As filed with the Securities and Exchange Commission on May 15, 2015
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 20-F
ANNUAL REPORT
PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
for the fiscal year ended December 31, 2014
Commission File Number 001-15106 Petróleo Brasileiro S.A.—Petrobras (Exact name of registrant as specified in its charter) | |
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Brazilian Petroleum Corporation—Petrobras (Translation of registrant’s name into English) | |
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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) Chief Financial Officer and Chief Investor Relations Officer (Name, telephone, e-mail and/or facsimile number and address of company contact person) |
Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of each class: | Name of each exchange on which registered: |
Petrobras Common Shares, without par value* | New York Stock Exchange* |
Petrobras American Depositary Shares, or ADSs (evidenced by American Depositary Receipts, or ADRs), each representing two Common Shares | New York Stock Exchange |
Petrobras Preferred Shares, without par value* | New York Stock Exchange* |
Petrobras American Depositary Shares (as evidenced by American Depositary Receipts), each representing two Preferred Shares | New York Stock Exchange |
6.125% Global Notes due 2016, issued by PGF (successor to PifCo) | New York Stock Exchange |
3.875% Global Notes due 2016, issued by PGF (successor to PifCo) | New York Stock Exchange |
3.500% Global Notes due 2017, issued by PGF (successor to PifCo) | New York Stock Exchange |
5.875% Global Notes due 2018, issued by PGF (successor to PifCo) | New York Stock Exchange |
7.875% Global Notes due 2019, issued by PGF (successor to PifCo) | New York Stock Exchange |
5.750% Global Notes due 2020, issued by PGF (successor to PifCo) | New York Stock Exchange |
5.375% Global Notes due 2021, issued by PGF (successor to PifCo) | New York Stock Exchange |
6.875% Global Notes due 2040, issued by PGF (successor to PifCo) | New York Stock Exchange |
6.750% Global Notes due 2041, issued by PGF (successor to PifCo) | New York Stock Exchange |
2.000% Global Notes due 2016, issued by PGF | New York Stock Exchange |
3.000% Global Notes due 2019, issued by PGF | New York Stock Exchange |
4.375% Global Notes due 2023, issued by PGF | New York Stock Exchange |
5.625% Global Notes due 2043, issued by PGF | New York Stock Exchange |
Floating Rate Global Notes due 2016, issued by PGF | New York Stock Exchange |
Floating Rate Global Notes due 2019, issued by PGF | New York Stock Exchange |
3.250% Global Notes due 2017, issued by PGF | New York Stock Exchange |
4.875% Global Notes due 2020, issued by PGF | New York Stock Exchange |
6.250% Global Notes due 2024, issued by PGF | New York Stock Exchange |
7.250% Global Notes due 2044, issued by PGF | New York Stock Exchange |
Floating Rate Global Notes due 2017, issued by PGF | New York Stock Exchange |
Floating Rate Global Notes due 2020, issued by PGF | New York Stock Exchange |
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* Not for trading, but only in connection with the registration of American Depositary Shares pursuant to the requirements of the New York Stock Exchange.
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
The number of outstanding shares of each class of stock as of December 31, 2014 was:
7,442,454,142 Petrobras Common Shares, without par value
5,602,042,788 Petrobras Preferred Shares, without par value
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.
YesR 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£ NoR
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.
YesR 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).
YesR 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 BoardR 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£ NoR
TABLE OF CONTENTS
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Management’s Discussion and Analysis of Financial Condition and Results of Operations | ||
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TABLE OF CONTENTS (cont.)
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The filing of this annual report for 2014 was delayed because we required additional time to complete disclosures in this annual report related to the write-off described below and to finalize disclosures in this annual report to describe material weaknesses in our internal control over financial reporting. Those material weaknesses are described in Item 15, Controls and Procedures.
In the third quarter of 2014, we wrote off U.S.$2,527 million of capitalized costs representing amounts that Petrobras overpaid for the acquisition of property, plant and equipment in prior years.
In 2009, the Brazilian federal police began an investigation called “Lava Jato” (Car Wash) aimed at criminal organizations engaged in money laundering in several Brazilian states. The Lava Jato investigation is extremely broad and involves numerous investigations into several criminal practices focusing on crimes committed by individuals in different parts of Brazil and sectors of the Brazilian economy.
Over the course of 2014, the Brazilian Federal Prosecutor’s Office focused part of its investigation on irregularities involving Petrobras’s contractors and suppliers and uncovered a broad payment scheme that involved a wide range of participants. According to testimony from Brazilian criminal investigations that became available beginning in October 2014, former senior Petrobras personnel conspired with contractors, suppliers and others from 2004 through April 2012 to establish and implement an illegal cartel that systematically overcharged Petrobras in connection with the acquisition of property, plant and equipment. Two former Petrobras executive officers (diretores) and one former executive manager were involved in this payment scheme, none of whom has been affiliated with us since April 2012; they are referred to in this annual report as the “former Petrobras personnel.” The overpayments were used to fund improper payments to political parties, elected officials or other public officials, individual contractor personnel, the former Petrobras personnel and other individuals involved in the payment scheme. We did not make the improper payments, which were made by the contractors and suppliers and by intermediaries acting on behalf of the contractors and suppliers.
We believe that under IAS 16, the amounts we overpaid pursuant to this payment scheme should not have been included in the historical costs of our property, plant and equipment. However, we cannot specifically identify either the individual contractual payments that include overcharges or the reporting periods in which overpayments occurred. As a result, we developed a methodology to estimate the aggregate amount that we overpaid under the payment scheme, in order to determine the amount of the write-off representing the overstatement of our property, plant and equipment resulting from overpayments used to fund improper payments. The circumstances and the methodology are described in this annual report.
The following sections of this annual report contain disclosures related to the Lava Jato investigation and the methodology adopted to address the overpayments:
· Item 3, Risk Factors, contains risks related to the estimation methodology used to determine the impact of the overpayments, the ongoing regulatory investigations, the pending civil litigation in the US, and material weaknesses in internal control over financial reporting;
· Item 4, Information on the Company, contains information regarding affected property, plant and equipment;
· Item 5, Operating and Financial Review and Prospects, contains a description of the charge for the overpayments, and a discussion of the estimation methodology in the Critical Accounting Estimates;
· Item 6, Directors, Senior Management and Employees, contains a description of the new board members, senior management, and the special committee serving as a reporting line for our internal investigations;
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· Item 8, Financial Information, contains a description of the ongoing legal proceedings involving us, and a description of certain of our internal commissions established to evaluate past transactions;
· Item 15, Controls and Procedures, contains a discussion of the implications for effectiveness of internal control over financial reporting, and for effectiveness of disclosure controls and procedures; and
· Item 18, Financial Statements, Note 3, The Lava Jato (Car Wash) Operation, and its effects on the Company, contains a description of the Lava Jato investigation, a description of the estimation methodology, a tabular analysis of the impact of the overpayments and a description of related civil litigation.
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This annual report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act, that are not based on historical facts and are not assurances of future results. The forward-looking statements contained in this annual report, which address our expected business and financial performance, among other matters, contain words such as “believe,” “expect,” “estimate,” “anticipate,” “intend,” “plan,” “aim,” “will,” “may,” “should,” “could,” “would,” “likely,” “potential” and similar expressions.
Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date on which they are made. There is no assurance that the expected events, trends or results will actually occur.
We have made forward-looking statements that address, among other things:
· our marketing and expansion strategy;
· our exploration and production activities, including drilling;
· our activities related to refining, import, export, transportation of oil, natural gas and oil products, petrochemicals, power generation, biofuels and other sources of renewable energy;
· our projected and targeted capital expenditures and other costs, commitments and revenues;
· our liquidity and sources of funding;
· our pricing strategy and development of additional revenue sources; and
· the impact, including cost, of acquisitions and divestments.
Our forward-looking statements are not guarantees of future performance and are subject to assumptions that may prove incorrect and to risks and uncertainties that are difficult to predict. Our actual results could differ materially from those expressed or forecast in any forward-looking statements as a result of a variety of assumptions and factors. These factors include, but are not limited to, the following:
· our ability to obtain financing;
· general economic and business conditions, including crude oil and other commodity prices, refining margins and prevailing exchange rates;
· global economic conditions;
· our ability to find, acquire or gain access to additional reserves and to develop our current reserves successfully;
· uncertainties inherent in making estimates of our oil and gas reserves, including recently discovered oil and gas reserves;
· competition;
· technical difficulties in the operation of our equipment and the provision of our services;
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· changes in, or failure to comply with, laws or regulations, including with respect to fraudulent activity, corruption and bribery;
· receipt of governmental approvals and licenses;
· international and Brazilian political, economic and social developments;
· natural disasters, accidents, military operations, acts of sabotage, wars or embargoes;
· the cost and availability of adequate insurance coverage;
· the outcome of ongoing corruption investigations and any new facts or information that may arise in relation to the Lava Jato investigation;
· the effectiveness of our risk management policies and procedures, including operational risk; and
· litigation, such as class actions or enforcement or other proceedings brought by governmental and regulatory agencies.
For additional information on factors that could cause our actual results to differ from expectations reflected in forward-looking statements, see “Risk Factors” in this annual report.
All forward-looking statements attributed to us or a person acting on our behalf are qualified in their entirety by this cautionary statement. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information or future events or for any other reason.
The crude oil and natural gas reserve data presented or described in this annual report are only estimates, and our actual production, revenues and expenditures with respect to our reserves may materially differ from these estimates.
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GLOSSARY OF PETROLEUM INDUSTRY TERMS
Unless the context indicates otherwise, the following terms have the meanings shown below:
ANEEL | TheAgência Nacional de Energia Elétrica(National Electrical Energy Agency), or ANEEL, is the federal agency that regulates the electricity industry in Brazil. |
ANP | TheAgência 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 andrenewable fuels industryin Brazil. |
API | Standard measure of oil density developed by the American Petroleum Institute. |
Assignment Agreement | An agreement under which the Brazilian federal government assigned to us the right to explore and produce oil, natural gas and other fluid hydrocarbons in specified pre-salt areas in Brazil. See Item 10. “Additional Information—Material Contracts—Assignment Agreement.” Also referred to as the “Transfer of Rights Agreement.” |
Barrels | Standard measure of crude oil volume. |
BNDES | TheBanco Nacional de Desenvolvimento Econômico e Social (the Brazilian Development Bank). |
BSR | Buoyancy supported riser. |
CGDU | TheControladoria Geral da União (General Federal Inspector’s Office), or CGDU, is an advisory body of the Brazilian Presidency, responsible for assisting in matters related to the protection of federal public property (patrimônio público) and the improvement of transparency in the Brazilian executive branch, through internal control activities, public audits, and the prevention and combat of corruption, among others. |
Condensate | Light hydrocarbon substances produced with natural gas, which condense into liquid at normal temperature and pressure. |
CMN | TheConselho Monetário Nacional (National Monetary Council), or CMN, is the highest authority of the Brazilian financial system, responsible for the formulation of the Brazilian currency and credit policy. |
CNPE | TheConselho 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(BrazilianSecurities and Exchange Commission), or CVM. |
Deep water | Between 300 and 1,500 meters (984 and 4,921 feet) deep. |
Distillation | A process by which liquids are separated or refined by vaporization followed by condensation. |
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DoJ | The U.S. Department of Justice. |
EWT | Extended well test. |
Exploration area | A region in Brazil under a regulatory contract without a known hydrocarbon accumulation or with a hydrocarbon accumulation that has not yet been declared commercial. |
FPSO | Floating production, storage and offloading unit. |
Heavy (crude) oil | Crude oil with API density less than or equal to 22°. |
Intermediate (crude) oil | Crude oil with API density higher than 22° and less than or equal to 31°. |
Light (crude) oil | Crude oil with API density higher than 31°. |
LNG | Liquefied natural gas. |
LPG | Liquefied petroleum gas, which is a mixture of saturated and unsaturated hydrocarbons, with up to five carbon atoms, used as domestic fuel. |
MME | TheMinistério de Minas e Energia(Ministry of Mines and Energy) of Brazil. |
MPBM | The Ministériodo Planejamento, Orçamento e Gestão (Ministry of Planning, Budget and Management) of Brazil. |
NGLs | Natural gas liquids, which are light hydrocarbon substances produced with natural gas, which condense into liquid at normal temperature and pressure. |
Oil | Crude oil, including NGLs and condensates. |
PGF | Petrobras Global Finance B.V. |
PLSV | Pipe laying support vessel. |
Post-salt reservoir | A geological formation containing oil or natural gas deposits located above a salt layer. |
Pre-salt reservoir | A geological formation containing oil or natural gas deposits located beneath a salt layer. |
Proved reserves | Consistent with the definitions in Rule 4-10(a) of Regulation S-X, proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to December 31, 2014, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced or we must be reasonably certain that we will commence the project within a reasonable time. |
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| Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. |
Proved developed reserves | Reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well. |
Proved undeveloped reserves | Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Proved undeveloped reserves do not include reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty. |
SPE | The Society of Petroleum Engineers. |
SS | Semi-submersible unit. |
Synthetic oil andsynthetic gas | A mixture of hydrocarbons derived by upgrading (i.e., chemically altering) natural bitumen from oil sands, kerogen from oil shales, or processing of other substances such as natural gas or coal. Synthetic oil may contain sulfur or other non-hydrocarbon compounds and has many similarities to crude oil. |
TCU | TheTribunal de Contas da União (Federal Auditor’s Office), or TCU, is an advisory body of the Brazilian Congress, responsible for assisting it in matters related to the supervision of the Brazilian executive branch with respect to accounting, finance, budget, operational and public property (patrimônio público) matters. |
TLWP | Tension Leg Wellhead Platform. |
Total depth | Total depth of a well, including vertical distance through water and below the mudline. |
Ultra-deep water | Over 1,500 meters (4,921 feet) deep. |
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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 |
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1 meter | = | 3.2808 feet |
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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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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$ | Brazilianreais |
t | Metric ton |
Tcf | Trillion cubic feet |
U.S.$ | United States dollars |
/d | Per day |
/y | Per year |
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PRESENTATION OF FINANCIAL AND OTHER INFORMATION
This is the annual report of Petróleo Brasileiro S.A.—Petrobras, or Petrobras. Unless the context otherwise requires, the terms “Petrobras,” “we,” “us,” and “our” refer to Petróleo Brasileiro S.A.—Petrobras and its consolidated subsidiaries, joint operations and structured entities.
We currently issue notes in the international capital markets through our wholly-owned finance subsidiary Petrobras Global Finance B.V., or PGF, a private company with limited liability incorporated under the law of The Netherlands. We fully and unconditionally guarantee the notes issued by PGF. In the past, we used our former wholly-owned subsidiary, Petrobras International Finance Company S.A., or PifCo, as a vehicle to issue notes that we fully and unconditionally guaranteed. On December 29, 2014, PifCo merged into PGF, and PGF assumed PifCo’s obligations under all outstanding notes originally issued by PifCo (together with the notes issued by PGF, the “PGF notes”), which continue to benefit from our full and unconditional guarantee. PGF is not required to file periodic reports with the U.S. Securities and Exchange Commission, or SEC. See Note 36 to our audited consolidated financial statements.
In this annual report, references to “real,” “reais” or “R$” are to Brazilianreais and references to “U.S. dollars” or “U.S.$” are to United States dollars. Certain figures included in this annual report have been subject to rounding adjustments; accordingly, figures shown as totals in certain tables may not be an exact arithmetic aggregation of the figures that precede them.
Our audited consolidated financial statements as of and for each of the three years ended December 31, 2014, 2013 and 2012 and the accompanying notes contained in this annual report have been presented in U.S. dollars and prepared in accordance with International Financial Reporting Standards, or IFRS, issued by the International Accounting Standards Board, or IASB. See Item 5. “Operating and Financial Review and Prospects” and Note 2 to our audited consolidated financial statements. Petrobras applies IFRS in its statutory financial statements prepared in accordance with Brazilian Corporate Law and regulations promulgated by the CVM.
Our IFRS financial statements filed with the CVM are presented usingreais,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 thereal. 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 thereal amounts in accordance with the criteria set forth in IAS 21 – “The effects of changes in foreign exchange rates.” Based on IAS 21, we have translated all assets and liabilities into U.S. dollars at the exchange rate as of the date of the balance sheet and all accounts in the statement of income and statement of cash flows at the average rates prevailing during the corresponding year.
Unless the context otherwise indicates:
· data contained in this annual report regarding capital expenditures, investments and other expenditures during the corresponding year that were not derived from the audited consolidated financial statements have been translated fromreais at the average rates prevailing during such corresponding year;
· historical data contained in this annual report regarding balances of investments, commitments or other related costs that were not derived from the audited consolidated financial statements have been translated fromreais at the period-end exchange rate; and
· estimated future capital expenditures and investments are based on the most recently budgeted amounts, which may not have been adjusted to reflect all factors that could affect such amounts.
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Our management is currently working on our updated business and management plan, which we expect to release soon. Until we release our updated business and management plan, and for purposes of this annual report, all of our projections and forward-looking amounts have been projected on a constant basis and have been translated fromreaisusing an average exchange rate for 2015 of R$3.10 to U.S.$1.00. In addition, future calculations involving an assumed price of crude oil have been calculated using a Brent crude oil price of U.S.$60 per barrel for 2015, adjusted for our quality and location differences, unless otherwise stated.
PRESENTATION OF INFORMATION CONCERNING RESERVES
We apply the SEC rules for estimating and disclosing oil and gas reserve quantities included in this annual report. In accordance with those rules, we estimate reserve volumes using the average prices calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, except for reserves in certain fields for which volumes have been estimated using gas prices as set forth in our contractual arrangements for the sale of gas. Reserve volumes of non-traditional reserves, such as synthetic oil and gas, are also included in this annual report in accordance with SEC rules. In addition, the rules also utilize a reliable technology definition that permits reserves to be added based on field-tested technologies.
DeGolyer and MacNaughton (D&M) used our reserve estimates to conduct a reserves audit of 96.5% of our net proved crude oil, condensate and natural gas reserves as of December 31, 2014 in certain properties we own in Brazil. In addition, D&M used its own estimates of our reserves to conduct a reserves evaluation of 100% of the net proved crude oil, condensate, NGL and natural gas reserves as of December 31, 2014 from the properties we operate in Argentina. Furthermore, D&M used our reserve estimates to conduct a reserves audit of 100% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2014 in properties we operate in the United States. The reserve estimates were prepared in accordance with the reserves definitions in Rule 4-10(a) of Regulation S-X. All reserve estimates involve some degree of uncertainty. See Item 3. “Key Information—Risk Factors—Risks Relating to Our Operations” for a description of the risks relating to our reserves and our reserve estimates.
On January 16, 2015, we filed proved reserve estimates for Brazil with the ANP, in accordance with Brazilian rules and regulations, totaling net volumes of 13.7 bnbbl of crude oil and condensate and 15.0 tcf of natural gas. The reserve estimates filed with the ANP were approximately 27.3% higher than those provided herein in terms of oil equivalent. This difference is due to: (i) the ANP requirement to estimate proved reserves through the technical-economical abandonment of production wells, as opposed to limiting reserve estimates to the life of the concession contracts as required by Rule 4-10 of Regulation S-X; and (ii) different technical criteria for booking proved reserves, including the use of future oil prices projected by Petrobras as opposed to the SEC requirement that the 12-month average price be used to determine the economic producibility of the reserves.
We also file reserve estimates from our international operations with various governmental agencies under the guidelines of the SPE. The aggregate reserve estimates from our international operations, under SPE guidelines, amounted to 0.3 bnbbl of crude oil, condensate and NGL and 1.0 tcf of natural gas as of December 31, 2014, which is approximately 2.6% higher than the reserve estimates calculated under Regulation S-X, as provided herein. This difference is due to different technical criteria for booking proved reserves, including the use of future oil prices projected by Petrobras as opposed to the SEC requirement that the 12-month average price be used to determine the economic producibility of the reserves.
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Item 1. Identity of Directors, Senior Management and Advisers
Not applicable.
Item 2. Offer Statistics and Expected Timetable
Not applicable.
This section contains selected consolidated financial data presented in U.S. dollars and prepared in accordance with IFRS as of and for each of the five years ended December 31, 2014, 2013, 2012, 2011 and 2010, derived from our audited consolidated financial statements, which were audited by PricewaterhouseCoopers Auditores Independentes–PwC for the years ended December 31, 2014, 2013 and 2012 and KPMG Auditores Independentes for the years ended December 31, 2011 and 2010.
The information below should be read in conjunction with, and is qualified in its entirety by reference to, our audited consolidated financial statements and the accompanying notes and Item 5. “Operating and Financial Review and Prospects.”
BALANCE SHEET DATA
IFRS Summary Financial Data
| As of December 31, | ||||
| 2014 | 2013 | 2012 | 2011 | 2010 |
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Assets: |
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Cash and cash equivalents | 16,655 | 15,868 | 13,520 | 19,057 | 17,655 |
Marketable securities | 9,323 | 3,885 | 10,431 | 8,961 | 15,612 |
Trade and other receivables, net | 7,969 | 9,670 | 11,099 | 11,756 | 10,845 |
Inventories | 11,466 | 14,225 | 14,552 | 15,165 | 11,808 |
Assets classified as held for sale | 5 | 2,407 | 143 | − | − |
Other current assets | 5,414 | 6,600 | 8,049 | 9,653 | 7,639 |
Long-term receivables | 18,863 | 18,782 | 18,856 | 18,962 | 22,637 |
Investments | 5,753 | 6,666 | 6,106 | 6,530 | 6,957 |
Property, plant and equipment | 218,730 | 227,901 | 204,901 | 182,918 | 168,104 |
Intangible assets | 4,509 | 15,419 | 39,739 | 43,412 | 48,937 |
Total assets | 298,687 | 321,423 | 327,396 | 316,414 | 310,194 |
Liabilities and shareholders’ equity: |
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Current liabilities | 31,118 | 35,226 | 34,070 | 36,364 | 33,577 |
Non-current liabilities(1) | 30,373 | 30,839 | 42,976 | 34,744 | 30,251 |
Non-current finance debt(2) | 120,218 | 106,235 | 88,484 | 72,718 | 60,417 |
Total liabilities | 181,709 | 172,300 | 165,530 | 143,826 | 124,245 |
Shareholders’ equity |
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Share capital (net of share issuance costs) | 107,101 | 107,092 | 107,083 | 107,076 | 107,062 |
Reserves and other comprehensive income (deficit)(3) | 9,171 | 41,435 | 53,631 | 64,240 | 77,048 |
Shareholders' equity attributable to the shareholders of Petrobras | 116,272 | 148,527 | 160,714 | 171,316 | 184,110 |
Non-controlling interests | 706 | 596 | 1,152 | 1,272 | 1,839 |
Total equity | 116,978 | 149,123 | 161,866 | 172,588 | 185,949 |
Total liabilities and shareholders' equity | 298,687 | 321,423 | 327,396 | 316,414 | 310,194 |
__________________ (1) Excludes non-current finance debt. | |||||
(2) Excludes current portion offinancedebt. | |||||
(3) Change in interest in subsidiaries, profit reserve and accumulated other comprehensive income (deficit). | |||||
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INCOME STATEMENT DATA
IFRS Summary Financial Data
| For the Year Ended December 31, | ||||
| 2014(1) | 2013 | 2012 | 2011 | 2010 |
| (U.S.$ million, except for share and per share data) | ||||
Sales revenues | 143,657 | 141,462 | 144,103 | 145,915 | 120,452 |
Net income (loss) before finance income (expense), share of earnings in equity-accounted investments, profit sharing and income taxes | (6,963) | 16,214 | 16,900 | 27,285 | 26,372 |
Net income (loss) attributable to the shareholders of Petrobras | (7,367) | 11,094 | 11,034 | 20,121 | 20,055 |
Weighted average number of shares outstanding: |
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Common | 7,442,454,142 | 7,442,454,142 | 7,442,454,142 | 7,442,454,142 | 5,683,061,430 |
Preferred | 5,602,042,788 | 5,602,042,788 | 5,602,042,788 | 5,602,042,788 | 4,189,764,635 |
Net income (loss) before financial results, profit sharing and income taxes per: |
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Common and Preferred shares | (0.53) | 1.24 | 1.30 | 2.09 | 2.67 |
Common and Preferred ADS | (1.06) | 2.48 | 2.60 | 4.18 | 5.34 |
Basic and diluted earnings (loss) per: |
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Common and Preferred shares | (0.56) | 0.85 | 0.85 | 1.54 | 2.03 |
Common and Preferred ADS | (1.12) | 1.70 | 1.70 | 3.08 | 4.06 |
Cash dividends per (2): |
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Common shares | − | 0.22 | 0.24 | 0.53 | 0.70 |
Preferred shares | − | 0.41 | 0.48 | 0.53 | 0.70 |
Common ADS | − | 0.44 | 0.48 | 1.06 | 1.40 |
Preferred ADS | − | 0.82 | 0.96 | 1.06 | 1.40 |
____________________ (1) In 2014, we wrote-off U.S.$2,527 million of incorrectly capitalized overpayments and recognized impairment losses of U.S.$16,823 million. See Notes 3 and 14 to our audited consolidated financial statements, respectively, for further information. (2) Pre-tax interest on capital and/or dividends proposed for the year. Amounts were translated from the original amounts inreais using the balance sheet date exchange rate. | |||||
15
Risks Relating to Our Operations
Maintaining our long-term growth objectives for oil production depends on our ability to successfully develop our reserves.
Our ability to maintain our long-term growth objectives for oil production is highly dependent upon our ability to successfully develop our existing reserves and, in the long term, to obtain additional reserves. The development of the sizable reservoirs in deep and ultra-deep waters, including the pre-salt reservoirs that have been granted to us by the Brazilian federal government, has demanded and will continue to demand significant capital investments. A primary operational challenge, particularly for the pre-salt reservoirs, will be (i) securing the critical resources that are necessary to meet our production targets, (ii) allocating our resources to build the necessary equipment and deploy such equipment at considerable distances from the shore and (iii) securing a qualified labor force and offshore oil services to develop reservoirs of such size and magnitude in a timely manner. We cannot guarantee that we will have or will be able to obtain, in the time frame that we expect, sufficient resources necessary to exploit the reservoirs in deep and ultra-deep waters that have been licensed and granted to us, or that may be licensed to us in the future, including as a result of the enactment of the new regulatory model for the oil and gas industry in Brazil.
Our exploration activities also expose us to the inherent risks of drilling, including the risk that we may not discover commercially productive crude oil or natural gas reserves. The costs of drilling wells are often uncertain, and numerous factors beyond our control (such as unexpected drilling conditions, equipment failures or incidents, and shortages or delays in the availability of drilling rigs and the delivery of equipment) may cause drilling operations to be curtailed, delayed or cancelled. In addition, increased competition in the oil and gas sector in Brazil may increase the costs of obtaining additional acreage in bidding rounds for new concessions. We may not be able to maintain our long-term growth objectives for oil production unless we conduct successful exploration and development activities of our large reservoirs in a timely manner.
International prices of crude oil, oil products and natural gas may affect us differently than our competitors and may cause our results to differ from our competitors in periods of higher international prices.
International prices for oil and oil products are volatile and have a significant effect on us. We may not adjust our prices for products sold in Brazil when the international prices of crude oil and oil products increase, or when therealdepreciates in relation to the U.S. dollar, which could have a negative impact on our results of operations and financial condition.
The majority of our revenue is derived primarily from sales in Brazil of crude oil and oil products and, to a lesser extent, natural gas. Changes in crude oil prices typically result in changes in prices for oil products and natural gas. Historically, international prices for crude oil, oil products and natural gas have fluctuated widely as a result of many global and regional factors. Volatility and uncertainty in international prices for crude oil, oil products and natural gas may continue. For instance, on September 1, 2014, the Brent crude oil price per barrel was U.S.$101.37, while only five months later, on January 30, 2015, the Brent crude oil price per barrel was U.S.$50.77.
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Our pricing policy in Brazil seeks to align the price of oil and oil products with international prices over the long term, however we do not necessarily adjust our prices for diesel, gasoline and other products to reflect oil price volatility in the international markets or short term movements in the value of thereal. Based on the decisions of the Brazilian federal government, as our controlling shareholder, we have, and may continue to have, periods during which our product prices will not be at parity with international product prices (See “—Risks Relating to Our Relationship with the Brazilian Federal Government—The Brazilian federal government, as our controlling shareholder, may pursue certain macroeconomic and social objectives through us that may have a material adverse effect on us.”). As a result, when we are a net importer by volume of oil and oil products to meet Brazilian demand, increases in the price of crude oil and oil products in the international markets may have a negative impact on our costs of sales and margins, since the cost to acquire such oil and oil products may exceed the price at which we are able to sell these products in Brazil. A similar effect occurs when thereal depreciates in relation to the U.S. dollar, as we sell oil and oil products in Brazil inreais and international prices for crude oil and oil products are set in U.S. dollars. A depreciation of thereal increases our cost of imported oil and oil products, without a corresponding increase in our revenues unless we are able to increase the price at which we sell products in Brazil.
