−
Investments	−	15	28	11	−	54	−
Cash and Cash Equivalents	−	4	−	117	−	121	−
Others	−	15	−	180	−	195	−
	50	341	28	1,988	−	2,407	143
Liabilities on assets classified as held for sale
Trade Payables	−	(26)	−	(138)	−	(164)	−
Provision for decommissioning costs	−	−	−	(30)	−	(30)	−
Non-current debt	−	(15)	−	(597)	−	(612)	−
Others	−	(23)	−	(244)	−	(267)	−
	−	(64)	−	(1,009)	−	(1,073)	−
(*) Net of impairment charges, as set out in note 14.3

10.4.Legal mergers, spin-offs and other information on investees

Partial spin-off of Petrobras International Finance Company S.A. - PifCo

On December 16, 2013, the Shareholders’ Extraordinary General Meeting of Petrobras approved the partial spin-off of certain assets and liabilities of Petrobras International Finance Company S.A. – PifCo, with the subsequent merger of the spun-off portion into Petrobras (not impacting share capital or additional paid in capital).

On February 12, 2014, Petrobras Global Finance B.V. (PGF), an indirect subsidiary of Petrobras, acquired the outstanding shares of PifCo for US$ 224 (net book value as of January 31, 2014).

See note 38 for further details about the transactions, which did not affect the consolidated financial statements.

F-35

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Legal mergers of subsidiaries

In 2013, the following subsidiaries were merged into Petrobras, but did not increase share capital or additional paid in capital:

Date of the Shareholders’ Extraordinary General Meeting / Company:

On September 30, 2013:

Comperj Participações S.A

Comperj Estirênicos S.A

Comperj MEG S.A

Comperj Poliolefinas S.A.

Sociedade Fluminense de Energia Ltda. (SFE)

On December 16, 2013:

Refinaria Abreu e Lima S.A. (RNEST)

Companhia de Recuperação Secundaria (CRSec)

Petrobras International Finance Company (PifCo) – partial spin-off

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 consolidated financial statements.

F-36

 

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
Subsidiaries
Petrobras Netherlands B.V. - PNBV	E&P	100.00%	100.00%	13,036	2,748	Netherlands
Petrobras Distribuidora S.A. - BR	Distribution	100.00%	100.00%	5,080	988	Brazil
Petrobras Gás S.A. - Gaspetro	Gas & Power	100.00%	100.00%	4,539	770	Brazil
Petrobras Transporte S.A. - Transpetro	RT&M	100.00%	100.00%	2,061	413	Brazil
Petrobras International Braspetro - PIB BV	International	88.12%	88.12%	1,859	1,801	Netherlands
Petrobras Logística de Exploração e Produção S.A. - PB-LOG	E&P	100.00%	100.00%	1,430	91	Brazil
Companhia Integrada Têxtil de Pernambuco S.A. - Citepe	RT&M	100.00%	100.00%	1,069	(100)	Brazil
Petrobras Biocombustível S.A. - PBIO	Biofuels	100.00%	100.00%	905	(150)	Brazil
Companhia Locadora de Equipamentos Petrolíferos S.A. - CLEP	E&P	100.00%	100.00%	653	34	Brazil
Companhia Petroquímica de Pernambuco S.A. - PetroquímicaSuape	RT&M	100.00%	100.00%	640	(257)	Brazil
Petrobras International Finance Company - PifCo	Corporate	100.00%	100.00%	(483)	(727)	Luxembourg
Liquigás Distribuidora S.A.	Distribution	100.00%	100.00%	367	11	Brazil
Araucária Nitrogenados S.A.	Gas & Power	100.00%	100.00%	337	(21)	Brazil
Termomacaé Ltda.	Gas & Power	99.99%	99.99%	319	53	Brazil
Termoaçu S.A.	Gas & Power	100.00%	100.00%	295	(25)	Brazil
INNOVA S.A. ( * )	RT&M	100.00%	100.00%	247	80	Brazil
5283 Participações Ltda.	International	100.00%	100.00%	221	214	Brazil
Breitener Energética S.A.	Gas & Power	93.66%	93.66%	216	−	Brazil
Termobahia S.A.	Gas & Power	98.85%	98.85%	185	10	Brazil
Termoceará Ltda.	Gas & Power	100.00%	100.00%	143	28	Brazil
Arembepe Energia S.A.	Gas & Power	100.00%	100.00%	134	43	Brazil
Petrobras Comercializadora de Energia Ltda. - PBEN	Gas & Power	99.91%	99.91%	128	38	Brazil
Baixada Santista Energia S.A.	Gas & Power	100.00%	100.00%	115	25	Brazil
Fundo de Investimento Imobiliário RB Logística - FII	E&P	99.00%	99.00%	106	139	Brazil
Energética Camaçari Muriçy I Ltda.	Gas & Power	100.00%	100.00%	77	45	Brazil
Termomacaé Comercializadora de Energia Ltda	Gas & Power	100.00%	100.00%	39	6	Brazil
Braspetro Oil Services Company - Brasoil	E&P	100.00%	100.00%	(29)	(21)	Cayman Islands
Cordoba Financial Services GmbH	Corporate	100.00%	100.00%	23	1	Austria
Petrobras Negócios Eletrônicos S.A. - E-Petro	Corporate	99.95%	99.95%	13	1	Brazil
Downstream Participações Ltda.	Corporate	100.00%	100.00%	(1)	−	Brazil
Joint operations
Fábrica Carioca de Catalizadores S.A. - FCC	RT&M	50.00%	50.00%	130	21	Brazil
Ibiritermo S.A.	Gas & Power	50.00%	50.00%	56	19	Brazil
Joint ventures
Logum Logística S.A.	RT&M	20.00%	20.00%	121	(29)	Brazil
Brasil PCH S.A. ( * )	Gas & Power	49.00%	49.00%	61	16	Brazil
Cia Energética Manauara S.A.	Gas & Power	40.00%	40.00%	64	6	Brazil
Petrocoque S.A. Indústria e Comércio	RT&M	50.00%	50.00%	53	10	Brazil
Brasympe Energia S.A.	Gas & Power	20.00%	20.00%	35	3	Brazil
Participações em Complexos Bioenergéticos S.A. - PCBIOS	Biofuels	50.00%	50.00%	26	−	Brazil
Refinaria de Petróleo Riograndense S.A.	RT&M	33.20%	33.33%	22	1	Brazil
METANOR S.A. - Metanol do Nordeste	RT&M	34.54%	50.00%	21	2	Brazil
Brentech Energia S.A.	Gas & Power	30.00%	30.00%	21	6	Brazil
Companhia de Coque Calcinado de Petróleo S.A. - Coquepar	RT&M	45.00%	45.00%	20	(8)	Brazil
Eólica Mangue Seco 4 - Geradora e Comercializadora de Energia Elétrica S.A.	Gas & Power	49.00%	49.00%	18	−	Brazil
Eólica Mangue Seco 3 - Geradora e Comercializadora de Energia Elétrica S.A.	Gas & Power	49.00%	49.00%	17	−	Brazil
Eólica Mangue Seco 1 - Geradora e Comercializadora de Energia Elétrica S.A.	Gas & Power	49.00%	49.00%	16	2	Brazil
Eólica Mangue Seco 2 - Geradora e Comercializadora de Energia Elétrica S.A.	Gas & Power	51.00%	51.00%	15	1	Brazil
GNL do Nordeste Ltda.	Gas & Power	50.00%	50.00%	−	−	Brazil
Associates
Braskem S.A.	RT&M	36.20%	47.03%	3,241	236	Brazil
Fundo de Investimento em Participações de Sondas	E&P	4.59%	4.59%	1,774	808	Brazil
Sete Brasil Participações S.A.	E&P	5.00%	5.00%	1,099	46	Brazil
UTE Norte Fluminense S.A.	Gas & Power	10.00%	10.00%	388	44	Brazil
UEG Araucária Ltda.	Gas & Power	20.00%	20.00%	300	17	Brazil
Deten Química S.A.	RT&M	27.88%	27.88%	128	32	Brazil
Energética SUAPE II S.A.	Gas & Power	20.00%	20.00%	92	39	Brazil
Termoelétrica Potiguar S.A. - TEP	Gas & Power	20.00%	20.00%	36	−	Brazil
Nitroclor Ltda.	RT&M	38.80%	38.80%	−	−	Brazil
Bioenergética Britarumã S.A.	Gas & Power	30.00%	30.00%	−	−	Brazil
(*) Classified as assets held for sale as of December 31, 2013, as set out in note 10.

F-37

 

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

	2013	2012
Investments measured using equity method
Braskem S.A.	2,201	2,703
Petrobras Oil & Gas BV (i)	1,707	−
Gas distributors	533	555
Guarani S.A.	510	482
Petroritupano - Orielo	198	233
Petrowayu - La Concepción	185	193
Nova Fronteira Bionergia S.A.	170	203
Other petrochemical investments	84	153
Transierra S.A.	68	69
Petrokariña - Mata	66	75
UEG Araucária	59	64
Termoaçu S.A. (ii)	−	267
Distrilec S.A. (iii)	−	41
Other associates and joint ventures	863	948
	6,644	5,986
Other investments	22	120
	6,666	6,106
(i) Consolidated company in 2012, as described in note 10.
(ii) Acquisition of control in 2013, as described in notes 3.1 and 10.
(iii) Investment sold in January 2013 by Petrobras Argentina S.A.

11.3.Investments in listed companies

	Thousand-share lot			Quoted stock exchange prices (US$  per share)		Market value
Company	2013	2012	Type	2013	2012	2013	2012
Indirect subsidiary
Petrobras Argentina	1,356,792	1,356,792	Common	0.80	0.69	1,083	936
						1,083	936
Associate
Braskem	212,427	212,427	Common	7.04	4.70	1,496	998
Braskem	75,793	75,793	Preferred A	8.96	6.26	680	475
						2,176	1,473

The market value of these shares does not necessarily reflect the realizable value of a large block of shares.

F-38

 

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, 2013 is US$ 596, of which US$ 593 is related to Petrobras Argentina S.A. Summarized information on Petrobras Argentina is set out following:

	Petrobras Argentina
	2013	2012
Current assets	980	1,117
Long-term receivables	174	290
Property, plant and equipment	1,468	1,727
Other noncurrent assets	636	763
	3,258	3,897
Current liabilities	618	882
Non-current liabilities	834	861
Shareholder's equity	1,806	2,154
	3,258	3,897
Sales revenues	254	270
Net income	139	129
Net change in cash and cash equivalents	(40)	76

Petrobras Argentina is an integrated energy company, indirectly controlled by Petrobras (directly controlled by PIB BV), whose 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 stations, refineries and other activities. Summarized accounting information is set out below:

	2013
	Joint ventures		Associates
	In Brazil	Abroad	In Brazil	Abroad
Current assets	1,603	2,391	9,677	2,749
Non-current assets	830	1,865	3,103	53
Property, plant and equipment	1,639	7,068	13,141	2,783
Other non-current assets	933	51	2,945	71
	5,005	11,375	28,866	5,656
Current liabilities	1,733	978	6,750	2,562
Non-current liabilities	1,022	6,193	13,864	1,035
Shareholders' equity	2,240	4,052	8,190	2,059
Non-controlling interest	10	152	62	−
	5,005	11,375	28,866	5,656
Sales revenues	5,646	1,792	21,363	93
Net Income for the Year	254	570	1,201	322
Ownership interest - %	20 to 83%	34 to 50%	5 to 49%	11 to 49%

F-39

 

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 improvements	Equipment and other assets	Assets under construction (*)	Exploration and development costs (Oil and gas producing properties)	Total
Balance at January 1, 2012	6,588	66,362	84,529	25,439	182,918
Additions	50	2,073	32,571	1,703	36,397
Additions to / review of estimates of decommissioning costs	−	−	−	5,207	5,207
Capitalized borrowing costs	−	−	3,792	−	3,792
Business combinations	83	182	2	−	267
Write-offs	(6)	(59)	(2,651)	(106)	(2,822)
Transfers	2,504	24,818	(30,413)	6,994	3,903
Depreciation, amortization and depletion	(477)	(6,626)	−	(3,765)	(10,868)
Impairment recognition (****)	(20)	(178)	(37)	(149)	(384)
Impairment reversal (****)	−	44	134	65	243
Cumulative translation adjustment	(558)	(4,908)	(6,264)	(2,022)	(13,752)
Balance at December 31, 2012	8,164	81,708	81,663	33,366	204,901
Cost	10,834	122,647	81,663	62,348	277,492
Accumulated depreciation, amortization and depletion	(2,670)	(40,939)	−	(28,982)	(72,591)
Balance at December 31, 2012	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
Weighted average of useful life in years	25 (25 to 40 ) (except land)	20 (3 to 31) (**)		Units of production method
(*) See note 30 for assets under construction by business area
(**) Includes exploration and production assets depreciated based on the units of production method.
(***) Includes the amount of US$ 22,134, reclassified from Intangible Assets to Property, Plant and Equipment as a result of the declaration of commerciality of areas of the Assignment Agreement (Franco and Sul de Tupi), as described in note 13; the amount related to PO&G (US$ 2,366), which have ceased to be consolidated; and amounts transferred to assets classified as held for sale, set out in note 10.3.
(****) Impairment charges and reversals are recognized in profit or loss as other operating expenses.

At December 31, 2013, property, plant and equipment includes assets under finance leases of US$ 86 (US$ 102 at December 31, 2012).

F-40

 

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 2013
5 years or less	5,396	(3,260)	2,135
6 - 10 years	20,571	(9,899)	10,671
11 - 15 years	944	(417)	526
16 - 20 years	34,986	(8,753)	26,233
21 - 25 years	15,890	(5,007)	10,884
25 - 30 years	22,484	(4,007)	18,477
30 years or more	22,934	(4,540)	18,394
Units of production method	20,175	(9,942)	10,233
	143,380	(45,825)	97,553
Buildings and improvements	10,011	(2,861)	7,150
Equipment and other assets	133,368	(42,963)	90,405

13.Intangible assets

13.1.By class of assets

		Softwares
	Rights and Concessions	Acquired	Developed in-house	Goodwill	Total
Balance at January 1, 2012	42,013	180	715	504	43,412
Addition	90	72	146	−	308
Capitalized borrowing costs	−	−	15	−	15
Write-offs	(119)	(2)	(3)	−	(124)
Transfers	(80)	12	(97)	(14)	(179)
Amortization	(48)	(61)	(142)	−	(251)
Impairment - reversal (***)	6	−	−	−	6
Cumulative translation adjustment	(3,349)	(13)	(57)	(29)	(3,448)
Balance at December 31, 2012	38,513	188	577	461	39,739
Cost	38,920	715	1,444	461	41,540
Accumulated amortization	(407)	(527)	(867)	−	(1,801)
Balance at December 31, 2012	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
Estimated useful life - years	(*)	5	5	Indefinite
(*) See note 3.9 (Intangible assets).
(**) Includes the amount of US$ 22,134, reclassified from Intangible Assets to Property, Plant and Equipment as a result of the declaration of commerciality of areas of the Assignment Agreement (Franco and Sul de Tupi) areas, as described below; and the amount related to PO&G (US$ 601), which have ceased to be consolidated, as described in note 10.
(***) Impairment charges and reversals are recognized in profit or loss as other operating expenses.