From the fourth quarter of 2010through the third quarter of 2014, we sold some of our oil products (such as diesel and gasoline) at prices below international prices. We may not be able to fully offset the losses in our Brazilian downstream operations during this 2010-2014 period if we are unable to benefit from the current spread between low international crude oil prices and high Brazilian domestic oil product prices for an extended period of time.
Substantial or extended declines in international crude oil prices may have a material adverse effect on our business, results of operations and financial condition, and may also affect the value of our proved reserves.
We havesubstantial liabilities and are exposed to short-term liquidity constraints, which could make it difficult for us to obtain financing for our planned investments and adversely affect our financial condition and results of operations.
In order to finance the capital expenditures needed to meet our long-term growth objectives for oil production, we have incurred a substantial amount of debt. As our cash flow from operations in recent years has not been sufficient to fund our capital expenditures, debt service and payment of dividends, our debt has significantly increased since 2010. Our total debt (including accrued interest) increased by 16% to U.S.$132,086 million as of December 31, 2014 from U.S.$114,236 million as of December 31, 2013. Our debt, net of cash, cash equivalents and marketable securities, increased by 12% to U.S.$106,108 million as of December 31, 2014 compared to U.S.$94,483 million as of December 31, 2013. 27% of our existing debt (principal), or U.S.$34.8 billion, will mature in the next three years. In order to develop our oil and natural gas reserves, maintain our ability to supply the Brazilian domestic market and amortize scheduled debt maturities, we will need to raise significant amounts of debt capital from a broad range of funding sources.
To service our debt after meeting our capital expenditure targets, we have relied upon, and may continue to rely upon, a combination of cash flows provided by our operations, drawdowns under our available credit facilities, our cashand short-term financial investments balance and the incurrence of additional indebtedness. Credit rating agencies have recently expressed concerns regarding (i) liquidity pressures and our capacity to meet our principal and interest payment obligations maturing in the short- and medium-term, (ii) our negative free cash flow in the last few years primarily resulting from our significant capital expenditures, (iii) our ability to access any source of financing in the short-term; (iv) the total size of our debt, (v) the increase of our indebtedness over the last few years and (vi) the diversion of our management’s focus from our core business in order to manage issues related to the ongoing Lava Jato investigation. On February 24, 2015, we lost our Moody’s investment grade rating for all of our credit ratings.
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If, for any reason, we are faced with continued difficulties in accessing debt financing, this could hamper our ability to achieve our long-term production targets and could impair our ability to timely meet our principal and interest payment obligations with our creditors, as our cash flow from operations is currently insufficient to fund such both planned capital expenditures and all of our debt service obligations.
Additionally, any further lowering of our credit ratings may have adverse consequences on our ability to obtain financing or may impact our cost of financing, also making it more difficult or costly to refinance maturing obligations. Our inability to obtain financing on favorable terms could have an adverse effect on our results of operations and financial condition. A further downgrade in our credit ratings may result in a less liquid market for our debt and equity securities, because certain institutions would be unable to purchase our securities, therefore reducing our investor base.
As a result of the above, we may not be able to make the capital expenditures in the amounts needed to maintain our long-term growth objectives for oil production, which may adversely affect our results of operations and financial condition.
If such constraints occur at a time when our cash flow from operations are less than the resources needed to fund our capital expenditures or to meet our principal and interest payments obligations, in order to provide additional liquidity to our operations, we could be forced to further reduce our planned capital expenditures and increase the numbers of assets to be sold under our divestment program. A reduction in our capital expenditure program or the sale of strategic assets under our divestment program could significantly affect our results of operations and financial condition.
Despite the fact that the Brazilian federal government (as our controlling shareholder) is not responsible or liable for any of our liabilities – including those derived from the bonds we issue in the international capital markets – our credit rating is sensitive to any change in the Brazilian federal government credit rating. Any lowering of the Brazilian federal government credit ratings may have additional adverse consequences on our ability to obtain financing or our cost of financing, and consequently, on our results of operations and financial condition.
We are vulnerable to increased debt service resulting from depreciation of the real in relation to the U.S. dollar and increases in prevailing market interest rates.
As of December 31, 2014, approximately 82% of our financial debt liabilities were denominated in currencies other than thereal. A substantial portion of our indebtedness is, and is expected to continue to be, denominated in or indexed to the U.S. dollar and other foreign currencies. A depreciation of therealagainst these other currencies will increase our debt service, as the amount ofreaisnecessary to pay principal and interest on foreign currency debt will increase with this depreciation. Considering the average exchange rate of each year, from 2003 to 2011, therealappreciated against U.S. dollar each year (by an average of 7% per year), except for 2009 (when it depreciated by 9%). In 2014 therealdepreciated 9.1% against the U.S. dollar, compared to depreciation of 10.4% in 2013 and depreciation of 16.7% in 2012. Throughout 2015, therealhas continued to depreciate against the U.S. dollar. Through April 30, 2015, it has depreciated by 12.7% compared to December 31, 2014.
This foreign exchange variation will have an immediate impact on our reported income, except for a portion of our obligations denominated in U.S. dollars that are subject to our hedge accounting policy. Additionally, following a devaluation of thereal, some of our operating expenses, capital expenditures, investments and import costs will increase. As most of our revenues are denominated inreais, unless we increase the prices of our products to reflect the depreciation of thereal, our cash generation relative to our capacity to service debt may decline, impacting our cash balance.
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As of December 31, 2014, approximately 50% of our total indebtedness consisted of floating rate debt. We generally do not enter into derivative contracts or similar financial instruments or make other arrangements with third parties to hedge against the risk of an increase in interest rates. Additionally, we have debt maturities that amount to U.S.$76.8 billion during the next five years, a portion of which may be refinanced by issuing new debt. To the extent that such floating rates rise, or the cost of debt increases when we refinance maturing obligations, we may incur additional expenses. The cost of any new indebtedness may also be negatively affected by the February 2015 downgrade of our credit ratings below investment grade by Moody’s and possible further downgrades.
As we refinance our existing debt in the coming years, the mix of our indebtedness may change, specifically as it relates to the ratio of fixed to floating interest rates, the ratio of short-term to long-term debt, and the currencies in which our debt is denominated or to which it is indexed. Such changes will affect the composition of our debt and may increase our debt service payments, which could have an adverse effect on our results of operations and financial condition.
We rely on key third-party suppliers and service providers to provide us with parts, components, services and critical resources that we need to operate our business and complete our major projects, which could be adversely affected by any failure or delay by such third parties in performing their obligations or any deterioration in the financial condition of such third parties.
Our ability to maintain our long-term growth objectives for oil production depends upon successful delivery of major exploration and production projects. Failure to successfully deliver such major projects, or delays in doing so, could adversely affect our results of operations and financial condition.
We rely upon various key third-party suppliers, vendors and service providers to provide us with parts, components, services and critical resources, which we need to operate and expand our business. If these key suppliers, vendors and service providers critically fail to deliver, or are delayed in delivering, equipment, service or critical resources to our major projects, we may not meet our operating targets in the time frame we expected. We may ultimately need to delay or suspend one or more of our major projects, which could have an adverse effect on our results of operations and financial condition.
We are susceptible to the risks of performance, product quality and financial condition of our key suppliers, vendors and service providers. For instance, their ability to adequately and timely provide us with parts, components, services and resources critical to our major projects may be affected if they are facing financial constrains or times of general financial stress and economic downturn. As a result of the ongoing Lava Jato investigation, a number of our Brazilian contractors and suppliers have been unable to secure financing and are currently facing liquidity and bankruptcy concerns that may affect their ability to continue as our key suppliers, vendors and service providers. Although we work closely with our key suppliers, vendors and service providers to avoid supply-related problems, there can be no assurance that we will not encounter supply disruptions in the future or that we will be able to timely replace such suppliers or service providers that are not able to meet our needs, which might adversely affect a timely and successful execution of our major projects, and consequently, our results of operations and financial condition. Currently, we are facing delays in the delivery of some key assets to meet our production targets and reach our long-term growth objectives for oil production. As a result, for instance, we have postponed the delivery of four FPSOs that had been scheduled to come on stream in 2016 (P-66, P-74, P-67 and P-65).
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In addition, we have imposed a temporary suspension on the ability of companies belonging to 24 corporate groups to participate as suppliers and contractors in future bids for new contracts and services, while we and the Brazilian authorities analyze the involvement and participation of these companies in alleged illegal conduct in connection with the Lava Jato investigation. See Note 3 to our audited consolidated financial statements for further information about the Lava Jato investigation. A number of these suppliers and contractors have historically acted as key suppliers, vendors and service providers for our major projects. There can be no assurance that these companies will be permitted to participate in our future major projects or that we will be able to replace such key suppliers, vendors and service providers with others that would be able to meet our needs, which could affect the successful and timely delivery of our major future projects, and consequently our results of operations and financial condition.
We are also subject to Brazilian local content requirements arising out of our concession agreements, the Assignment Agreement and the Libra’s Production Sharing Agreement. These requirements, along with the temporary suspension of many of our local suppliers described above, could cause delays in some of our major projects if we are unable to timely replace Brazilian suppliers or service providers that fail to perform their obligations under our contracts. Unless ANP exempts us from complying with local content requirements, as to which there is no assurance, we could face delays or fines in the execution of our current major exploration and production projects.
We are exposed to the credit risks of certain of our customers and associated risks of default. Any material nonpayment or nonperformance by some of our customers could adversely affect our cash flow, results of operations and financial condition.
Some of our customers may experience financial constrains or liquidity issues that could have a significant negative effect on their creditworthiness. Severe financial issues encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. For instance, as of December 31, 2014, certain subsidiaries of Centrais Elétricas Brasileiras S.A. – Eletrobras owed us U.S.$3.0 billion under energy supply agreements. In 2014, we recognized an allowance for impairment of trade receivables from the isolated electricity sector in the Northern region of Brazil (amounting to U.S.$1.9 billion), mostly to cover certain trade receivables due by Eletrobras’s subsidiaries. See Note 8.4 to our audited consolidated financial statements.
In addition, many of our customers finance their activities through their cash flows from operations, the incurrence of short and long term debt or the issuance of debt. Declining financial results and economic conditions in Brazil, and resulting decreased cash flows, combined with a lack of debt or equity financing for our customers may affect us, since many of our customers are Brazilian, and may have significantly reduced liquidity and limited ability to make payments or perform their obligations to us. As we have not obtained any other guarantees to minimize our customers’ credit risk, their financial problems could result in a decrease in our operating cash flows and may also reduce or curtail our customers’ future demand for our products and services, which may have an adverse effect on our results of operations and financial condition.
Exploration and production of oil in deep and ultra-deep waters involves risks.
Exploration and production of oil involves risks that are increased when carried out in deep and ultra-deep waters. The majority of our exploration and production activities are carried out in deep and ultra-deep waters, and the proportion of our deepwater activities will remain constant or increase due to the location of our pre-salt reservoirs. Our activities, particularly in deep and ultra-deep waters, present several risks, such as the risk of oil spills, explosions on platforms and in drilling operations and natural disasters. The occurrence of any of these events or other incidents could result in personal injuries, loss of life, severe environmental damage with the resulting containment, clean-up and repair expenses, equipment damage and liability in civil and administrative proceedings.
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Our insurance policies do not cover all liabilities, and insurance may not be available for all risks. There can be no assurance that incidents will not occur in the future, that insurance will adequately cover the entire scope or extent of our losses or that we will not be found liable in connection with claims arising from these and other events.
Our crude oil and natural gas reserve estimates involve some degree of uncertainty, which could adversely affect our ability to generate income.
Our proved crude oil and natural gas reserves set forth in this annual report are the estimated quantities of crude oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made) according to applicable regulations. Our proved developed crude oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties in estimating quantities of proved reserves related to prevailing crude oil and natural gas prices applicable to our production, which may lead us to make revisions to our reserve estimates. Downward revisions in our reserve estimates could lead to lower future production, which could have an adverse effect on our results of operations and financial condition.
We do not own any of the subsoil accumulations of crude oil and natural gas in Brazil.
Under Brazilian law, the Brazilian federal government owns all subsoil accumulations of crude oil and natural gas in Brazil and the concessionaire owns the oil and gas it produces from those subsoil accumulations pursuant to applicable agreements executed with the Brazilian federal government. We possess, as a concessionaire of certain oil and natural gas fields in Brazil, the exclusive right to develop the volumes of crude oil and natural gas included in our reserves pursuant to concession agreements, the Libra Production Sharing Agreement and the Assignment Agreement awarded to us by the Brazilian federal government, and except for the profit oil owed to the Brazilian federal government under the Libra Production Sharing Agreement, we own the hydrocarbons we produce under those contractual arrangements. Access to crude oil and natural gas reserves is essential to an oil and gas company’s sustained production and generation of income, and our ability to generate income would be adversely affected if the Brazilian federal government were to restrict or prevent us from exploiting these crude oil and natural gas reserves. In addition, we may be subject to fines by the ANP and our concessions, the Libra Production Sharing Agreement and the Assignment Agreement may be revoked if we do not comply with our obligations under such contractual arrangements.
The Assignment Agreement we entered into with the Brazilian federal government is a related party transaction subject to future price readjustment.
The transfer to us of oil and gas exploration and production rights related to specific pre-salt areas, subject to a maximum production of five billion boe, is governed by Law No. 12,276/2010 and by the Assignment Agreement, which is a contract between the Brazilian federal government, our controlling shareholder, and us. The negotiation of the Assignment Agreement involved significant issues, including (1) the area covered by the assignment of rights, consisting of exploratory blocks; (2) the volume, on a barrel of oil equivalent basis, that we can extract from this area; (3) the price to be paid for the assignment of rights; (4) the terms of any subsequent revision of the contract price and volume; and (5) the terms of the reallocation of volumes among the exploratory blocks assigned to us.
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The Assignment Agreement includes provisions for a subsequent revision of the contract terms, including the price we paid for the rights we acquired. The future negotiation with the Brazilian federal government will be conducted in accordance with the terms of the Assignment Agreement and will be based on a number of factors, including assumptions regarding the timing of our oil and gas production, operating and investment costs, and the value of the crude oil at prevailing international prices at the time of the declaration of commerciality of the relevant pre-salt area. At the time the Assignment Agreement was negotiated, the initial contract price paid by us was based on an assumed Brent oil crude price of approximately U.S.$80 per barrel. Once the revision process is concluded pursuant to the terms of the Assignment Agreement, if the revised contract price is higher than the initial contract price, we will either make an additional payment to the Brazilian federal government or reduce the amount of barrels of oil equivalent subject to the Assignment Agreement.
In December 2013, we began ongoing negotiations with the Brazilian federal government regarding the revision process of the Assignment Agreement. See Item 4. “Information on the Company—Exploration and Production-Santos Basin—Assignment Agreement” and Item 10. “Material contracts—Assignment Agreement” for further information. During the term of the Assignment Agreement, novel issues may arise in the implementation of the revision process and other provisions that could require further negotiations.
Beginning June 2014, CNPE Resolution No. 01/2014 authorized the Brazilian federal government to directly engage Petrobras, under production sharing agreements, to produce oil, natural gas and fluid hydrocarbons in the Assignment Agreement areas at a volume exceeding the five bnboe maximum production originally agreed to under the Assignment Agreement. However, we have not initiated negotiations of the terms of these production sharing agreements and do not have an estimate of when these agreements may be executed, nor can we assure that their terms would be favorable to us.
We are subject to numerous environmental, health and safety regulations and industry standards that are becoming more stringent and may result in increased capital and operating expenditures and decreased production.
Our activities are subject to evolving industry standards and best practices, and a wide variety of federal, state and local laws, regulations and permit requirements relating to the protection of human health, safety and the environment, both in Brazil and in other jurisdictions in which we operate. Particularly in Brazil, our oil and gas business is subject to extensive regulation by several governmental agencies, including the ANP, ANEEL,Agência Nacional de Transportes Aquaviários (Brazilian Water Transportation Agency), or ANTAQ andAgência Nacional de Transportes Terrestres (Brazilian Land Transportation Agency), or ANTT. Failure to observe or comply with these laws and regulations could result in penalties that could adversely affect our operations. In Brazil, for example, we could be exposed to administrative and criminal sanctions, including warnings, fines and closure orders for non-compliance with these environmental, health and safety regulations, which, among other things, limit or prohibit emissions or spills of toxic substances produced in connection with our operations. Waste disposal and emissions regulations may also require us to clean up or retrofit our facilities at significant costs and could result in substantial liabilities. TheInstituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis(Brazilian Institute of the Environment and Renewable Natural Resources, or IBAMA), the various Brazilian state environmental agencies and the ANP, among others, routinely inspect our facilities, and may impose fines, restrictions on operations, or other sanctions in connection with their inspections, including unexpected, temporary shutdowns and delays resulting in decreased production. In addition, we are subject to environmental laws that require us to incur significant costs to cover damage that a project may cause to the environment. These additional costs may have a negative impact on the profitability of the projects we intend to implement or may make such projects economically unfeasible.
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As environmental, health and safety regulations become more stringent with evolving industry standards, and as new laws and regulations relating to climate change, including carbon controls, become applicable to us, it is possible that our capital expenditures and investments for compliance with such laws and regulations and industry standards will increase substantially in the future. In addition, if compliance with such laws, regulations and industry standards results in significant unplanned shutdowns, there could be a material adverse effect on our production. We also cannot guarantee that we will be able to maintain or renew our licenses and permits if they are revoked or if the applicable environmental authorities oppose or delay their issuance or renewal. Increased expenditures to comply with environmental, health and safety regulations to mitigate the environmental impact of our operations or to restore the biological and geological characteristics of the areas in which we operate may result in reductions in other strategic investments. Any substantial increase in expenditures for compliance with environmental, health or safety regulations or reduction in strategic investments and significant decreases in our production from unplanned shutdowns may have a material adverse effect on our results of operations and financial condition.
We may incur losses and spend time and financial resources defending pending litigations and arbitrations.
We are currently a party to numerous legal proceedings relating to civil, administrative, tax, labor, environmental and corporate claims filed against us. These claims involve substantial amounts of money and other remedies. Several individual disputes account for a significant part of the total amount of claims against us. See Item 8. “Financial Information—Legal Proceedings” and Note 30 to our audited consolidated financial statements included in this annual report for a description of the legal proceedings to which we are subject. In the event that claims involving a material amount and for which we have no provisions were to be decided against us, or in the event that the losses estimated turn out to be significantly higher than the provisions made, the aggregate cost of unfavorable decisions could have a material adverse effect on results of operations and financial condition. We may also be subject to litigation and administrative proceedings in connection with our concessions and other government authorizations, which could result in the revocation of such concessions and government authorizations. In addition, our management may be required to direct its time and attention to defending these claims, which could prevent them from focusing on our core business. Depending on the outcome, litigation could result in restrictions on our operations and have a material adverse effect on some of our businesses.
We are a defendant in a purported class action lawsuit and three individual actions by institutional investors, all in the United States District Court for the Southern District of New York (SDNY). See Item 8. “Financial Information—Legal Proceedings” for a description of the U.S. securities class action litigation. Because the actions are in their early stages, the possible loss or range of losses, if any, arising from the litigation cannot be estimated, and consequently we have made no provisions with respect to this litigation. In the event that this litigation is decided against us, or we enter into an agreement to settle such matters, we may be required to pay substantial amounts.
We are not insured against business interruption for our Brazilian operations, and most of our assets are not insured against war or sabotage.
We do not maintain insurance coverage for business interruptions of any nature for our Brazilian operations, including business interruptions caused by labor action. If, for instance, our workers or those of our key third-party suppliers, vendors and service providers were to strike, the resulting work stoppages could have an adverse effect on us. In addition, we do not insure most of our assets against war or sabotage. Therefore, an attack or an operational incident causing an interruption of our business could have a material adverse effect on our results of operations and financial condition.
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Developments in the oil and gas industry and other factors have resulted, and may result, in substantial write-downs of the carrying amount of certain of our assets, which could adversely affect our operating results and financial condition.
We evaluate on an annual basis, or more frequently where the circumstances require, the carrying amount of our assets for possible impairment. Our impairment tests are performed by a comparison of the carrying amount of an individual asset or a cash-generating unit with its recoverable amount. Whenever the recoverable amount of an individual asset or cash-generating unit is less than its carrying amount, an impairment loss is recognized to reduce the carrying amount to the recoverable amount.
Changes in the economic, regulatory, business or political environment in Brazil or other markets where we operate, such as the recent significant decline in international crude oil and gas prices, the devaluation of the real and lower projected economic growth in Brazil, among other factors, may result in the recognition of impairment charges in certain of our assets. For example, in 2014, we recognized impairment charges of U.S.$16,823 million for certain of our property, plant and equipment, intangible assets and assets classified as held for sale. See Item 5. “Operating and Financial Review and Prospects—Results of Operations-2014 compared to 2013”, Item 5. “Operating and Financial Review and Prospects—Critical Accounting Policies and Estimates” and Notes 5.2 and 14 to our audited consolidated financial statements for further information about the impairment of certain of our assets.
Future developments in the economic environment, in the oil and gas industry and other factors could result in further substantial impairment charges, adversely affecting our operating results and financial condition.
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Compliance and Control Risks
We are exposed to behaviors incompatible with our ethics and compliance standards, and failure to timely detect or remedy any such behavior may have a material adverse effect on our results of operations and financial condition.
Our business, including relationships with third parties, is guided by ethical principles. We have adopted a Code of Ethics and a number of internal policies designed to guide our management, employees and contractors and reinforce our principles and rules for ethical behavior and professional conduct. We offer a confidential hotline, managed through our Ombudsman, for employees, contractors and other third parties. See Item 6. “Directors, Senior Management and Employees—Ombudsman.”
We are subject to the risk that our employees, contractors or any person doing business with us may engage in fraudulent activity, corruption or bribery, circumvent or override our internal controls and procedures or misappropriate or manipulate our assets for their personal or business advantage to our detriment. This risk is heightened by the fact that we have a large number of complex, valuable contracts with local and foreign suppliers, as well as the geographic distribution of our operations and the wide variety of counterparties involved in our business. We have in place a number of systems for identifying, monitoring and mitigating these risks, but our systems may not be effective.
It is difficult for us to ensure that all of our employees and contractors, totaling over 371,000, will comply with our ethical principles. Any failure – real or perceived – to follow these principles or to comply with applicable governance or regulatory obligations could harm our reputation, limit our ability to obtain financing and otherwise have a material adverse effect on our results of operations and financial condition.
Our management has identified material weaknesses in our internal control over financial reporting, and has concluded that our internal control over financial reporting was not effective at December 31, 2014, which may have a material adverse result on our results of operation and financial condition.
Our management identified a number of material weaknesses in our internal control over financial reporting in 2014. For example, management overrides by certain former Petrobras personnel relating to our large investment projects in the Exploration and Production, Refining, and Gas and Power business segments did not comply with our existing internal controls over the process of contracting for services in these segments.
In addition, our management identified material weaknesses related to (i) internal controls over property, plant and equipment (specifically with respect to the evaluation of the financial condition of our contractors and suppliers, termination costs and write-downs of payments made in advance, among others), (ii) the review and approval of manual journal entries, and (iii) managing access to critical transactions in our systems and segregation of duties. As a result, our management concluded that our internal control over financial reporting was not effective at December 31, 2014. Although we have developed and implemented several measures to remedy these material weaknesses, we cannot be certain that there will be no other material weaknesses in our internal control over financial reporting in the future. For more information about these matters, see Item 15. “Controls and Procedures—Management’s Report on Internal Control over Financial Reporting.”
If our efforts to remediate the material weaknesses are not successful, we may be unable to report our results of operations for future periods accurately and in a timely manner and make our required filings with government authorities, including the SEC. There is also a risk that there could be accounting errors in our financial reporting, and we cannot be certain that in the future additional material weaknesses will not exist or otherwise be discovered. Any of these occurrences could adversely affect our business and operating results and could generate negative market reactions, potentially leading to a decline in the price of our shares, ADSs and debt securities.
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Ongoing SEC and DoJ investigations regarding the possibility of non-compliance with the U.S. Foreign Corrupt Practices Act could adversely affect us. Violations of this or other laws may require us to pay fines and expose us and our employees to criminal sanctions and civil suits.
In November 2014, we received a subpoena from the SEC requesting certain documents and information about us relating to, among other things, the Lava Jato investigation and any allegations regarding a violation of the U.S. Foreign Corrupt Practices Act. The DoJ is conducting a similar inquiry, and we are voluntarily cooperating with both investigations. The internal investigation and related government inquiries concerning these matters remain ongoing, and it is still not possible to estimate the duration, scope or results of the internal investigation or related inquiries by relevant authorities. While we are cooperating fully with both investigations, adverse developments in connection with these investigations, including any expansion of the scope of the investigations, could negatively impact us and could divert the efforts and attention of our management team from our ordinary business operations. In connection with any SEC or DoJ investigation, there can be no assurance that we will not be required to pay penalties or provide other financial relief, or consent to injunctions or orders on future conduct or suffer other penalties, any of which could have a material adverse effect on us. See “Item 8. – Financial Information—Legal Proceedings.”
Our methodology to estimate the incorrectly capitalized overpayments, uncovered in the context of the Lava Jato investigation, involves some degree of uncertainty. If substantive additional information comes to light in the future that would make our estimate for the overstatements of our assets appear, in retrospect, to have been materially underestimated or overestimated, this could require a restatement of our financial statements and may have a material adverse effect on our results of operations and financial condition and affect the market value of our securities.
As a result of the findings of the Lava Jato investigation, in the third quarter ended September 30, 2014, we wrote off U.S.$2,527 million of capitalized costs representing amounts that Petrobras overpaid for the acquisition of property, plant and equipment in prior years.
According to testimony from Brazilian criminal investigations that became available beginning October 2014, senior Petrobras personnel conspired with contractors, suppliers and others, from 2004 through April 2012, to establish and implement an illegal cartel that systematically overcharged us in connection with the acquisition of property, plant and equipment. In addition to the payment scheme, the investigations identified several specific instances of other contractors and suppliers that allegedly overcharged Petrobras and used the overpayment received from their contracts with us to fund improper payments, unrelated to the payment scheme, to certain Petrobras employees, including the former Petrobras personnel and a former Chief International Officer. See “Explanatory Note” and Note 3 to our audited consolidated financial statements for further information about the Lava Jato investigation, the overpayments charged by certain contractors and suppliers to Petrobras and our methodology to estimate the overstatement of our assets.
We concluded that a portion of our costs incurred to build property, plant and equipment that resulted from contractors and suppliers in the cartel overcharging us to make improper payments should not have been capitalized in our historical costs of property, plant and equipment. As it is impracticable to identify the specific periods and amounts for the overpayments made by us, we considered all the available information to determine the impact of the overpayments charged to us. As a result, to account for these overpayments, we developed a methodology to estimate the aggregate amount that we overpaid under the payment scheme, in order to determine the amount of the write-off representing the overstatement of our assets resulting from overpayments used to fund improper payments.
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The Lava Jato investigation is still ongoing and it could be a significant amount of time before the Brazilian federal prosecutors conclude their investigation. As a result of this investigation, substantive additional information might come to light in the future that would make our estimate for overpayments appear, in retrospect, to have been materially low or high, which may require us to restate our financial statements to further adjust the write-offs representing the overstatement of our assets recognized in our interim consolidated financial statements for the nine-month period ended September 30, 2014.
We believe that we have used the most appropriate methodology and assumptions to determine the amounts of overpayments incorrectly capitalized based on the information available to us, but our estimation methodology involves some degree of uncertainty. There can be no assurance that the write-offs representing the overstatement of our assets, determined using our estimation methodology, and recognized in our interim consolidated financial statements for the nine-month period ended September 30, 2014, are not underestimated or overestimated. In the event that we are required to write-off additional historical costs from our property, plant and equipment or to reverse write-offs previously recognized in our financial statements, this might impact the total value of our assets and we may be subject to negative publicity, credit rating downgrades, or other negative material events, which may have a material adverse effect on our results of operations and financial condition and affect the market value of our securities.
Risks Relating to Our Relationship with the Brazilian Federal Government
The Brazilian federal government, as our controlling shareholder, may pursue certain macroeconomic and social objectives through us that may have a material adverse effect on us.
As our controlling shareholder, the Brazilian federal government has pursued, and may pursue in the future, certain of its macroeconomic and social objectives through us, as permitted by law. Brazilian law requires that the Brazilian federal government own a majority of our voting stock, and so long as it does, the Brazilian federal government will have the power to elect a majority of the members of our board of directors and, through them, a majority of the executive officers who are responsible for our day-to-day management. As a result, we may engage in activities that give preference to the objectives of the Brazilian federal government rather than to our own economic and business objectives.