On December 19, 2013, the Company submitted to the Agência Nacional de Petróleo, Gás Natural e  Biocombustíveis – ANP the declaration of commerciality of Franco and Sul de Tupi, located at the pre-salt area in the Santos basin. The exploration stage confirmed the volumes defined in the Assignment Agreement related to Franco (now Búzios) and Sul de Tupi (now Sul de Lula), of 3,058 billion barrels of oil equivalent and 128 million barrels of oil equivalent, respectively.

F-41

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

After the declaration of commerciality, the amounts of US$ 21,357 and US$ 777, paid to the Federal Government for the acquisition of Franco and Sul de Tupi, were reclassified from Intangible assets to Property, plant and equipment, according to the policy set out in note 3.9. These amounts will be the subject to the review of the Assignment Agreement, as set out in note 13.2.

13.2.Concession for exploration of oil and natural gas - Assignment Agreement (“Cessão Onerosa”)

At December 31, 2013, the Company’s Intangible Assets include US$ 10,424 (US$ 36,608 at December 31, 2012) related to the Assignment agreement, net of amounts paid as signature bonuses for Franco (now Campo de Búzios) and Sul de Tupi (now Campo de Sul de Lula) which have been transferred to Property, Plant and Equipment, as set out in note 13.1.

Petrobras, the Federal Government (assignor) and the ANP (regulator and inspector) entered into the 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 years and renewable for a further five years upon certain conditions having been met.

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 of the Assignment Agreement will be concluded after the date of the last declaration of commerciality.

If the review determines that the value of acquired rights are 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 in the terms of the agreement. If the review determines that the value of the acquired rights are 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.

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.

The agreement also establishes a compulsory exploration program for each one 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 so far, expectations regarding the production potential of the areas are being confirmed and the Company will continue to develop its investment program and activities as established in the agreement.

13.3.Exploration rights returned to Agência Nacional de Petróleo, Gás Natural e Biocombustíveis (ANP)

Exploration areas returned to ANP in 2013, in the amount of US$ 61 (US$ 113 in 2012) are set out below:

Exclusive Concession Blocks (Petrobras):

- Campos Basin: C-M-95; C-M-96; C-M-119; C-M-120; C-M-403;

- Espírito Santo Basin: ES-M-523;

F-42

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

-Parecis Basin: PRC-T-104; PRC-T-105;            

-Solimões Basin: SOL-T-150; SOL-T-173.

Blocks in partnership (returned by Petrobras or by its operators):

-Ceará Basin: BM-CE-1;

- Camamu Almada Basin: CAL-M-120; CAL-M-186;

-Campos Basin: C-M-593;

- Espírito Santo Basin: ES-M-588; ES-M-590; ES-M-592; ES-M-663;

-Paraíba-Pernambuco Basin: PEPB-M-837;

-Potiguar Basin: POT-T-699; POT-T-745; POT-T-774;

-São Francisco Basin: SF-T-101; SF-T-102; SF-T-111; SF-T-112;

- Santos Basin: S-M-172; S-M-674; S-M-789.

13.4.Oil and Gas fields operated by Petrobras returned to ANP

During 2013 the following oil and gas fields were returned to ANP: Coral, Carataí, Corruíra, Biquara, Guaiúba, Iraí, Dentão, Acauã Leste, Guajá and Noroeste do Morro Rosado.

13.5.Service concession agreement - Distribution of piped natural gas

At December 31, 2013, intangible assets include service concession agreements related to piped natural gas distribution in Brazil, in the amount of US$ 229 maturing between 2029 and 2043, which may be extended. According to the agreements, distribution service can be provided to industrial, residential, commercial, automotive, air conditioning, transport, and other sectors.

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.

14.Impairment 

14.1.Property, plant and equipment and intangible

Value in use is calculated to assess the recoverable amount of the Cash-Generating Units, and the basis for estimates of cash flow projections include: an estimate of the useful life of the assets in the CGU; budgets, forecasts and assumptions approved by management; and pre-tax discount rate derived from the weighted average cost of capital (WACC) method.

The recoverable amount of the Distribution CGU (including goodwill) was calculated using value in use, and no impairment losses were recognized. The basis for estimates of cash flow projections include: average useful life of 17 years, non-growing perpetuity, budgets, forecasts and assumptions approved by management, and pre-tax discount rate derived from the WACC method.

Based on 2013 impairment tests, the following amounts were recognized as impairment losses / reversals in other operating expenses, in profit or loss:

-Exploration and Production

F-43

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Based on impairment tests, impairment losses of US$ 58 were recognized in exploration and production assets, mainly related to mature oil and gas producing properties under concessions in Brazil.

A review of projects, which are now financially viable, along with the implementation of operational efficiency programs and of operating costs optimization programs in certain CGUs led to the reversal of impairment losses recognized in previous years, related to oil and gas producing properties under concessions in Brazil (US$ 118).

-International 

Based on impairment tests, impairment losses of US$ 11 were recognized in international assets, mainly related to mature oil and gas exploration and producing properties in the United States, representing the carrying amount of Garden Banks 200 and 201 blocks.

A US$ 553 impairment loss was recognized to reduce the carrying amounts of exploration and production assets in Angola and Tanzania classified as held for sale to fair value less cost to sell, as set out in note 10.2.

14.2.Investments in associates and joint ventures (including goodwill)

Value in use is generally used for impairment test of goodwill associated to investments in associates and joint ventures. The basis for estimates of cash flow projections included: projections covering a period of 5 to 12 years, non-growing perpetuity, budgets, forecasts and assumptions approved by management, and pre-tax discount rate derived from the WACC method.

Based on 2013 impairment tests, no impairment losses were recognized, related to those assets. The carrying amounts and goodwill of the most significant investments in associates and joint ventures are set out below:

Investments	Segment	Pre-tax discount rate (real interest rate)	Value in use	Carrying Amount
Braskem S.A.	RT&M	16%	2,808	2,201
Natural Gas Distributors	Gas & Power	7% to 14%	2,557	533
Guarani S.A.	Biofuels	9%	553	510

-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, 2013, was U.S.$ 2,176, based on the quoted values of both Petrobras’ share in common stock (47% of the outstanding shares), and preferred stock (22% of the outstanding shares). 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. Thus if common shares and preferred shares were valued at the same price per share, market value would amount to US$ 2,584.

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 these investments via dividends and other distributions to arrive at value in use. As the recoverable amount was higher than the carrying amount, no impairment losses were recognized in 2013 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$ 2.23 to U.S.$1.00 in 2014 (converging to R$ 1.87 in the long term); (ii) Brent crude oil price of US$ 105.00 for 2014, declining to U.S.$ 95.00 in 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 along with the next growth cycle of the petrochemical industry during the next years and declining in the long term.

F-44

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

14.3.Assets classified as held for sale

Due to the approval by the Board of Directors of the disposal of PI, PIII, PIV and PXIV drilling rigs, these assets were remeasured at fair value and impairment losses of US$ 64 were recognized in the exploration and production segment.

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 until 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 (*)	2013	2012
Property plant and equipment
Opening Balance	10,649	10,120
Additions to capitalized costs pending determination of proved reserves	4,981	6,640
Capitalized exploratory costs charged to expense	(1,251)	(2,782)
Transfers upon recognition of proved reserves (***)	(4,174)	(2,628)
Cumulative translation adjustment	(1,403)	(701)
Closing Balance	8,802	10,649
Intangible Assets (**)	13,880	37,968
Capitalized Exploratory Well Costs / Capitalized Acquisition Costs	22,682	48,617
(*) Amounts capitalized and subsequently expensed in the same period have been excluded from the table above.
(**) The balance of intangible assets comprises mainly the amounts related to the Assignment Agreement (note 13.2).
(***) Includes US$ 736 relative to PO&G, which has been unconsolidated, as set out in note 10.

Exploration costs recognized in profit or loss and cash used in oil and gas exploration and evaluation activities are set out in the table below:

Exploration costs recognized in profit or loss	2013	2012	2011
Geological and Geophysical Expenses	968	1,022	1,024
Exploration expenditures written off (incl.dry wells and signature bonuses)	1,892	2,847	1,480
Other exploration expenses	99	89	101
Total expenses	2,959	3,958	2,605
Cash used in activities	2013	2012	2011
Operating activities	1,073	1,139	1,107
Investment activities	8,605	6,640	6,258
Total cash used	9,678	7,779	7,365

F-45

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

15.1.Aging of Capitalized Exploratory Well Costs

An aging of the number of wells and the capitalized exploratory well costs based on the drilling completion date, along with the number of projects for which exploratory well costs have been capitalized for a period greater than one year are set out in the table below:

Aging of capitalized exploratory well costs (*)
	2013	2012
Capitalized expl. well costs that have been capitalized for a period of one year	2,568	4,219
Capitalized expl. well costs that have been capitalized for a period greater than one year	6,234	6,430
Ending balance	8,802	10,649
Number of projects that have expl. well costs that have been capitalized for a period greater than one year	86	145

	Amounts capitalized	Number of wells
2012	2,464	39
2011	1,636	34
2010	896	18
2009	432	22
2008 and previous years	806	15
Ending balance	6,234	128
(*) Amounts paid for obtaining rights and concessions for exploration of oil and gas (capitalized acquisition costs) are not included.

Of the amount of US$ 6,234 for 86 projects that include wells suspended for more than one year since the completion of drilling, US$ 989 are related to wells in areas for which drilling was under way or firmly planned for the near future and for which an evaluation plan (“Plano de Avaliação”) has been submitted and is subject to approval by ANP; and US$ 5,245 are related to costs incurred to assess the reserves and their potential development.

16.Trade payables

	2013	2012
Current Liabilities
Third parties
In Brazil	5,346	6,511
Abroad	6,061	5,104
Related parties (note 19)	512	509
	11,919	12,124

F-46

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

17.Finance debt

Funding requirements are related to the development of oil and gas production projects, building of vessels and pipelines, as well as construction and expansion of industrial plants, among other uses. Changes in the noncurrent debt and the balance of current debt in 2013 and 2012 are set out below:

	Export Credit Agencies	Banking Market	Capital Market	Others	Total
Non-current
In Brazil
Opening balance at January 1 , 2012	−	30,218	1,250	80	31,548
Additions (new funding obtained)	−	3,163	258	−	3,421
Interest incurred during the period	−	45	30	2	77
Foreign exchange/inflation indexation charges	−	1,184	51	3	1,238
Transfer from long term to short Term	−	(1,023)	(227)	(15)	(1,265)
Cumulative translation adjustment (CTA)	−	(2,610)	(107)	(6)	(2,723)
Balance at December 31, 2012	−	30,977	1,255	64	32,296
Abroad
Opening balance at January 1 , 2012	5,004	14,430	21,026	710	41,170
Additions (new funding obtained)	879	5,870	9,524	−	16,273
Interest incurred during the period	3	5	203	−	211
Foreign exchange/inflation indexation charges	91	536	104	11	742
Transfer from long term to short Term	(677)	(836)	(592)	(85)	(2,190)
Cumulative translation adjustment (CTA)	(255)	(521)	766	(8)	(18)
Balance at December 31, 2012	5,045	19,484	31,031	628	56,188
Total Balance at December 31, 2012	5,045	50,461	32,286	692	88,484
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 period	−	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 period	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

Current debt	2013	2012
Short-term debt	3,654	3,666
Current portion of long-term debt	3,118	2,795
Accrued interest	1,229	1,018
	8,001	7,479

F-47

 

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 afterwards	Total	Fair value
Financing in Brazilian Reais (BRL):	1,115	1,392	2,920	2,156	2,320	12,922	22,825	22,712
Floating rate debt	743	984	2,571	1,802	1,996	11,183	19,279
Fixed rate debt	372	408	349	354	324	1,739	3,546
Average interest rate	7.4%	7.8%	9.2%	8.7%	8.9%	8.8%	8.7%
Financing in U.S. Dollars (USD):	5,832	5,635	8,939	5,722	11,230	35,583	72,941	73,588
Floating rate debt	4,747	4,249	4,273	3,629	8,861	13,576	39,335
Fixed rate debt	1,085	1,386	4,666	2,093	2,369	22,007	33,606
Average interest rate	3.1%	3.3%	3.1%	3.0%	3.1%	4.3%	3.7%
Financing in Brazilian Reais indexed to U.S. Dollars:	240	104	372	682	682	6,755	8,835	9,016
Floating rate debt	−	−	−	−	−	5	5
Fixed rate debt	240	104	372	682	682	6,750	8,830
Average interest rate	5.2%	4.9%	6.7%	7.0%	7.0%	7.3%	7.1%
Financing in Pound Sterling (£):	13	−	−	−	−	1,859	1,872	1,904
Fixed rate debt	13	−	−	−	−	1,859	1,872
Average interest rate	5.6%	−	−	−	−	5.9%	5.9%
Financing in Japanese Yen (¥):	581	118	446	108	98	−	1,351	1,373
Floating rate debt	98	98	98	98	98	−	490
Fixed rate debt	483	20	348	10	−	−	861
Average interest rate	0.9%	0.9%	1.8%	0.8%	0.8%	−	1.2%
Financing in Euro (€):	213	14	11	11	1,721	4,428	6,398	6,631
Fixed rate debt	213	14	11	11	1,721	4,428	6,398
Average interest rate	4.4%	1.4%	1.4%	1.4%	4.9%	4.2%	4.4%
Financing in other currencies:	7	3	4	−	−	−	14	14
Fixed rate debt	7	3	4	−	−	−	14
Average interest rate	12.5%	15.3%	15.3%	−	−	−	14.0%
Total as of December 31, 2013	8,001	7,266	12,692	8,679	16,051	61,547	114,236	115,238
Total Average interest rate	3.6%	4.2%	4.6%	4.7%	4.3%	5.6%	5.0%
Total as of December 31, 2012	7,479	4,177	7,125	13,665	9,389	54,128	95,963	102,486
* The average maturity of outstanding debt at December 31, 2013 is 7.1 years.