Accordingly, we may make investments, incur costs and engage in sales with parties or on terms that may have an adverse effect on our results of operations and financial condition. In particular, we continue to assist the Brazilian federal government in ensuring that the supply and pricing of crude oil and oil products in Brazil meets Brazilian consumption requirements. Prior to January 2002, prices for crude oil and oil products were regulated by the Brazilian federal government, occasionally set below prices prevailing in the world oil markets. We cannot assure you that price controls will not be reinstated in Brazil.
Our investment budget is subject to approval by the Brazilian federal government, and failure to obtain approval of our planned investments could adversely affect our operating results and financial condition.
The Brazilian federal government maintains control over our investment budget and establishes limits on our investments and long-term debt. As a state-controlled entity, we must submit our proposed annual budgets to the MPBM, the MME and the Brazilian Congress for approval. Our approved budget may reduce our proposed investments and incurrence of new debt, and we may be unable to obtain financing that does not require Brazilian federal government approval. As a result, we may not be able to make all the investments we envision, including those we have agreed to make to expand and develop our crude oil and natural gas fields, which may adversely affect our operating results and financial condition.
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Risks Relating to Brazil
Brazilian political and economic conditions and investor perception of these conditions have a direct impact on our business and may have a material adverse effect on us.
The Brazilian federal government’s economic policies may have important effects on Brazilian companies, including us, and on market conditions and prices of Brazilian securities. Our financial condition and results of operations may be adversely affected by the following factors and the Brazilian federal government’s response to these factors:
· exchange rate movements and volatility;
· inflation;
· financing of government current account deficit;
· price instability;
· interest rates;
· liquidity of domestic capital and lending markets;
· tax policy;
· regulatory policy for the oil and gas industry, including pricing policy;
· allegations of corruption against political parties, elected officials or other public officials, including allegations made in relation to the Lava Jato investigation; and
· other political, diplomatic, social and economic developments in or affecting Brazil.
Uncertainty over whether the Brazilian federal government will implement changes in policy or regulations that may affect any of the factors mentioned above or other factors in the future may lead to economic uncertainty in Brazil and increase the volatility of the Brazilian securities market and securities issued abroad by Brazilian companies, which may have a material adverse effect on our results of operations and financial condition.
Historically, the country’s political scenario has influenced the performance of the Brazilian economy and political crises have affected the confidence of investors and the general public, which resulted in economic deceleration and heightened volatility in the securities issued abroad by Brazilian companies. Currently, Brazilian markets are experiencing heightened volatility due to the uncertainties derived from the ongoing Lava Jato investigation and its impacts on the Brazilian economy and political environment. Although Brazilian authorities have publicly described Petrobras as a victim of the alleged illegal conduct identified during the Lava Jato investigation, at this stage of the investigation, any developments in the Lava Jato investigation (foreseeable and unforeseeable) could have a material adverse effect on the Brazilian economy and on our results of operations and financial condition.
Additionally, since 2011, Brazil has been experiencing an economic slowdown. Gross Domestic Product, or GDP, growth rates were 0.1% in 2014, 2.7% in 2013, 1.8% in 2012 and 3.9% in 2011, compared to a GDP growth of 7.5% in 2010. Our results of operations and financial condition have been, and will continue to be, affected by the growth rate of GDP in Brazil because a substantial portion of our oil products are sold in Brazil. We cannot assure that GDP will increase or remain stable in the future. Future developments in the Brazilian economy may affect Brazil’s growth rates and, consequently, the consumption of our oil products. As a result, these developments could impair our results of operations and financial condition.
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Allegations of political corruption against the Brazilian federal government and the Brazilian legislative branch could create economic and political instability.
In the past, members of the federal government and the Brazilian legislative branch have faced allegations of political corruption. As a result, a number of politicians, including senior federal officials and congressman, resigned or have been arrested. Currently, elected officials and other public officials in Brazil are being investigated for allegations of unethical and illegal conduct identified during the Lava Jato investigation being conducted by the Office of the Brazilian Federal Prosecutor. The potential outcome of these investigations is unknown, but they have already had an adverse impact on the image and reputation of the implicated companies (including Petrobras), in addition to the adverse impact on general market perception of the Brazilian economy. These proceedings, their conclusions or further allegations of illicit conduct could have additional adverse effects on the Brazilian economy. We cannot predict whether such allegations will lead to further instability or whether new allegations against Brazilian government officials will arise in the future. In addition, we cannot predict the outcome of any such allegations nor their effect on the Brazilian economy.
Inflation, and the Brazilian government’s measures to combat inflation, may contribute significantly to economic uncertainty in Brazil, and may materially adversely affect us.
Brazil has historically experienced high rates of inflation, particularly prior to 1995. Inflation, as well as government efforts to combat inflation, had significant negative effects on the Brazilian economy. More recently, inflation rates were 6.41% in 2014, 5.91% in 2013 and 5.84% in 2012, as measured by the IPCA, the National Consumer Price Index, compiled by IBGE (Brazilian Institute of Geography and Statistics).
Brazil may experience high levels of inflation in the future. The Brazilian government may introduce policies to reduce inflationary pressures, which could have the effect of reducing the overall performance of the Brazilian economy. Some of these policies may have an effect on our ability to access foreign capital or reduce our ability to execute our future business and management plans, particularly for those projects that rely on foreign partners.
The Brazilian government’s measures to control inflation have often included maintaining a tight monetary policy with high real interest rates. These policies have contributed to limiting the size and attractiveness of the local debt markets, requiring borrowers like us to seek foreign currency funding in the international capital markets. To the extent that there is economic uncertainty in Brazil, which weakens our ability to obtain external financing on favorable terms, the local Brazilian market may be insufficient to meet our financing needs, which in turn may materially adversely affect us.
Risks Relating to Our Equity and Debt Securities
The size, volatility, liquidity or regulation of the Brazilian securities markets may curb the ability of holders of ADSs to sell the common or preferred shares underlying our ADSs.
Petrobras shares are among the most liquid traded on the São Paulo Stock Exchange, or BM&FBOVESPA, but overall, the Brazilian securities markets are smaller, more volatile and less liquid than the major securities markets in the United States and other jurisdictions, and may be regulated differently from the way in which U.S. investors are accustomed. Factors that may specifically affect the Brazilian equity markets may limit the ability of holders of ADSs to sell the common or preferred shares underlying our ADSs at the price and time they desire.
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The market for PGF’s debt securities may not be liquid.
Some of PGF’s notes are not listed on any securities exchange and are not quoted through an automated quotation system. PGF’s notes are currently listed both on the New York Stock Exchange and the Luxembourg Stock Exchange and trade on the NYSE Euronext and Euro MTF market, respectively. PGF can issue new notes that can be listed in markets other than the New York Stock Exchange and the Luxembourg Stock Exchange and traded in markets other than the NYSE Euronext and the Euro MTF market. We can make no assurance as to the liquidity of or trading markets for PGF’s notes. We cannot guarantee that the holders of PGF’s notes will be able to sell their notes in the future. If a market for PGF’s notes does not develop, holders of PGF’s notes may not be able to resell the notes for an extended period of time, if at all.
Holders of our ADSs may be unable to exercise preemptive rights with respect to the common or preferred shares underlying the ADSs.
Holders of ADSs who are residents of the United States may not be able to exercise the preemptive rights relating to the common or preferred shares underlying our ADSs unless a registration statement under the Securities Act is effective with respect to those rights or an exemption from the registration requirements of the Securities Act is available. We are not obligated to file a registration statement with respect to the common or preferred shares relating to these preemptive rights, and therefore we may not file any such registration statement. If a registration statement is not filed and an exemption from registration does not exist, The Bank of New York Mellon, as depositary, will attempt to sell the preemptive rights, and holders of ADSs will be entitled to receive the proceeds of the sale. However, the preemptive rights will expire if the depositary cannot sell them. For a more complete description of preemptive rights with respect to the common or preferred shares, see Item 10. “Additional Information—Memorandum and Articles of Incorporation—Preemptive Rights.”
If holders of our ADSs exchange their ADSs for common or preferred shares, they risk losing the ability to timely remit foreign currency abroad and forfeiting Brazilian tax advantages.
The Brazilian custodian for our common or preferred shares underlying our ADSs must obtain a certificate of registration from the Central Bank of Brazil to be entitled to remit U.S. dollars abroad for payments of dividends and other distributions relating to our preferred and common shares or upon the disposition of the common or preferred shares. Such remittances under an ADR program are subject to a specific tax treatment in Brazil that may be more favorable to a foreign investor if compared to remitting gains originated from securities directly acquired by the investor in the Brazilian regulated stock markets. Therefore, an investor who opts to exchange ADSs for the underlying common or preferred share may be subject to less favorable tax treatment on gains with respect to these investments.
The exchange of ADSs for the underlying common or preferred shares is governedbyCMN Resolution No. 4,373 and foreign investors who intend to do so are required to appoint a representative in Brazil for the purposes of Annex I of CMN Resolution No. 4,373, who will be in charge for keeping and updating the investors’ certificates of registrations with the Central Bank of Brazil, which entitles registered foreign investors to buy and sell directly on the BM&FBOVESPA. Such arrangements may require additional expenses from the foreign investor. Moreover, if such representatives fail to obtain or update the relevant certificates of registration, investors may incur in additional expenses or be subject to operational delays which could affect their ability to receive dividends or distributions relating to the common or preferred shares or the return of their capital in a timely manner.
The custodian’s certificate of registration or any foreign capital registration directly obtained by such holders may be affected by future legislative or regulatory changes, and we cannot assure such holders that additional restrictions applicable to them, the disposition of the underlying common or preferred shares, or the repatriation of the proceeds from the process will not be imposed in the future.
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Holders of our ADSs may face difficulties in protecting their interests.
Our corporate affairs are governed by our bylaws and Brazilian Corporate Law, which differ from the legal principles that would apply if we were incorporated in a jurisdiction in the United States or elsewhere outside Brazil. In addition, the rights of an ADS holder, which are derivative of the rights of holders of our common or preferred shares, as the case may be, to protect their interests against actions by our board of directors are different under Brazilian Corporate Law than under the laws of other jurisdictions. Rules against insider trading and self-dealing and the preservation of shareholder interests may also be different in Brazil than in the United States. In addition, shareholders in Brazilian companies ordinarily do not have standing to bring a class action, and under Petrobras’s by-laws must, generally with respect to disputes concerning rules regarding the operation of the capital markets, arbitrate any such claims.See Item 10. “Additional Information—Memorandum and Articles of Incorporation—Dispute Resolution.”
We are a state-controlled company organized under the laws of Brazil, and all of our directors and officers reside in Brazil. Substantially all of our assets and those of our directors and officers are located in Brazil. As a result, it may not be possible for holders of ADSs to effect service of process upon us or our directors and officers within the United States or other jurisdictions outside Brazil or to enforce against us or our directors and officers judgments obtained in the United States or other jurisdictions outside Brazil. Because judgments of U.S. courts for civil liabilities based upon the U.S. federal securities laws may only be enforced in Brazil if certain requirements are met, holders of ADSs may face greater difficulties in protecting their interest in actions against us or our directors and officers than would shareholders of a corporation incorporated in a state or other jurisdiction of the United States.
Holders of our ADSs do not have the same voting rights as our shareholders. In addition, holders of ADSs representing preferred shares do not have voting rights.
Holders of our ADSs do not have the same voting rights as holders of our shares. Holders of our ADSs are entitled to the contractual rights set forth for their benefit under the deposit agreements. ADS holders exercise voting rights by providing instructions to the depositary, as opposed to attending shareholders meetings or voting by other means available to shareholders. In practice, the ability of a holder of ADSs to instruct the depositary as to voting will depend on the timing and procedures for providing instructions to the depositary, either directly or through the holder’s custodian and clearing system.
In addition, a portion of our ADSs represents our preferred shares. Under Brazilian law and our bylaws, holders of preferred shares do not have the right to vote in shareholders’ meetings. This means, among other things, that holders of ADSs representing preferred shares are not entitled to vote on important corporate transactions or decisions.
We would be required to pay judgments of Brazilian courts enforcing our obligations under the guaranty relating to PGF’s notes only inreais.
If proceedings were brought in Brazil seeking to enforce our obligations in respect of the guaranty relating to PGF’s notes, we would be required to discharge our obligations only inreais. Under Brazilian exchange controls, an obligation to pay amounts denominated in a currency other thanreais, which is payable in Brazil pursuant to a decision of a Brazilian court, may be satisfied inreaisat the rate of exchange, as determined by the Central Bank of Brazil, in effect on the date of payment.
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A finding that we are subject to U.S. bankruptcy laws and that the guaranty executed by us was a fraudulent conveyance could result in PGF noteholders losing their legal claim against us.
PGF’s obligation to make payments on the PGF notes is supported by our obligation under the corresponding guaranty. We have been advised by our external U.S. counsel that the guaranty is valid and enforceable in accordance with the laws of the State of New York and the United States. In addition, we have been advised by our general counsel that the laws of Brazil do not prevent the guaranty from being valid, binding and enforceable against us in accordance with its terms. In the event that U.S. federal fraudulent conveyance or similar laws are applied to the guaranty, and we, at the time we entered into the relevant guaranty:
· were or are insolvent or rendered insolvent by reason of our entry into such guaranty;
· were or are engaged in business or transactions for which the assets remaining with us constituted unreasonably small capital; or
· intended to incur or incurred, or believed or believe that we would incur, debts beyond our ability to pay such debts as they mature; and
· in each case, intended to receive or received less than reasonably equivalent value or fair consideration therefor,
then our obligations under the guaranty could be avoided, or claims with respect to that agreement could be subordinated to the claims of other creditors. Among other things, a legal challenge to the guaranty on fraudulent conveyance grounds may focus on the benefits, if any, realized by us as a result of the issuance of the PGF notes. To the extent that the guaranty is held to be a fraudulent conveyance or unenforceable for any other reason, the holders of the PGF notes would not have a claim against us under the relevant guaranty and would solely have a claim against PGF. We cannot assure you that, after providing for all prior claims, there will be sufficient assets to satisfy the claims of the PGF noteholders relating to any avoided portion of the guaranty.
Holders in some jurisdictions may not receive payment of gross-up amounts for withholding pursuant to the European Council Directive 2003/48/EC on the taxation of savings income.
Austria has opted out of certain exchange of information provisions of the European Council Directive 2003/48/EC on the taxation of savings income (the Directive) and is instead, during a transitional period, applying a withholding tax on payments of interest, at a rate of up to 35%, made by a paying agent within thosejurisdictions 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 Statesunless the beneficial owner of the interest payments opts for exchange of information as required under the Directive. Neither we nor the paying agent (nor any other person) would be required to pay additional amounts in respect of the notes as a result of the imposition of withholding tax by any EU Member State or another country or territory which has opted for a withholding system. For more information, see Item 10. “Additional Information—Taxation Relating to PGF’s Notes—European Union Savings Directive.” An investor should consult a tax adviser to determine the tax consequences of holding PGF’s notes for such investor.
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Item 4. Information on the Company
Petróleo Brasileiro S.A.—Petrobras was incorporated in 1953 to conduct the Brazilian federal government’s hydrocarbon activities. We began operations in 1954 and since then have been carrying out crude oil and natural gas production and refining activities in Brazil on behalf of the government. As of December 31, 2014, the Brazilianfederalgovernment owned 28.67% of our outstanding capital stock and 50.26% of our voting shares. See Item 7. “Major Shareholders and Related Party Transactions—Major Shareholders.” Our common and preferred shares have been traded on the BM&FBOVESPA since 1968 and on the NYSE in the form of ADSs since 2000.
As part of a comprehensive reform of the oil and gas regulatory system, the Brazilian Congress amended the Brazilian Constitution in 1995 to authorize the Brazilian federal government to contract with any state or privately-owned company to carry out upstream, oil refining, cross-border commercialization and transportation activities in Brazil of oil, natural gas and their respective products. On August 6, 1997, the Brazilian federal government enacted Law No. 9,478/1997, which established a concession-based regulatory framework, ended our exclusive right to carry out oil and gas activities, and allowed competition in all aspects of the oil and gas industry in Brazil. The law also created an independent regulatory agency, the ANP, to regulate the oil, natural gas and renewable fuel industry in Brazil and to create a competitive environment in the oil and gas sector. See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Price Regulation.”
In 2010, new laws were enacted to regulate exploration and production activities in pre-salt areas not subject to existing concessions. Pursuant to this new legislation, we entered into an agreement with the Brazilian federal government on September 3, 2010, the Assignment Agreement, under which the government assigned to us the right to explore and produce oil, natural gas and other fluid hydrocarbons in specified pre-salt areas in Brazil. On December 2, 2013, we executed our first agreement with the Brazilian federal government under a production sharing regime. See Item 10. “Additional Information—Material Contracts—Assignment Agreement” and Item 10. “Additional Information—Material Contracts – Production Sharing Agreement.”
We operate through subsidiaries, joint ventures, joint operations and associated companies established in Brazil and many other countries. Our principal executive office is located at Avenida República do Chile 65, 20031-912 Rio de Janeiro, RJ, Brazil and our telephone number is (55-21) 3224-4477.
We are an integrated oil and gas company that is one of the largest companies in Latin America in terms of revenue. As a result of our legacy as Brazil’s former sole supplier of crude oil and oil products and our strong and continuous commitment to find and develop oil fields in Brazil, our operations account for the majority of Brazil’s oil and gas production, and we hold a large base of proved reserves and a fully developed operational infrastructure. In 2014, our average domestic daily oil production was 2,034mbbl/d, which represents more than 90% of Brazil’s total oil production. Over 62.7% (7,965.9 mmboe) of our domestic proved reserves are located in our most developed area - the offshore Campos Basin - which allows us to optimize our infrastructure and limit our costs of exploration, development and production. The contribution of our most promising deepwater fields, located in the offshore Santos Basin (southeast Brazil), to our proved reserves and oil production is continuously growing. Our production process in the Santos Basin has benefited from the expertise we cultivated through similar production experiences in the Campos Basin.
Over 46 years of developing Brazil’s offshore basins, we have developed special expertise in deepwater exploration and production, which we exploit both in Brazil and in other offshore oil areas.
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As of December 31, 2014, we had proved developed oil and gas reserves of 8,112.8 mmboe and proved undeveloped reserves of 4,599.7 mmboe in Brazil. The development of this large reserve base and the exploration of pre-salt areas has demanded, and will continue to demand, significant investments and the growth of our operations. To support this growth we have ordered the construction of 16 new FPSOs and planned 15 more for the period between 2015 and 2020, and are also making necessary investments in subsea equipment and infrastructure.
We operate substantially all of the refining capacity in Brazil. Most of our refineries are located in southeastern Brazil, within the country’s most populated and industrialized markets and adjacent to the source of most of our crude oil in the Campos Basin. Our domestic crude distillation capacity of 2,176 mbbl/d and domestic refining throughput of 2,106 mbbl/d are currently below the levels required to meet domestic demand for transportation fuels, particularly gasoline, diesel and jet fuel. We are in the process of expanding and upgrading our refining capacity to meet growing demand in Brazil, but our current capacity is not sufficient to process the oil produced in Brazil necessary to satisfy such demand. Consequently, and for the foreseeable future, we will continue to import oil and oil products. We are also involved in the production of petrochemicals. We distribute oil products through our own retail network and to wholesalers.
We participate in most aspects of the Brazilian natural gas market, including the logistics and processing of natural gas. To meet our domestic demand, we process natural gas derived from our onshore and offshore (mainly from fields in the Campos, Espírito Santo and Santos Basins) production, import natural gas from Bolivia, and to the extent necessary, import LNG through our regasification terminals. We also participate in the domestic power market primarily through our investments in gas-fired thermoelectric power plants and in renewable energy. In addition, we participate in the fertilizer business, which is another important natural gas market.
Outside of Brazil, we operate in 16 countries. In Latin America, our operations extend from exploration and production to refining, marketing, retail services, natural gas and electricity power plants. In North America, we produce oil and gas and have refining operations in the United States. In Africa, through a joint venture, we produce oil in Nigeria and have oil and gas exploration in other countries while in Asia we have refining operations in Japan.
Comprehensive information and tables on reserves and production is presented at the end of Item 4. See “Information on the Company—Additional Reserves and Production Information.”
Our activities are organized into six business segments:
· Exploration and Production: crude oil, NGL and natural gas exploration, development and production in Brazil;
· Refining, Transportation and Marketing: includes refining, logistics, transportation, trading operations, oil products and crude oil exports and imports and petrochemical investments in Brazil;
· Distribution: distribution of oil products, ethanol, biodiesel and natural gas to wholesalers and through our Petrobras Distribuidora S.A. (“Petrobras Distribuidora”) retail network in Brazil;
· Gas and Power: transportation and trading of natural gas and LNG, produced in or imported into Brazil, as well as generation and trading of electric power, and the fertilizer business;
· Biofuel: production of biodiesel and its co-products and ethanol-related activities such as equity investments, production and trading of ethanol, sugar and the excess electricity generated from sugarcane bagasse; and
· International: exploration and production of oil and gas, refining, transportation and marketing, distribution and gas and power operations outside of Brazil.
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Additionally, we have a Corporate segment that has activities that are not attributed to the other segments, notably those related to corporate financial management, corporate overhead and other expenses, including actuarial expenses related to the pension and medical benefits for retired employees and their dependents.
The following table sets forth key information for each business segment in 2014:
| Key Information by Business Segment, 2014 | ||||||||
| Exploration and Production | Refining, Transportation and Marketing | Gas and Power | Biofuel | Distribution | International | Corporate | Eliminations | Group Total |
| (U.S.$ million) | ||||||||
Sales revenues | 65,616 | 112,320 | 17,882 | 266 | 41,729 | 13,912 | − | (108,068) | 143,657 |
Income (loss) before income taxes | 21,764 | (22,983) | (553) | (166) | 760 | (608) | (7,714) | 676 | (8,824) |
Total assets at December 31 | 151,524 | 70,038 | 28,367 | 1,109 | 7,221 | 13,009 | 32,385 | (4,966) | 298,687 |
Capital expenditures and investments | 24,164 | 7,778 | 2,545 | 112 | 446 | 1,513 | 446 | − | 37,004 |
Exploration and Production Key Statistics | |||
| 2014 | 2013 | 2012 |
| (U.S.$ million) | ||
Exploration and Production: |
| ||
Sales revenues | 65,616 | 68,210 | 74,714 |
Income (loss) before income taxes | 21,764 | 29,619 | 35,465 |
Property, plant and equipment | 135,671 | 126,716 | 102,779 |
Capital expenditures and investments | 24,164 | 27,566 | 21,959 |
Oil and gas exploration and production activities in Brazil are the largest components of our portfolio. We have gradually increased production over the past four decades, from 164 mbbl/d of crude oil, condensate and NGL in Brazil in 1970 to 2,034 mbbl/d in 2014. We aim to grow oil and gas reserves and production sustainably and be recognized for excellence in exploration and production operations.
The major target of our exploration and production segment is to produce (in Brazil and abroad), on average, 4,000 mbbl/d of crude oil, condensate and NGL during the 2020-2030 period. We expect to meet this target by:
• Finding and acquiring hydrocarbon reserves in Brazil, maintaining a minimum 12-year ratio (under SPE guidelines) between our reserves and production;
• Developing oil production in the pre-salt province in Brazil;
• Maximizing the oil and gas recovery in our production areas that have largely been developed;
• Exploring the Brazilian basins in a selective manner and sharing related risks with partners; and
• Exploring the Brazilian basins for natural gas.
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In supporting these objectives, we have implemented a variety of programs designed to manage our capital and operational expenditures: PROEF – which aims to increase operational efficiency; PROCOP – which aims to reduce the operational expenditures of our exploration and production segment; PRC-Poço – focused on reducing capital expenditures in the construction of our wells; PRC-SUB – focused on reducing capital expenditures in the installation of our subsea systems; and INFRALOG – which seeks to optimize our logistics infrastructure.
Brazil’s richest oil fields are located offshore, most of them in deep waters. We have been active in these waters since 1971, when we started exploration in the Campos Basin, and we have become globally recognized as innovators in the technology required to explore and produce hydrocarbons in deep and ultra-deep waters. Our exploration success has been in the deepwater, where the reservoirs in which we have made discoveries are substantially larger and where our technology and expertise have created a competitive advantage for us. In 2014, offshore production accounted for 90% of our production and deep water production accounted for 78% of our production in Brazil. According to production data from PFC Energy, we operate more production (on a boe basis) from fields in deep and ultra-deep water than any other company.
Historically, we focused our offshore exploration and production activities on sandstone turbidite reservoirs, located primarily in the Campos Basin. In 2006, we were successful in drilling through a massive salt layer off the Brazilian coast that stretches from the Campos to the Santos Basins. The oil under the salt layer has in many areas been well-preserved in large reservoirs, leading to a number of important discoveries. This province, identified by the salt layer, occupies an area of approximately 149,000 km2 (36.8 million acres), of which we have rights to produce from 17.8% of the total area (approximately 26,430 km2 or 6.5 million acres), through acreage assigned to us under Concession Agreements and the Assignment Agreement. We are also part of the consortium that was granted a concession covering approximately 1,547.8 km2 (0.4 million acres), in the Libra area, under a Production Sharing Agreement.
The pre-salt reservoirs we have discovered are located in deep and ultra-deep waters at total depths of up to 7,000 meters (22,965 feet). The southern part of the pre-salt province consists of the Santos Basin, where the salt layer is approximately two kilometers thick. We have made significant discoveries in that area, including:
· BM-S-11: Lula, formerly Tupi, and the area of Berbigão, Sururu and Oeste de Atapu, formerly lara;
· BM-S-9: Lapa and Sapinhoá, formerly Carioca and Guará;
· BM-S-8: Carcará;
· BM-S-24: Júpiter;
· Assignment Agreement area: Búzios, Sul de Lula, Sul de Sapinhoá, Sépia and Itapu, formerly Franco, Sul de Tupi, Sul de Guará, Nordeste de Tupi and Florim, and the area of Norte de Berbigão, Sul de Berbigão, Norte de Sururu, Sul de Sururu and Atapu, formerly Entorno de Iara; and
· Libra.
In the northern part of the pre-salt province, the salt is thinner and much of the oil has migrated through the salt to the post-salt sandstone reservoirs of the Campos Basin. While some of the oil that formed has migrated, we still have made important discoveries in pre-salt reservoirs in the Campos Basin, as we drilled through the salt layers. Most of our current and future capital will be committed to developing the oil found in the pre-salt province, with an emphasis on the Santos Basin, given the size of its reservoirs and its potential.
In December 2014, the monthly average production in the pre-salt area (Campos and Santos Basins) was 666 mbbl/d, an increase of 93% compared to December 2013. Wells in the pre-salt province are highly productive. Total pre-salt production reached800 mbbl/d onApril11, 2015 (a new daily production record) with only 39 producing wells. Twenty of these wells are located in the Santos Basin and were responsible for 64% of that production (511 mbbl/d).
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The map below shows the location of the pre-salt reservoirs as well as the status of our exploratory activities there.
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Production
During 2014, our oil and gas production in Brazil averaged 2,284 mboe/d, of which 89% was oil and 11% was natural gas. On December 31, 2014, our estimated net proved crude oil and natural gas reserves in Brazil were 12.7 bnboe, of which 85.4% was crude oil and 14.6% was natural gas. Brazil represented 92% of our worldwide production in 2014 and accounted for 97% of our worldwide reserves on December 31, 2014 on a barrels of oil equivalent basis. Over the last five years, approximately 90% of our total Brazilian production has been oil.