The sensitivity analysis for financial instruments subject to foreign exchange variation is set out in note 34.

F-48

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

17.2. Weighted average capitalization rate for borrowing costs

The weighted average interest rate, of the costs applicable to borrowings that are outstanding, applied over the balance of assets under construction for capitalization of borrowing costs was 4.5% p.a. in  2013 (4.5% p.a. in 2012).

17.3.Funding – Outstanding balance

a)Abroad 

	Amount in US$ million
Company	Available (Line of Credit)	Used	Balance
PGT	1,000	500	500
Petrobras	2,500	253	2,247

b)In Brazil

Company	Available (Line of Credit)	Used	Balance
Transpetro (*)	4,272	879	3,393
Petrobras	5,964	3,795	2,169
PNBV	4,217	−	4,217
Liquigas	47	35	12
(*)Purchase and sale agreements for 49 vessels and 20 convoys were signed with six Brazilian shipyards in the amount of US$ 5,017.

17.4.Guarantees 

Financial institutions do not require Petrobras to provide guarantees related to loans and financing, except for funding from development banks, such as the BNDES, which are collateralized by the assets being financed. Certain subsidiaries issue securities fully and unconditionally guaranteed by Petrobras, as set out in note 38.

The loans obtained by structured entities are collateralized by the project assets, as well as a lien on credit rights and shares of the structured entities.

F-49

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

18.Leases 

18.1.Future minimum lease payments / receipts – finance leases

	2013
	Minimum receipts	Minimum payments
At December 31, 2013
2014	170	22
2015 - 2018	704	77
2019 and thereafter	1,821	266
Estimated lease receipts/payments	2,695	365
Less Interest expense (annual)	(1,174)	(276)
Present value of the lease receipts/payments	1,521	89
2014	96	9
2015 - 2018	398	32
2019 and thereafter	1,027	48
Present value of the lease receipts/payments	1,521	89
Current	58	16
Non-current	1,463	73
At December 31, 2013	1,521	89
Current	60	18
Non-current	1,536	86
At December 31, 2012	1,596	104

18.2.Future minimum lease payments - operating leases

	2013
2014	14,683
2015 - 2018	24,189
2019 and thereafter	13,219
At December 31, 2013	52,091
At December 31, 2012	52,051

During 2013 the Company paid US$ 11,520 (US$ 10,389 in 2012) for operating lease installments, recognized as a period expense. Those operating leases include oil and gas production units, drilling rigs, exploration and production equipment, vessels and support vessels, thermoelectric power plants, helicopters, land and building leases. 

19.Related parties

The Company carries out commercial transactions with its subsidiaries, joint arrangements, consolidated structure entities and associates at normal market prices and market conditions. At December 31, 2013 and December 31, 2012, no losses were recognized on the statement of financial position for related party accounts receivable.

19.1.Transactions with joint ventures, associates, government entities and pension funds

The balances of significant transactions are set out in the table below:

F-50

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

	2013			2012
	Profit or Loss	Assets	Liabilities	Profit or Loss	Assets	Liabilities
Joint ventures and associates
Natural gas distributors	3,920	424	209	3,200	446	216
Petrochemical companies	7,456	94	120	7,693	152	109
Other associates and joint ventures	940	140	193	686	182	272
	12,316	658	522	11,579	780	597
Government entities
Government bonds	1,044	6,247	−	2,169	18,086	−
Banks controlled by the Federal Government	(1,973)	2,801	29,791	(1,850)	3,640	31,877
Receivables from the Electricity sector (Note 19.2)	747	2,156	−	926	1,937	−
Petroleum and alcohol account - Receivables from Federal government (Note 19.3)	−	357	−	−	409	−
Federal Government - Dividends and Interest on Capital	(18)	−	834	3	−	478
Others	92	209	334	(117)	361	452
	(108)	11,770	30,959	1,131	24,433	32,807
Pension plan (Petros)	−	−	156	(6)	−	163
	12,208	12,428	31,637	12,704	25,213	33,567

The line items effect in profit or loss and their carrying amounts in the statement of financial position are set out below:

	2013			2012
	Profit or Loss	Assets	Liabilities	Profit or Loss	Assets	Liabilities
Revenues (mainly sales revenues)	13,164			12,365
Foreign exchange and inflation indexation charges, net	(791)			(1,083)
Finance income (expenses), net	(165)			1,422
Current assets		7,622			20,354
Non-current assets		4,806			4,859
Current liabilities			3,568			3,361
Non-Current Liabilities			28,069			30,206
	12,208	12,428	31,637	12,704	25,213	33,567

19.2.Receivables from the electricity sector

At December 31, 2013, the Company had US$ 2,156 of receivables from the Brazilian electricity sector (US$ 1,937 at December, 31, 2012), of which US$ 1,743 were classified to non-current assets.

The Company supplies fuel to thermoelectric power plants located in the northern region of Brazil, which are direct or indirect subsidiaries of Eletrobras, the Federal Government electric energy company. Part of the costs for supplying fuel to these thermoelectric power stations is borne by the Fuel Consumption Account (Conta de Consumo de Combustível - CCC), managed by Eletrobras.

Collections of amounts related to fuel supply to Independent Power Producers (Produtores Independentes de Energia - PIE), which are companies created for the purpose of generating power exclusively for Amazonas Distribuidora de Energia S.A. - AME, a direct subsidiary of Eletrobras rely directly on AME, which transfers funds to the Independent Power Producers.

In March 2013 a private instrument of debt acknowledgement was signed by AME, having Eletrobras as a guarantor. The amount of US$ 422 will be paid in 60 successive monthly installments of US$ 7, indexed to the SELIC interest rate.

The Company continues to vigorously pursue an agreement to recover these receivables in full and partial payments have been made. The balance of these receivables at December 31, 2013 was US$ 1,977 (US$ 1,723 at December 31, 2012), of which US$ 1,450 was past due (US$ 1,451 at December 31, 2012).

F-51

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

The Company also has electricity supply contracts with AME signed in 2005 by its subsidiary Breitener Energética S.A., which, pursuant to the terms of the agreements, are considered a finance lease of the two thermoelectric power plants, since the contracts determine that the power plants should be returned to AME at the end of the agreement period with no residual value (20-year term), among other contractual provisions. The balance of these receivables was US$ 179 (US$ 214 at December, 31, 2012) none of which was overdue.

19.3.Petroleum and Alcohol accounts - Receivables from Federal Government

At December 31, 2013, the balance of receivables related to the Petroleum and Alcohol accounts was US$ 357 (US$ 409 at December 31, 2012). 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.

19.4.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 month of December 2013 and December 2012 were:

	2013	2012
Amounts refer to monthly compensation in U.S. dollars
Compensation per employee
Lowest compensation	1,169.61	1,118.64
Average compensation	6,246.79	5,631.54
Highest compensation	36,077.81	33,233.06
Compensation per officer of Petrobras (highest)	44,144.51	41,415.24

The total compensation of Petrobras’ key management are set out below:

	2013			2012
	Officers	Board	Total	Officers	Board	Total
Short-term compensation	4.6	0.5	5.1	5.1	0.6	5.7
Long-term compensation (post-retirement benefits)	0.3	−	0.3	0.3	−	0.3
Total compensation	4.9	0.5	5.4	5.4	0.6	6.0
Number of members	7	10	17	7	10	17

In 2013 the compensation of board members and officers for the consolidated Petrobras group amounted to US$ 27.6 (US$ 29.0 in 2012).

F-52

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

20.Provision for decommissioning costs

Non-current liabilities	2013	2012
Opening balance	9,441	4,712
Revision of provision	(902)	5,226
Payments made	(506)	(286)
Interest accrued	199	134
Others (*)	59	4
Cumulative translation adjustment	(1,158)	(349)
Closing balance	7,133	9,441
(*) Includes amounts related to liabilities associated with assets classified as held for sale, as set out in note 10.

21.Taxes  

21.1.Income taxes

	2013	2012
Current assets
Taxes In Brazil	951	1,255
Taxes Abroad	109	207
	1,060	1,462
Current liabilities
Taxes In Brazil	158	280
Taxes Abroad	123	65
	281	345

F-53

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

21.2.Other taxes

Current assets	2013	2012
Taxes In Brazil:
ICMS (VAT)	1,623	1,542
PIS/COFINS (Taxes on Revenues)	2,069	2,279
CIDE	20	23
Others	151	193
	3,863	4,037
Taxes Abroad	48	73
	3,911	4,110
Non-current assets
Taxes In Brazil:
Deferred ICMS (VAT)	879	903
Deferred PIS and COFINS (Taxes on Revenues)	4,197	4,051
Others	292	252
	5,368	5,206
Taxes Abroad	12	17
	5,380	5,223
Current liabilities
Taxes In Brazil:
ICMS (VAT)	1,164	1,488
PIS/COFINS (Taxes on Revenues)	230	491
CIDE	16	17
Production Taxes	2,432	2,624
Withholding income taxes	256	565
Others	350	360
	4,448	5,545
Taxes abroad	221	238
	4,669	5,783

F-54

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

21.3.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, 2012 (*)	(11,374)	(2,203)	(425)	(844)	335	343	634	473	1,289	(11,772)
Recognized in profit or loss for the year	(2,327)	(1,284)	961	217	59	998	(119)	595	(366)	(1,266)
Recognized in shareholders’ equity	−	−	−	−	−	−	−	−	1,519	1,519
Cumulative translation adjustment	1,038	341	24	77	(76)	(213)	(48)	(18)	(314)	811
Others	(14)	35	1	(38)	28	(19)	−	−	16	9
Balance at December 31, 2012(*)	(12,677)	(3,111)	561	(588)	346	1,109	467	1,050	2,144	(10,699)
Recognized in profit or loss for the period	(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)
Deferred tax assets										1,277
Deferred tax liabilities										(11,976)
Balance at December 31, 2012 (*)										(10,699)
Deferred tax assets										1,130
Deferred tax liabilities										(9,906)
Balance at December 31, 2013										(8,776)
(*) Restated, as set out on note 2.3.

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.

F-55

 

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 recovered as provisions are settled and future events occur, both based on estimates that have been made.

At December 31, 2013 the estimated recovery / reversal dates of net deferred tax assets (liabilities) recoverable (payable) is set out in the following table:

	Deferred income tax
	Assets	Liabilities
2014	111	102
2015 and thereafter	1,019	9,804
Recognized deferred tax credits	1,130	9,906
Brazil	642	−
Abroad	2,223	−
Unrecognized deferred tax credits	2,865	−
Total	3,995	9,906

At December 31, 2013, the Company had unused tax loss carryforwards from companies abroad, for which no deferred tax assets have been recognized, in the amount of US$ 2,223 (US$ 2,122 at December 31, 2012) 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$ 1,680 (US$ 1,329 at December 31, 2012), as well as from entities in Spain, in the amount of US$ 543, subject to applicable statute of limitations that lapse in 20 years from the date the losses are recognized.

An aging of the tax carryforwards not recognized, from companies abroad, by lapse of the applicable statute of limitations is set out below:

2013
Lapse of Statute of Limitations	2020	2021	2022	2023	2024	2025	2026	2027	2028	2029	2030 and afterwards	Total
Unrecognized deferred tax credits	55	174	79	74	94	6	113	130	163	203	1,132	2,223

F-56

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

21.4.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:

	2013	2012	2011
Income before income taxes	13,410	14,493	26,724
Income taxes computed based on Brazilian Statutory Corporate Tax Rates (34%)	(4,558)	(4,928)	(9,089)
Adjustments between Income Taxes based on Statutory Rates and on the Effective Tax Rate:
·   Tax benefits from the deduction of interest on capital distribution	1,306	1,612	2,123
·    Different jurisdictional taxes rates for Companies abroad	644	335	422
·    Tax incentives	57	58	220
·    Tax losses not recorded as assets	(1)	(341)	(345)
·    Non-deductible/(deductible) expenses, net (*)	(198)	(559)	(268)
·    Tax credits of companies abroad in the exploration stage	(2)	(2)	−
·    Others	174	263	205
Income taxes expense	(2,578)	(3,562)	(6,732)
Deferred income taxes	(402)	(1,266)	(3,599)
Current income taxes	(2,176)	(2,296)	(3,133)
	(2,578)	(3,562)	(6,732)
Effective Tax Rate	19.2%	24.6%	25.2%
(*) Includes share of profit of equity-accounted investments.

22.Employee benefits (Post-Employment)

The carrying amounts of employee benefits (post-employment) are set out below:

	2013	2012	01.01.2012
Liabilities
Petros Pension Plan	5,342	11,141	6,871
Petros 2 Pension Plan	121	547	606
AMS Medical Plan	6,999	8,390	8,214
Other plans	111	146	127
	12,573	20,224	15,818
Current	816	788	761
Non-current	11,757	19,436	15,057
	12,573	20,224	15,818

The current balance relates to an estimate of the payments to be made in 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 under private law with administrative and financial autonomy.

F-57

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

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 BR Distribuidora, 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.

At December 31, 2013, the Terms of Financial Commitment (TFC), signed by Petrobras and Petros in 2008 comprise a balance of US$ 3,514, including US$ 209 related to interest expense due in 2014. The TCF are due in 20 years, with 6% p.a. semiannual coupon payments based on the updated balance.  The carrying amount of US$ 2,976 related to crude oil and oil products pledged as security for the TFC replaced the long-term National Treasury Notes that were previously held as collateral in July 2012.

The employers' expected contributions to the plan for 2014 are US$ 456.

 The duration of the actuarial liability related to the plan, as of December 31, 2013 is 12.26 years.

b)Petros Plan 2 - Fundação Petrobras de Seguridade Social

Petros Plan 2 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 (or from the date the employee was hired, for those admitted during this period) in which the Petros Plan was closed and the participants did not have a pension plan. The plan is open to new participants although there will no longer be payments relating to past service costs.

Certain elements of the Petros Plan 2 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 recognized in profit or loss and are intended to constitute a reserve for programmed retirement. The contributions for the portion of the plan with defined contribution characteristics were US$ 308 in 2013.

The defined benefit portion of the contributions has been suspended from July 1, 2012 to June 30, 2014, as decided by the Deliberative Council of Petros, based on advice from by the actuarial consultants from Fundação Petros. Therefore, the entire contributions are being appropriated in the individual accounts of plan participants.

For 2014 the employers' expected contributions to the defined-benefit portion of the plan are US$ 292. The duration of the actuarial liability related to the plan, as of December 31, 2013 is 27.86 years.

F-58

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

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 to meet the assessed risk of each different class of asset and provide for diversification, in order to lower portfolio risk. The portfolio must comply with the Brazilian National Monetary Council regulations. Portfolio allocation limits for the period between 2014 and 2018 are 30% to 60% in fixed-income securities, 30% to 50% in variable-income securities, 3.0% to 8.0% in real estate, 1.5% to 15% in loans to participants, 4% to 10% in structured finance projects and up to 1% in investments abroad.

Fundação Petros establishes investment policies for 5-year periods, annually reviewed. Based on the last investment policy established (2013-2017), Petros determined that an asset liability management model (ALM) be used to solve net cash flow mismatches of the benefit plans, based on liquidity and solvency parameters, simulating a 30-year period.

The pension plan assets by type are set out following:

	2013				2012
Type of asset	Quoted prices in active markets	Unquoted prices	Total fair value	%	Total fair value	%
Fixed income	6,523	1,998	8,521	37%	12,792	46%
Corporate bonds	−	536	536		863
Government bonds	6,523	−	6,523		10,000
Other investments	−	1,462	1,462		1,929
Variable income	10,152	347	10,499	47%	10,928	39%
Common and preferred shares	10,152	−	10,152		10,792
Other investments	−	347	347		136
Structured investments	−	1,571	1,571	7%	1,836	7%
Private equity funds	−	1,464	1,464		1,729
Venture capital funds	−	29	29		39
Real estate Funds	−	78	78		68
Real estate properties	−	1,388	1,387	6%	1,304	5%
	16,675	5,304	21,978	97%	26,860	97%
Loans to participants			757	3%	825	3%
			22,735	100%	27,685	100%

At December 31, 2013, the investments include Petrobras’ common and preferred shares in the amount of US$ 228 and US$ 169, respectively, and real estate properties leased by the Company in the amount of US$ 172.

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 and BR Distribuidora operate a medical benefit plan for employees in Brazil (active and inactive) 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.

F-59

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

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 assets held as collaterals for the health care plan. Benefits are paid and recognized by the Company based on the costs incurred by the participants.

The duration of the actuarial liability related to the plan, as of December 31, 2013 is 20.34 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-60

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

a)Movement in the actuarial liabilities, in the fair value of the assets and in the amounts recognized in the statement of financial position

	2013					2012 (*)
	Pension plan		Medical Plan	Other plans		Pension plan		Medical Plan	Other plans
	Petros	Petros 2	A M S		Total	Petros	Petros 2	A M S		Total
Changes in the present value of obligations
Obligations at the beginning of the year	38,548	789	8,390	182	47,909	32,966	780	8,214	162	42,122
Interest expense:	3,373	73	735	20	4,201	3,551	86	892	8	4,537
· Term of financial commitment (TFC)	298	−	−	1	299	303	(1)	(5)	3	300
· Actuarial	3,075	73	735	19	3,902	3,248	87	897	5	4,237
Current service cost	484	145	192	10	831	(9)	197	146	7	341
Contributions paid by participants	182	−	−	−	182	197	28	−	−	225
Benefits paid	(1,155)	(6)	(364)	(10)	(1,535)	(1,168)	(3)	(363)	(10)	(1,544)
Remeasurement: Experience (gains) / losses	1,701	(118)	(1,978)	(2)	(397)	(2,795)	(703)	(1,738)	(6)	(5,242)
Remeasurement: (gains) / losses - demographic assumptions	323	(31)	2	(5)	289	726	36	352	6	1,120
Remeasurement: (gains) / losses - financial assumptions	(11,215)	(443)	1,066	5	(10,587)	8,180	403	1,566	15	10,164
Others	−	22	−	(27)	(5)	(6)	32	40	20	86
Cumulative Translation Adjustment	(4,437)	(77)	(1,044)	(22)	(5,580)	(3,094)	(67)	(719)	(20)	(3,900)
Obligations at the end of the year	27,804	354	6,999	151	35,308	38,548	789	8,390	182	47,909
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	26,096	174	−	35	26,305
Interest income	2,461	22	−	4	2,487	2,829	25	−	2	2,856
Contributions paid by the sponsor (Company)	255	−	364	24	643	257	22	363	5	647
Contributions paid by participants	182	−	−	−	182	196	28	−	−	224
Receipts from the Term of financial commitment (TFC)	153	−	−	−	153	164	−	−	−	164
Benefits Paid	(1,155)	(6)	(364)	(10)	(1,535)	(1,168)	(3)	(363)	(10)	(1,544)
Remeasurement: Return on plan assets exceeding interest income	(3,458)	8	−	3	(3,447)	1,339	8	−	2	1,349
Others	−	−	−	(13)	(13)	2	7	−	7	16
Cumulative Translation Adjustment	(3,383)	(33)	−	(4)	(3,420)	(2,308)	(19)	−	(5)	(2,332)
Fair value of plan assets at the end of the year	22,462	233	−	40	22,735	27,407	242	−	36	27,685
Amounts recognized in the Statement of Financial Position
Present value of obligations	27,804	354	6,999	151	35,308	38,548	789	8,390	182	47,909
( -) Fair value of plan assets	(22,462)	(233)	−	(40)	(22,735)	(27,407)	(242)	−	(36)	(27,685)
Net actuarial liability as of December 31,	5,342	121	6,999	111	12,573	11,141	547	8,390	146	20,224
Changes in the net actuarial liability
Balance as of December 31, 2011						2,271	327	6,909	132	9,639
(+) Adoption of amendments to IAS 19						4,600	279	1,305	(5)	6,179
Balance as of January 1,	11,141	547	8,390	146	20,224	6,871	606	8,214	127	15,818
(+) Remeasurement effects recognized in other comprehensive income	(5,733)	(600)	(910)	(5)	(7,248)	4,772	(272)	180	13	4,693
(+) Costs incurred in the period	1,396	218	927	25	2,566	705	284	1,077	25	2,091
(-) Contributions paid	(255)	−	(364)	(24)	(643)	(257)	(22)	(363)	(5)	(647)
(-) Payments related to Term of financial commitment (TFC)	(153)	−	−	−	(153)	(164)	−	−	−	(164)
Others	−	−	−	(13)	(13)	−	(1)	1	1	1
Cumulative Translation Adjustment	(1,054)	(44)	(1,044)	(18)	(2,160)	(786)	(48)	(719)	(15)	(1,568)
Balance as of December 31,	5,342	121	6,999	111	12,573	11,141	547	8,390	146	20,224
(*) Amounts restated, as set out in note 2.3.

F-61

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

b) Defined benefit costs

	2013					2012 (*)					2011 (*)
	Pension Plans		Medical Plan			Pension Plans		Medical Plan			Pension Plans		Medical Plan
	Petros	Petros 2	AMS	Other Plans	Total	Petros	Petros 2	AMS	Other Plans	Total	Petros	Petros 2	AMS	Other Plans	Total
Service cost	484	145	192	10	831	(9)	197	146	7	341	(9)	182	146	6	325
Interest on net Liabilities (Assets)	912	51	735	16	1,714	722	61	892	6	1,681	629	33	926	10	1,598
Others	−	22	−	(1)	21	(8)	26	39	12	69	(226)	3	30	−	(193)
Net costs for the year	1,396	218	927	25	2,566	705	284	1,077	25	2,091	394	218	1,102	16	1,730
Related to active employees:
Included in the cost of sales	597	119	267	3	986	218	124	228	4	574	123	91	212	8	434
Operating expense recognized in profit or loss	355	94	211	20	680	121	153	180	21	475	58	122	180	8	368
Related to retired employees	444	5	449	2	900	366	7	669	−	1,042	213	5	710	−	928
Net costs for the year	1,396	218	927	25	2,566	705	284	1,077	25	2,091	394	218	1,102	16	1,730
(*) Amounts restated, as set out in note 2.3.

F-62

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

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	(2,689)	3,256	(712)	865	981	(814)
Current Service cost and interest cost	(119)	140	(47)	55	157	(128)

d)Significant actuarial assumptions

Assumptions	2013	2012
Discount rate	12.88% (1) / 12.97% (2) / 12.90% (3)	9.35% (1) (2) / 9.42% (3)
Salary growth rate	8.03% (1) / 10,21% (2)	7.62% (1) / 9.51% (2)
Medical plans turnover	0.590% p.a (4)	0.700% p.a (4)
Pension plans turnover	Null	Null
Variance assumed in medical and hospital costs	11.62% to 4.09%p.a (5)	11.74% to 4.11%p.a (5)
Mortality table	Basic AT 2000, sex-specific, 20% smoothing coefficient (6)	AT 2000 sex specific. 30% smoothing coefficient - female(6)
Disability table	TASA 1927 (7)	TASA 1927 (7)
Mortality table for disabled participants	Sex-specific Winklevoss, 20% smoothing coefficient (8)	Sex-specific Winklevoss, 20% smoothing coefficient (8)
(1) Petros Plan for Petrobras Group.
(2) Petros 2 Plan.
(3) AMS Plan.
(4) Average turnover according to age and employment time. In 2013, except for BR (1.247%) and Liquigas (8.546%).
(5) Decreasing rate, converging by the end of the next 30 years to the long-term expected inflation.
(6) Except for Petros 2 Plan, for which AT 2000 (80% male + 20% female) 10%-smoothed has been used.
(7) Except for Petros 2 Plan, for which Álvaro Vindas invalidity table has been used.
(8) Except for Petros 2 Plan, for which tables IAPB 1957 (2013) and AT 49 Male (2012) for disabled have been applied.

e)Expected maturity analysis of pension and medical benefits

	2013
	Pension Plan		Medical Plan
	Petros	Petros 2	AMS	Other Plans	Total
Up to 1 Year	1,715	12	357	3	2,087
1 To 2 Years	1,681	14	365	3	2,063
2 To 3 Years	1,644	15	363	2	2,024
3 To 4 Years	1,600	15	378	2	1,995
Over 4 Years	21,164	298	5,536	141	27,139
	27,804	354	6,999	151	35,308

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 2013, in the amount of US$ 3 were recognized in profit or loss.

F-63

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

23.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 by the Ministry of Mines and Energy, and are computed based on the consolidated income before profit sharing and non‐controlling interests.

The Company has recognized profit sharing expenses in the amount of US$ 520 (US$ 524 in 2012) pursuant to these regulations, considering a 4.5 percentage applied over the income before profit sharing and non-controlling interest in Brazilian reais. 

A negotiation between the Company and the unions to determine a new method for determining profit sharing benefits is underway, as established in the 2013 Collective Bargaining Agreement.

24.Shareholders’ equity

24.1.Share capital

At December 31, 2013, subscribed and fully paid share capital was US$ 107,371, 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.

Capital increase with reserves in 2013

The Shareholders’ Extraordinary General Meeting, held jointly with the Annual General Meeting on April 29, 2013 approved a capital increase through capitalization of a portion of the profit reserve relating to tax incentives, recognized in 2012 in the amount of US$ 9 (in compliance with article 35, paragraph 1, of Ordinance 2,091/07 of the Ministry for National Integration), without issue of new shares (pursuant to article 169, paragraph 1, of Law 6,404/76). Share capital increased from US$ 107,362 to US$ 107,371.

Capital increase with reserves in 2014

A proposal will be made to the Shareholders’ Extraordinary General Meeting, to be held jointly with the Annual General Meeting in 2014 to increase capital through capitalization of a portion of the profit reserve for tax incentives established in 2013, of US$ 9. Share capital will increase from US$ 107,371 to US$ 107,380.

24.2.Additional paid in capital

a)Incremental costs directly attributable to the issue of new shares

These include any transaction costs directly attributable to the issue of new shares, net of taxes.

b)Change in interest in subsidiaries

These include 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-64

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

24.3.Profit reserves

a)Legal reserve

The legal reserve represents 5% of the net income for the year, calculated pursuant to article 193 of the Brazilian Corporation Law.

b)Statutory reserve

The 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.

c)Tax incentives reserve

Government grants are recognized in profit or loss 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 increasing share capital.

In 2013, government grants of US$ 9 related to investments (using resources provided by income taxes benefits) for the development of the Northeast of Brazil (Superintendências de Desenvolvimento do Nordeste – SUDENE) and the Amazon region (SUDAM) were appropriated from profit or loss.

d)Profit retention reserve

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.

An appropriation of US$ 7,277 to profit retention reserve, to provide partial funding for our 2014 capital budget, will be proposed and voted at the 2014 Annual General Meeting.

24.4.Accumulated other comprehensive income

a)Cumulative translation adjustment

This account 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), recognized as cumulative translation adjustments (CTA) within accumulated other comprehensive income.

b)Other comprehensive income

This account comprises gains or losses arising from measurement at fair value of available-for-sale financial assets; from cash flow hedges; and from remeasurements of the net pension and medical benefits liability.

24.5.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.

F-65

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Preferred shares have priority in case of capital returns and dividend distribution, which is based on the highest of 3% of the preferred shares’ net book value, or 5% of the preferred share capital.

Dividends for 2013 of US$ 3,970 are to be voted at the 2014 Annual General Meeting and are consistent with the rights granted to preferred shares in the bylaws of the Company and to the minimum mandatory dividend for common shares. Dividends proposed for 2013 represent 41.85% of the adjusted net income in Brazilian Reais (adjusted in accordance with Brazilian Corporation Law), as 3% of the book value of shareholders’ equity regarding preferred shares stake was higher than the minimum mandatory dividend (25% of the adjusted net income for the year).

Interest on capital will be indexed based on the SELIC rate from December 31, 2013 to the date of payment, which will be voted at the 2014 Annual General Meeting.

Interest on capital is subject to a withholding income tax rate of 15%, except for shareholders that are declared immune or exempt, pursuant to Law 9,249/95. Interest on capital is a form of dividend distribution, which is deductible for tax purposes in Brazil and is included in the dividend distribution for the year, as established in the Company’s bylaws. The tax credit from the deduction of interest on capital is recognized in profit or loss. An amount of US$ 1,389 was recognized in 2013 (US$ 1,612 in 2012) relating to tax benefits from the deduction of interest on capital. For accounting purposes, shareholders’ equity is reduced in a manner similar to a dividend, pursuant to CVM Deliberation 207/96.