Information about our main oil and gas producing fields in Brazil is summarized in the table below:
Main Oil and Gas Producing Fields in Brazil | ||||
Basin | Fields | Petrobras % | Type | Fluid(1) |
Camamu | Manati | 35% | Shallow | Natural Gas |
Campos | Albacora | 100% | Shallow | Intermediate Oil |
|
| 100% | Deepwater | Intermediate Oil |
| Albacora Leste | 90% 90% | Deepwater Ultra-deepwater | Intermediate Oil Intermediate Oil |
| Baleia Azul Baleia Franca | 100% 100% | Deepwater Deepwater | Intermediate Oil Intermediate Oil |
| Barracuda | 100% | Deepwater | Intermediate Oil |
| Cachalote | 100% | Deepwater | Intermediate Oil |
| Carapeba | 100% | Shallow | Intermediate Oil |
| Caratinga | 100% | Deepwater | Intermediate Oil |
| Cherne | 100% | Shallow | Intermediate Oil |
| Espadarte | 100% | Deepwater | Intermediate Oil |
| Jubarte | 100% | Deepwater | Heavy Oil |
| Marimbá | 100% | Deepwater | Heavy Oil |
| Marlim | 100% | Deepwater | Heavy Oil |
| Marlim Leste | 100% | Deepwater | Intermediate Oil |
| Marlim Sul | 100% 100% | Deepwater Ultra-deepwater | Intermediate Oil Intermediate Oil |
| Namorado | 100% | Shallow | Intermediate Oil |
| Papa-Terra Pampo | 62.5% 100% | Deepwater Shallow | Heavy Oil Intermediate Oil |
| Roncador | 100% | Ultra-deepwater | Intermediate Oil |
| Vermelho | 100% | Shallow | Intermediate Oil |
Espírito Santo | Fazenda Alegre | 100% 100% | Onshore | Heavy Oil |
Potiguar | Canto do Amaro | 100% | Onshore | Intermediate Oil/Natural Gas |
| Estreito | 100% | Onshore | Heavy Oil |
Recôncavo | Araçás | 100% | Onshore | Light Oil |
Santos | Baúna | 100% | Shallow | Light Oil |
| Mexilhão | 100% | Shallow | Natural Gas |
| Lula | 65% | Ultra-deepwater | Intermediate Oil |
| Sapinhoá | 45% | Ultra-deepwater | Intermediate Oil |
| Piracaba | 100% | Shallow | Light Oil |
| Uruguá | 100% | Deepwater | Intermediate Oil/Natural Gas |
Sergipe/Alagoas | Carmópolis | 100% | Onshore | Intermediate Oil |
| Piranema | 100% | Deepwater | Light Oil |
Solimões | Leste do Urucu | 100% | Onshore | Light Oil/Natural Gas |
| Rio Urucu | 100% | Onshore | Light Oil/Natural Gas |
(1) Heavy oil = up to 22° API; intermediate oil = 22° API to 31° API; light oil = greater than 31° API
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Our average production per basin in Brazil as of December 31, 2014, December 31, 2013 and December 31, 2012 is summarized in the table below:
| 2014 | 2013 | 2012 | |||||||||
Campos | Santos | Others | Total | Campos | Santos | Others | Total | Campos | Santos | Others | Total | |
Production(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (mbb/d) | 1,525.8 | 246.7 | 261.9 | 2,034.4 | 1,531.1 | 136.9 | 263.4 | 1,931.4 | 1,618.3 | 98.6 | 263.2 | 1,980.1 |
Gas (bcf/d) | 0.6 | 0.4 | 0.5 | 1.5 | 0.6 | 0.3 | 0.6 | 1.5 | 0.5 | 0.3 | 0.6 | 1.4 |
Total (mboe/d) | 1,617.2 | 315.5 | 351.7 | 2,284.4 | 1,623.4 | 183.7 | 358.6 | 2,165.7 | 1,701.4 | 148.0 | 356.1 | 2,205.5 |
Stationary production units | 56 | 11 | 55 | 122 | 56 | 11 | 59 | 126 | 55 | 8 | 62 | 125 |
___________________________
(1) Includes synthetic oil and gas.
We offset the natural decline from our reservoirs and increase our total production of oil and gas by installing additional units in our deepwater fields. In 2014, our production of crude oil, condensate and NGL in Brazil averaged 2,034 mbbl/d, a 5.3% increase compared to the previous year. This increase was mainly attributable to the production from a number of recently received FPSOs that came online in 2013 and 2014 with a total oil processing capacity of 1,300 mbbl/d.
Information about our systems that came online in 2013 and 2014 is summarized in the table below:
RecentlyDeveloped Projects | ||||||||
Basin | Field | Unit Type | Production Unit | Crude Oil | Natural Gas (mmcf/d) | Water Depth (meters) | Start Up (year) | Notes |
Campos | Papa-Terra–Module 2 | FPSO | P-63 | 140,000 | 35.3 | 1,200 | 2013 | Post-salt |
Campos | Roncador–Module 3 | SS | P-55 | 180,000 | 211.9 | 1,795 | 2013 | Post-salt |
Campos | Roncador–Module 4 | FPSO | P-62 | 180,000 | 211.9 | 1,600 | 2014 | Post-Salt |
Campos | Parque das Baleias (Baleia Azul, Jubarte, Cachalote, Baleia Anã & Baleia Franca) | FPSO | P-58 | 180,000 | 211.9 | 1,399 | 2014 | Pre and post-salt |
Campos | Papa-Terra–Module 1(1) | TLWP | P-61 | ‒ | ‒ | 1,180 | 2015 | Post-salt production processed by P-63 |
Santos | Sapinhoá Pilot | FPSO | Cidade de São Paulo | 120,000 | 176.6 | 2,140 | 2013 | Pre-salt |
Santos | Lula Northeastern area | FPSO | Cidade de Paraty | 120,000 | 176.6 | 2,140 | 2013 | Pre-salt |
Santos | Baúna | FPSO | Cidade de Itajaí | 80,000 | 70.6 | 275 | 2013 | Post-salt |
Santos | Lula-Iracema Southern area | FPSO | Cidade de Mangaratiba | 150,000 | 282.5 | 2,220 | 2014 | Pre-salt |
Santos | Sapinhoá – Northern area | FPSO | Cidade de Ilhabela | 150,000 | 211.9 | 2,140 | 2014 | Pre-salt |
___________________________
(1) Production from the P-61 platform is processed by the P-63 platform.
In 2014, we were able to connect and start producing from 57 new wells. Due to the new production systems that came online in 2014 and those that are planned to go online in 2015, we expect to increase our oil production in Brazil in 2015 by between 3.5% and 5.5% above our 2014 average.
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We recognized impairment lossesfor the fiscal year ended December 31, 2014 of U.S.$1.6 billion due to the impact of the recent decline in international crude oil prices on the price assumptions for certain of our oil and gas producing properties located in Brazil, including Frade, Pirapitanga, Tambuatá, Carapicu and Piracucá. We have alsorecognized impairment lossesfor the fiscal year ended December 31, 2014 of U.S.$536 million with respect to oil and gas production and drilling equipment, unrelated to oil and gas producing properties. These impairment losses are mainly related to the idle capacity of two drilling rigs in the future and to the demobilization of two oil platforms, which were not deployed in any oil and gas property as of December 31, 2014. For further information, see Note 14 to our audited consolidated financial statements.
Our exploration and production activities outside Brazil are included in our International business segment. See “Item 4. Information on the Company—International.”
Exploration
As of December 31, 2014, we had133 exploration agreements covering a total of158 exploratory blocks, corresponding to a total gross exploratory acreage of90,000km2 (22.24million acres), or a net exploratory acreage of64,000km2 (15.81million acres). We also had56 evaluation plans underway, including 40 in exploratory areas and 16 in ring fence areas. We are exclusively responsible for conducting exploration activities under68 exploratory agreements.
As of December 31, 2014, we had exploration partnerships with 29foreign and domestic companies and were party to a total of82partnership exploratory agreements, in 58 of which we are the operator. We hold interests ranging from40% to 100% in the exploration areas under concession or assigned tous.
In 2014, we invested a total of U.S.$4.5 billion in exploration activities in Brazil. We drilled a total of 74 exploratory wells in 2014, of which 37 were offshore and 37 onshore.
Reserves
Our reserves in Brazil as of December 31, 2014, December 31, 2013 and December 31, 2012 are summarized in the table below:
| 2014 | 2013 | 2012 | |||||||||
| Campos | Santos | Others | Total | Campos | Santos | Others | Total | Campos | Santos | Others | Total |
Proved Reserves |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (mmbbl) | 7,202.8 | 2,917.4 | 730.7 | 10,850.9 | 7,642.3 | 2,209.8 | 806.3 | 10,658.4 | 8,199.5 | 1,483.5 | 856.3 | 10,539.2 |
Gas (bcf) | 4,578.4 | 4,339.7 | 2,252.2 | 11,170.3 | 4,662.4 | 3,935.4 | 2,693.9 | 11,291.7 | 4,911.8 | 2,552.0 | 2,880.7 | 10,344.6 |
Total (mmboe) | 7,965.9 | 3,640.7 | 1,106.1 | 12,712.6 | 8,419.4 | 2,865.7 | 1,255.3 | 12,540.4 | 9,081.1 | 1,908.8 | 1,336.4 | 12,263.3 |
For the twenty-third consecutive year, we achieved a reserve replacement ratio higher than 100% under ANP and SPE guidelines, which means that we added more volume to our reserves than we produced throughout the year. Under SEC rules for estimating and disclosing oil and gas reserve quantities, our reserve replacement ratio in 2014 was 121%.
Exploration and Production Regimes Applicable to Petrobras in Brazil
We have historically conducted exploration, development and production activities in Brazil through concession agreements, which we have obtained through participation in bid rounds conducted by the ANP. Some of our existing concessions were granted by the ANP without an auction in 1998, as provided by Law No. 9,478/1997. These are known as the “Round Zero” concession agreements. Since then, we have participated in all of the auction rounds conducted by the ANP, including the first production-sharing regime auction round held on October 21, 2013. Currently, we operate under three different exploration and production regimes:
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· Concession Agreements: ANP grants rights, from time to time, through public auctions open to qualified operators, to explore and produce crude oil and gas reserves in Brazil under concession agreements for the blocks offered in each auction. We have participated in all of the concession auction rounds conducted by the ANP, including the 11th Round, held on May 14, 2013, in which we acquired 34 blocks located in multiple basins, and the 12th Round, held on November 28, 2013, in which we acquired, directly and in partnership with other companies, 49 blocks located in multiple basins. These concession agreements have a term of 27 years following the declaration of commerciality, with the possibility of extension by the ANP.
· Assignment Agreement (Contrato de Cessão Onerosa): On September 3, 2010, we entered into an agreement with the Brazilian federal government, under which it assigned to us the right to conduct activities for the exploration and production of oil, natural gas and other fluid hydrocarbons in specified pre-salt areas. The agreement is subject to a maximum production of five bnboe over 40 years (extendable for five additional years), and we have already declared commerciality for this entire volume in the areas of Franco (Búzios), Sul de Tupi (Sul de Lula), Florim (Itapu), Nordeste de Tupi (Sépia), Sul de Guará (Sul de Sapinhoá) and Entorno de Iara (Norte de Berbigão, Sul de Berbigão, Norte de Sururu, Sul de Sururu and Atapu). See Item 10. “Additional Information—Material Contracts—Assignment Agreement.”
· Production Sharing Agreement (Contrato de Partilha de Produção): Under this regime, exploration and production licenses are awarded through a public auction to the consortium that offers the highest share of profit oil to the government. At a public auction held on October 21, 2013, a consortium including Petrobras was awarded the rights and obligations to operate and explore a strategic pre-salt area (known as Libra – which has an estimated recoverable volume of between 8 and 12 bnboe according to the ANP) located in the Santos Basin. On December 2, 2013, we executed the first agreement under this regime. We have a 40% interest in the Libra block and are its exclusive operator. This agreement has a term of 35 years. In June 2014, the CNPE enacted Resolution No. 1, which established that Petrobras could be directly engaged by the Brazilian federal government under a production sharing regime to produce the volume of oil, natural gas and fluid hydrocarbons from the Assignment Agreement areas that exceeds the five bnboe maximum production originally agreed under the Assignment Agreement or that may be negotiated during the revision process of the Assignment Agreement.
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The following map shows our concession areas in Brazil as of December 2014.
Primary Basins in Which Petrobras Operates
Our domestic oil and gas exploration and production efforts are primarily focused on four major offshore basins in Brazil: Campos, Santos, Espírito Santo and Sergipe-Alagoas.
Campos Basin
The Campos Basin, which covers approximately 115,000 km2 (28.4 million acres), is the most prolific oil and gas basin in Brazil in terms of proved hydrocarbon reserves and annual production. Since we began exploring this area in 1971, over 60 hydrocarbon accumulations have been discovered, including eight large oil fields in deep and ultra-deep waters. The Campos Basin is our largest oil- and gas-producing area, with an average production of 1,526 mbbl/d of oil and 548.4 mmcf/d (14.5 mmm3/d) of associated natural gas from 43 producing fields in 2014.
During 2014, 71% of our total domestic production came from this basin. In 2014, the proved crude oil and natural gas reserves in the Campos Basin represented 66.4% and 41% of our total proved reserves in Brazil, respectively. In 2014, we operated 42 floating production systems and 14 fixed platforms in water depths from 80 to 1,886 meters (262 to 6,188 feet), delivering oil with an average API gravity of 21.3° and maximum basic sediment and water (a measurement of the water and sediment content of flowing crude oil) of 1%.
Our oil and gas activities in the Campos Basin are focused on increasing production by installing new production systems, tapping pre-salt reservoirs with both new and existing production units, and maintaining our production in relatively mature fields. We also have significant exploration plans in this area.
All of our production in the Campos Basin is under concession agreements.
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Campos Basin Production
In 2013 and 2014, we installed several major systems in the Campos Basin. The largest systems were P-55 and P-62, FPSOs with individual capacities of 180 mbbl/d of oil and 211.9 mmcf/d (6 mmm3/d) of natural gas located in modules 3 and 4 of our largest field in the Campos Basin, Roncador. Another major project was P-58, an FPSO with 180 mmbl/d of oil and 211.9 mmcf/d (6 mmm3/d) of natural gas capacity located in the Parque das Baleias field. The last major project being developed in the Campos Basin is the Papa Terra development, consisting of two units with a combined capacity of 140 mbbl/d of oil and 35.3 mmcf/d (1 mmm3/d) of natural gas. Our projects in Roncador and Parque das Baleias are owned and operated 100% by Petrobras, while in Papa Terra we operate and have a 62.5% interest.
Most of our production in the Campos Basin is from post-salt reservoirs, but pre-salt reservoirs in the basin are a growing source of production. We first began pre-salt oil production in 2008 in the Jubarte field located in the Parque das Baleias region. In December 2014, the Campos Basin pre-salt area monthly average production was 260 mbbl/d, which represents an increase of 60% compared to December 2013. Our share of oil produced from the Campos Basin pre-salt reservoirs is 100%.
With the installation of these units, we expect that major new development projects for the Campos Basin have been completed, and most of our future development projects will focus on the pre-salt projects of the Santos Basin.
Maintenance in Mature Fields
We seek to slow the natural decline in mature fields of the Campos Basin by improving the operational efficiency of our equipment and reservoirs through our PROEF program. Over the past few years, based on efficiency metrics set forth under the PROEF program, we increased the efficiency of the Campos Basin Operational Unit from 75.4% in 2013 to 79.7% in 2014, and the efficiency of our Rio de Janeiro Operational Unit increased from 92.4% in 2013 to 95.4% in 2014. As a result of our investments to increase efficiency, production in 2014 from these areas was 104 mbbl/d greater than it otherwise would have been. To achieve these results, we conducted extensive campaigns and regular maintenance on our platforms, in addition to scheduled unit stoppages to improve performance. Furthermore, we have internal planning and resource management procedures, such as standardization of equipment to ease maintenance and the preparation of backup inventory for critical equipment, ensuring greater availability of those resources.
Exploration
As of December 31, 2014, we held rights to ten exploratory blocks and two exploration plans in the Campos Basin, comprising a total of 3,398 km2 (0.84 million acres). During 2014, we drilled a total of ten exploratory wells (six of them in pre-salt reservoirs).
Santos Basin
The Santos Basin, which covers approximately 348,900 km2 (86 million acres) and is located adjacent to and southwest of Campos Basin, is one of the most promising offshore exploration and production areas in the world. Since discovery in 2006, and with first production only in 2009, we have increased monthly oil production from the Santos Basin pre-salt area to 406,000 bbl/d by year-end 2014 (which represents an increase of 122% compared to December 2013). As of December 31, 2014, 26.9% and 38.9% of our total proved crude oil and natural gas reserves in Brazil, respectively, came from the Santos Basin.
Santos Basin Production
We are currently exploring and developing the Santos Basin pre-salt area under the Concessions, Assignment Agreement and Libra Production Sharing Agreement.
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Concession Agreements
In 2000 and 2001, we and our partners acquired eight blocks in the Santos Basin pre-salt through public auction under concession agreements. In November 2007, we announced the discovery of this important new province, and we began producing oil in May 2009, through an EWT in block BMS -11 (formerly Tupi, now Lula).
In October 2010, we replaced the EWT with a long-term production system, the FPSO Cidade de Angra dos Reis. In 2012, this FPSO reached its maximum capacity of 100 mbbl/d with four production wells connected.
In 2013 we continued our development of the Santos Basin pre-salt with two additional units: FPSO Cidade de São Paulo in the Sapinhoá field (formerly known as Guará), with a production capacity of 120,000 bbl/d of oil and 176.6 mmcf/d (5 mmm3/d) of natural gas and FPSO Cidade de Paraty, in the Lula field at Lula Nordeste area, with the same production capacity as FPSO Cidade de São Paulo. Both units reached their maximum capacity in 2014, each having only four production wells connected.
In 2014, two additional systems were installed: FPSO Cidade de Mangaratiba in the Lula field at Iracema Norte, with a production capacity of 150,000 bbl/d of oil and 282.5 mmcf/d (8 mmm³/d) of natural gas and FPSO Cidade de Ilhabela, in the northern area of Sapinhoá field, with a production capacity of 150,000 bbl/d of oil and 211.9 mmcf/d (6 mmm³/d) of natural gas. By January 2015, this first unit was producing 66,000 bbl/d with only two wells connected and the second unit was producing 30,000 bbl/d of oil through one well that has been connected since November 2014.
We continue to concentrate our efforts on gathering information about the pre-salt reserves through EWTs and pilots. We currently have two units that can perform EWTs in the Santos Basin pre-salt area, the FPSO Dynamic Producer and Cidade de São Vicente. In 2014, EWTs were performed in Lula Central, Lula Sul and Iara Oeste.
We are also testing drilling technologies to improve efficiency and to optimize the definitive design of production platforms.
We have reduced the time required to drill and complete production wells in the Santos Basin pre-salt. In 2014, we drilled and completed a well in the Lula/Iracema Sul area with a final depth of 5,450 meters in 92 days.
As of December 31, 2014, we held exploration rights to one block and six exploration plans in the Santos Basin, comprising 4,774 km2 (1.6 million acres), through Concession Agreements.
Assignment Agreement (Contrato de Cessão Onerosa)
Under the Assignment Agreement, we acquired six blocks and one contingent block which comprise our rights to explore, evaluate and produce up to five bnboe in the pre-salt area of the Santos Basin, and we have already declared commerciality for this entire volume from all six blocks. We are developing these blocks in an integrated manner with the pre-salt areas we already have under concession. Following the declaration of commerciality for these six blocks, we have initiated the revision process of the Assignment Agreement with the Brazilian federal government, and we have returned the contingent block to the Brazilian federal government. See Item 10. “Additional Information—Material Contracts—Assignment Agreement.”
In 2014, we drilled nine wells located in the Assignment Agreement area. Over the next three years, we intend to proceed with our exploration program, and we have been performing an EWT in the Búzios field since March 2015. In the coming years, we intend to continue with our drilling program to acquire reservoir data and develop the fields in the Assignment Agreement area.
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In June 2014, the CNPE enacted Resolution No. 1, which established that Petrobras could be directly engaged by the Brazilian federal government under a production sharing agreement to produce the volume of oil, natural gas and fluid hydrocarbons from the Assignment Agreement areas that exceeds the five bnboe maximum production originally agreed under the Assignment Agreement or that may be negotiated during the revision process. This excess production would be extracted from the following areas regulated by the Assignment Agreement: (i) Búzios, (ii) Entorno de Iara; (iii) Florim and (iv) Nordeste de Tupi. See Item 10. “Additional Information—Material Contracts—Assignment Agreement–Additional Production in the Assignment Agreement Areas.”
Production Sharing Agreement (Contrato de Partilha de Produção)
In October 2013, a consortium led by Petrobras (holding a 40% interest and acting as exclusive operator of the area), Shell (20% interest), Total (20% interest), CNPC (10% interest) and CNOOC (10% interest) was awarded the rights and obligations to operate the Libra block in the ultra-deep waters of the Santos Basin in the first production-sharing regime auction ever held in Brazil. Through this Production Sharing Agreement, the consortium was granted rights to explore and produce in an area comprising 1,547.76 km2 (0.4 million acres) with estimated recoverable volumes ranging from 8 to 12 bnboe, according to the ANP. The exploration phase of the block will continue until December 2, 2017, and the minimum exploratory program to be carried out during this period includes 3D seismic acquisition for the entire block, two exploratory wells and one extended well test. In February 2015, the consortium concluded drilling and testing the first appraisal well. This well is situated four kilometers away from the pioneer well. The drilling results confirmed the presence of an approximately 290-meter oil column and carbonate reservoirs that show high porosity and permeability. The two production tests, performed in two different zones, confirmed strong productivity and oil quality of these reservoirs. See Item 10. “Additional Information—Material Contracts—Production Sharing Agreement.”
Exploration
We continue to explore the Santos Basin pre-salt area. In 2014, we drilled eight exploratory wells, including seven in the pre-salt area, and we made several oil discoveries in the areas of Florim 2, Entorno de Iara 2 and 3, Júpiter Apollonia and NW1 LIBRA. We also declared the commerciality of the new exploratory fields Sul de Sapinhoá, Sépia, Itapu, Norte de Berbigão, Sul de Berbigão, Berbigão, Norte de Sururu, Sul de Sururu, Sururu, Oeste de Atapu, and Atapu, with total estimated recoverable volume of more than 6.2 billion barrels of oil.
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Santos Basin Projects
The primary source of our expected future production growth will be from the Santos Basin pre-salt area. We currently have 16 major projects contracted that are expected to be installed in this area in the coming years. Of these, six are in the Assignment Agreement area (Búzios 1, Búzios 2, Búzios 3, Búzios 4, Sépia and Entorno de Iara). The following FPSOs are currently being constructed:
Field | Unit Type | Production Unit | Crude Oil | Natural Gas (mmcf/d) | Water Depth (meters) |
Iracema Norte | FPSO | Cidade de Itaguaí | 150,000 | 282.5 | 2,100 |
Lula Alto | FPSO | Cidade de Maricá | 150,000 | 211.9 | 2,100 |
Lula Central | FPSO | Cidade de Saquarema | 150,000 | 211.9 | 2,100 |
Lula Sul | FPSO | P-66 | 150,000 | 211.9 | 2,100 |
Búzios 1 | FPSO | P-74 | 150,000 | 247.2 | 2,100 |
Lapa | FPSO | Cidade de Caraguatatuba | 100,000 | 176.6 | 2,100 |
Lula Norte | FPSO | P-67 | 150,000 | 211.9 | 2,100 |
Búzios 2 | FPSO | P-75 | 150,000 | 247.2 | 2,100 |
Lula Extremo Sul | FPSO | P-68 | 150,000 | 211.9 | 2,100 |
Atapu Norte | FPSO | P-69 | 150,000 | 211.9 | 2,100 |
Búzios 3 | FPSO | P-76 | 150,000 | 247.2 | 2,100 |
Atapu Sul | FPSO | P-70 | 150,000 | 211.9 | 2,100 |
Búzios 4 | FPSO | P-77 | 150,000 | 247.2 | 2,100 |
Itapu | FPSO | P-72 | 150,000 | 211.9 | 2,100 |
Berbigão | FPSO | P-71 | 150,000 | 211.9 | 2,100 |
Búzios 6 | FPSO | P-73 | 150,000 | 211.9 | 2,100 |
We are also developing post-salt fields in the Santos Basin. The FPSO Cidade de Itajaí in Baúna (formerly Tiro and Sidon) started operating in February 2013. This FPSO has a capacity to process up to 80,000 bbl/d of oil and 70.6 mmcf/d (2 mmm³/d) of natural gas.
Espírito Santo Basin
From 2000 to 2007, we made important discoveries in the Golfinho, Camarupim and Camarupim Norte fields. In 2014, we have made additional discoveries in the post-salt area of the Espírito Santo basin, including in Tanganika, Brigadeiro and Lontra.
In 2014, we produced oil from 42 fields at an average rate of 51.6 mbbl/d, and our average daily production of natural gas was of 154.1 mmcf/d (4.1 mmm3/d). The proved crude oil and natural gas reserves in the Espírito Santo Basin represented 0.6% and 3.3% in 2014 of our total proved reserves in Brazil, respectively.
As of December 31, 2014, we held exploration rights to 17 blocks (6 onshore and 11 offshore), and 6 exploration plans (1 onshore and 5 offshore), comprising a total of 6,334.51 Km2 (1.53 million acres) in the Espírito Santo Basin.
In 2014, our PROEF program was implemented in the Espírito Santo Basin to improve our operational efficiency. We increased the efficiency of the offshore units of the Espírito Santo Basin operational unit to 92.9% in 2014 (compared to an efficiency target of 88.3%). As a result of our effort, production in 2014 from this area was 52 mbbl/d greater than it otherwise would have been.
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Sergipe-Alagoas Basin
The Sergipe-Alagoas Basin is one of our oldest onshore and shallow water producing basins and one of our new frontiers for offshore exploration. In 2014, we had proved crude oil and natural gas reserves in the Sergipe-Alagoas Basin representing 1.4% and 2.0% of our total proved reserves in Brazil, respectively. Our aggregate production level in the Sergipe–Alagoas Basin was 49.4 mbbl/d of oil and 73.8 mmcf/d (2.0 mmm3/d) of natural gas, largely from onshore fields.
Our exploration efforts in ultra-deep waters in the Sergipe-Alagoas Basin have led to a series of new discoveries. During 2014, we made discoveries of oil and gas resources in the areas informally known as Muriú, Moita Bonita, Farfan, Cumbe and Barra-1, all approximately 100 km from the coast of Aracaju. As of December 31, 2014, we held exploration rights to one block and seven exploration plans in this basin, comprising 5,917 km2 (1.4 million acres).
Other Basins
We produce hydrocarbons and hold exploration acreage in 20 other basins in Brazil. While our onshore production is primarily in mature fields, we plan to sustain and slightly increase production from these fields in the future by using enhanced recovery methods. In 2014, production from these other basins amounted to 160.9 mbbl/d of oil and 311.2 mmcf/d (8.2 mmm3/d) of natural gas.
The most significant potential for exploratory success within our other basins is the equatorial margin and the south of Bahia offshore.
Critical Resources in Exploration and Production
We seek to develop and retain the critical resources that are necessary to meet our production targets. Drilling rigs are an important resource for our exploration and production operations and substantial lead time is required when fleet expansion is needed. When we discovered the pre-salt, in 2006, our activities as operators were constrained by a lack of rigs, but our subsequent efforts to lease additional rigs have eliminated this constraint. Whereas in 2008 we only had three rigs capable of drilling in waters with depth greater than 2,000 meters (6,560 feet), we had 39 as of December 31, 2014. In addition to those rigs, we hired three others to begin operating in the first half of 2015, including two in the Libra area. We now have sufficient rigs to meet our long-term production targets, and we will continue to evaluate our drilling requirements and will adjust our fleet size as needed.
In addition to leasing the additional rigs that are now operating in Brazil, all of which were built internationally, we have been working since 2008 on developing the capacity to construct drilling rigs in Brazil. We have awarded contracts for additional rigs to be built in Brazil to meet our long-term needs and satisfy Brazilian local content requirements, under the expected terms of Production Sharing Agreements, the Assignment Agreement and concession agreements obtained in later Brazilian exploration bid rounds. The contracts for the locally built rigs were awarded to Sete Brasil S.A. (Sete BR), a Brazilian company in which Petrobras holds a 5% interest.
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Drilling Units in Use by Exploration and Production on December 31 of Each Year | ||||||
| 2014 | 2013 | 2012 | |||
| Leased | Owned | Leased | Owned | Leased | Owned |
Onshore | 16 | 10 | 12 | 10 | 24 | 11 |
Offshore, by water depth (WD) | 55 | 6 | 61 | 7 | 65 | 9 |
Jack-up rigs | – | 2 | – | 3 | – | 5 |
Floating rigs: | 55 | 4 | 61 | 4 | 65 | 4 |
500 to 999 meters WD | 2 | 2 | 4 | 2 | 6 | 2 |
1000 to 1999 meters WD | 14 | 2 | 17 | 2 | 19 | 2 |
2000 to 3200 meters WD | 39 | – | 40 | – | 40 | – |
In order to advance our exploration and production plans, we also need to secure a number of specialized vessels to connect wells to the FPSOs and for subsea construction. In the past we have experienced shortages of PLSVs, but we now have enough capacity of specialized vessels to meet ourneeds.