24.6.Earnings per Share

	2013	2012	2011
Net income attributable to Shareholders of Petrobras	11,094	11,034	20,121
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)	0.85	0.85	1.54

25.Sales revenues

	2013	2012	2011
Gross sales	172,016	176,714	183,022
Sales taxes	(30,554)	(32,611)	(37,107)
Sales revenues (*)	141,462	144,103	145,915
Domestic Market	106,464	100,497	98,941
Exports	15,172	22,353	24,649
International Sales (**)	19,826	21,253	22,325
(*) See note 30 for a breakdown of sales revenues by business segment
(**) Sales revenues from operations outside of Brazil, other than exports

F-66

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

26.Other operating expenses, net

	2013	2012	2011
Unscheduled stoppages and pre-operating expenses	(923)	(856)	(901)
Pension and medical benefits - inactive employees	(900)	(1,042)	(928)
Institutional relations and cultural projects	(821)	(777)	(884)
Inventory write-down to net realizable value	(580)	(742)	(643)
Collective bargaining agreement	(419)	(444)	(430)
Legal, administrative and arbitration proceedings	(269)	(716)	130
Expenditures on health, safety and environment	(225)	(289)	(474)
Impairment	(544)	(137)	(369)
Expenditures/reimbursements from operations in E&P partnerships	241	268	10
Government Grants	181	385	378
Gains / (losses) on disposal/write-offs of assets	1,764	(2)	7
Others	258	167	120
	(2,237)	(4,185)	(3,984)

27.Expenses by nature

	2013	2012	2011
Raw material / products for resale	(60,116)	(58,410)	(57,274)
Production taxes	(14,498)	(16,083)	(16,228)
Employee Compensation	(12,769)	(12,071)	(12,207)
Depreciation, depletion and amortization	(13,188)	(11,119)	(10,535)
Changes in inventories	1,681	724	5,278
Materials, Freight, rent, third-party services and other related costs	(22,608)	(24,016)	(23,457)
Exploration expenditures written off (inc. dry wells and signature bonuses)	(1,892)	(2,847)	(1,480)
Other taxes	(780)	(386)	(460)
Legal, administrative and arbitration proceedings	(269)	(716)	130
Institutional relations and cultural projects	(821)	(777)	(884)
Unscheduled stoppages and pre-operating expenses	(923)	(856)	(901)
Expenditures on health, safety and environment	(225)	(289)	(474)
Inventory write-down to net realizable value (market value)	(580)	(742)	(643)
Impairment	(544)	(137)	(369)
Gains / (losses) on disposal/write-offs of assets	1,764	(2)	7
	(125,768)	(127,727)	(119,497)
Cost of sales	(108,254)	(107,534)	(99,595)
Selling expenses	(4,904)	(4,927)	(5,346)
General and Administrative expenses	(4,982)	(5,034)	(5,161)
Exploration costs	(2,959)	(3,994)	(2,630)
Research and development expenses	(1,132)	(1,143)	(1,454)
Other taxes	(780)	(386)	(460)
Other operating expenses, net	(2,237)	(4,185)	(3,984)
Profit sharing	(520)	(524)	(867)
	(125,768)	(127,727)	(119,497)

F-67

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

28.Net finance income (expense)

	2013	2012	2011
Foreign exchange and inflation indexation charges on net debt (*)	(1,603)	(3,327)	(2,918)
Debt interest and charges	(5,491)	(5,152)	(4,866)
Income from investments and marketable securities	1,278	1,716	2,948
Financial result on net debt	(5,816)	(6,763)	(4,836)
Capitalized borrowing costs	3,921	3,807	4,403
Gains (losses) on derivatives	(181)	(52)	(215)
Interest income from marketable securities	(95)	919	286
Other finance expense and income, net	(320)	404	(39)
Other exchange and indexation charges, net	(300)	(241)	477
Finance income (expenses), net	(2,791)	(1,926)	76
Income	1,815	3,659	3,943
Expenses	(2,673)	(2,016)	(1,424)
Foreign exchange and inflation indexation charges, net	(1,933)	(3,569)	(2,443)
	(2,791)	(1,926)	76
(*) Includes indexation charges on debt in local currency indexed to the U.S. dollar.

29.Supplemental information on statement of cash flows

	2013	2012	2011
Additional information on cash flows:
Amounts paid during the period
Income taxes paid	1,244	1,093	2,049
Withholding income tax paid for third-parties	1,733	2,045	2,377
	2,977	3,138	4,426
Investing and financing transactions not involving cash
Purchase of property, plant and equipment on credit	209	187	8
Finance leases	−	−	19
Amounts related to the recognition (reversal) of a provision for decommissioning costs	(629)	5,208	1,407

F-68

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

30.Segment Information

Consolidated assets by Business Area - 12.31.2013
	Exploration and Production	Refining, Transportation & Marketing	Gas & Power	Biofuels	Distribution	International	Corporate	Eliminations	Total
Current assets	5,902	19,064	3,864	77	2,457	5,089	21,643	(5,441)	52,655
Non-current assets	146,805	73,043	23,839	1,119	5,224	13,034	6,897	(1,193)	268,768
Long-term receivables	6,251	4,387	1,853	2	2,253	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	66,200	20,882	222	2,672	7,971	3,312	(74)	227,901
Operating assets	90,888	32,313	16,698	205	2,009	3,792	2,312	(74)	148,143
Under construction	35,828	33,887	4,184	17	663	4,179	1,000	−	79,758
Intangible assets	13,744	138	355	−	293	565	324	−	15,419
Total Assets	152,707	92,107	27,703	1,196	7,681	18,123	28,540	(6,634)	321,423
Consolidated assets by Business Area - 12.31.2012
Current assets	6,565	20,362	3,610	117	3,176	3,517	27,382	(6,935)	57,794
Non-current assets	144,873	70,973	24,593	1,131	4,954	15,087	8,482	(491)	269,602
Long-term receivables	4,760	4,459	1,464	16	1,852	2,102	4,694	(491)	18,856
Investments	80	2,897	1,160	860	15	937	157	−	6,106
Property, plant and equipment	102,779	63,463	21,585	255	2,733	10,882	3,204	−	204,901
Operating assets	64,455	29,327	18,106	237	2,061	6,814	2,237	−	123,237
Under construction	38,324	34,136	3,479	18	672	4,068	967	−	81,664
Intangible assets	37,254	154	384	−	354	1,166	427	−	39,739
Total Assets	151,438	91,335	28,203	1,248	8,130	18,604	35,864	(7,426)	327,396

F-69

 

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 - 2013
	2013
	Exploration and Production	Refining, Transportation & Marketing	Gas & Power	Biofuels	Distribution	International	Corporate	Eliminations	Total
Sales revenues	68,210	111,051	14,017	388	41,365	16,302	−	(109,871)	141,462
Intersegments	67,096	38,103	1,191	324	995	2,162	−	(109,871)	−
Third parties	1,114	72,948	12,826	64	40,370	14,140	−	−	141,462
Cost of sales	(34,279)	(119,617)	(12,149)	(433)	(37,580)	(13,886)	−	109,690	(108,254)
Gross profit (loss)	33,931	(8,566)	1,868	(45)	3,785	2,416	−	(181)	33,208
Income (expenses)	(4,133)	(3,791)	(1,167)	(102)	(2,424)	(541)	(4,932)	96	(16,994)
Selling, administrative and general expenses	(443)	(2,781)	(1,087)	(55)	(2,417)	(860)	(2,406)	163	(9,886)
Exploration costs	(2,784)	−	−	−	−	(175)	−	−	(2,959)
Research and development expenses	(523)	(242)	(57)	(16)	(2)	(2)	(290)	−	(1,132)
Other taxes	(238)	(162)	(81)	(1)	(19)	(141)	(138)	−	(780)
Other operating expenses, net	(145)	(606)	58	(30)	14	637	(2,098)	(67)	(2,237)
Income / (loss) before financial results and income taxes	29,798	(12,357)	701	(147)	1,361	1,875	(4,932)	(85)	16,214
Net finance income (expense)	−	−	−	−	−	−	(2,791)	−	(2,791)
Share of profit of equity-accounted investments	2	73	243	(20)	2	174	33	−	507
Profit sharing	(181)	(133)	(23)	(1)	(40)	(14)	(128)	−	(520)
Income / (loss) before income taxes	29,619	(12,417)	921	(168)	1,323	2,035	(7,818)	(85)	13,410
Income taxes	(10,070)	4,247	(230)	51	(447)	(246)	4,087	30	(2,578)
Net income (Loss)	19,549	(8,170)	691	(117)	876	1,789	(3,731)	(55)	10,832
Net income attributable to:
Shareholders of Petrobras	19,523	(8,162)	631	(117)	876	1,729	(3,331)	(55)	11,094
Non-controlling interests	26	(8)	60	−	−	60	(400)	−	(262)
	19,549	(8,170)	691	(117)	876	1,789	(3,731)	(55)	10,832

F-70

 

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 - 2012
	2012
	Exploration and Production	Refining, Transportation & Marketing	Gas & Power	Biofuels	Distribution	International	Corporate	Eliminations	Total
Sales revenues	74,714	116,710	11,803	455	40,712	17,929	−	(118,220)	144,103
Intersegments	73,871	37,950	1,288	365	878	3,868	−	(118,220)	−
Third parties	843	78,760	10,515	90	39,834	14,061	−	−	144,103
Cost of sales	(33,622)	(130,088)	(9,621)	(481)	(36,997)	(14,082)	−	117,357	(107,534)
Gross profit (loss)	41,092	(13,378)	2,182	(26)	3,715	3,847	−	(863)	36,569
Income (expenses)	(5,448)	(4,075)	(1,080)	(102)	(2,290)	(1,886)	(4,937)	149	(19,669)
Selling, administrative and general expenses	(494)	(3,052)	(967)	(64)	(2,235)	(922)	(2,376)	149	(9,961)
Exploration costs	(3,613)	−	−	−	−	(381)	−	−	(3,994)
Research and development expenses	(540)	(228)	(36)	(34)	(2)	−	(303)	−	(1,143)
Other taxes	(53)	(66)	(57)	(1)	(12)	(111)	(86)	−	(386)
Other operating expenses, net	(748)	(729)	(20)	(3)	(41)	(472)	(2,172)	−	(4,185)
Income / (loss) before financial results and income taxes	35,644	(17,453)	1,102	(128)	1,425	1,961	(4,937)	(714)	16,900
Net finance income (expense)	−	−	−	−	−	−	(1,926)	−	(1,926)
Share of profit of equity-accounted investments	(1)	(104)	193	(27)	1	(14)	(5)	−	43
Profit sharing	(178)	(142)	(18)	(1)	(40)	(14)	(131)	−	(524)
Income / (loss) before income taxes	35,465	(17,699)	1,277	(156)	1,386	1,933	(6,999)	(714)	14,493
Income taxes	(12,057)	5,981	(367)	44	(472)	(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

F-71

 

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 - 2011
	2011
	Exploration and Production	Refining, Transportation & Marketing	Gas & Power	Biofuels	Distribution	International	Corporate	Eliminations	Total
Sales revenues	74,117	118,630	9,738	320	44,001	16,956	−	(117,847)	145,915
Intersegments	73,601	38,146	1,304	288	731	3,777	−	(117,847)	−
Third parties	516	80,484	8,434	32	43,270	13,179	−	−	145,915
Cost of sales	(32,883)	(122,897)	(5,698)	(351)	(40,347)	(12,933)	−	115,514	(99,595)
Gross profit (loss)	41,234	(4,267)	4,040	(31)	3,654	4,023	−	(2,333)	46,320
Income (expenses)	(4,198)	(4,194)	(1,519)	(134)	(2,459)	(1,901)	(4,809)	179	(19,035)
Selling, administrative and general expenses	(489)	(3,306)	(1,038)	(66)	(2,403)	(928)	(2,456)	179	(10,507)
Exploration costs	(2,182)	−	−	−	−	(448)	−	−	(2,630)
Research and development expenses	(743)	(280)	(69)	(30)	(5)	−	(327)	−	(1,454)
Other taxes	(48)	(53)	(97)	(1)	(24)	(113)	(124)	−	(460)
Other operating expenses, net	(736)	(555)	(315)	(37)	(27)	(412)	(1,902)	−	(3,984)
Income / (loss) before financial results and income taxes	37,036	(8,461)	2,521	(165)	1,195	2,122	(4,809)	(2,154)	27,285
Net finance income (expense)	−	−	−	−	−	−	76	−	76
Share of profit of equity-accounted investments	44	(98)	238	15	5	24	2	−	230
Profit sharing	(271)	(194)	(34)	(1)	(66)	(29)	(272)	−	(867)
Income / (loss) before income taxes	36,809	(8,753)	2,725	(151)	1,134	2,117	(5,003)	(2,154)	26,724
Income taxes	(12,495)	3,025	(845)	56	(360)	(926)	4,145	668	(6,732)
Net income (Loss)	24,314	(5,728)	1,880	(95)	774	1,191	(858)	(1,486)	19,992
Net income attributable to:
Shareholders of Petrobras	24,326	(5,718)	1,862	(95)	774	1,179	(721)	(1,486)	20,121
Non-controlling interests	(12)	(10)	18	−	−	12	(137)	−	(129)
	24,314	(5,728)	1,880	(95)	774	1,191	(858)	(1,486)	19,992

F-72

 

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
	2013
	Exploration & Production	Refining, Transportation & Marketing	Gas & Power	Distribution	Corporate	Eliminations	Total
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 attributable to shareholders of Petrobras	1,644	(12)	68	92	(62)	(1)	1,729
	2012
	Exploration & Production	Refining, Transportation & Marketing	Gas & Power	Distribution	Corporate	Eliminations	Total
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 attributable to shareholders of Petrobras	1,317	(400)	121	70	(403)	14	719
	2011
	Exploration & Production	Refining, Transportation & Marketing	Gas & Power	Distribution	Corporate	Eliminations	Total
Sales revenues	5,148	8,510	543	4,972	−	(2,217)	16,956
Intersegments	3,808	2,142	23	27	−	(2,223)	3,777
Third parties	1,340	6,368	520	4,945	−	6	13,179
Income before financial results, profit sharing and income taxes	2,379	(136)	115	80	(304)	(12)	2,122
Net income attributable to shareholders of Petrobras	1,331	(128)	158	67	(237)	(12)	1,179
	Exploration & Production	Refining, Transportation & Marketing	Gas & Power	Distribution	Corporate	Eliminations	Total
Total assets - breakdown of International Business Area
At 12.31.2013	13,656	2,652	602	1,085	1,970	(1,842)	18,123
At 12.31.2012	15,080	2,404	759	1,085	1,449	(2,173)	18,604

F-73

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

31.Provisions for legal proceedings, contingent liabilities and contingent assets

Legal proceedings provided for, contingent liabilities and judicial deposits are set out following.

31.1.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, losses and damages 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.

The Company has provisions for legal proceedings, in the amounts set out below:

Non-current liabilities	2013	2012
Labor claims	569	336
Tax claims	94	341
Civil claims	545	514
Environmental Claims	26	63
Other claims	12	11
	1,246	1,265

	2013	2012
Opening Balance	1,265	1,088
New provisions, net (*)	415	647
Payments made	(249)	(440)
Accruals and charges	77	99
Others	(57)	(26)
Cumulative translation adjustment	(205)	(103)
Closing Balance	1,246	1,265
(*) Includes reversal of tax claims provisions due to the adherence to REFIS, as set out in note 31.5.

31.2.Judicial Deposits

Judicial deposits made in connection with legal proceedings and guarantees are set out in the table below according to the nature of the corresponding lawsuits:

Non-current assets	2013	2012
Labor	882	869
Tax	1,002	1,117
Civil	529	638
Environmental	83	69
Others	8	3
	2,504	2,696

F-74

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

31.3.Contingent Liabilities

Contingent liabilities for which the likelihood of loss is considered to be possible are not recognized 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 for which the likelihood of loss is considered to be possible are set out in the table below.

Nature	Estimate
Tax	30,395
Civil - General	2,496
Labor	2,402
Civil - Environmental	1,248
Others	2
	36,543

A brief description of the nature of the main contingent liabilities (tax, civil and environmental) is set out in the following tables. Labor claims include a large number of individual claims and, therefore, are not presented.

F-75

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

a)Tax Proceedings

Description of tax proceedings	Estimate
Plaintiff: Secretariat of the Federal Revenue of Brazil
1) Deduction of expenses from the renegotiation of the Petros Plan from the calculation basis of income tax (IRPJ) and social contribution (CSLL) and penalty charged.
Current status: Awaiting the hearing of an appeal at the administrative level.	1,962
2) Profits of subsidiaries and associates domiciled abroad in the years of 2005, 2006, 2007, 2008 and 2009 not included in Petrobras' calculation basis of IRPJ and CSLL.
Current status: Awaiting the hearing of an appeal at the administrative level.	2,020
3) Deduction from the calculation basis of IRPJ and CSLL of expenses incurred in 2007 and 2008 related to employee benefits and Petros.
Current status: This claim is being disputed at the administrative level, involving three administrative proceedings.	786
4) Non-payment of withhold income tax (IRRF) and Contribution of Intervention in the Economic Domain (CIDE) over remittances for payment of platforms' affreightment.
Current status: This claim involves lawsuits in different administrative and judicial stages, in which the Company is taking legal actions to ensure its rights.	5,771
5) Non-payment of CIDE on imports of naphtha.
Current status: This claim is being discussed at the administrative level.	1,553
6) Non-payment of CIDE in the period from March 2002 until October 2003 in transactions with distributors and service stations that were holders of judicial injunctions that determined the sale of fuel without the gross-up of such tax.
Current status: This claim is in judicial stage, in which the Company is taking legal actions to ensure its rights.	647
7) Non-payment of tax on financial operations (IOF) over intercompany loans with, PifCo, Brasoil and BOC in 2007, 2008 and 2009.
Current status: Awaiting the hearing of an appeal at the administrative level.	2,437
8) Non-payment of withhold income tax (IRRF) over remittances abroad 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.	1,722
9) Tax credits recovery denied due to failure to comply with an accessory obligation.
Current status: Awaiting the hearing of an appeal at the administrative level.	1,813
Plaintiff: State Finance Department of AM, BA, DF, ES, PA, PE and RJ
10)Non-payment of ICMS on crude oil and natural gas sales due to differences in measuring beginning and ending inventory.
Current status: This claim involves lawsuits in different administrative levels, in which the Company is taking legal actions to ensure its rights.	1,646
Plaintiff: State Finance Department of Rio de Janeiro
11) ICMS on exit operations of liquid natural gas (LNG) without issuance of tax document by the main establishment.
Current status: This claim involves lawsuits in different administrative and judicial stages, in which the Company is taking legal actions to ensure its rights.	1,366
12) Dispute over ICMS tax levy in operations of sale of jet fuel, as Decree 36,454/2004 was declared as unconstitutional.
Current status: This claim involves lawsuits in different administrative and judicial stages, in which the Company is taking legal actions to ensure its rights.	772
Plaintiff: State Finance Department of São Paulo
13) Dispute over ICMS tax levy on the importing of a drilling rig – temporary admission in São Paulo and clearance in Rio de Janeiro and a fine for breach of accessory obligations.
Current status: This claim involves lawsuits in different administrative and judicial stages, in which the Company is taking legal actions to ensure its rights.	1,921
Plaintiff: Municipal governments of Anchieta, Aracruz, Guarapari, Itapemirim, Marataízes, Linhares, Vila Velha, Vitória and Maragogipe.
14) Failure to withhold and collect tax on services provided offshore (ISSQN) in some municipalities located in the State of Espírito Santo, despite Petrobras having made the withholding and payment of these taxes to the municipalities where the respective service providers are established, in accordance with Complementary Law No. 116/03.
Current status: This claim involves lawsuits in different administrative and judicial stages, in which the Company is taking legal actions to ensure its rights.	923
Plaintiff: State Finance Departments of Rio de Janeiro and Sergipe
15) Use of ICMS tax credits on the purchase of drilling rig bits and chemical products used in formulating drilling fluid.
Current status: This claim involves lawsuits in different administrative and judicial stages, in which the Company is taking legal actions to ensure its rights.	409
16) Other tax proceedings	4,647
Total for tax proceedings	30,395

F-76

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

b)Civil Proceedings – General

Description of civil proceedings	Estimate
Plaintiff: Agência Nacional de Petróleo, Gás Natural e Biocombustíveis - ANP
1) Dispute on differences in the payment of special participation charge in fields of the Campos Basin. In addition, the plaintiff is claiming fines for alleged non-compliance with minimum exploratory programs. Administrative proceedings are in course in connection with alleged irregularities in the platforms' measurement system.
Current status: This claim involves proceedings in different administrative and/or judicial stages, in which the Company is taking legal actions to ensure its rights.	1,252
2) Other civil proceedings	1,244
Total for civil proceedings	2,496

c)Environmental Proceedings – General

Description of environmental proceedings	Estimate
Plaintiff: Ministério Público Federal, Ministério Público Estadual do Paraná,
AMAR - Associação de Defesa do Meio Ambiente de Araucária e IAP - Instuituto 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 for the plaintiff, however both parties (the plaintiff and the Company) filed an appeal.	764
2) Other environmental proceedings	484
Total for environmental proceedings	1,248

31.4.Contingent assets

31.4.1.Legal proceeding in the United States - P-19 and P-31

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, 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 are currently in course before Brazilian courts.

F-77

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Brasoil, Petrobras and the insurance companies already pleaded the dismissal of the Brazilian legal proceedings but their definitive dismissal is awaiting the hearing of an appeal filed by the platforms’ shipbuilding company before the Superior Court for Non-Constitutional Matters (STJ).

The Company is intensifying actions taken, in an attempt to settle this lawsuit. The amount of damages claimed is approximately US$ 245.

31.4.2.Recovery of PIS and COFINS

Petrobras and its subsidiaries filed a civil lawsuit 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 such paragraph as 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 in its non-current assets.

At December 31, 2013, the Company had US$ 975 related to this lawsuit that is not yet recognized in the financial statements due to the lack of a final favorable decision.

31.5.Tax settlement program (REFIS)

In December 2013, the Company decided to adhere to the federal tax amnesty and refinancing program (Programa de Recuperação Fiscal – REFIS), introduced by Federal Laws No. 11,941/2009 and No. 12,249/2010, the deadlines for which were extended pursuant to Federal Law No. 12,865/2013.

REFIS includes tax debts and tax claims related to CIDE (taxation on fuel), II (import tax), IPI (tax on industrial production), IOF (tax on financial operations), IRRF (withholding income tax), as well as COFINS (tax on revenues). By deciding to adhere the program, the Company disbursed US$ 602 related to tax expenses, along with the use of judicial deposits of US$ 17, totaling US$ 619.

The adherence to REFIS resulted in savings of US$ 432 from penalties and interest reductions pursuant to regulations. Amounts recognized in profit or loss, including reversals of provisions related to tax claims are set out below:

	2013
Taxes	(313)
Finance income (expenses), net	(306)
	(619)
Other operating income (expenses), net (*)	358
Income taxes	76
	(185)
(*) Reversal of provision for tax claims

The Company has complied with all legal requirements necessary to adhere to the REFIS and is now awaiting approval from the Brazilian Internal Revenue Service (Receita Federal do Brasil) and the Office of the Attorney-General of the National Treasury (Procuradoria Geral da Fazenda Nacional - PGFN) regarding payments made in connection with the Company’s adherence to the REFIS  in order to settle such tax proceedings.

F-78

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

32.Natural Gas Purchase Commitments

Petrobras has entered into an agreement with Yacimientos Petrolíferos Fiscales Bolivianos (YPFB) to purchase 201.9 billion m³ of natural gas during the term of the agreement and to purchase a minimum annual volume commitment at a price calculated based on a formula comprising the price of fuel oil. The agreement is valid until 2019, renewable until the total volume commitment has been consumed.

At December 31, 2013, the minimum purchase commitment from 2014 to 2020 is approximately 52.7 billion m³ of natural gas, equivalent to 24.06 million m³ per day, which corresponds to an estimated amount of US$ 15.17 billion.

33.Collateral in connection with concession agreements for petroleum exploration

The Company has granted collateral to the 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$ 3,408, of which US$ 3,088 are still in force, net of commitments that have been undertaken. The collateral comprises crude oil from previously identified producing fields, pledged as security, amounting to US$ 1,943 and bank guarantees in the amount of US$ 1,145.

34.Risk management and derivative instruments

The Company is exposed to a variety of risks arising from its operations: market risk (including price risk related to crude oil and oil products), foreign exchange risk, interest rate risk, credit risk and liquidity risk.

34.1.Risk management

Petrobras’ officers are responsible for performing risk management based on a corporate policy. The objective of the overall risk management policy of the company, which considers all positions held and their respective risks in the analysis and decisions made, is to achieve an appropriate balance between growth, increased return on investments and risk exposure level, which can arise from its normal activities or from the context within which the Company operates, so that, through effective allocation of its physical, financial and human resources it may achieve its strategic goals.

34.2.Market risk

34.2.1.Risk management of price risk (related to crude oil and oil products)

Petrobras 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 transactions carried out abroad, which are usually short-term transactions similar to commercial transactions.

F-79

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

a)Notional amount, fair value and guarantees of crude oil and oil products derivatives

	Notional value (in thousands of bbl)*		Fair value**		Maturity
Statement of Financial Position	2013	2012	2013	2012
Futures contracts	10,224	(3,380)	(20)	(18)	2014
Purchase commitments	52,267	16,500
Sale commitments	(42,043)	(19,880)
Options contracts	−	(2,050)	−	(1.5)	2014
Call	−	(1,080)	−	(1)
Long position	2,200	3,204
Short position	(2,200)	(4,284)
Put	−	(970)	−	(0.5)
Long position	1,869	2,029
Short position	(1,869)	(2,999)
Total recognized in other current assets and liabilities			(20)	(19.5)
* Negative notional values (in bbl) represent short positions.
** Negative fair values were recorded in liabilities and positive fair values in assets.

Finance income	2013	2012	2011
Gain / (Loss) recognized in profit or loss for the period	(105)	(103)	(199)

Guarantees given as collateral	2013	2012
Generally consist of deposits	143	103

b)Sensitivity analysis of crude oil and oil products derivatives

The probable scenario is the fair value at  December 31, 2013. The stressed scenarios consider price changes of 25% and 50% on the risk variable, respectively, comparatively to December 31, 2013.

Crude Oil and Oil Products	Risk	Probable Scenario at 2013	Stressed Scenario (∆ of 25%)	Stressed Scenario (∆ of 50%)
Crude oil	Derivative (WTI prices decrease)	(23)	(187)	(347)
	Inventories (WTI prices increase)	16	177	337
		(7)	(10)	(10)
Diesel	Derivative (Diesel prices decrease)	7	(33)	(72)
	Inventories (Diesel prices increase)	(8)	31	70
		(1)	(2)	(2)
Gasoline	Derivative (Gasoline prices increase)	(1)	(10)	(18)
	Inventories (Gasoline prices decrease)	3	11	19
		2	1	1
Fuel Oil	Derivative (Fuel Oil prices increase)	(1)	(50)	(97)
	Inventories (Fuel Oil prices decrease)	3	51	99
		2	1	2
Propane	Derivative (Propane prices increase)	(2)	(28)	(53)
	Inventories (Propane prices decrease)	1	26	52
		(1)	(2)	(1)

F-80

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

c)Embedded derivatives – sale of ethanol

On March 8, 2013 the Company entered into an agreement to amend the ethanol sale contract, modifying prices and quantities. The selling price of each future ethanol shipment will be based on the price of ethanol in the Brazilian market (ESALQ) plus a spread. The amended agreement therefore no longer has a derivative instrument measured as an embedded derivative.

The notional value, fair value and the sensitivity analysis of the swap are presented below:

		Fair Value		Sensitivity analysis at 2013
Forward Contract	Notional value (in thousands of m³)	2013	2012	Risk	Probable Scenario	Stressed Scenario (∆ 25%)	Stressed Scenario ( ∆ 50%)
Long position (maturity in 2015)		−	36	Decrease in spread (Naphtha x Ethanol)	−	−	−

Finance Income	2013	2012	2011
Gain/ (loss) recognized in profit or loss for the period	(37)	10	(31)

34.2.2.Foreign exchange risk management

Petrobras seeks to identify and manage foreign exchange risk in an integrated manner, considering an integrated analysis of natural hedges, to benefit from the correlation between income and expenses. The Company chooses the currency in which to hold cash, such as the Brazilian Real, U.S. dollar or other currency for short-term risk management.