Refining, Transportation and Marketing
Refining, Transportation and Marketing Key Statistics | |||
| 2014 | 2013 | 2012 |
| (U.S.$ million) | ||
Refining, Transportation and Marketing: |
|
|
|
Sales revenues | 112,320 | 111,665 | 116,826 |
Income (loss) before income taxes | (22,983) | (12,401) | (17,700) |
Property, plant and equipment | 49,662 | 66,552 | 63,822 |
Capital expenditures and investments | 7,778 | 14,243 | 14,745 |
We are an integrated company with a dominant market share in our home market. We own and operate 13 refineries in Brazil (including Abreu e Lima – RNEST, which became operational in December 2014), with a total net distillation capacity of 2,176 mbbl/d, and are one of the world’s largest refiners. As of December 31, 2014, we operated substantially all of Brazil’s total refining capacity. We supplied almost all of the refined product needs of third-party wholesalers, exporters and petrochemical companies, in addition to the needs of our Distribution segment. We operate a large and complex infrastructure of pipelines, terminals and a shipping fleet to transport oil products and crude oil to domestic and export markets. Most of our refineries are located near our crude oil pipelines, storage facilities, refined product pipelines and major petrochemical facilities, facilitating access to crude oil supplies and end-users.
From 2010 to 2012, the Brazilian market was characterized by very high rates of growth in consumption of oil products,driven primarily by economic growth, rising real incomes and the decline of domestic ethanol production. Because domestic oil consumption has grown faster than our oil production, we have shifted from being a net exporter of oil and oil products to being a net importer. Since 2013, the domestic growth rate of consumption of oil products has diminished, particularly diesel, as a result of the Brazilian economic slowdown. The21% growth rate during this period for fuel oil sales was an exception resulting mainly from increased thermoelectric consumption.
Our Refining, Transportation and Marketing segment also includes (i) petrochemical operations that add value to the hydrocarbons we produce and meet the needs of the growing Brazilian economy and (ii) extraction and processing of shale.
We participate in refining, transportation and marketing operations outside of Brazil through our International business segment. See “—International.”
Refining
Our crude distillation capacity in Brazil as of December 31, 2014, was 2,176 mbbl/d and our average throughput during 2014 was 2,106 mbbl/d.
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The following table shows the installed capacity of our Brazilian refineries as of December 31, 2014, and the average daily throughputs of our refineries in Brazil in 2014, 2013 and 2012.
Capacity and Average Throughput of Refineries | |||||
Name (Alternative Name) | Location | Crude Distillation Capacity at December 31, 2014 | Average Throughput* | ||
2014 | 2013 | 2012 | |||
|
| (mbbl/d) | (mbbl/d) | ||
LUBNOR | Fortaleza (CE) | 8 | 9 | 8 | 8 |
RECAP (Capuava) | Capuava (SP) | 53 | 54 | 53 | 53 |
REDUC (Duque de Caxias) | Duque de Caxias (RJ) | 239 | 271 | 282 | 263 |
REFAP (Alberto Pasqualini) | Canoas (RS) | 201 | 192 | 197 | 154 |
REGAP (Gabriel Passos) | Betim (MG) | 157 | 158 | 150 | 145 |
REMAN (Isaac Sabbá) | Manaus (AM) | 46 | 44 | 42 | 38 |
REPAR (Presidente Getúlio Vargas) | Araucária (PR) | 208 | 204 | 194 | 199 |
REPLAN (Paulínia) | Paulinia (SP) | 415 | 408 | 421 | 387 |
REVAP (Henrique Lage) | São Jose dos Campos (SP) | 252 | 262 | 234 | 248 |
RLAM (Landulpho Alves) | Mataripe (BA) | 315 | 287 | 279 | 239 |
RPBC (Presidente Bernardes) | Cubatão (SP) | 170 | 177 | 177 | 172 |
RPCC (Potiguar Clara Camarão) | Guamaré (RN) | 38 | 38 | 37 | 37 |
RNEST (Abreu e Lima) | Ipojuca (PE) | 74 | 3 | – | – |
Average crude oil throughput |
| 2,176 | 2,065 | 2,029 | 1,898 |
Average NGL throughput |
| – | 41 | 45 | 46 |
Average throughput |
| – | 2,106 | 2,074 | 1,944 |
* Consider oil and NGLs processing (fresh feedstock)
In recent years, we have made substantial investments in our refinery system for the following purposes:
· Improving gasoline and diesel quality to comply with stricter environmental regulations;
· Increasing crude slate flexibility to process more Brazilian crude, especially from the pre-salt areas, taking advantage of light/heavy crude price differentials;
· Increasing residue conversion; and
· Reducing the environmental impact of our refining operations.
In 2014, we invested a total of U.S.$1.5 billion in our refineries (excluding RNEST), of which U.S.$712 million was invested in hydrotreating units necessary to improve the quality of our diesel oil and gasoline.
Our modernization efforts to meet stricter standards (such as diesel S-10 and gasoline S-50) and improve facilities for our existing refineries began in 2005 and have been largely completed. In 2015, we expect to finalize the construction of the diesel hydrotreating unit at RPBC.
Major Refinery Projects
In December 2014, the first refining unit of Abreu e Lima – RNEST refinery in northeastern Brazil, which is designed to process 115 mbbl/d of crude oil, to produce low sulfur diesel (10 ppm) as well as LPG, naphtha, bunker fuel and petroleum coke, started fuel production with a partial capacity of 74 mbbl/d.
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SuspendedMajor Refinery Projects
Recent changes in our business context and the impact of the Lava Jato investigation prompted a review of our future prospects and ultimately led to the reduction in the pace of our capital expenditures. As a result, our management postponed for an extended period of time the completion of the following refining projects: (i) Petrochemical Complex of Rio de Janeiro (Complexo Petroquímico do Rio de Janeiro - Comperj); and (ii) the second refining unit of RNEST. We have recognized impairment lossesfor the fiscal year ended December 31, 2014 of U.S.$11.7 billion. For further information, see Notes 3.3 and 14 to our audited consolidated financial statements.
In addition, in January 2015, our board of directors decided not to move forward with the construction of two new refineries in northeastern Brazil (Premium I and Premium II), because the assumptions and conditions in our 2014-2018 Plan were not met. We havewritten off from our financial statements for the fiscal year ended December 31, 2014 U.S.$1.24 billion due to the cancellation of these projects. See Note 12.4 to our audited consolidated financial statements.
Domestic Output of Oil Products and Consolidated Sales Volumes
The following tables summarize our domestic output of oil products and consolidated sales by product for the last three years.
Domestic Output of Oil Products: Refining and marketing operations, mbbl/d(1) | |||
| 2014 | 2013 | 2012 |
Diesel | 853 | 850 | 782 |
Gasoline | 494 | 491 | 438 |
Fuel oil | 286 | 255 | 238 |
Naphtha | 85 | 90 | 106 |
LPG | 130 | 137 | 143 |
Jet fuel | 105 | 96 | 93 |
Other | 217 | 206 | 196 |
Total domestic output of oil products | 2,170 | 2,124 | 1,997 |
Installed capacity(2) | 2,176 | 2,102 | 2,018 |
Crude distillation utilization (%)(3) | 98 | 97 | 94 |
Domestic crude oil as % of total feedstock processed | 82 | 82 | 82 |
(1) Output volumes are larger than throughput volumes as a result of gains during the refining process.
(2) Installed capacity as of December 31, 2014, 2013 and 2012.
(3) Crude distillation utilization considers average installed capacity as of December 31, 2014, 2013 and 2012.
Consolidated Sales Volumes, mbbl/d | |||
| 2014 | 2013 | 2012 |
Diesel | 1,001 | 984 | 937 |
Gasoline | 620 | 590 | 570 |
Fuel oil | 119 | 98 | 84 |
Naphtha | 163 | 171 | 165 |
LPG | 235 | 231 | 224 |
Jet fuel | 110 | 106 | 106 |
Other | 210 | 203 | 199 |
Total oil products | 2,458 | 2,383 | 2,285 |
Ethanol, nitrogen fertilizers, renewables and other products | 99 | 91 | 83 |
Natural gas | 446 | 409 | 357 |
Total domestic market | 3,003 | 2,883 | 2,725 |
Exports | 393 | 395 | 554 |
International sales | 571 | 514 | 506 |
Total international market | 964 | 909 | 1,060 |
Total sales volumes | 3,967 | 3,792 | 3,785 |
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Delivery Commitments
We sell crude oil through long-term and spot-market contracts. Our long-term contracts specify the delivery of fixed and determinable quantities, subject to a price negotiation with third parties on a delivery-by-delivery basis. We are committed through long-term contracts to deliver a total of approximately 200 mbbl/d of crude oil in 2015. We believe our domestic proved reserves will be sufficient to allow us to continue to deliver all contracted volumes. For 2015, approximately 40% of our exported crude oil will be committed to meeting our contractual delivery commitments to third parties.
Imports and Exports
Our import and export of oil products depend on our refinery output and Brazilian demand levels. Much of the crude oil we produce in Brazil is heavy or intermediate. We import some light crude to balance the slate for our refineries, and export heavier crude oil from our production in Brazil. We also import oil products to balance any shortfall between production from our Brazilian refineries and the market demand for each product.
The demand for oil products in Brazil increased rapidly between 2010 and 2012, at an average of 7.9% per year. From 2010 to 2012, we met this incremental growth in demand primarily by increasing imports, as our refining capacity was insufficient to meet the increasing demand. Despite the slower rates of growth in consumption of oil products in 2013 and 2014, we are still a net importer of oil products.
In 2014, due to the positive results from modernization investments, our Brazilian refineries expanded output by 2.1%, while consumption increased by 2.7%. This led to an increase in oil product imports compared to 2013.
We export oil products that our refineries produce in excess of Brazilian market demand, which is largely fuel oil.
The table below shows our exports and imports of crude oil and oil products in 2014, 2013 and 2012:
Exports and Imports of Crude Oil and Oil Products, mbbl/d | |||
| 2014 | 2013 | 2012 |
Exports |
|
|
|
Crude oil | 232 | 207 | 364 |
Fuel oil (including bunker fuel) | 128 | 151 | 153 |
Gasoline | 0 | 0 | 1 |
Other | 30 | 35 | 30 |
Total exports | 390 | 393 | 548 |
Imports |
|
|
|
Crude oil | 392 | 404 | 346 |
Diesel | 185 | 174 | 190 |
LPG | 70 | 63 | 53 |
Gasoline | 41 | 32 | 87 |
Naphtha | 88 | 83 | 58 |
Other | 29 | 37 | 45 |
Total imports | 805 | 793 | 779 |
Logistics and Infrastructure for Oil and Oil Products
We own and operate an extensive network of crude oil and oil product pipelines in Brazil that connect our terminals, refineries and other primary distribution points. On December 31, 2014, our onshore and offshore, crude oil and oil products pipelines extended over 20,913 km (12,998 miles). We operate 28 marine storage terminals and 21 other tank farms with nominal aggregate storage capacity of 64 mmbbl. Our marine terminals handle an average 10,595 tankers and oil barges annually.
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We operate a fleet of owned and chartered vessels. These provide shuttle services between our producing basins offshore Brazil and the Brazilian mainland, and shipping to other parts of South America and internationally. The fleet includes double-hulled vessels, which operate internationally where required, and single-hulled vessels, which operate in Brazil only. We are increasing our fleet of owned vessels to replace older vessels and decrease our dependency on chartered vessels. Upgrades will include replacing single-hulled tankers with double-hulled vessels and replacing vessels nearing the end of their 25-year useful life. Our long-term strategy continues to focus on the flexibility afforded by operating a combination of owned and chartered vessels.
Two new oil tankers were delivered to Transpetro in 2014. We plan to have another 37 vessels delivered to us in the future, all of which will be built in Brazilian shipyards.
The table below shows our operating fleet and vessels under contract as of December 31, 2014.
Owned and Chartered Vessels in Operation and Under Construction Contracts at December 31, 2014 | ||||
| In Operation | Under Contract/Construction | ||
| Number | Tons Deadweight Capacity | Number | Tons Deadweight Capacity |
Owned fleet: |
|
|
|
|
Tankers | 48 | 4,034,223 | 29 | 2,928,135 |
LPG tankers | 5 | 35,653 | 8 | 42,000 |
Anchor Handling Tug Supply (AHTS) | 1 | 1,920 | – | – |
Total | 54 | 4,071,796 | 37 | 2,970,135 |
Chartered vessels: |
|
|
|
|
Tankers | 171 | 17,352,452 | – | – |
LPG tankers | 32 | 656,029 | – | – |
Total | 203 | 18,008,481 | – | – |
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Petrochemicals
Our petrochemicals operations provide an outlet for our growing production volumes of gas and other refined products, which increase their value and provide substitute for products that are otherwise imported. Our strategy is to operate in an integrated manner with the other businesses of Petrobras, preferably through partnerships with other companies.
We engage in our petrochemicals operations through the following subsidiaries, joint ventures, joint operations and associated companies:
| mmt/y (nominal capacity) | Petrobras interest (%) |
Braskem(1): | ||
Ethylene | 3.95 | 36.20 |
Polyethylene | 3.03 | |
Polypropylene | 3.99 | |
DETEN Química S.A.: | ||
LAB(1) | 0.22 | 27.88 |
LABSA(1) | 0.12 | |
METANOR S.A./COPENOR S.A.(2): | ||
Methanol | 0.08 | 34.54 |
Formaldehyde | 0.09 | |
Hexamine | 0.01 | |
FCC Fábrica Carioca de Catalisadores S.A.: | ||
Catalysts | 0.04 | 50.00 |
Additives | 0.01 | |
PETROQUÍMICASUAPE COMPLEX(3): | ||
Purified Terephthalic Acid - PTA | 0.70 | 100.00 |
Polyethylene Terephthalate - PET | 0.45 | |
Polymer and polyester filament textiles | 0.24 | |
PETROCOQUE S.A.: | ||
Calcined petroleum coke | 0.50 | 50.00 |
________________________ |
|
|
(1) Feedstock for the production of biodegradable detergents.
(2) Copernor S.A. is a Metanor S.A. subsidiary.
(3) The PTA unit started operations in January 2013 and the PET unit started operations in August 2014.
Our investments in petrochemical companies amount to U.S.$1.8 billion and the largest investment is in Braskem S.A. (Braskem), Brazil’s largest petrochemical company.
We also recognized impairment lossesfor the fiscal year ended December 31, 2014 ofU.S.$1.1 billion with respect to the Suape Petrochemical complex, mainly attributable to changes in market assumptions and forecasts resulting from a decrease in economic activity, a reduction in the spread for petrochemical products in the international market and modifications in tax regulations. For further information, see Note 14 to our audited consolidated financial statements.
Our management also decided that we will not participate in the construction of petrochemical projects that were under evaluation or various stages of engineering or design: (i) Aromatics, MDI and Policarbonates, all projects located in the Complexo Petroquímico do Rio de Janeiro—Comperj and (ii) Companhia de Coque Calcinado de Petróleo—Coquepar.
In August 2013, Petrobras executed an agreement to sell 100% of its equity interest in Petroquímica Innova S.A. to Videolar S.A. and its majority shareholder for U.S.$369 million. This transaction closed in October 2014, after approval by the Brazilian Antitrust Authority – CADE.
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Distribution Key Statistics | |||
| 2014 | 2013 | 2012 |
| (U.S.$ million) | ||
Distribution: |
|
|
|
Sales revenues | 41,729 | 40,023 | 40,596 |
Income (loss) before income taxes | 760 | 1,306 | 1,387 |
Property, plant and equipment | 2,284 | 2,350 | 2,374 |
Capital expenditures and investments | 446 | 514 | 666 |
We are Brazil’s leading oil products distributor, operating through our own retail network, through our own wholesale channels, and by supplying other fuel wholesalers and retailers. Our Distribution segment sells oil products that are primarily produced by our Refining, Transportation and Marketing segment, or RTM, and works to expand the domestic market for these oil products and for other fuels, including LPG, ethanol and biodiesel.
The primary focus of our Distribution segment is to:
· Lead the market in the domestic distribution of oil products and biofuels, increasing our market share and profit through an integrated supply chain; and
· Be the preferred brand of our consumers while upholding and promoting social and environmental responsibility.
We supply and operate Petrobras Distribuidora, which accounts for 37.9% of the total Brazilian retail and wholesale distribution market. Petrobras Distribuidora distributes oil products, ethanol, biodiesel and natural gas to retail, commercial and industrial customers. In 2014, Petrobras Distribuidora sold the equivalent of 988.9 mbbl/d of oil products and other fuels to wholesale and retail customers, of which the largest portion (41.1%) was diesel.
At December 31, 2014, our Petrobras Distribuidora branded service station network was Brazil’s leading retail marketer, with 7,931 service stations, or 20% of the stations in Brazil. Petrobras Distribuidora owned and franchised stations that represented 29.7% of Brazil’s retail sales of diesel, gasoline, ethanol, vehicular natural gas and lubricants in 2014.
Most Petrobras Distribuidora stations are owned by franchisees that use the Petrobras Distribuidora brand name under license and purchase exclusively from us; we also provide franchisees with technical support, training and advertising. We own 1,060 of the Petrobras Distribuidora stations and are required by law to subcontract the operation of these owned stations to third parties. We believe that our market share position is supported by a strong Petrobras Distribuidora brand image and by the remodeling of service stations and addition of lubrication centers and convenience stores.
Our wholesale distribution of oil products and biofuels under the Petrobras Distribuidora brand to commercial and industrial customers accounts for 57.1% of the total Brazilian wholesale market. Our customers include aviation, transportation and industrial companies, as well as utilities and government entities.
Our LPG distribution business – Liquigas Distribuidora – held a 22.5% market share and ranked second in LPG sales in Brazil in 2014, according to the ANP.
We participate in the retail sector in other South American countries through our International business segment. See “—International.”
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Gas and Power Key Statistics | |||
| 2014 | 2013 | 2012 |
| (U.S.$ million) | ||
Gas and Power: |
|
|
|
Sales revenues | 17,882 | 14,017 | 11,803 |
Income (loss) before income taxes | (553) | 921 | 1,277 |
Property, plant and equipment | 22,126 | 20,882 | 21,585 |
Capital expenditures and investments | 2,545 | 2,716 | 2,113 |
Our Gas and Power segment comprises gas transmission and distribution, LNG regasification, the manufacture of nitrogen-based fertilizers, gas-fired and flex-fuel power generation, and power generation from renewable sources, including solar, wind and small-scale hydroelectric sources.
The primary focus of our Gas and Power segment is to:
· Add value by monetizing Petrobras’s natural gas resources;
· Assure flexibility and reliability in the supply of natural gas;
· Consolidate our electric energy business, exploring synergies between our natural gas supply and power generation capacities, along with the expansion of our electric energy commercialization activities; and
· Add value to natural gas by chemically processing it, prioritizing nitrogen fertilizers and other value- added products.
As a result of our efforts to develop the market, natural gas in 2013 supplied 12.8% of Brazil’s total energy needs, compared to 3.7% in 1998, and is expected to supply 14.2% of Brazil’s total energy needs by 2023, according to Empresa de Pesquisa Energética, a branch of the MME.
Natural Gas
We have three principal markets for natural gas:
· Industrial, commercial and retail customers;
· Thermoelectric generation; and
· Consumption by our refineries and fertilizer plants.
Our volume of natural gas sales to industrial, gas-fired electric power generation, commercial and retail customers in 2014 was70.5 mmm3/d, representing an increase of 10% compared to 2013. This increase is attributable to the increase in consumption by the power generation industry by 20% from 2013 to 2014 due to low rainfall, which reduced the reservoir storage levels of Brazilian hydroelectric power plants. Natural gas consumption by refineries and fertilizer plants increased by 12%.
As a result of a multi-year infrastructure development program in pipeline networks that was completed in 2011, we now have an integrated system centered around two main, interlinked pipeline networks that allow us to deliver natural gas from our main offshore natural gas producing fields in the Santos, Campos and Espírito Santo Basins, as well as from three LNG terminals, and a gas pipeline connection with Bolivia.
55
Currently, our natural gas pipeline network extends over 9,190 km. In 2014, we invested U.S.$207 million in our natural gas infrastructure, and in 2015, we plan to invest in (i) the construction of two gas transfer pipelines connecting our pre-salt natural gas producing fields to the Cabiúnas Terminal and Comperj’s processing plant; (ii) the expansion of the natural gas processing capacity of the Cabiúnas Terminal in order to receive up to 459 mmcf/d (13 mmm3/d) with the expectation of increasing the associated natural gas production from the pre-salt reservoirs in the Santos Basin, and (iii) the development of a natural gas processing plant with a capacity of 742 mmcf/d (21 mmm3/d), located at Comperj’s petrochemical complex, also associated with the pre-salt reservoirs in the Santos Basin. The Cabiúnas Terminal expansion is expected to be fully operational by January 2016 and Comperj’s natural gas processing plant (which is a specific project that has not been subject to any impairment) is scheduled to begin operations by October 2017.
We also own and operate three LNG flexible terminals using three FSRUs (Floating Storage and Regasification Units), one in Guanabara Bay (State of Rio de Janeiro) with a send-out capacity of 706 mmcf/d (20 mmm3/d), another in Pecém (State of Ceará) in Northeastern Brazil with a send-out capacity of 247 mmcf/d (7 mmm3/d) and the last one located in the Todos os Santos Bay (State of Bahia), with a send-out capacity of 494 mmcf/d (14 mmm3/d).
In 2014, we conducted 114 cargo purchase operations, 99 of which were received in Brazil (including two cargo later exported) and 15 directly resold abroad.
We also own and operate four natural gas processing facilities. Two of them, Sul Capixaba and Cacimbas, located in the State of Espírito Santo, have the capacity to process 2.5 mmm3/d and 16 mmm3/d of natural gas, respectively, and are designated to process natural gas from the Campos Basin. Caraguatatuba plant, located in the State of São Paulo, has the capacity to process 20 mmm3/d of natural gas, and is designated to process natural gas from the Santos Basin post-salt and pre-salt areas. The TECAB plant, located in State of Rio de Janeiro, has the capacity to process 24 mmm3/d of natural gas from the Campos Basin and the Santos Basin pre-salt.
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The map below shows our gas pipeline networks, LNG terminals and natural gas processing plants.
We hold interests ranging from 24% to 100% in 20 of Brazil’s 27 local gas distribution companies. We had approximately a 23.5% net equity interest in the combined 2,401.4 mmcf/d (68 mmm3/d) of natural gas distributed by Brazil’s local distribution companies in 2014.
According to our estimates, our three most significant holdings, CEG Rio, Bahiagás and Petrobras Distribuidora, are Brazil’s third, fifth and sixth largest gas distributors. These companies, together with independent distributors Comgás and CEG supply 64% of the Brazilian market.
In October 2014, we sold our 40% equity interest in Gasmig, the local gas distribution company of the State of Minas Gerais, representing a 2% reduction in our net equity interest in natural gas distributed in Brazil compared to 2013.
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Principal Natural Gas Local Distribution Holdings | ||||
Name | State | Group Interest % | Average Gas Sales in 2014 (mmm3/d) | Customers(1) |
|
|
|
|
|
CEG RIO | Rio de Janeiro | 37.41 | 10.5 | 46,053 |
BAHIAGAS | Bahia | 41.50 | 3.8 | 31,555 |
PETROBRAS DISTRIBUIDORA | Espírito Santo | 100.00 | 3.5 | 31,251 |
COPERGAS | Pernambuco | 41.50 | 3.2 | 16,225 |
___________________________
(1) Units of households and industries attended by local gas distribution companies.
The table below shows the sources of our natural gas supply, our sales and internal consumption of natural gas, and revenues in our local gas distribution operations for each of the past three years.
Supply and Sales of Natural Gas in Brazil, mmm3/d | |||
| 2014 | 2013 | 2012 |
Sources of natural gas supply |
|
|
|
Domestic production | 43.2 | 40.8 | 39.5 |
Imported from Bolivia | 32.9 | 30.5 | 27.0 |
LNG | 20.0 | 14.5 | 8.4 |
Total natural gas supply | 96.1 | 85.9 | 74.9 |
Sales of natural gas |
|
|
|
Sales to local gas distribution companies(1) | 38.9 | 38.6 | 39.3 |
Sales to gas-fired power plants | 31.6 | 26.0 | 16.6 |
Total sales of natural gas | 70.5 | 64.6 | 55.9 |
Internal consumption (refineries, fertilizer and gas-fired power plants)(2) | 25.6 | 20.8 | 18.5 |
Revenues (U.S.$ billion)(3) | 9.8 | 9.0 | 8.1 |
________________________
(1) Includes sales to local gas distribution companies in which we have an equity interest.
(2) Includes gas used in the transport system.
(3) Includes natural gas sales revenues from the Natural Gas segment to other operating segments, service and other revenues from natural gas companies.
Long-Term Natural Gas Commitments
When we began construction of the Bolivia-Brazil pipeline in 1996, we entered into a long-term Gas Supply Agreement, or GSA, with the Bolivian state-owned company Yacimientos Petroliferos Fiscales Bolivianos, or YPFB, to purchase certain minimum volumes of natural gas at prices linked to the international fuel oil price through 2019, after which the agreement may be extended until all contracted volume has been delivered.
On December, 19, 2009, Petrobras and YPFB signed the fourth amendment to the GSA, which provides for annual additional payments to YPFB for liquids contained in the natural gas purchased by Petrobras through the GSA. Until August 18, 2014, Petrobras had paid all obligations owed for 2007, but YPFB had not then met the condition precedent necessary to receive additional payments for the years after 2007.
After more than two years of negotiations, on August 18, 2014, Petrobras and YPFB reached an agreement and settled contractual disputes regarding several aspects of the GSA, including those related to payment for the liquids contained in the natural gas provided by YPFB under the GSA’s fourth amendment, which was formally terminated as of January 1, 2014. As a result of this agreement, Petrobras has agreed to pay YPFB a net lump sum of U.S.$438 million, primarily for the liquids contained in the natural gas purchased by Petrobras from 2008 to 2013. The net economic effect of this arrangement with YPFB has generated a net positive cash flow for us of U.S.$319.78 million as of February 28, 2015, and we will generate an expected net present value of U.S.$566.15 million by December 2016. We also reached an agreement that provides for the supply of natural gas for the Cuiabá power plant (UTE Cuiabá), currently being leased by us, to facilitate operations through December 31, 2016.
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Our agreement with YPFB also provides that with respect to natural gas we find in the gas fields we operate in Bolivia, we will have the right to sell such natural gas to the Brazilian market after confirming that Bolivian market needs have been met.
Our volume obligations under the ship-or-pay arrangements entered into with Gas Transboliviano S.A. (GTB) and Transportadora Brasileira Gasoduto Bolívia-Brasil S.A. (TBG) were generally designed to match our gas purchase obligations under the GSA through 2019. The tables below show our contractual commitments under these agreements for the five-year period from 2015 through 2019.
| 2015 | 2016 | 2017 | 2018 | 2019 |
Purchase commitments to YPFB |
|
|
|
|
|
Volume obligation (mmm3/d)(1) | 24.06 | 24.06 | 24.06 | 24.06 | 24.06 |
Volume obligation (mmcf/d)(1) | 850.00 | 850.00 | 850.00 | 850.00 | 850.00 |
Brent crude oil projection (U.S.$)(2) | 58.00 | 70.20 | 70.00 | 70.00 | 70.00 |
Estimated payments (U.S.$ million)(3) | 1,785.80 | 1,571.70 | 1,691.30 | 1,690.60 | 1,687.40 |
Ship-or-pay contract with GTB |
|
|
|
|
|
Volume commitment (mmm3/d) | 30.08 | 30.08 | 30.08 | 30.08 | 30.08 |
Volume commitment (mmcf/d) | 1,062.26 | 1,062.26 | 1,062.26 | 1,062.26 | 1,062.26 |
Estimated payments (U.S.$ million)(5) | 139.97 | 141.04 | 141.37 | 142.06 | 142.78 |
Ship-or-pay contract with TBG |
|
|
|
|
|
Volume commitment (mmm3/d)(4) | 35.28 | 35.28 | 35.28 | 35.28 | 35.28 |
Volume commitment (mmcf/d) | 1,246.09 | 1,246.09 | 1,246.09 | 1,246.09 | 1,246.09 |
Estimated payments (U.S.$ million)(5) | 518.19 | 522.86 | 527.00 | 529.29 | 531.97 |
(1) 25.3% of contracted volume supplied by Petrobras Bolivia.
(2) Brent price forecast based on our 2030 Strategic Plan, which is currently under review by our management.
(3) Estimated payments are calculated using gas prices expected for each year based on our Brent price forecast. Gas prices may be adjusted in the future based on contract clauses and amounts of natural gas purchased by Petrobras may vary annually.
(4) Includes ship-or-pay contracts relating to TBG’s capacity increase.
(5) Amounts calculated based on current prices defined in natural gas transport contracts.