The risk management strategy of the Company may involve the use of derivative instruments to hedge certain liabilities, minimizing foreign exchange exposure.

a)Hedge Accounting

i) Cash Flow Hedge involving the Company’s future exports

Effective mid-May 2013, the Company formally documented and designated hedging relationships to account for the effects of the existing natural hedge between a portion of its obligations denominated in U.S. dollars and a portion of its future export revenues in U.S. dollars, relative to foreign currency rates risk. The foreign currency rates risk is related to the spot rates and the hedged future exports are those considered highly probable.

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, for which a portion of the company’s long-term debt in U.S. dollars is the hedging instrument. The hedging instruments (long-term debt) have different maturities, with an average of approximately 7.1 years. 

The principal amounts and the carrying amount of the hedging instruments as of December 31, 2013, along with the foreign currency losses recognized in other comprehensive income (shareholders’ equity) are set out below:

F-81

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Hedging Instrument	Hedged Transactions	Nature of the Risk	Maturity Date	Principal  Amount (US$)	Carrying amount of the Hedging Instruments on 2013 (R$)
Non-Derivative Financial Instruments	Portion of Highly Probable Future Monthly Export Revenues	Foreign Currency – Real vs U.S. Dollar Spot Rate	January 2014 to November 2020	40,742	95,443

Changes in the Principal Amount	US$
Amounts designated in May 2013	43,859
New hedging instruments designated	3,062
Exports affecting profit or loss	(2,904)
Principal repayments / amortization	(3,274)
Amounts designated as of December 31, 2013	40,742

Finance income and shareholders' equity	2013	2012
Gain /(loss) recognized in profit or loss for the period	(303)	−
Gain/ (loss) recognized in other comprehensive income - shareholders' equity	(5,924)	−

A schedule of the expected reclassification to profit or loss of the balance of losses recognized in other comprehensive income in the shareholders’ equity as of December 31, 2013 is set out below:

Period	2014	2015	2016	2017	2018	2019	2020	Total
Expected reclassification	(820)	(852)	(1,031)	(1,101)	(936)	(834)	(350)	(5,924)

ii) 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. The Company does not intend to settle these contracts before the maturity. The relationship between the derivative and the loan qualify as cash flow hedge and hedge accounting is applied.

b)Notional value, fair value and guarantees of derivative financial instruments

	Notional value (in millions)		Fair Value
Statement of financial position	2013	2012	2013	2012
Cross Currency Swap (Maturity in 2016)			11	76
Long position (JPY) - 2.15% p.a.	JPY 35,000	JPY 35,000	353	434
Short position (USD) - 5.69% p.a.	USD 298	USD 298	(342)	(358)
U.S. dollar forward			(1)	0.5
U.S. dollar forward (short position)	USD 17	USD 1,077	(1)	0.5
Total recognized in other current assets and liabilities			10	76.5

Finance income and shareholders' equity	2013	2012	2011
Gain /(loss) recognized in profit or loss for the period	(39)	41	15
Gain/ (loss) recognized in other comprehensive income - shareholders' equity	10	7	4

Margin is not required for the operations the Company has entered into, related to foreign currency derivatives.

F-82

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

c)Sensitivity analysis for foreign exchange risk on financial instruments

The Company has assets and liabilities subject to foreign exchange risk. The main exposure involves the Brazilian Real, relative to the U.S. dollar. Foreign exchange risk arises on financial instruments that are denominated in a currency other than the Brazilian Real. Assets and liabilities of foreign subsidiaries, denominated in a currency other than the Brazilian Real are not included in the sensitivity analysis set out below when transacted in a currency equivalent to their respective functional currencies.

The probable scenario, computed based on external data, as well as the stressed scenarios (a 25% and a 50% change in the foreign exchange rates) are set out below:

Financial Instruments	Exposure at 12.31.2013	Risk	Probable Scenario*	Stressed Scenario (∆ of 25%)	Stressed Scenario (∆ of 50%)
Assets	2,616		42	654	1,308
Liabilities	(50,756)	Dollar	(810)	(12,689)	(25,378)
Cash flow hedge on exports	40,742		651	10,186	20,371
Forward Derivative (Net short Position)	(17)		−	(4)	(9)
	(7,415)		(117)	(1,853)	(3,708)
Liabilities	(842)	Yen	(8)	(210)	(421)
Cross-currency Swap	333		3	117	353
	(509)		(5)	(93)	(68)
Assets	3,286	Euro	(113)	821	1,643
Liabilities	(9,290)		319	(2,323)	(4,645)
	(6,004)		206	(1,502)	(3,002)
Assets	925	Pound	(24)	231	462
Liabilities	(2,662)	Sterling	70	(665)	(1,331)
	(1,737)		46	(434)	(869)
Assets	368	Peso	(14)	92	184
Liabilities	(731)		27	(183)	(365)
	(363)		13	(91)	(181)
	(16,028)		143	(3,973)	(7,828)
(*) The probable scenario was computed based on the following changes for December, 31, 2013: Real x Dollar – a 1.60% depreciation of the Real relative to the Dollar / Yen x Dollar – a 0.91% appreciation of the Yen / Dollar x Euro: a 3.43% depreciation of the Euro / Dollar x Pound Sterling: a 2.61% depreciation of the Pound Sterling / Dollar x Peso: a 3.83% depreciation of the Peso. The data were obtained from the Focus Report of the Central Bank of Brazil and from Bloomberg.

The impact of foreign exchange depreciation / appreciation does not jeopardize the liquidity of the Company in the short term due to the balance between liabilities, assets, revenues and future commitments in foreign currency, since most of its debt mature in the long term.

34.2.3.Interest rate risk management

The Company considers that exposure to interest rate risk does not cause a significant impact and therefore, preferably does not use derivative financial instruments to manage interest rate risk, except for specific situations encountered by certain companies of the Petrobras group.

F-83

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

a)Main transactions and future commitments hedged by interest rate derivatives

Swap contracts

Floating-to-fixed swap (LIBOR USD) vs. Fixed rate (USD)

The Company has an interest rate swap, in order to exchange a floating interest rate for a fixed rate, aiming at eliminating the mismatch between the cash flows of assets and liabilities from investment projects. The Company does not intend to settle the operation before the maturity date, and therefore, adopted hedge accounting for the relationship between the finance debt and the derivative.

Other positions held are set out in the table below.

b)Notional value, fair value, guarantees and sensitivity analysis for interest rate derivatives

	Notional value		Fair value
Statement of Financial Position	2013	2012	2013	2012
Swaps (maturity in 2020)
Short position	USD 440	USD 460	(20)	(42)
Swaps (maturity in 2015)			(0.6)	(1)
Long position – Euribor	EUR 10	EUR 15	−	0.5
Short position – 4.19% Fixed rate	EUR 10	EUR 15	(0.6)	(1.5)
Total recognized in other assets and liabilities			(20.6)	(43)

Finance income and shareholders' equity	2013	2012	2011
Gain / (Loss) recognized in profit or loss for the period	−	(0.5)	−
Gain/(Loss) recognized in other comprehensive income - shareholders' equity	22	(9)	(22)

Interest Rate Derivatives	Risk	Probable Scenario (*)	Stressed Scenario (∆ de 25%)	Stressed Scenario (∆ de 50%)
HEDGE (Derivative - Swap)	LIBOR decline	4	(0.4)	(1)
Debt	LIBOR increase	(4)	0.4	1
Net effect		−	−	−
(*) The probable scenario was obtained based on LIBOR futures.

Margin is not required for the operations the Company has entered into, related to interest rate derivatives.

34.3.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 and to fund its Business and Management Plan (BMP), adding value to its shareholders.

The planned investments will be mainly financed by funds generated internally, debt issuance in the international capital markets, loan agreements with commercial banks, cash provided by asset disposals (divesting), among other sources, assuming that no new shares will be issued.

F-84

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Petrobras has determined the upper limits of 2.5 times net debt to adjusted EBITDA ratio and 35% financial leverage ratio (net debt to net total capitalization) in order to maintain a strong financial situation and considering oil product prices in Brazil converging to international prices.

Net debt is calculated as total debt (short-term and long-term) less cash, cash equivalents and government bonds with maturities higher than 90 days. Adjusted EBITDA is calculated by adding back net finance income (expenses), income taxes, depreciation/amortization, share of profit of equity-accounted investments and impairment charges 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.

	2013	2012
Total debt (current and noncurrent)	114,325	96,067
Cash and cash equivalents	(15,868)	(13,520)
Government securities (maturity of more than 90 days)	(3,878)	(10,212)
Net debt	94,579	72,335
Net debt/(net debt+shareholders' equity)	39%	31%
Adjusted EBITDA	29,426	27,632
Net debt/Adjusted EBITDA ratio	3.21	2.62

Undertaking capital expenditures in the oil and gas industry is financial-capital intensive and involves long-term maturity. Thus the Company’s ratios may temporarily exceed the established upper-limits during periods in which there is no cash flow from operations of ongoing capital expenditures.

34.4.Credit risk

Petrobras is exposed to the credit risk arising from commercial transactions and from cash management, related to financial institutions and to credit exposure to customers. Credit risk is the risk that a customer or financial institution will fail to pay amounts due, relating to outstanding receivables or to financial investments, guarantees or deposits with financial institutions.

Credit risk management in Petrobras is a portion of its financial risk management, which is performed by the Company’s officers, under a corporate policy of risk management.

The credit risk management policy is part of the Company’s global risk management policy and aims at reconciling the need for minimizing exposure to credit risk and maximizing the result of commercial and financial transactions, through an efficient credit analysis process and efficient credit granting and management processes.

The Company manages credit risk by applying quantitative and qualitative parameters that are appropriate for each of the market segments in which it operates.

The Company’s commercial credit portfolio is much diversified and the credits granted are divided between clients from the domestic market and from foreign markets.

Credit granted to financial institutions is spread among the major international banks rated by the international rating agencies as Investment Grade and highly-rated Brazilian banks.

F-85

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

34.4.1.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.

Allowances for impairment of trade and other receivables have been recognized in an amount considered adequate by management to cover losses on these assets.

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 & Poors, Moody’s and Fitch. The credit quality of those financial assets, that are neither past due nor impaired, are set out below:

	2013	2012
Cash and cash equivalents
AAA	23	61
AA	7	5
A	4,959	1,942
BBB	62	76
AAA.br	9,926	10,555
AA.br	462	−
Other ratings	429	881
	15,868	13,520
Marketable securities
AAA.br	3,979	10,387
Other ratings	37	220
	4,016	10,607

34.5.Liquidity risk

The Company's liquidity risk is represented by the possibility of a shortage of funds, cash or another financial asset in order to settle its obligations on the established dates.

Liquidity risk management by the Company involves several policies, such as: Centralized cash management, in order to optimize the level of cash and cash equivalents held and reduce working capital needs; a robust minimum cash level to ensure that the need of cash for investments and short-term obligations is met, even in adverse market conditions; the use of several funding sources in the domestic and international markets, increasing the number of investors of the Company and development a strong presence in the international capital markets; along with the search for new funding sources, including new markets and financial products.

A maturity analysis of the long-term debt, including face value and interest payments is set out in the following table:

F-86

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

Maturity
2014	12,283
2015	12,998
2016	15,572
2017	12,548
2018	16,769
2019	18,555
2020 and thereafter	66,450
Balance at December 31, 2013	155,175
Balance at December 31, 2012	136,068

34.6.Financial investments (derivative financial instruments)

Operations with derivatives are, both in the domestic and foreign markets, earmarked exclusively for the exchange of indices of the assets that comprise the portfolios, and their purpose is to provide flexibility to the managers in their quest for efficiency in the management of short-term financial assets.

The market values of the derivatives held in the exclusive investment funds at December 31, 2013 are set out below:

Contract	Number of Contracts (Thousands)	Notional value	Fair value	Maturity
Future DI (Interbank Deposit)			−	2014 to 2016
Long position	4,821	187	−
Short position	(35,658)	(1,331)	−
DDI (Foreign Exchange Coupon) forward			−	2014
Long position	413	21	−
Short position	(73)	(4)	−

35.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, trade accounts receivable, short term debt and trade accounts payable are the same as their carrying values. The fair values of other long-term assets and liabilities 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-87

 

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	3,895	−	−	3,895
Foreign currency derivatives	−	10	−	10
Balance at December 31, 2013	3,895	10	−	3,905
Balance at December 31, 2012	10,463.5	76	36	10,575.5
Liabilities
Commodity derivatives	(20)	−	−	(20)
Interest derivatives	−	(20.6)	−	(20.6)
Balance at December 31, 2013	(20)	(20.6)	−	(40.6)
Balance at December 31, 2012	(62.5)	−	−	(62.5)

The estimated fair value for the Company’s long term debt as of December 31, 2013, computed based on the prevailing market rates for operations that have similar nature, maturity and risk to the contracts recognized, is set out in note 17.

36.Insurance 

The Company’s insurance policies involve acquiring insurance to cover assets that might lead to material negative impacts in the shareholders’ equity (in the case of an eventual damage), as well as risks subject to legal or contractual mandatory insurance. The remaining risks are subject to self-insurance and Petrobras intentionally assumes the entire risk by abstaining from contracting insurance. The Company assumes a significant portion of its risk, by including franchises that may reach an amount equivalent to US$ 80 in its insurance policies.

The risk assumptions adopted 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, 2013 is set out below:

Assets	Types of coverage	Amount insured
Facilities, equipment inventory and products inventory	Fire, operational risks and engineering risks	180,341
Tankers and auxiliary vessels	Hulls	3,039
Fixed platforms, floating production systems and offshore drilling units	Oil risks	33,037
Total		216,417

Petrobras does not have loss of earnings insurance or insurance related to well control, automobiles and pipeline networks in Brazil.

F-88

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

37.Subsequent events

Funding

a)Pricing of Global Notes

On January 14, 2014, Petrobras, through Petrobras Global Finance B.V. (PGF), its wholly-owned indirect subsidiary, issued 4, 7 and 11-year Global Notes denominated in Euros (€) and 20-year Global Notes denominated in Pounds Sterling (£), as set out below:

Currency	Amount	Maturity	Coupon*
Euro	€ 1,500 million	Jan/2018	2.75% p.a.
Euro	€ 750 million	Jan/2021	3.75% p.a.
Euro	€ 800 million	Jan/2025	4.75% p.a.
Pounds Sterling	£ 600 million	Jan/2034	6.625% p.a.
(*) Coupon payments begin in 2015.

The Global Notes are unsecured and unsubordinated obligations of PGF B.V., unconditionally and irrevocably guaranteed by Petrobras.

b)Banking market

On January 29, 2014, Petrobras, through its indirect subsidiary Petrobras Global Trading BV (PGT BV), signed a credit line agreement of US$ 3 billion in the banking market.

On February 14, 2014 Petrobras, through PGT BV, signed two credit line agreements of US$ 1 billion in the banking market.

F-89

 

Petróleo Brasileiro S.A. – Petrobras

Notes to the financial statements

(Expressed in millions of US Dollars, unless otherwise indicated)

38.Information Related to Guaranteed Securities Issued by Subsidiaries

38.1.Petrobras Global Finance B.V. (PGF)

Petróleo Brasileiro S.A. - Petrobras has fully and unconditionally guaranteed 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.

38.2.Petrobras International Finance Company – PifCo

A partial spin-off of certain assets and liabilities of Petrobras International Finance Company S.A. (PifCo), a wholly -owned subsidiary of Petrobras, with the subsequent merger of the spun-off portion into Petrobras was approved for immediate implementation by the Shareholders’ Extraordinary General Meeting held by Petróleo Brasileiro S.A. - Petrobras on December 16, 2013. The transaction resulted in the transfer of the assets and liabilities related to PifCo’s commercial activities to Petrobras. After the spin-off, PifCo became a 100-percent-owned finance subsidiary of Petrobras. There are no significant restrictions on the ability of Petrobras to obtain funds from PifCo.

PifCo’s remaining assets and liabilities related to capital-raising activities and loan transactions with companies in the Petrobras Group, including various series of notes issued by PifCo and guaranteed by Petrobras, will subsequently be merged into Petrobras Global Finance B.V. – PGF, resulting in the dissolution of PifCo. That merger will not affect the guarantees and commitments undertaken by Petrobras regarding the bonds previously issued by PifCo, and those bonds will continue to be fully and unconditionally guaranteed by Petrobras. As an initial step for the merger, PGF acquired all of PifCo’s outstanding shares on February 12, 2014.

F-90

 

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 adoption of the SEC rules seeking to modernize the supplemental oil and gas disclosures and the FASB’s issuance of the Accounting Standards Update nº 2011-03, “Oil and Gas Reserve Estimation and Disclosure”, generated no material impact on the Company’s consolidated financial statements other than additional disclosures.

The international geographic area includes activities in South America, which includes Argentina, Colombia, Ecuador, Peru, Uruguay and Venezuela; North America, which includes Mexico and the United States of America; Africa, which includes Angola, Libya, Tanzania, and Others, which includes Portugal and Turkey. The equity investments are composed 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-91 

 

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, 2013
Unproved oil and gas properties	21,261	826	685	22	−	1,533	22,794	−
Proved oil and gas properties	71,638	2,410	5,907	−	−	8,318	79,956	3,972
Support Equipaments	63,833	490	(277)	(15)	4	202	64,036	1
Gross Capitalized costs	156,732	3,727	6,316	7	4	10,053	166,785	3,973
Depreciation and depletion	(44,694)	(2,045)	(948)	−	(4)	(2,997)	(47,690)	(1,455)
	112,039	1,682	5,367	7	−	7,056	119,095	2,518
Construction and installations in progress	28,421	(131)	3	−	−	(127)	28,293
Net capitalzed 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	52,012	3,950	3,572	2,467	−	9,989	62,001	491
Support Equipaments	55,729	1,488	−	26	7	1,522	57,251	−
Gross Capitalized costs	155,996	6,143	5,213	3,994	32	15,382	171,378	491
Depreciation and depletion	(43,277)	(3,013)	(625)	(1,415)	(3)	(5,057)	(48,333)	(170)
	112,719	3,130	4,588	2,579	29	10,326	123,045	321
Construction and installations in progress	27,314	11	2	−	−	13	27,327	−
Net capitalzed costs	140,033	3,141	4,590	2,579	29	10,339	150,372	321
December 31, 2011
Unproved oil and gas properties	51,773	523	1,898	593	36	3,050	54,823	−
Proved oil and gas properties	43,940	3,915	2,141	3,235	−	9,291	53,231	575
Support Equipaments	51,509	1,119	24	(24)	2	1,121	52,630	1
Gross Capitalized costs	147,222	5,557	4,063	3,804	38	13,462	160,684	576
Depreciation and depletion	(39,518)	(2,937)	(454)	(1,316)	(1)	(4,708)	(44,226)	(198)
	107,704	2,620	3,609	2,488	37	8,754	116,458	378
Construction and installations in progress	23,640	286	−	90	−	376	24,016	−
Net capitalzed costs	131,344	2,906	3,609	2,578	37	9,130	140,474	378

F-92

 

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, 2013
Acquisition of properties
Proved	−	17	973	−	−	990	990	−
Unproved	−	−	−	−	−	−	−	−
Exploration costs	9,605	183	397	1	1	582	10,187	−
Development costs	16,732	656	165	282	2	1,105	17,837	237
Total	26,337	856	1,535	283	3	2,677	29,014	237
December 31, 2012
Acquisition of properties
Proved	−	118	498	−	−	617	617	−
Unproved	−	−	−	−	−	−	−	−
Exploration costs	5,670	282	601	86	1	970	6,640	−
Development costs	16,217	759	538	285	60	1,642	17,859	19
Total	21,887	1,160	1,638	371	60	3,229	25,116	19
December 31, 2011
Acquisition of properties
Proved	−	16	−	−	36	52	52	3
Unproved	4	194	344	15	−	553	557	−
Exploration costs	5,643	316	160	322	20	818	6,461	1
Development costs	14,370	437	98	−	−	535	14,905	58
Total	20,017	963	602	337	56	1,958	21,975	62

(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, 2013, 2012 and 2011 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-93

 

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, 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	−
Results 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)
December 31, 2011
Net operation revenues:
Sales to third parties	516	1,018	8	290	−	1,316	1,832	289
Intersegment	73,601	1,553	108	2,123	−	3,784	77,385	7
	74,117	2,571	116	2,413	−	5,100	79,217	296
Production costs	(26,755)	(1,198)	(31)	(134)	−	(1,363)	(28,118)	(142)
Exploration expenses	(2,182)	(224)	(28)	(92)	(97)	(441)	(2,623)	(1)
Depreciation, depletion and amortization	(6,358)	(408)	(53)	(263)	(1)	(725)	(7,083)	(121)
Impairment of oil and gas properties	(229)	1	−	−	−	1	(228)	(56)
Other operating expenses	(1,557)	(214)	(216)	258	(22)	(194)	(1,751)	−
Income before income tax expenses	37,036	528	(212)	2,182	(120)	2,378	39,414	(24)
Income tax expenses	(12,592)	(151)	−	(791)	−	(942)	(13,534)	4
Results of operations (excluding corporate overhead and interest costs)	24,444	377	(212)	1,391	(120)	1,436	25,880	(20)

F-94

 

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 2013, 2012 and 2011 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-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)

(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, 2010	10,379.0	209.8	10.1	124.9	344.8	7.4	10,731.2	33.5
Revisions of previous estimates	571.6	(2.5)	36.4	8.1	42.0	2.4	616.0	(1.1)
Extensions and discoveries	151.2	9.4	8.0	−	17.4	−	168.6	−
Improved Recovery	1.9	−	−	6.1	6.1	−	8.0	−
Sales of reserves	−	−	−	−	−	−	−	−
Purchases of reserves	−	−	−	−	−	−	−	−
Production for the year	(692.5)	(25.5)	(0.8)	(21.0)	(47.3)	(1.2)	(741.0)	(2.8)
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	−
Sales of reserves	−	−	−	−	−	−	−	−
Purchases of reserves	−	−	−	−	−	−	−	−
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)
Purchases of reserves	0.0	−	−	−	−	−	0.0	−
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
*Amounts transferred from consolidated entities to equity-method entities, as the Company ceased to consolidate PO&G. See note 10.2 for further details.
** Includes 105 million barrels related to assets classified as held for sale.

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)

(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, 2010	10,554.0	1,235.7	51.7	40.4	1,327.8	12.0	11,893.8	59.8
Revisions of previous estimates	993.9	(9.7)	15.2	(1.1)	4.4	3.3	1,001.6	(15.0)
Extensions and discoveries	192.3	76.3	9.1	−	85.4	−	277.7	−
Improved Recovery	0.3	−	−	−	−	−	0.3	−
Sales of reserves	−	−	−	−	−	−	−	−
Purchases of reserves	−	−	−	−	−	−	−	−
Production for the year	(673.5)	(112.7)	(4.1)	−	(116.8)	(1.9)	(792.2)	(1.3)
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)	−
Sales of reserves	−	−	−	−	−	−	−	−
Purchases of reserves	−	−	−	−	−	−	−	−
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
*Amounts transferred from consolidated entities to equity-method entities, as the Company ceased to consolidate PO&G. See note 10.2 for further details.
** Includes 363 billion cubic feet related to assets classified as held for sale.

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)

(iv) Reserve quantities information

2013

2012

2011

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

6,509.3

8.8

6,578.9

11.8

6,397.5

8.3

6,811.5

13.3

6,973.5

8.6

6,836.0

13.4

South America

86.0

−

368.4

−

96.5

−

414.1

−

106.6

−

440.9

−

North America

46.2

−

9.9

−

21.2

−

25.2

−

4.5

−

32.1

−

Africa

−

−

−

−

77.8

−

35.8

−

70.3

−

39.3

−

Others

−

−

−

−

−

−

−

−

−

−

−

−

International

132.2

−

378.3

−

195.5

−

475.1

−

181.4

−

512.3

−

Total Consolidated Entities

6,641.6

8.8

6,957.3

11.8

6,593.0

8.3

7,286.6

13.3

7,154.9

8.6

7,348.3

13.4

Nonconsolidated Entitites

Brazil

−

−

−

−

−

−

−

−

−

−

−

−

South America

12.4

−

14.9

−

12.7

−

14.6

−

17.5

−

20.2

−

North America

−

−

−

−

−

−

−

−

−

−

−

−

Africa

37.3

−

15.7

−

−

−

−

−

−

−

−

−

Others

−

−

−

−

−

−

−

−

−

−

−

−

International

49.8

−

30.5

−

12.7

−

14.6

−

17.5

−

20.2

−

Total Nonconsolidated Entities

49.8

−

30.5

−

12.7

−

14.6

−

17.5

−

20.2

−

Total Consolidated and Nonconsolidated Entities

6,691.4

8.8

6,987.8

11.8

6,605.7

8.3

7,301.2

13.3

7,172.4

8.6

7,368.5

13.4

Net proved undeveloped reserves:

Consolidated Entities

Brazil

4,149.1

−

4,712.7

−

4,141.7

−

3,533.0

−

3,437.5

−

4,231.0

−

South America

80.1

−

690.1

−

78.9

−

669.5

−

84.7

−

748.6

−

North America

77.0

−

123.1

−

52.8

−

42.5

−

49.3

−

40.1

−

Africa

−

−

−

−

62.4

−

9.8

−

47.8

−

−

−

Others

−

−

−

−

−

−

−

−

−

−

−

−

International

157.1

−

813.2

−

194.1

−

721.8

−

181.8

−

788.7

−

Total Consolidated Entities

4,306.2

−

5,525.9

−

4,335.8

−

4,254.8

−

3,619.3

−

5,019.7

−

Nonconsolidated Entitites

Brazil

−

−

−

−

−

−

−

−

−

−

−

−

South America

8.8

−

26.4

−

11.6

−

33.2

−

12.1

−

23.3

−

North America

−

−

−

−

−

−

−

−

−

−

−

−

Africa

25.9

−

4.9

−

−

−

−

−

−

−

−

−

Others

−

−

−

−

−

−

−

−

−

−

−

−

International

34.7

−

31.3

−

11.6

−

33.2

−

12.1

−

23.3

−

Total Nonconsolidated Entities

34.7

−

31.3

−

11.6

−

33.2

−

12.1

−

23.3

−

Total Consolidated and Nonconsolidated Entities

4,340.8

−

5,557.2

−

4,347.4

−

4,288.0

−

3,631.4

−

5,043.0

−

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)

(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-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)

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
At 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
At 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
At december 31, 2011
Future cash inflows	1,099,570	17,606	4,839	13,064	35,509	1,135,079	2,273
Future production costs	(432,615)	(7,911)	(1,485)	(2,714)	(12,110)	(444,725)	(1,205)
Future development costs	(62,488)	(1,923)	(1,349)	(2,618)	(5,890)	(68,378)	(59)
Future income tax expenses	(209,065)	(2,321)	−	(2,753)	(5,074)	(214,139)	(341)
Undiscounted future net cash flows	395,402	5,451	2,005	4,979	12,435	407,837	668
10 percent midyear annual discount for timing of estimated cash flows*	(203,006)	(2,006)	(871)	(1,514)	(4,391)	(207,397)	(223)
Standardized measure of discounted future net cash flows	192,396	3,445	1,134	3,465	8,044	200,440	445
*Semiannual capitalization
** Includes the amount of US$ 1,758 related to assets classified as held for sale in 2013.

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)

(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, 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. See note 10.2 for further details.
** Includes the amount of US$ 1,758 related to assets classified as held for sale.
*** Development costs related to oil and gas producing properties.

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)

(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, 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	60	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)	(60)	(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
* Development costs related to oil and gas producing properties.

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)

(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	International	Total	Total
Balance at January 1, 2011	124,274	3,714	230	3,062	7,006	131,280	324
Sales and transfers of oil and gas, net of production cost	(45,745)	(1,076)	(82)	(2,037)	(3,195)	(48,940)	(70)
Development cost incurred*	13,943	437	98	−	535	14,478	44
Net change due to purchases and sales of minerals in place	−	−	−	−	−	−	−
Net change due to extensions, discoveries and improved recovery less related costs	4,892	212	307	377	896	5,788	−
Revisions of previous quantity estimates	19,483	44	1,071	570	1,685	21,168	(32)
Net change in prices, transfer prices and in production costs	114,630	661	49	2,735	3,445	118,075	133
Changes in estimated future development costs	(15,984)	(441)	(517)	(120)	(1,078)	(17,062)	(30)
Accretion of discount	12,427	476	23	294	793	13,220	54
Net change in income taxes	(35,524)	(48)	−	(982)	(1,030)	(36,554)	(6)
Timing	−	(70)	26	−	(44)	(44)	−
Other - unspecified	−	(463)	(72)	(434)	(969)	(969)	28
Balance at December 31,2011	192,396	3,446	1,133	3,465	8,044	200,440	445
* Development costs related to oil and gas producing properties.

F-103