Natural Gas Sales Contracts
We sell our gas primarily to local gas distribution companies and to gas fired plants generally based on standard take-or-pay, long-term supply contracts. This represents 70% of our total sale volumes, and the price formulas under these contracts are mainly indexed to an international fuel oil basket. In order to maintain the competitiveness of our natural gas in the Brazilian market, since 2011 we have applied a non-permanent discount to the prices we charge under some of our natural gas sales contracts. Additionally, we have a variety of sales contracts designed to create flexibility in matching customer demand with our gas supply capabilities. These include flexible and interruptible long-term gas sales contracts, auction mechanisms for short-term contracts, weekly electronic auctions and a type of gas sales contract that consists of a seller delivery option that helps balance natural gas sales in case of low demand for natural gas from gas-fired power plants. In this circumstance, the excess natural gas volumes are offered to end consumers who ordinarily use energy sources other than natural gas.
In 2014, we continued to renegotiate some existing long-term natural gas sales contracts with local distribution companies of natural gas in order to promote adjustments tailored to specific market demands, encompassing term extensions for some contracts and prolonging our natural gas sales portfolio.
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The table below shows our future gas supply commitments from 2015 to 2019, including sales to both local gas distribution companies and gas-fired power plants:
Future Commitments under Natural Gas Sales Contracts, mmm3/d | 2015 | 2016 | 2017 | 2018 | 2019 |
To local gas distribution companies: |
|
|
|
|
|
Related parties(1) | 17.66 | 18.10 | 18.20 | 18.42 | 19.00 |
Third parties | 20.34 | 20.65 | 20.81 | 21.27 | 21.27 |
To gas-fired power plants: |
|
|
|
|
|
Related parties(1) | 3.67 | 0.65 | 0.18 | 0.17 | 0.20 |
Third parties | 11.63 | 11.44 | 11.53 | 11.42 | 11.48 |
Total(2) | 53.31 | 50.85 | 50.71 | 51.28 | 51.96 |
Estimated amounts to be invoiced (U.S.$ billion)(3)(4) | 6.6 | 6.4 | 6.3 | 6.3 | 6.3 |
(1) For purposes of this table, “related parties” include all local gas distribution companies and power generation plants in which we have an equity interest and “third parties” refer to those in which we do not have an equity interest.
(2) Estimated volumes are based on “take or pay” agreements in our contracts, expected volumes and contracts under negotiation (including renewals of existing contracts), not maximum sales.
(3) Estimates are based on outside sales and do not include internal consumption or transfers.
(4) Prices may be adjusted in the future and actual amounts may vary.
Fertilizers
We are expanding production of nitrogenous fertilizers in order to meet the growing needs of Brazilian agriculture, to substitute for imports, and to expand the market for the growing production of our associated natural gas.
Our fertilizer plants in Bahia, Sergipe and Paraná produce ammonia and urea for the Brazilian market. The combined production capacity of these plants is 1,667,000 t/y of urea and 1,265,000 t/y of ammonia. Most of our ammonia production is used to produce urea, and the excess production is mainly sold in the Brazilian market. In 2014, we started the production of ammonium sulfate in Sergipe in a unit with a 300,000 t/y production capacity.
The table below shows our ammonia and urea sales, and revenues for each of the past three years:
Ammonia and Urea (t/y) | |||
| 2014 | 2013 | 2012 |
Ammonia | 234,339 | 205,029 | 229,575 |
Urea | 1,046,004 | 1,071,827 | 848,000 |
Revenues (U.S.$ million)(1) | 663 | 621 | 571 |
(1) Includes nitrogenous fertilizers sales revenues from the Fertilizer segment to other operating segments, services and other revenues from fertilizers companies.
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Our business context of lower projected economic growth ultimately led to the reduction in the pace of our capital expenditures. As a result, our management decided to reevaluate the schedule for the construction of the following fertilizing facilities:
• UFN III, with the capacity to produce 1.2 mmt/y of urea and 70 mt/y of ammonia from 2.2 mmm3/d of natural gas; and
• UFN V, with the capacity to produce 519,000 t/y of ammonia from 1.3 mmm3/d of natural gas.
For further information, see Note 14 to our audited consolidated financial statements.
We haverecognized impairment lossesfor the fiscal year ended December 31, 2014 of U.S.$116 million with respect totheAraucária fertilizer plant. The impairment loss is mainly attributable to operational inputs that required higher capital expenditures during 2014. See Note 14 to our audited consolidated financial statements.
Power
Brazilian electricity needs are mainly supplied by hydroelectric power plants (89,211 MW of installed capacity), which account for 67% of Brazil’s generation capacity. Hydroelectric power plants are dependent on the annual level of rainfall; in the years where rainfall is abundant, Brazilian hydroelectric power plants will generate more electricity and consequently less generation from thermoelectric power plants will be demanded. The total installed capacity of the Brazilian National Interconnected Power Grid (Sistema Interligado Nacional—SIN) in 2014 was 133,713 MW. Of this total, 6,410 MW (or 4.8%) was available from 21 thermoelectric plants we operate. These plants are designed to supplement power from the hydroelectric power plants.
In 2014, hydroelectric power plants in Brazil generated 44,815 MWavg, which corresponded to 69% of Brazil’s total electricity needs (64,728 MWavg). Hydroelectric generation capacity is supplemented by other sources of energy (wind, coal, nuclear, fuel oil, diesel oil, natural gas, and others). Total electricity generated by these sources averaged 19,913 MW in 2014, of which our thermoelectric power plants contributed 4,761 MWavg, as compared to 4,043 MWavg in 2013 and 2,699 MWavg in 2012. In 2014, we invested U.S.$299 million in our power business segment.
Electricity Sales and Commitments for Future Generation Capacity
Under Brazil’s power pricing regime, a thermoelectric power plant may sell only electricity that is certified by the MME and which corresponds to a fraction of its installed capacity. This certificate is granted to ensure a constant sale of commercial capacity over the course of years to each power plant, given its role within Brazil’s system to supplement hydroelectricity power during periods of unfavorable rainfall. The amount of certified capacity for each power plant is determined by its expected capacity to generate energy over time.
The total capacity certified by the MME (garantia física) may be sold through long-term contracts in auctions to power distribution companies (standby availability), sold through bilateral contracts executed with free customers and used to attend the energy needs of our own facilities.
In exchange for selling this certified capacity, the thermoelectric power plants shall produce energy whenever requested by the national operator (ONS). In addition to a capacity payment, thermoelectric power plants also receive from the Electric Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica, or CCEE) reimbursement for its variable costs (previously declared to MME to calculate its commercial certified capacity) incurred whenever they are requested to generate electricity.
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In 2014, the commercial capacity certified by MME for all thermoelectric power plants controlled by us was 4,222 MWavg, although our total generating capacity was 6,410 MWavg. Of the total 4,542 MWavg of commercial capacity available (capacidade comercial disponívelor lastro) for sale in 2014, approximately 53% was sold as standby availability in public auctions in the regulated market (compared to 39% in 2013) and approximately 35% was committed under bilateral contracts and self-production (i.e. sales to related parties) (compared to 53% in 2013).
In 2014, public auctions on the regulated market were the main channel used by our thermoelectric generation business to sell energy that had not been previously contracted. Distribution companies must purchase, through a public auction process on the regulated market, their expected electricity requirements for their captive customers. The public auction process is administered by ANEEL, either directly or through theCâmara de Comercialização de Energia Elétrica (Electric Energy Trading Chamber), or CCEE, under certain guidelines provided by the MME.
Existing power generators (such as our thermoelectric power plants) can hold auctions (i) in the year before the initial delivery date (“A-1 Auctions”), (ii) every year, for the delivery of energy for up to the following 15 years (“A Auctions”) and (iii) every year for the delivery of energy for up to the following 2 years (“Adjustment Auctions”). Electricity auctions for new generation projects are held (i) in the fifth year before the initial delivery date of electricity (“A-5 Auctions”), and (ii) in the third year before the commencement of commercial operation (“A-3 Auctions”).
To benefit from attractive sale prices for energy that has not been previously contracted, for the delivery of energy starting in 2014, we sold some of our remaining certified commercial capacity as standby capacity under public auctions on the electricity regulated market as follows: (i) 10 MWavg per month in a A-1 Auction held on December 17, 2013 for the sale of energy between January 1, 2014 to December 31, 2014; (ii) 574 MWavg per month in an A Auction held on April 30, 2014 for the sale of energy between May 1, 2014 to December 31, 2019. For the delivery of energy starting in 2015, we sold (i) 270 MWavg per month in an A-1 Auction held on December 5, 2014 for the sale of energy between January 1, 2015 to December 31, 2017 and (ii) 205 MWavg per month in the 18th Adjustment Auction held on January 15, 2015 for the sale of energy between January 1st to June 30, 2015. With these sales, we can now better predict our revenues derived from the sale of electricity for the next 3 years.
Under the terms of standby availability contracts, we are paid a fixed amount whether or not we generate any power. Additionally, whenever we have to deliver energy under these contracts, we receive an additional payment for the energy delivered that is set on the auction date and is revised monthly or annually based on inflation-adjusted international fuel price indexes.
Our future commitments under bilateral contracts and self-production are of 1,421 MWavg in 2015, 1,460 MWavg in 2016 and 1,520 MWavg in 2017. The agreements expire gradually, with the last contract expiring in 2028. As existing bilateral contracts expire, we will sell our remaining certified commercial capacity under contracts in new auctions to be conducted by MME or through the execution of new bilateral contracts.
The table below shows the evolution of our installed thermoelectric power plants’ capacity, our purchases in the free market and the associated certificated commercial capacity.
|
|
|
|
| 2015 | 2014 | 2013 |
Installed power capacity and utilization |
|
|
|
Installed capacity (MW) | 6,684 | 6,410 | 6,548 |
Certified commercial capacity (MWavg) | 4,229 | 4,222 | 4,367 |
Purchases in the free market (MWavg) | 250(1) | 320 | 217 |
Commercial capacity available (Lastro) (MWavg) | 4,479 | 4,542 | 4,584 |
(1) Includes 220 Mwavg already purchased in the free market and 30 Mwavg forecasted in our 2014-2018 Business Plan to be purchased in 2015.
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The table below shows the allocation of our sales volume between our customers and our revenues for each of the past three years:
Volumes of Electricity Sold (MWavg) | |||
| 2014 | 2013 | 2012 |
Total sale commitments | 4,012 | 4,235 | 4,438 |
Bilateral contracts | 1,183 | 2,021 | 2,318 |
Self-production | 428 | 416 | 423 |
Public auctions to distribution companies | 2,425 | 1,798 | 1,697 |
Generation volume | 4,637 | 3,983 | 2,699 |
Revenues (U.S.$ million)(1) | 7,693 | 5,173 | 3,755 |
(1) Includes electricity sales revenues from the Power segment to other operating segments, service and other revenues from electricity companies.
Renewable Energy
We have invested, alone and in partnership with other companies, in renewable power generation sources in Brazil including wind and small hydroelectric plants. The power generation capacity we have (through the equity interest we hold on renewable energy companies) is equivalent to 25.4 MW of hydroelectric capacity, 1.1 MW of solar capacity and 105.8 MW of wind capacity. We and our partners sell energy from these plants directly to the Brazilianfederalgovernment via the renewable energies incentive program (PROINFA) and the 2009 “reserve energy” auctions.
International Key Statistics | |||
| 2014 | 2013 | 2012 |
| (U.S.$ million) | ||
International: |
|
|
|
Sales revenues | 13,912 | 16,302 | 17,929 |
Income (loss) before income taxes | (608) | 2,035 | 1,933 |
Property, plant and equipment | 6,058 | 7,971 | 10,882 |
Capital expenditures and investments | 1,513 | 2,368 | 2,572 |
In addition to Brazil, we have operations in 16 countries, encompassing all phases of the energy business, with an emphasis on oil and gas exploration in Latin America, Africa and the United States. The strategies of our international operations are:
· Investing in overseas exploration to discover and add to reserves, increasing our volumes of oil and gas;
· Developing and commercializing natural gas reserves overseas, supplementing our supply of natural gas in Brazil; and
· Maintaining the operational integrity and optimizing the management and efficiency of our refining and distribution assets abroad.
International Upstream Activities
Most of our international activities are in exploration and production of oil and gas. We have long been active in Latin America. In the Gulf of Mexico and West Africa, we focus on opportunities to leverage the deepwater expertise we have developed in Brazil. From 2012 to 2014 we substantially reduced our international activities and production through the sale of assets to meet our announced divestment targets.
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In 2014, our net production outside Brazil averaged 115.9 mbbl/d of crude oil and NGLs and 560.3 mmcf/d (15.9 mmm3/d) of natural gas, representing 8.4% of our total production on a barrels of oil equivalent basis. During 2014, our capital expenditures and investments for international exploration and production totaled U.S.$1.3 billion, representing 5.2% of our total exploration and production capital spending.
International Refining Activities
Our international crude distillation capacity as of December 31, 2014 was 230.2 mbbl/d and the utilization factor for our international consolidated refining plants was 69%.
The following table shows the installed capacity of our international refineries as of December 31, 2014, and the average daily throughputs in 2014, 2013 and 2012, respectively.
Capacity and Average Throughput of Refineries | |||||
Name (Alternative Name) | Location | Crude Distillation Capacity at December 31, 2014 | Average Throughput* | ||
2014 | 2013 | 2012 | |||
|
| (mbbl/d) | (mbbl/d) | ||
PRSI (Pasadena Refining System Inc.) | Texas (USA) | 100.0 | 100.3 | 101.8 | 97.9 |
NSS (Nansei Sekiyu Kabushiki Kaisha) | Okinawa (JP) | 100.0 | 35.9 | 38.6 | 49.8 |
RBB (Ricardo Eliçabe Refinery) | Bahía Blanca (AR) | 30.2 | 27.2 | 29.0 | 29.2 |
Total average crude oil throughput |
| 230.2 | 158.9 | 160.8 | 161.8 |
Average external intermediate throughput |
|
| 4.5 | 8.6 | 15.1 |
Total average throughput |
| ‒ | 163.4 | 169.4 | 176.9 |
* Consider oil (fresh feedstock) and external processed intermediate oil products.
International Activities by Region and Country
In addition to exploring, producing and refining oil, our international activities include petrochemicals, distribution and gas and power activities. Information about our international presence, by region and country, is provided in the text that follows. See the table at the end of this section for more information about our main international exploration and production assets in development.
South America
We are present in Argentina, Bolivia, Chile, Colombia, Venezuela, Paraguay and Uruguay. In 2014, our average net production from South America (outside of Brazil) was 153.2 mboe/d, or 73% of our international production compared to 167.2 mboe/d, or 76% of our international production in 2013. Reserves in the region represent 50.4% of our international reserves. Our most significant natural gas production operations outside of Brazil are located in Argentina and Bolivia, where we produced an average 514.6 mmcf/d (14.6 mmm3/d) of natural gas in 2014, or 92% of our international production.
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Our largest operating region outside Brazil isArgentina, where we participate across the energy value chain, primarily through our 67.2% interest in Petrobras Argentina S.A., or PESA. Our main oil production is concentrated in the Medanito, Entre Lomas and El Tordillo fields, and our main gas production is concentrated in the El Mangrullo, Río Neuquén fields in the Neuquén Basin and Santa Cruz I fields in the Austral Basin. In January 2014, we announced the sale of the remaining 38.45% interest we held in the Puesto Hernandez field to YPF for U.S.$40.7 million and in March 2015, the sale of our assets in Austral Basin, which includes 26 exploration and production contracts and related infrastructure located in the Santa Cruz province, to Compañia General de Combustibles S.A. (CGC) for U.S.$101 million. The conclusion of this transaction is subject to the approval of regulatory authorities in Argentina. Through our interest in PESA, we own the Bahia Blanca Refinery, with a capacity of 30.2 mbbl/d, and stakes in the Refinor refinery in Campo Duran and in two petrochemical plants in Puerto General San Martín and Zárate. We also own 262 retail service stations, four electric power plants, Pichi Picún Leufú (hydrogeneration), Genelba (gas powered combined cycle), Genelba Plus (gas powered) and EcoEnergia (Cogeneration), and we hold an interest in two other electric power plants, Central Termelétrica José de San Martín S.A. and Central Termelétrica Manuel Belgrano S.A. Through our interest in PESA, we also have stake in a natural gas transportation company called TGS (Transportadora Gas del Sur). Through Petrobras Participaciones SL (Spain), we have an interest in Mega Company, a natural gas separation facility.
InBolivia, our oil and gas production comes principally from the San Alberto, San Antonio and Itaú fields. Following enactment of the Bolivian government’s May 1, 2006 nationalization of hydrocarbons, we entered into new production-sharing contracts under which we continue to operate the fields, but are required to make all hydrocarbon sales to YPFB with the right to recover our costs and participate in profits. On January 25, 2009, Bolivia adopted a new constitution that prohibits private ownership of the country’s oil and gas resources. As a result, we were not able to include any of our Bolivian proved reserves in our consolidated proved reserves since year-end 2009. We continue to report production from our operations in Bolivia under our existing contracts in that country. Additionally, we operate gas fields that supply gas to Brazil and Bolivia. We hold an 11% interest in GTB, owner of the Bolivian section of the Bolivia-to-Brazil (BTB) pipeline that transports natural gas we produce in Bolivia to the Brazilian market. We also hold a 21% interest in the Rio Grande Compression Unit, where the Bolivia-Brasil Gas Pipeline starts. In August 2014, we sold our interest (44.5%) in Transierra S.A. to YPFB for U.S.$106.7 million.
InChile, our operations include 269 service stations, the distribution and sales of fuel at airports and a lubricant plant.
InColombia, we concluded the sale of 100% of the shares of our subsidiary Petrobras Colombia Limited (PEC) to Perenco Colombia Ltda. in May 2014 for a total amount of U.S.$380 million. Our remaining upstream portfolio in Colombia includes offshore exploration blocks and one onshore exploration block. See Note 10 to our audited consolidated financial statements. Additionally, we also have 113 service stations and a lubricant plant.
InParaguay, our operations include 176 service stations, the distribution and sales of fuel at three airports and an LPG refueling plant.
InPeru, we concluded the sale of 100% of the shares of our subsidiary Petrobras Energia Peru (PEP) to China National Petroleum Corporation (CNPC) in November 2014 for U.S.$2.6 billion and we closed our operations in the country. See Note 10 to our audited consolidated financial statements.
InVenezuela, through PESA, we hold minority interests in four joint ventures with subsidiaries of Petróleos de Venezuela S.A., or PDVSA, which hold production rights. PDVSA is the majority holder and operator.
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InUruguay, we concluded the sale of our interests in offshore exploration blocks 3 and 4, located in the Punta del Este Basin to Shell in May 2014 for U.S.$17 million. We have no further upstream portfolio in the country. We also have downstream operations in the country, including 87 service stations and gas segment assets.
North America
In theUnited States,we focus on deepwater fields in the Gulf of Mexico. As of December 31, 2014, we held interests in 137 offshore blocks, 98 of which we operate. Our production in the United States during 2014 originated mainly from the Cascade, Chinook and Cottonwood fields. The Cascade and Chinook fields began oil production in February 2012 and September 2012, respectively. These projects are the first Gulf of Mexico operation to use an FPSO. Other assets include the Saint Malo, which began oil production in December 2014, Lucius, which began oil production in January 2015, Hadrian South block, which began gas production in March 2015, and Tiber, among others, which are currently in the exploratory stage. In April2014, we sold 50% of our 100% interest in the Urca field and transferred the operation to Murphy Oil Corporation, for U.S.$15 million. We also own 100% of the Pasadena Refining System Inc., or PRSI, and 100% of PRSI’s related trading company – PRSI Trading, LLC.
We have recognized impairment lossesfor the fiscal year ended December 31, 2014 of U.S.$1.7 billion due to the impact of the recent decline in international crude oil prices in our exploration and production producing properties outside Brazil. The impairment losses are mainly in the Cascade and Chinook fields, located in the United States (U.S.$1.6 billion). For further information, see Note 14 to our audited consolidated financial statements.
We have held non-risk service contracts through our joint venture with PTD Servicios Multiplos SRL for the Cuervito and Fronterizo blocks in the Burgos Basin ofMexico since 2003. Under these service contracts, we receive fees for our services, but any production is transferred to the Mexican national oil company Petróleos Mexicanos, or Pemex.
Africa
In June 2013, we established a joint venture with BTG Pactual to jointly explore oil and gas opportunities in Africa. This joint venture, was formed upon the acquisition by BTG Pactual of 50% of the shares issued by Petrobras Oil & Gas B.V. (PO&G), an once wholly-owned subsidiary of Petrobras International Braspetro B.V. (PIBBV), for U.S.$1.5 billion.
PO&G is primarily involved in the exploration and production of oil and gas through its subsidiaries in Nigeria and branches in Benin, Gabon and Namibia. In May 2014, PO&G’s portfolio was further expanded when it obtained control over a Petrobras subsidiary in Tanzania and in June 2014, when it obtained control over a Petrobras branch in Angola. During 2014, PO&G’s exploration resulted in four drilled wells considered dry and one considered a subcommercial discovery.
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The assets of our joint venture with BTG Pactual include:
InAngola, the Block 26 license, retained at the end of 2014, and which will expire in May 2015. During 2014, the licenses of 3 blocks expired: Block 2/85 in April and Blocks 6/06 and 18/06 in November. All of these blocks were in an exploratory phase;
InBenin, Block 4, which is in an exploratory phase;
InGabon, the Ntsina Marin and Mbeli Marin Blocks, which are in an exploratory phase;
InNamibia, we returned the Block 2714A license to the Namibian government in April 2014;
InNigeria, 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 whilethe Preowei and Egina South fields are under appraisal; and
InTanzania, two offshore exploration blocks, Blocks 6 and 8.
Asia
InJapan, we own the Nansei Sekiyu Kabushiki Kaisha (NSS) refinery in Okinawa, with a crude distillation capacity of 100 mbbl/d, which produces refined products such as gasoline, diesel, fuel oil and jet fuel. In February 2015, we decided to begin winding down our operations of this refinery. This plan involves continuing NSS’s activities in the maritime terminal in order to maintain the supply of fuel oil, gasoline and diesel to Okinawa Island until the completion of this process, which will be conducted in collaboration with the Ministry of Economy, Trade and Industry of the Japanese Government. As a result of the plan,we have recognized impairment lossesfor the fiscal year ended December 31, 2014 of U.S.$129 million. See Notes 14 and 35 to our audited consolidated financial statements.
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International Exploration and Production Assets in Development
The table below shows our main exploration and production projects being developed worldwide, as of December 31, 2014.
| Main International Exploration and Production Assets in Development | ||||
Countries | Main projects in development | Phase | Operated by | Petrobras interest (%) | |
South America |
|
|
|
| |
1 | Argentina(1) | Sierra Chata Rio Neuquén Santa Cruz I(2) El Mangrullo Entre Lomas | Production Production Production Production | Petrobras Petrobras Petrobras Petrobras | 46 100 |
2 | Bolivia(3) | San Alberto Itaú Colpa y Caranda (1) | Production Production Production | Petrobras Petrobras Petrobras | 35 30 |
3 | Colombia | Tayrona | Exploration | Petrobras | 40 |
4 | Venezuela(4) | Oritupano-Leona | Production | Partner | 22 |
North America |
|
|
|
| |
5 | Mexico(5) | Cuervito | Production | Petrobras | 45 |
6 | U.S.A. | Cascade Lucius | Production Production | Petrobras Partner | 100 11.5 |
Africa |
|
|
|
| |
7 | Angola(6) | Block 26 | Exploration | Petrobras | 40 |
8 | Benin(6) | Block 4 | Exploration | Partner | 35 |
9 | Gabon(6) | Ntsina Marin Mbeli Marin | Exploration Exploration | Partner Partner | 50 50 |
10 | Nigeria(6) | Akpo | Production | Partner | 20 |
11 | Tanzania(6) | Block 6 Block 8 | Exploration Exploration | Petrobras Petrobras | 38 50 |
(1) All Argentine and Colpa Caranda exploration and production projects are held through our indirect 67.2% share in Petrobras Argentina S.A. (PESA).
(2) Assets sold in March 2015 (Austral Basin) to third parties. See Item 4. “Information on the Company—International—International Activities by Region and Country.”
(3) Production-sharing contract, under which Petrobras’s expenditures are reimbursed only if exploration results in economically viable oil discoveries.
(4) Joint venture through Petrobras Argentina S.A. (PESA).
(5) Non-risk service contract, under which Petrobras’s expenditures are reimbursed regardless of whether exploration results in economically viable oil discoveries.
(6) Since June 2013, our projects in Angola, Benin, Gabon, Namibia, Nigeria and Tanzania have been developed through a joint venture between Petrobras International Braspetro B.V. and BTG Pactual.
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Biofuels Key Statistics | |||
| 2014 | 2013 | 2012 |
| (U.S.$ million) | ||
Biofuel: |
|
|
|
Sales revenues | 266 | 388 | 455 |
Income (loss) before income taxes | (166) | (168) | (156) |
Property, plant and equipment | 205 | 222 | 255 |
Capital expenditures | 112 | 143 | 147 |
Brazil is a global leader in the use and production of biofuels. In 2014, 88.2% of new light vehicles sold in Brazil had flexfuel capability, and service stations offered a choice of 100% ethanol and an ethanol/gasoline blend. Starting in March 2015, the Brazilian federal government increased the anhydrous ethanol content requirement for the gasoline sold in Brazil from 25% to 27%.
Biodiesel
Since November 2014, all diesel fuel sold in Brazil is required to have at least 7% biodiesel. In 2014, we supplied 17% of Brazil’s biodiesel (assuming 100% of BSBIOS Sul Brasil production) and we act as a market catalyst by securing and blending biodiesel supplies and furnishing these to smaller distributors as well as our own service stations. We directly own three biodiesel plants and, through our 50% interest in BSBIOS Indústria e Comércio de Biodiesel Sul Brasil S.A. (BSBIOS Sul Brasil), we own two additional plants. The biodiesel production capacity of these five plants totals 14.1 mbbl/d, ranking us amongst the five main biodiesel producers in Brazil.
Ethanol
Due to our ownership interest in Guarani S.A. (Guarani) (42.95%), Brazil’s fourth largest sugarcane processor, Nova Fronteira Bioenergia S.A. (Nova Fronteira) and Bambuí Bioenergia S.A. (Bambuí Bioenergia), we also have a presence in the whole ethanol and sugar production chain and we also sell the exceeding electricity generated from sugarcane bagasse burn. We have all the necessary infrastructure for the distribution and export of ethanol.
Through our associated companies Bambuí Bioenergia, Nova Fronteira and Guarani, we own ethanol plants situated in the States of Minas Gerais, Goiás and São Paulo and in Mozambique, Africa. These associated companies’ total milling in the 2014/2015 harvest amounted to 26.4 mmt of sugarcane, corresponding to an ethanol and sugar production of 21.3 mbbl/d and 1.6 mmt respectively compared to 18.2 mbbl/d and 1.6 mmt respectively in the 2013/2014 harvest. These associated entities sold 1,295 GWh of exceeding electricity generated during the 2014/2015 harvest.
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Corporate Key Statistics | |||
| 2014 | 2013 | 2012 |
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Corporate: |
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Income (loss) before income taxes | (7,714) | (7,818) | (6,999) |
Property, plant and equipment | 2,787 | 3,312 | 3,204 |
Capital expenditures and investments | 446 | 547 | 747 |
Our Corporate segment comprises activities that cannot be attributed to other segments, including corporate financial management, central administrative overhead and actuarial expenses related to our pension and medical benefits for retired employees and their dependents.
As of December 31, 2014, we had 26 direct subsidiaries and two direct joint operations as listed below. Twenty-four are entities incorporated under the laws of Brazil and four are incorporated abroad. We also have indirect subsidiaries (including Petrobras Argentina S.A. and PGF). As described in Note 36 to our audited consolidated financial statements, on December 29, 2014, PifCo merged into PGF. See Exhibit 8.1 for a complete list of our subsidiaries and joint operations, including their full names, jurisdictions of incorporation and our percentage of equity interest.
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PETROBRAS | ||
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BRAZIL |
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Petrobras Distribuidora S.A. - BR |
| Petrobras Netherlands B.V. - PNBV |
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Transportadora Associada de Gás S.A. - TAG |
| Petrobras International Braspetro - PIB BV |
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Petrobras Transporte S.A. - Transpetro |
| Braspetro Oil Services Company - Brasoil |
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Petrobras Logística de Exploração e Produção S.A. - PB-LOG |
| Cordoba Financial Services GmbH |
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Petrobras Gás S.A. - Gaspetro |
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Petrobras Biocombustível S.A. |
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Companhia Integrada Têxtil de Pernambuco S.A. - CITEPE |
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Liquigás Distribuidora S.A. |
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Termomacaé Ltda. |
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Companhia Petroquímica de Pernambuco S.A. - PetroquímicaSuape |
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Araucária Nitrogenados S.A. |
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Breitener Energética S.A. |
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Petrobras Comercializadora de Energia Ltda. - PBEN |
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Termobahia S.A. |
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Arembepe Energia S.A. |
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5283 Participações Ltda. |
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Baixada Santista Energia S.A. |
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Energética Camaçari Muricy I Ltda. |
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Fundo de Investimento Imobiliário RB Logística - FII |
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Termomacaé Comercializadora de Energia Ltda |
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Petrobras Negócios Eletrônicos S.A. - E-Petro |
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Downstream Participações Ltda. |
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Fábrica Carioca de Catalizadores S.A. - FCC (*) |
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Ibiritermo S.A. (*) |
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(*) Joint operations. |
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Our most important tangible assets are wells, platforms, refining facilities, pipelines, vessels, other transportation assets, power plants as well as fertilizers and biodiesels plants. Most of these are located in Brazil. We own and lease our facilities and some owned facilities are subject to liens, although the value of encumbered assets is not material.
We have the right to exploit crude oil and gas reserves in Brazil under concession agreements, but the reserves themselves are the property of the government under Brazilian law. Item 4. “Information on the Company” includes a description of our reserves and sources of crude oil and natural gas, key tangible assets, and material plans to expand and improve our facilities.
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As of December 31, 2014, our property, plant and equipment included U.S.$28,164 million (U.S.$21,510 million as of December 31, 2013) related to the Assignment Agreement (see Item 10. “Additional Information—Material Contracts—Assignment Agreement.”) On December 29, 2014, we submitted the last declaration of commerciality of crude oil and natural gas accumulations, located in the Entorno de Iara block, to the ANP. During 2014, acquisition costs related to Florim (now Itapu field), Sul de Guará (now Sul de Sapinhoá field), Entorno de Iara (now Norte de Berbigão, Sul de Berbigão, Norte de Sururu, Sul de Sururu and Atapu fields) and Nordeste de Tupi (now Sepia field) were reclassified from intangible assets to property, plant and equipment as their commerciality was declared. During 2013, acquisition costs related to Franco (now Búzios field) and Sul de Tupi (now Sul de Lula field), had already been reclassified from intangible assets to property, plant and equipment. See Note 12.3 to our audited consolidated financial statements.
We have also recognized impairment charges of U.S.$16,823 million in 2014 for certain property, plant and equipment, intangible assets and assets classified as held for sale. Further information about impairment of our assets is provided in Note 14 to our audited consolidated financial statements.
Regulation of the Oil and Gas Industry in Brazil
Concession Regime for Oil and Gas
Under Brazilian law, the Brazilian federal government owns all crude oil and natural gas subsoil accumulations in Brazil. The Brazilian federal government holds a monopoly over the exploration, production, refining and transportation of crude oil and oil products in Brazil and its continental shelf, with the exception that companies that were engaged in refining and distribution in 1953 were permitted to continue those activities. Between 1953 and 1997, we were the Brazilian federal government’s exclusive agent for exploiting its monopoly, including the importation and exportation of crude oil and oil products.
As part of a comprehensive reform of the oil and gas regulatory system, the Brazilian Congress amended the Brazilian Constitution in 1995 to authorize the Brazilian federal government to contract with any state or privately-owned company to carry out upstream, oil refining, cross-border commercialization and transportation activities in Brazil of oil, natural gas and their respective products. On August 6, 1997, Brazil enacted Law No. 9,478, which established a concession-based regulatory framework, ended our exclusive right to carry out oil and gas activities, and allowed competition in all aspects of the oil and gas industry in Brazil. Since that time, we have been operating in an increasingly deregulated and competitive environment. Law No. 9,478/1997 also created an independent regulatory agency, the ANP, to regulate the oil, natural gas and renewable fuel industry in Brazil, and to create a competitive environment in the oil and gas sector. Effective January 2, 2002, Brazil deregulated prices for crude oil, oil products and natural gas.
Law No. 9,478/1997 established a concession-based regulatory framework and granted us the exclusive right to exploit crude oil reserves in each of our producing fields under the existing concession contracts for an initial term of 27 years from the date when they were declared commercially profitable. These are known as the “Round Zero” concession contracts. This initial 27-year period for production can be extended at the request of the concessionaire and subject to approval from the ANP. Law No. 9,478/1997 also established a procedural framework for us to claim exclusive exploratory rights for a period of up to three years, later extended to five years, to areas where we could demonstrate that we had made commercial discoveries or exploration investments prior to the enactment of the Law No. 9,478/1997. In order to perfect our claim to explore and develop these areas, we had to demonstrate that we had the financial capacity to carry out these activities, either alone or through other cooperative arrangements. Starting in 1999, all areas not already subject to concessions became available for public bidding conducted by the ANP. All the concessions that we have obtained since then were obtained through participation in public bidding rounds.
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Taxation under Concession Regime for Oil and Gas
According to the Law No. 9,478/1997 and under our concession agreements for exploration and production activities with ANP, we are required to pay the government the following:
· Signing bonuses paid upon the execution of the concession agreement, which are based on the amount of the winning bid, subject to the minimum signing bonuses published in the relevant bidding guidelines (edital de licitação);
· Annual retention bonuses for the occupation or retention of areas available for exploration and production, at a rate established by the ANP in the relevant bidding guidelines based on the size, location and geological characteristics of the concession block;
· Special participation charges at a rate ranging from 0 to 40% of the net income derived from the production of fields that reach high production volumes or profitability, according to the criteria established in the applicable legislation. Net revenues are gross revenues less royalties paid, investments in exploration, operational costs and depreciation adjustments and applicable taxes. The Special Participation Tax uses as a reference international oil prices converted toreais at the current exchange rate. In 2014, we paid this tax on 21 of our fields, namely Albacora, Albacora Leste, Baleia Azul, Baleia Franca, Barracuda, Baúna, Cachalote, Canto do Amaro, Caratinga, Carmópolis, Jubarte, Leste do Urucu, Lula, Manati, Marlim, Marlim Leste, Marlim Sul, Mexilhão, Rio Urucu, Roncador and Sapinhoá; and
· Royalties, to be established in the concession contracts at a rate ranging between 5% and 10% of gross revenues from production, based on reference prices for crude oil or natural gas established by Decree No. 2,705 and ANP regulatory acts. In establishing royalty rates in the concession contracts, the ANP also takes into account the geological risks and expected productivity levels for each concession. Virtually all of our crude oil production is currently taxed at the maximum royalty rate.
Law No. 9,478/1997 also requires concessionaires of onshore fields to pay to the owner of the land a participation fee that varies between 0.5% and 1.0% of the sales revenues derived from the production of the field.
Production-Sharing Contract Regime for Unlicensed Pre-Salt and Potentially Strategic Areas
Discoveries of large oil and natural gas reserves in the pre-salt areas of the Campos and Santos Basins prompted a change in the legislation regarding oil and gas exploration and production activities.
In 2010, three new laws were enacted to regulate exploration and production activities in pre-salt and other potentially strategic areas not subject to existing concessions: Law No. 12,351, Law No. 12,304, and Law No. 12,276. The enacted legislation does not impact the existing pre-salt concession contracts, which cover approximately 28% of the pre-salt areas.
Law No. 12,351/2010 regulates production-sharing contracts for oil and gas exploration and production in pre-salt areas not under concession and in potentially strategic areas to be defined by the CNPE. Under the production-sharing regime, we will be the exclusive operator of all blocks. The exploration and production rights for these blocks can either be granted to us on an exclusive basis or, in the case where they are not awarded to us on an exclusive basis, they will be offered under public bids. If offered under public bids, we would still be required to participate as the operator, with a minimum interest to be established by the CNPE that would not be less than 30%, with the additional right, at our discretion, to participate in the bidding process to increase our interest in those areas. Under the production-sharing regime, the winner of the bid will be the company that offers to the Brazilian federal government the highest percentage of “profit oil,” which is the production of a certain field after deduction of royalties and “cost oil,” which is the cost associated with oil production. According to Law No. 12,351, we must accept the economic terms of the winning bid.
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Law No. 12,734 became partially effective on November 30, 2012, and amended Law 12,351, establishing a royalty rate of 15% applicable to the gross production of oil and natural gas under future production sharing contracts.
Law No. 12,304/2010, authorized the incorporation of a new state-run non-operating company that will represent the interests of the Brazilian federal government in the production-sharing contracts and will manage the commercialization contracts related to the Brazilian federal government’s share of the “profit oil.” This new state-owned company was incorporated on August 1, 2013, named Pré-Sal Petróleo S.A. – PPSA, and will participate in operational committees, with a casting voteand veto powers, as defined in the contract, and will manage and control costs arising from production-sharing contracts. Where production-sharing contracts are concerned, this new company will exercise its specific legal activities alongside the ANP, the independent regulatory agency that regulates and oversees oil and gas activities under all exploration and production regimes, and the CNPE, the entity that sets the guidelines to be applied to the oil and gas sector, including with respect to the new regulatory model.
Assignment Agreement (Cessão Onerosa)and Global Offering
Pursuant to Law No. 12,276/2010, we entered into an agreement with the Brazilian federal government on September 3, 2010 (Assignment Agreement), under which the government assigned to us the right to conduct activities for the exploration and production of oil, natural gas and other fluid hydrocarbons in specified pre-salt areas, subject to a maximum production of five bnboe. The initial contract price for our rights under the Assignment Agreement was R$74,807,616,407, which was equivalent to U.S.$42,533,327,500 as of September 1, 2010. See Item 10. “Additional Information—Material Contracts—Assignment Agreement.”
Natural Gas Law of 2009
In March 2009, the Brazilian Congress enacted Law No.11,909, or Gas Law, regulating activities in the gas industry, including transport, processing, storage, liquefaction, regasification and commercialization. The Gas Law created a concession regime for the construction and operation of new pipelines to transport natural gas, while maintaining an authorization regime for pipelines subject to international agreements. According to the Gas Law, after a certain exclusivity period, operators(transportadores) will be required to grant access to transport pipelines and maritime terminals, except LNG terminals, to third parties in order to maximize utilization of capacity.
The Gas Law authorized the ANP to regulate prices for the use of gas transport pipelines subject to the new concession regime, based on a procedure defined in the Gas Law as a “chamada pública,” and to approve prices submitted by carriers(carregadores), according to previously established criteria, for the use of new gas transport pipelines subject to the authorization regime.
Authorizations previously issued by the ANP for natural gas transport will remain valid for 30 years from the date of publication of the Gas Law, and initial carriers (carregadores iniciais) were granted exclusivity in these pipelines for 10 years. All pipelines that Petrobras’s subsidiaries currently own and operate in Brazil are subject to an authorization regime. The ANP will issue regulations governing third-party access and carrier compensation if no agreement is reached between the parties.
The Gas Law also authorized certain consumers, who can purchase natural gas on the open market or obtain their own supplies of natural gas, to construct facilities and pipelines for their own use in the event local gas distributors controlled by the states, which have monopoly over local gas distribution, do not meet their distribution needs. These consumers are required to delegate the operation and maintenance of the facilities and pipelines to local gas distributors, but they are not required to sign gas supply agreements with the local gas distributors.
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In December 2010, Decree No. 7,382 was enacted in order to regulate Chapter I to VI and VIII of the Gas Law as it relates to activities in the gas industry, including transportation and commercialization. Since the publication of this decree, various administrative regulations were enacted by the ANP and the MME in order to regulate various issues in the Gas Law and Decree No. 7,382 that needed to be further clarified. Among those is ANP Resolution No. 51/2013, which prevents a carrier from holding any equity interest in concessionaires of gas transport pipelines. Resolution No. 51/2013 applies only to the concessions granted after its publication, not affecting, therefore, the transportation of Petrobras’s natural gas production through pipelines operated by its subsidiaries and subject to the previous authorization regime.
Price Regulation
Until the passage of Law No. 9,478 in 1997, the Brazilian federal government had the power to regulate all aspects of the pricing of crude oil, oil products, ethanol, natural gas, electric power and other energy sources. In 2002, the government eliminated price controls for crude oil and oil products, although it retained regulation over certain natural gas sales contracts and electricity. The Brazilian federal government has periodically adjusted taxes applicable to crude oil, oil and natural gas products as a tool to maintain price stability to end consumers and also to increase its tax revenues.
Environmental Regulations
All phases of the crude oil and natural gas business present environmental risks and hazards. Our facilities in Brazil are subject to a wide range of federal, state and local laws, regulations and permit requirements relating to the protection of human health and the environment, and they fall under the regulatory authority of theConselho Nacional doMeio Ambiente(National Council for the Environment, or CONAMA).
Our offshore activities are subject to the administrative authority of IBAMA, which issues operating and drilling licenses. We are required to submit reports, including safety and pollution monitoring reports (IOPP) to IBAMA in order to maintain our licenses.
Most of the onshore environmental, health and safety conditions are controlled either at the federal or the state level depending on the localization of our facilities, the type of activity under development and other criteria to be set forth in regulation that is still pending. However, it is also possible for these conditions to be controlled on a local basis whenever the activities generate a local impact or are established in a county conservation unit. Under Brazilian law, there is strict and joint liability for environmental damage, mechanisms for enforcement of environmental standards and licensing requirements for polluting activities.
Individuals or entities whose conduct or activities cause harm to the environment are subject to criminal and administrative sanctions. Government environmental protection agencies may also impose administrative sanctions for noncompliance with environmental laws and regulations, including:
· Fines;
· Partial or total suspension of activities;
· Requirements to fund reclamation and environmental projects;
· Forfeiture or restriction of tax incentives or benefits;
· Closing of establishments or operations; and
· Forfeiture or suspension of participation in credit lines with official credit establishments.
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We are subject to a number of administrative and legal proceedings relating to environmental matters. For more information about these proceedings, see Item 8. “Financial Information—Legal Proceedings.” and Note 30 to our audited consolidated financial statements included in this annual report.
In 2014, we invested U.S.$1.4 billion in environmental projects, compared to U.S.$1.5 billion in 2013 and U.S.$1.5 billion in 2012. These investments continued to be primarily directed at reducing emissions and wastes from industrial processes, managing water use and effluents, remedying impacted areas, implementing new environmental technologies, upgrading our pipelines and improving our ability to respond to emergencies.
Health, Safety and Environmental Initiatives
The protection of human health and the environment is one of our primary concerns, and is essential to our success as an integrated energy company.
We have a Health, Safety and Environmental (HSE) Committee (Comitê de Segurança, Meio Ambiente e Saúde) composed of three members of our board of directors who are responsible for assisting our board in the following matters:
· Definition of strategic goals in relation to HSE matters;
· Establishment of global policies related to the strategic management of HSE matters within Petrobras’s group of companies;
· Assessment of the conformity of Petrobras’s Strategic Plan to its global HSE policies, among others.
Our efforts to address health, safety and environmental concerns and ensure compliance with environmental regulations (which in 2014 totaled an investment of U.S.$2.4 billion) involve the management of environmental costs related to production and operations, pollution control equipment and systems, projects to rehabilitate degraded areas, safety procedures and initiatives for emergency prevention and control, health and safety programs as well as:
· An HSE management system that seeks to minimize the impacts of operations and products on health, safety and the environment, reduce the use of natural resources and pollution and prevent accidents;
· ISO 14001 (environment) and OHSAS 18001 (health and safety) certification of our operating units. All the oil refined in Brazil was processed by certified units. TheFrota Nacionalde Petroleiros(National Fleet of Vessels) has been fully certified by the International Maritime Organization (IMO) International Management Code for Safe Operation of Ships and for Pollution Prevention (ISM Code) since December 1997;
· Regular and active engagement with the MME and IBAMA, in order to discuss environmental issues related to new oil and gas production and other transportation and logistical aspects of our operations;
· A strategic goal to reduce the intensity of greenhouse gas emissions, along with a set of performance indicators with targets to monitor progress with respect to this goal; and
· We evaluate each of our operational projects to identify risks and to ensure compliance with all of our HSE requirements and the adoption of the best HSE practices throughout a project’s life cycle. In addition, we conduct more extensive environmental studies for new projects when required by applicable environmental legislation.
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In recent years, we have expanded our activities in almost all of our business segments, which consequently has led to an increase in our greenhouse gas emissions. In 2014, our emissions increased by 5% compared to 2013, mainly due to the higher energy generation of our thermoelectric power plants. Nevertheless, we are committed to reducing the intensity of greenhouse gas emissions from our processes and products. We have been able to reduce greenhouse gas emissions through several different initiatives, including the modernization of our facilities, utilization of more efficient equipment and standardization of projects and operational practices, in furtherance of our ongoing investments in research and technology.
Environmental Remediation Plans and Procedures
As part of our environmental plans, procedures and efforts, we maintain detailed response and remediation contingency plans to be implemented in the event of an oil spill or leak from our offshore operations. In order to respond to these events, Petrobras has 36 dedicated oil spill recovery vessels (OSRVs) fully equipped for oil spill control and firefighting, 113 support boats and other vehicles, 270 additional support and recovery boats available to fight offshore oil spills and leaks, around 92 km of containment booms and 118 km of absorbent booms and around 113,000 liters of oil dispersants, among others. These resources are distributed in 12 environmental protection centers in strategic areas in which we operate throughout Brazil and in emergency response centers (distributed over 21 cities) in order to ensure rapid and coordinated response to onshore or offshore oil spills. Our regional facilities are supported by 11 local advanced bases dedicated to oil spill prevention, control and response.
We have more than 500 trained workers available to respond to oil spills 24 hours a day, seven days a week, and we can mobilize additional trained workers for shoreline cleanups on short notice from a large group of trained environmental agents in the country. While these workers are located in Brazil, they are also available to respond to an offshore oil spill outside of Brazil.
Since 2012, Petrobras has been a participating member of the Oil Spill Response Limited – OSRL, an international organization that brings together over 160 corporations, including oil major, national/independent oil companies, energy related companies as well as other companies operating elsewhere in the oil supply chain. OSRL participates in the Global Response Network, an organization composed of several other companies dedicated to fighting oil spills. As a member of the OSRL, Petrobras has access to all resources available through that network, and we also subscribe to their Subsea Well Intervention Services (SWIS), which provides swift international deployment of response-ready capping and containment equipment. The capping equipment is stored and maintained at bases worldwide, including Brazil. An OSRL Brazilian base opened in March 2014 and is now operational.
In 2014, we conducted 22 emergency drills of regional scope with the Brazilian navy, the civil defense, firefighters, the military police, environmental organizations and local governmental and community entities.
We set up a Zero Spill Plan, aiming at optimizing management and reducing the risk of oil spills in our operations. This plan encompasses investments to improve the management of processes and to ensure the integrity of our equipment and installations. Additionally, Petrobras has a model of communication, processing and recording of oil spills that permits the daily monitoring of these incidents, their impacts and mitigation measures.
The oil spill level in our upstream operations in 2014 was kept below 0.5 m3 per mmbbl produced. Data for 2012 compiled by the International Association of Oil & Gas Producers indicates that the industry average was 0.76 m3 of oil spilled per mmbbl produced. We continue to evaluate and develop initiatives to address HSE concerns and to reduce our exposure to HSE risks. In 2014, we had oil spills totaling 437.1 barrels of crude oil, compared to 1,176 barrels of crude oil in 2013 (a 63% reduction) and 2,436 barrels of crude oil in 2012.
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Our insurance programs focus principally on the evaluation of risks and the replacement value of assets, which is customary for our industry. Under our risk management policy, risks associated with our principal assets, such as refineries, tankers and offshore production units and drilling rigs, are insured for their replacement value with third-party Brazilian insurers. Although some policies are issued in Brazil, most of our policies are reinsured abroad with reinsurers rated A- or higher by Standard & Poor’s rating agency or B+ or higher by A.M. Best. Part of our international operations are insured or reinsured by our Bermudian subsidiary BEAR following the same rating criteria.
Less valuable assets, including but not limited to small auxiliary boats, certain storage facilities, and some administrative installations, are self-insured. We do not maintain coverage for business interruption, except for a minority of our international operations and a few specific assets in Brazil. We generally do not maintain coverage for our wells for all of our Brazilian operations, except when required by a joint operating agreement. Although we do not insure most of our pipelines, we have insurance against damage or loss to third parties resulting from specific incidents, such as unexpected seepage and oil pollution. We also maintain coverage for risks associated with cargo, hull and machinery. All projects and installations under construction that have an estimated maximum loss above U.S.$80 million are covered by a construction insurance policy.
We have operations in 16 countries outside Brazil and maintain varying levels of third-party liability insurance for our domestic and international operations as a result of a variety of factors, including our country risk assessments, whether we have onshore and offshore operations or legal requirements imposed by the particular country in which we operate. We maintain insurance coverage for operational third-party liability with respect to our onshore and offshore activities, including losses to third parties resulting from environmental risks such as oil spills, in Brazil up to an aggregate policy limit of U.S.$250 million. We also maintain additional protection and indemnity (P&I) marine insurance against third-party liability related to our domestic offshore operations up to an aggregate policy limit of up to U.S.$500 million for a period of 12 months. In the event of an explosion or similar event at one of our offshore rigs in Brazil, these policies can provide combined third-party liability coverage of up to U.S.$750 million.
Our domestic and international operational third-party liability policies cover claims made against us by or on behalf of individuals who are not our employees in the event of property damage, personal injury or death, subject to the policy limits set forth above. As a general rule, our service providers are required to indemnify us for a claim we pay directly to a third party as a result of a court decision holding us liable for the actions of that service provider. Our operational third-party liability policies also cover environmental damage from oil spills (including liability arising from an explosion or similar sudden and accidental event at one of our offshore rigs) as well as litigation and clean-up and remediation costs, but do not cover governmental fines or punitive damages.
We maintain separate “control-of-well” insurance policies at our international operations to cover liability arising from the uncontrolled eruption of oil, gas, water or drilling fluid, as well as to cover claims for environmental damage from well blow-outs and similar events as well as related clean-up costs, with aggregate policy limits up to U.S.$540 million for a period of 18 months depending on the country. In the U.S. Gulf of Mexico, for example, we maintain third-party liability coverage up to an aggregate policy limit of U.S.$250 million, and control-of-well liability insurance up to U.S.$540 million. Depending on the particular circumstances, either of these policies could apply in the event of an explosion or similar event at one of our offshore rigs in the U.S. Gulf of Mexico.
We generally do not maintain control-of-well insurance for our domestic operations onshore and offshore Brazil, except when required by a joint operating agreement. As a result, we would bear the costs of clean-up, decontamination and any proceedings arising out of a control-of-well incident. Any loss of hydrocarbon containment from our domestic operations onshore and offshore that is not attributable to a control-of-well issue would be covered by either our Protection & Indemnity (P&I) insurance, with coverage of up to U.S.$500 million for our mobile offshore units, or our onshore-offshore liability policy, with coverage of up to U.S.$250 million.
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The premium for renewing our domestic property risk insurance policy for an 18-month period beginning December 2013 was U.S.$104.9 million. This represented a nominal increase of 7.7% over the prior 18-month period. The insured value of our assets, in the same period, increased by 11.3% to U.S.$168.2 billion. Since 2001, our risk retention for operational risks has been U.S.$20 million while for engineering risks it may reach U.S.$80 million in certain circumstances.
Additional Reserves and Production Information
During 2014, our oil and gas production in Brazil averaged 2,284 mboe/d, of which 89% was oil and 11% was natural gas. The Campos Basin is one of Brazil’s main and most prolific oil and gas offshore basins, with over 60 hydrocarbon fields discovered, eight large oil fields and a total area of approximately 115,000 km2 (28.4 million acres). In 2014, the Campos Basin produced an average 1,526 mbbl/d of oil and 548.4 mmcf/d (14.5 mmm3/d) of associated natural gas, comprising 71% of our total production from Brazil. We also conduct limited oil shale mining operations in São Mateus do Sul, in the Paraná Basin of Brazil, and we use oil shale from these deposits to produce synthetic oil and gas. Our oil shale industrialization business unit does not utilize the fracking method or the hydraulic fracturing method for purposes of oil production given that they are not proper for this end. We crush and subsequently heat in high temperatures all the shale we produce, obtaining a proper segregation of the products derived from such process. We do not inject any water or chemicals in the soil in connection with our oil shale mining operations.
On December 31, 2014, our estimated proved reserves of crude oil, condensate and natural gas in Brazil totaled 12.7 bnbbl of oil equivalent, including 10.9 bnbbl of crude oil and condensate and 296.0 bnm3 (11.2 tcf) of natural gas. As of December 31, 2014, our domestic proved developed crude oil and condensate reserves represented 64.5% of our total domestic proved crude oil and condensate reserves, and our domestic proved developed natural gas reserves represented 59.6% of our total domestic proved natural gas reserves. Total domestic proved crude oil and condensate reserves increased at an average annual rate of 1.8% in the last five years, and total natural gas proved reserves increased at an average annual rate of 2.7% over the same period.
We calculate reserves based on forecasts of field production, which depend on a number of technical parameters, such as seismic interpretation, geological maps, well tests, reservoir engineering studies and economic data. All reserve estimates involve some degree of uncertainty. The uncertainty depends primarily on the amount of reliable geological and engineering data available at the time of the estimate and the interpretation of that data. Our estimates are thus made using the most reliable data and technology at the time of the estimate, in accordance with the best practices in the oil and gas industry and regulations promulgated by the SEC.
Internal Controls over Proved Reserves
The reserve estimation process begins with an initial evaluation of our assets by geophysicists, geologists and engineers. Corporate Reserves Coordinators (Coordenadores de Reservas Corporativos, or CRCs) safeguard the integrity and objectivity of our reserve estimates by supervising and providing technical support to Regional Reserves Coordinators (Coordenadores de Reservas Regionais, or CRRs) who are responsible for preparing the reserve estimates. Our CRRs and CRCs have degrees in geophysics, geology, petroleum engineering, accounting and economics and are trained internally and abroad in international reserve estimates seminars. CRCs are responsible for compliance with SEC rules and regulations, consolidating and auditing the reserve estimation process. The technical person primarily responsible for overseeing the preparation of our domestic reserves is a member of the SPE, with 26 years of experience in the field and has been with Petrobras for over 31 years. The technical person primarily responsible for overseeing the preparation of our international reserves has 25 years of experience in the field and has been with Petrobras for 32 years. Our reserve estimates are approved by our board of executive officers, which then informs our board of directors of its approval.
79
DeGolyer and MacNaughton (D&M) used our reserve estimates to conduct a reserve audit of 96.5% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2014 from certain properties we own in Brazil. In addition, D&M used its own estimates of our reserves to conduct a reserves evaluation of 100% of the net proved crude oil, condensate, NGL and natural gas reserves as of December 31, 2014 from the properties we operate in Argentina. Furthermore, D&M used our reserve estimates to conduct a reserves audit of 100% of the net proved crude oil, condensate and natural gas reserves as of December 31, 2014 in properties we operate in the United States. The reserve estimates were prepared in accordance with the reserves definitions of Rule 4-10(a) of Regulation S-X of the SEC. For further information about our proved reserves, see “Supplementary Information on Oil and Gas Exploration and Production” beginning on page F-96. For disclosure describing the qualification of D&M’s technical person primarily responsible for overseeing our reserves audit and reserves evaluation, see Exhibit 99.1.
Changes in Proved Reserves
During 2014, we added 1,096.7 mmboe to our proved reserves, excluding synthetic oil and synthetic gas, while we (i) relinquished to the ANP eleven fields in Brazil(fourwith proved reserves) and (ii) we divested from fields in which we had interests in Peru, Colombia, Argentina and United States, representing aggregate proved reserves of 192.5 mmboe. The net result of these additions and dispositions was an increase of 904.1 mmboe to our proved reserves in 2014. Considering a production of 896.2 mmboe in 2014, our net increase of proved reserves was 7.9 mmboe. This volume production does not take into account the production of Extended Well Tests (EWTs) in exploratory blocks in Brazil, production of synthetic oil and synthetic gas and production in Bolivia, since the Bolivian Constitution prohibits the disclosure and registration of its reserves.
At year‐end 2014 compared to year‐end 2013, our proved undeveloped reserves company‐wide decreased by a net total of 493.8 mmboe. Thus, we had a total of 4,773.2 mmboe of proved undeveloped reserves company‐wide at December 31, 2014, compared to 5,267.0 mmboe of proved undeveloped reserves company-wide at December 31, 2013.
In Brazil, the net decrease in our proved undeveloped reserves in 2014 compared to 2013 is mostly derived from the conversion of some of our proved undeveloped reserves to proved developed reserves, attributable to the start-up of new production units in the Campos and Santos Basins, and the drilling of wells in existing production fields, amounting to 1,222.6 mmboe. In addition, our proved undeveloped reserves in Brazil were reduced by 29.3 mmboe due to the relinquishment of four fields with proved reserves to the ANP. This net decrease was partially offset by the 632.8 mmboe increase of proved undeveloped reserves derived from revisions to previous estimates and a 284.3 mmboe increase from extensions and discoveries mainly in the pre-salt areas of Santos and Campos Basins.
All reserve volumes described above are “net” to the extent that they only include Petrobras’s proportional participation in reserve volumes and exclude reserves attributed to our partners.
In 2014, we invested a total of U.S.$19.8 billion in development projects, of which 92% (U.S.$18.2 billion) was invested in Brazil, and converted a total of 1,299.5 mmboe of proved undeveloped reserves to proved developed reserves, approximately 94% (1,222.6 mmboe) of which were Brazilian reserves.
Most of our investments relate to long-term development projects which are developed in phases due to the large volumes and extensions involved, the deep and ultra-deep water infrastructure and the production resources complexity. In these cases, the full development of the reserves related to these investments can exceed five years.
We had a total of 4,773.2 mmboe of proved undeveloped reserves company-wide at year‐end 2014, approximately 2.1% (100.4 mmboe) of which have remained undeveloped for five years or more as a result of several factors affecting development and production, including the inherent complexity of ultra‐deepwater development projects, particularly in Brazil, and constraints in the capacity of our existing infrastructure.
80
The majority of the 100.4 mmboe of our proved undeveloped reserves that have remained undeveloped for five years or more consist of reserves in the Campos Basin, in which we are making investments to develop necessary infrastructure.
The following tables set forth our production of crude oil, natural gas, synthetic oil and synthetic gas by geographic area in 2014, 2013 and 2012:
| Hydrocarbon Production by Geographic Area | ||||||||||||||
| 2014 | 2013 | 2012 | ||||||||||||
| Oil (mbbl/d) (5) | Synthetic (4) | Nat. Gas (mmcf/d) (1) | Synthetic (1)(4) | Total (mboe/d) | Oil (mbbl/d) (5) | Synthetic (4) | Nat. Gas (mmcf/d) (1) | Synthetic (1)(4) | Total (mboe/d) | Oil | Synthetic | Nat. Gas (mmcf/d)(1) | Synthetic | Total (mboe/d) |
Brazil: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Roncador field(2) | 276.0 | ‒ | 121.6 | ‒ | 296.3 | 268.2 | ‒ | 105.3 | ‒ | 285.8 | 262.8 | ‒ | 101.4 | ‒ | 279.7 |
Other | 1,755.5 | 2.9 | 1,377.8 | 1.0 | 1,988.2 | 1,660.5 | 2.7 | 1,299.7 | 0.9 | 1,879.9 | 1,714.3 | 3.0 | 1,249.8 | 1.1 | 1,925.8 |
Total Brazil | 2,031.5 | 2.9 | 1,499.4 | 1.0 | 2,284.4 | 1,928.7 | 2.7 | 1,404.9 | 0.9 | 2,165.7 | 1,977.1 | 3.0 | 1,351.3 | 1.1 | 2,205.5 |
International: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South America (outside ofBrazil) | 57.3 | ‒ | 545.9 | ‒ | 148.3 | 70.2 | ‒ | 546.7 | ‒ | 161.4 | 76.4 | ‒ | 629.9 | ‒ | 181.4 |
North America | 27.3 | ‒ | 12.8 | ‒ | 29.5 | 11.8 | ‒ | 11.9 | ‒ | 13.8 | 9.0 | ‒ | 18.8 | ‒ | 12.1 |
Africa | ‒ | ‒ | ‒ | ‒ | ‒ | 25.9 | ‒ | 0.0 | ‒ | 25.9 | 51.8 | ‒ | ‒ | ‒ | 51.8 |
Total International | 84.7 | ‒ | 558.7 | ‒ | 177.8 | 107.9 | ‒ | 558.7 | ‒ | 201.1 | 137.3 | ‒ | 648.7 | ‒ | 245.4 |
Total consolidatedproduction | 2,116.2 | ‒ | 2,058.1 | ‒ | 2,462.2 | 2,036.6 | 2.7 | 1,963.6 | 0.9 | 2,366.7 | 2,114.4 | 3.0 | 2,000.0 | 1.1 | 2,450.9 |
Equity and non-consolidated affiliates(3): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South America (outside of Brazil) | 4.6 | ‒ | 1.6 | ‒ | 4.9 | 5.5 | ‒ | 1.7 | ‒ | 5.8 | 6.4 | ‒ | 2.4 | ‒ | 6.8 |
Africa | 26.6 | ‒ | ‒ | ‒ | 26.6 | 13.8 | ‒ | 0.0 | ‒ | 13.8 | ‒ | ‒ | ‒ | ‒ | ‒ |
Worldwide production | 2,147.4 | 2.9 | 2,059.7 | 1.0 | 2,493.7 | 2,055.9 | 2.7 | 1,965.3 | 0.9 | 2,386.4 | 2,120.8 | 3.0 | 2,002.4 | 1.1 | 2,457.7 |
(1) Natural gas production figures are the production volumes of natural gas available for sale, excluding flared and reinjected gas and gas consumed in operations.
(2) Roncador field is separately included as it contains more than 15% of our total proved reserves.
(3) Equity-accounted investees.
(4) We produce synthetic oil and synthetic gas from oil shale deposits in São Mateus do Sul, in the Paraná Basin of Brazil.
(5) Oil production includes LNG and production from extended well tests.
81
The following table sets forth our estimated net proved developed and undeveloped reserves of crude oil and natural gas by region as of December 31, 2014.
Estimated Net Proved Developed and Undeveloped Reserves | |||||||
Reserves category | Reserves | ||||||
| Oil (mmbbl) | Natural gas (bncf) | Total oil and natural gas (mmboe) | Synthetic oil (mmbbl)(1) | Synthetic gas (bncf)(1) | Total synthetic oil and synthetic gas (mmboe) | Total oil and gas products (mmboe) |
Proved developed: |
| ||||||
Brazil | 7,002.7 | 6,661.0 | 8,112.8 | 7.9 | 10.6 | 9.6 | 8,122.5 |
International |
|
|
|
|
|
| |
South America (outside of Brazil) | 52.0 | 358.2 | 111.7 | 0.0 | 0.0 | 0.0 | 111.7 |
North America | 63.6 | 146.2 | 88.0 | 0.0 | 0.0 | 0.0 | 88.0 |
Total International | 115.6 | 504.3 | 199.7 | 0.0 | 0.0 | 0.0 | 199.7 |
Total consolidated proved developedreserves | 7,118.3 | 7,165.4 | 8,312.5 | 7.9 | 10.6 | 9.6 | 8,322.2 |
Equity and non-consolidated affiliates |
|
|
|
|
|
| |
South America (outside of Brazil) | 9.4 | 15.7 | 12.0 | 0.0 | 0.0 | 0.0 | 12.0 |
Africa | 30.8 | 14.4 | 33.2 | 0.0 | 0.0 | 0.0 | 33.2 |
Total non-consolidated proved developed reserves | 40.2 | 30.2 | 45.2 | 0.0 | 0.0 | 0.0 | 45.2 |
Total proved developed reserves | 7,158.5 | 7,195.6 | 8,357.8 | 7.9 | 10.6 | 9.6 | 8,367.4 |
|
|
|
|
|
|
|
|
Proved undeveloped: |
|
|
|
|
|
|
|
Brazil | 3,848.2 | 4,509.2 | 4,599.7 | 0.0 | 0.0 | 0.0 | 4,599.7 |
International |
|
|
|
|
|
|
|
South America (outside of Brazil) | 14.6 | 372.5 | 76.7 | 0.0 | 0.0 | 0.0 | 76.7 |
North America | 56.4 | 33.8 | 62.1 | 0.0 | 0.0 | 0.0 | 62.1 |
Total International | 71.1 | 406.3 | 138.8 | 0.0 | 0.0 | 0.0 | 138.8 |
Total consolidated proved undevelopedreserves | 3,919.2 | 4,915.6 | 4,738.5 | 0.0 | 0.0 | 0.0 | 4,738.5 |
Equity and non-consolidated affiliates |
|
|
|
|
|
|
|
South America (outside of Brazil) | 8.6 | 11.9 | 10.5 | 0.0 | 0.0 | 0.0 | 10.5 |
Africa | 23.3 | 4.9 | 24.1 | 0.0 | 0.0 | 0.0 | 24.1 |
Total non-consolidated proved undevelopedreserves | 31.9 | 16.8 | 34.7 | 0.0 | 0.0 | 0.0 | 34.7 |
Total proved undeveloped reserves | 3,951.1 | 4,932.3 | 4,773.2 | 0.0 | 0.0 | 0.0 | 4,773.2 |
Total proved reserves (developed and undeveloped) | 11,109.6 | 12,127.9 | 13,130.9 | 7.9 | 10.6 | 9.6 | 13,140.6 |
_____________
(1) Volumes of synthetic oil and synthetic gas from oil shale deposits in the Paraná Basin in Brazil have been included in our proved reserves in accordance with the SEC rules for estimating and disclosing reserve quantities.
82
The table below summarizes information about the changes in total proved reserves of our consolidated entities for 2014, 2013 and 2012:
Total Proved Developed and Undeveloped Reserves (consolidated entities only) (1) | |||||||
| Oil (mmbbl) | Natural gas (bncf) | Total oil and natural gas (mmboe) | Synthetic oil (mmbbl) | Synthetic gas (bncf) | Total synthetic oil and synthetic gas (mmboe) | Total oil and gas products (mmboe) |
Reserves quantity information for the year ended December 31, 2014 |
|
|
|
|
|
|
|
January 1, 2014 | 10,947.7 | 12,483.2 | 13,028.3 | 8.8 | 11.8 | 10.7 | 13,039.0 |
Revisions of previous estimates | 631.4 | 539.6 | 721.4 | 0.2 | 0.1 | 0.2 | 721.6 |
Improved recovery | 0.5 | 10.8 | 2.3 | 0.0 | 0.0 | 0.0 | 2.3 |
Purchases of mineralsin situ | 22.9 | 47.1 | 30.8 | 0.0 | 0.0 | 0.0 | 30.8 |
Extensions and discoveries | 272.3 | 264.0 | 316.3 | 0.0 | 0.0 | 0.0 | 316.3 |
Production | (732.9) | (911.8) | (884.8) | (1.1) | (1.4) | (1.3) | (886.1) |
Sales of mineralsin situ | (104.5) | (351.9) | (163.1) | 0.0 | 0.0 | 0.0 | (163.1) |
December 31, 2014 | 11,037.5 | 12,081.0 | 13,051.0 | 7.9 | 10.6 | 9.6 | 13,060.7 |
|
|
|
|
|
|
|
|
Reserves quantity information for the year ended December 31, 2013 |
|
|
|
|
|
|
|
January 1, 2013 | 10,928.5 | 11,541.2 | 12,852.1 | 8.3 | 13.3 | 10.6 | 12,862.6 |
Transfer/Disposal of assets with loss of control(2) | (65.0) | (22.5) | (68.8) | ‒ | ‒ | ‒ | (68.8) |
Revisions of previous estimates | (74.7) | (213.3) | (110.2) | 1.3 | (0.1) | 1.2 | (109.0) |
Improved recovery | 124.2 | 916.0 | 276.8 | ‒ | ‒ | ‒ | 276.8 |
Purchases of mineralsin 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 mineralsin 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 mineralsin 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 mineralsin situ | ‒ | ‒ | ‒ | ‒ | ‒ | ‒ | ‒ |
December 31, 2012 | 10,928.5 | 11,541.2 | 12,852.1 | 8.3 | 13.3 | 10.6 | 12,862.6 |
____________
(1) Natural gas production volumes used in this table are the net volumes withdrawn from Petrobras’s proved reserves, including flared gas consumed in operations and excluding reinjected gas. Oil production volumes used in this table are net volumes withdrawn from Petrobras’s proved reserves and exclude LNG and production from extended well tests. As a result, the oil and natural gas production volumes in this table are different from those shown in the production table above, which shows the production volumes of natural gas available for sale.
(2) This line represents the amount of proved reserves excluded from our consolidated total proved reserves due to the implementation of our joint venture with BTG Pactual to jointly explore oil and gas opportunities in Africa. Since July 2013, we no longer hold the corporate control of the entities incorporated in Nigeria directly responsible for our operations in such country. As such, we no longer consolidate the Nigeria reserves held by Brasoil Oil Services Company (Nigeria) Ltd., Petroleo Brasileiro Nigeria Ltd into our consolidated reserves.
83
We do not have any material acreage expiring before 2025.
The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage in which Petrobras had interests as of December 31, 2014.
Gross and Net Productive Wells and Gross and Net Developed and Undeveloped Acreage | ||||||||
| As of December 31, 2014 | |||||||
| Oil | Natural gas | Synthetic oil | Synthetic gas | ||||
| ||||||||
Gross and net productive wells(1): | Gross | Net | Gross | Net | Gross | Net | Gross | Net |
Consolidated subsidiaries |
|
|
|
|
|
|
|
|
Brazil | 8,275 | 8,263 | 227 | 219 | ‒ | ‒ | ‒ | ‒ |
International |
|
|
|
|
|
|
|
|
South America (outside of Brazil) | 2,362 | 1,737 | 406 | 305 | ‒ | ‒ | ‒ | ‒ |
North America | 8 | 5.8 | 4 | 2.3 | ‒ | ‒ | ‒ | ‒ |
Total international | 2,370 | 1,743 | 410 | 307.3 | ‒ | ‒ | ‒ | ‒ |
Total consolidated | 10,645 | 10,006 | 637 | 526.3 | ‒ | ‒ | ‒ | ‒ |
Equity and non-consolidated affiliates: |
|
|
|
|
|
|
|
|
South America (outside of Brazil) | 130 | 37.5 | 3 | 1.1 | ‒ | ‒ | ‒ | ‒ |
Africa | 40 | 3.4 | ‒ | ‒ | ‒ | ‒ | ‒ | ‒ |
Total gross and net productive wells | 10,815 | 10,047 | 640 | 527 | ‒ | ‒ | ‒ | ‒ |
| As of December 31, 2014 | |||||||
| Oil | Natural gas | Synthetic oil | Synthetic gas | ||||
| (in acres) | |||||||
Gross and net developed acreage: | Gross | Net | Gross | Net | Gross | Net | Gross | Net |
Brazil | 4,214,376.3 | 3,914,470.8 | 408,031.7 | 391,053.3 | 1,346.0 | 1,346.0 | ‒ | ‒ |
International |
|
|
|
|
|
|
|
|
South America (outside of Brazil) | 1,328,531.1 | 1,030,824.9 | 2,331,174.6 | 1,629,335.5 | ‒ | ‒ | ‒ | ‒ |
North America | 12,776.3 | 7,220.1 | 6,194.1 | 1,764.4 | ‒ | ‒ | ‒ | ‒ |
Total international | 1,341,307.4 | 1,038,045.0 | 2,337,368.7 | 1,631,099.9 | ‒ | ‒ | ‒ | ‒ |
Total consolidated | 5,555,683.7 | 4,952,515.8 | 2,745,400.5 | 2,022,153.2 | 1,346.0 | 1,346.0 | ‒ | ‒ |
Equity and non-consolidated affiliates: |
|
|
|
|
|
|
|
|
South America (outside of Brazil) | 250,346.7 | 61,750.1 | 12,195.0 | 4,031.3 | ‒ | ‒ | ‒ | ‒ |
Africa | 312,368.3 | 23,771.2 | ‒ | ‒ | ‒ | ‒ | ‒ | ‒ |
Total non-consolidated | 562,715.0 | 85,521.3 | 12,195.0 | 4,031.3 | ‒ | ‒ | ‒ | ‒ |
Total gross and net developed acreage | 6,118,398.7 | 5,038,037.1 | 2,757,595.4 | 2,026,184.5 | 1,346.0 | 1,346.0 | ‒ | ‒ |
84
| As of December 31, 2014 | |||||||
| Oil | Natural gas | Synthetic oil | Synthetic gas | ||||
| (in acres) | |||||||
Gross and net undeveloped acreage: | Gross | Net | Gross | Net | Gross | Net | Gross | Net |
Brazil | 1,298,072.5 | 1,156,821.2 | 255,516.2 | 248,728.1 | ‒ | ‒ | ‒ | ‒ |
International |
|
|
|
|
|
|
|
|
South America (outside of Brazil) | 224,401.9 | 150,499.4 | 719,218.6 | 500,523.4 | ‒ | ‒ | ‒ | ‒ |
North America | 10,921.9 | 7,113.2 | 1,690.2 | 1,376.9 | ‒ | ‒ | ‒ | ‒ |
Total international | 235,323.7 | 157,612.6 | 720,908.8 | 501,900.3 | ‒ | ‒ | ‒ | ‒ |
Total consolidated | 1,533,396.3 | 1,314,433.8 | 976,425.0 | 750,628.3 | ‒ | ‒ | ‒ | ‒ |
Equity and non-consolidated affiliates: |
|
|
|
|
|
|
|
|
South America (outside of Brazil) | 289,377.7 | 73,915.4 | 22,689.6 | 7,596.8 | ‒ | ‒ | ‒ | ‒ |
Africa | 332,206.1 | 27,904.1 | ‒ | ‒ | ‒ | ‒ | ‒ | ‒ |
Total non-consolidated | 621,583.8 | 101,819.5 | 22,689.6 | 7,596.8 | ‒ | ‒ | ‒ | ‒ |
Total gross and net undeveloped acreage | 2,154,980.1 | 1,416,253.4 | 999,114.6 | 758,225.2 | ‒ | ‒ | ‒ | ‒ |
_____________
(1) A “gross” well or acre is a well or acre in which a working interest is owned, while the number of “net” wells or acres is the sum of fractional working interests in gross wells or acres.
85
The following table sets forth the number of net productive and dry exploratory and development wells drilled for the last three years.
Net Productive and Dry Exploratory and Development Wells | |||
| 2014 | 2013 | 2012 |
Net productive exploratory wells drilled: |
|
|
|
Consolidated subsidiaries: |
|
|
|
Brazil | 48.3 | 67.55 | 44.7 |
South America (outside of Brazil) | 4.7 | 3.5 | 4.0 |
North America | 0.4 | ‒ | 1.1 |
Africa | ‒ | ‒ | ‒ |
Other | ‒ | ‒ | ‒ |
Total consolidated subsidiaries | 53.4 | 71.05 | 49.8 |
Equity and non-consolidated affiliates: |
|
|
|
South America (outside of Brazil) | ‒ | ‒ | 0.4 |
Africa | ‒ | ‒ | ‒ |
Total productive exploratory wells drilled | 53.4 | 71.05 | 50.2 |
Net dry exploratory wells drilled: |
|
|
|
Consolidated subsidiaries: |
|
|
|
Brazil | 19.15 | 16.75 | 42.2 |
South America (outside of Brazil) | 1.1 | 0.8 | 3.0 |
North America | ‒ | 0.9 | 0.5 |
Africa | ‒ | ‒ | 0.7 |
Other | ‒ | ‒ | ‒ |
Total consolidated subsidiaries | 20.25 | 18.45 | 46.4 |
Equity and non-consolidated affiliates: |
|
|
|
South America (outside of Brazil) | ‒ | 0.5 | ‒ |
Africa | 0.9 | ‒ | ‒ |
Total dry exploratory wells drilled | 21.15 | 18.95 | 46.4 |
Total number of net exploratory wells drilled | 74.55 | 90.0 | 96.6 |
Net productive development wells drilled: |
|
|
|
Consolidated subsidiaries: |
|
|
|
Brazil | 397.97 | 399.73 | 355.1 |
South America (outside of Brazil) | 41.8 | 57.7 | 239.9 |
North America | ‒ | 2.5 | 1.8 |
Africa | ‒ | ‒ | 0.6 |
Other | ‒ | ‒ | ‒ |
Total consolidated subsidiaries | 439.77 | 459.93 | 597.4 |
Equity and non-consolidated affiliates: |
|
|
|
South America (outside of Brazil) | 0.4 | 1.5 | 2.4 |
Africa | 0.7 | 0.6 | ‒ |
Total productive development wells drilled | 440.87 | 462.03 | 599.8 |
Net dry development wells drilled: |
|
|
|
Consolidated subsidiaries: |
|
|
|
Brazil | 12.65 | 6 | 1 |
South America (outside of Brazil) | ‒ | ‒ | ‒ |
North America | ‒ | ‒ | ‒ |
Africa | ‒ | ‒ | ‒ |
Other | ‒ | ‒ | ‒ |
Total consolidated subsidiaries | 12.65 | 6.0 | 1 |
Equity and non-consolidated affiliates: |
|
|
|
South America (outside of Brazil) | ‒ | ‒ | ‒ |
Africa | 0.1 | ‒ | ‒ |
Total dry development wells drilled | 12.75 | 6.0 | 1 |
Total number of net development wells drilled | 453.62 | 468.03 | 600.8 |
86
The following table summarizes the number of wells in the process of being drilled as of December 31, 2014. For more information about our ongoing exploration and production activities in Brazil, see “—Exploration and Production.” Our present exploration and production activities outside of Brazil are described in “—International.”
Number of Wells Being Drilled as of December 31, 2014 | ||
| Year-end 2014 | |
| Gross | Net |
Wells Drilling |
|
|
Consolidated Subsidiaries: |
|
|
Brazil | 45 | 39.05 |
International: |
|
|
South America (outside of Brazil) | 8 | 4.6 |
North America | 3 | 1.4 |
Africa | ‒ | ‒ |
Others | ‒ | ‒ |
Total International | 11 | 6 |
Total consolidated production | 56 | 45.05 |
Equity and non-consolidated affiliates: |
|
|
South America (outside of Brazil) | 3 | 0.9 |
Africa | 3 | 0.3 |
Total wells drilling | 62 | 46.25 |
The following table sets forth our average sales prices and average production costs by geographic area and by product type for the last three years.
| Brazil | South America (outside of Brazil) | North America | Africa | Total | Equity and non-consolidated affiliates(2) |
| (U.S.$) | |||||
During 2014 |
|
|
|
|
|
|
Average sales prices |
|
|
|
|
|
|
Oil, per barrel | 87.84 | 79.28 | 90.31 | ‒ | 87.64 | 100.62 |
Natural gas, per thousand cubic feet(1) | 7.99 | 3.50 | 4.77 | ‒ | 7.45 | ‒ |
Synthetic oil, per barrel | 92.63 | ‒ | ‒ | ‒ | 92.63 | ‒ |
Synthetic gas, per thousand cubic feet | 9.68 | ‒ | ‒ | ‒ | 9.68 | ‒ |
Average production costs, per barrel – total | 16.89 | 12.32 | 6.23 | ‒ | 16.49 | 32.45 |
During 2013 |
|
|
|
|
|
|
Average sales prices |
|
|
|
|
|
|
Oil, per barrel | 98.19 | 82.82 | 99.29 | 107.88 | 97.72 | 108.75 |
Natural gas, per thousand cubic feet(1) | 7.95 | 3.88 | 3.97 | ‒ | 7.40 | ‒ |
Synthetic oil, per barrel | 99.54 | ‒ | ‒ | ‒ | 99.54 | ‒ |
Synthetic gas, per thousand cubic feet | 8.24 | ‒ | ‒ | ‒ | 8.24 | ‒ |
Average production costs, per barrel – total | 15.26 | 17.29 | 30.79 | 6.93 | 15.40 | 9.40 |
During 2012 |
|
|
|
|
|
|
Average sales prices |
|
|
|
|
|
|
Oil, per barrel | 104.60 | 81.53 | 100.56 | 112.15 | 103.90 | 89.73 |
Natural gas, per thousand cubic feet(1) | 8.08 | 3.37 | 3.17 | ‒ | 7.75 | ‒ |
Synthetic oil, per barrel | 99.13 | ‒ | ‒ | ‒ | 99.13 | ‒ |
Synthetic gas, per thousand cubic feet | 7.33 | ‒ | ‒ | ‒ | 7.33 | ‒ |
Average production costs, per barrel – total | 13.75 | 13.71 | 6.69 | 9.39 | 13.62 | 22.80 |
(1) The volumes of natural gas used in the calculation of this table are the production volumes of natural gas available for sale and are also shown in the production table above. Natural gas amounts were converted from bbl to cubic feet in accordance with the following scale: 1 bbl = 6 cubic feet.
(2) Operations in Venezuela and in Africa-PO&G (2014 and 2013).
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Item 4A. Unresolved Staff Comments
None.
Item 5. Operating and Financial Review and Prospects
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The information derived from our financial statements as of and for the years ended December 31, 2014, 2013 and 2012 has been prepared in accordance with IFRS issued by the IASB. For more information, see “Presentation of Financial and Other Information” and Notes 2, 4 and 5 to our audited consolidated financial statements.
You should read the following discussion of our financial condition and results of operations together with our audited consolidated financial statements and the accompanying notes beginning on page F-4 of this annual report.
We earn income from:
· domestic sales, which consist of sales of oil products (including diesel, gasoline, jet fuel, naphtha, fuel oil and liquefied petroleum gas), natural gas, ethanol, electricity and petrochemical products;
· export sales, which consist primarily of sales of crude oil and oil products;
· international sales (excluding export sales), which consist of sales of crude oil, natural gas and oil products that are purchased, produced and refined abroad; and
· other sources, including services, interest income from investments, shareofearnings in equity-accounted investees, foreign exchange variation gains and inflation indexation gains on financial instruments.
Our expenses include:
· costs of sales (comprised of direct labor costs, operating costs and purchases of crude oil and oil products); property, plant and equipment maintenance and repairs; depreciation, depletion and amortization of property, plant and equipment, oil fields and signing bonuses (acquisition costs); and oil and gas exploration costs;
· selling (which include expenses for transportation and distribution of our products), general and administrative expenses;
· research and development;
· impairment of assets and other operating expenses; and
· interest expense, inflation indexation and foreign exchange variation losses on debt and other financial instruments.
Fluctuations in our financial condition and results of operations are driven by a combination of factors, including:
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· the volume of crude oil, oil products and natural gas we produce and sell;
· changes in international prices of crude oil and oil products (denominated in U.S. dollars);
· changes in the domestic prices of crude oil and oil products (denominated inreais);
· the demand for oil products in Brazil and the amount of imports required to meet the domestic demand;
· the recoverable amounts of assets for impairment testing purposes;
· fluctuations in thereal vs. U.S. dollar exchange rates and, to a lesser degree, other currencies, as set out in Note 33.2(c) to our audited consolidated financial statements; and
· the amount of production taxes from our operations that we are required to pay.
The profitability of our operations in any particular accounting period is related to the sales volume and prices of the crude oil, oil products, natural gas and biofuels that we sell and the relationship of these prices to international prices. Our consolidated net sales in 2014 totaled 1,447,912 mboe, representing U.S.$143,657 million in sales revenues, compared to 1,384,616 mboe, representing U.S.$141,462 million in sales revenues, in 2013, and 1,385,917 mboe, representing U.S.$144,103 million in sales revenues, in 2012.
As a vertically integrated company, we process most of our crude oil production in our refineries and sell the refined oil products primarily in the Brazilian domestic market. Therefore, the price of oil products in Brazil has a more significant impact on our financial results than crude oil prices. International oil product prices vary over time as the result of many factors, including the price of crude oil. Over the long term, we intend to sell our products in Brazil at parity with international product prices. However, because we do not adjust our prices for gasoline, diesel and certain other oil products to reflect short-term volatility in the international markets, our downstream margins may be significantly different than those of other integrated international oil companies within a given financial reporting period due to significant rapid or sustained increases or decreases in the international prices of crude oil and oil products, or in therealvs. U.S. dollar exchange rate.
The average price of Brent crude, an international benchmark oil, was U.S.$98.99 per barrel in 2014, U.S.$108.66 per barrel in 2013 and U.S.$111.58 per barrel in 2012. In December 2014, Brent crude oil prices averaged U.S.$62.53 per barrel. Due to the devaluation of thereal throughout 2014, the average price of the Brent crude, when expressed inreais, decreased to R$231.30 per barrel during 2014 from R$234.52 per barrel during 2013.
In 2012, we announced price increases at the refinery gate (the wholesale price we sell to distributors), totaling 7.8% for gasoline and 10.2% for diesel compared to December 31, 2011 prices, to partially adjust to higher international oil product prices. In 2013, we announced further price increases at the refinery gate, totaling 10.9% for gasoline and 19.6% for diesel compared to December 31, 2012 prices, and in November 2014 we announced further price increases at the refinery gate totaling 3% for gasoline and 5% for diesel compared to December 31, 2013 prices.
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Since November 2013, our diesel and gasoline pricing policy has been based on the following principles and objectives:
• Achieving, in a reasonable time period, an alignment of Brazilian and international diesel and gasoline prices; and
• Preventing the transfer of volatility in diesel and gasoline international prices to the domestic consumer.
During 2014, 77.7% of our sales revenues were derived from sales of oil products, natural gas and other products in Brazil, compared to 75.3% in 2013 and 69.7% in 2012.
| For the Year Ended December 31, | ||||||||
| 2014 | 2013 | 2012 | ||||||
| Volume | Net Average Price | Sales Revenues | Volume | Net Average Price | Sales Revenues | Volume | Net Average Price | Sales Revenues |
| (mbbl, except as otherwise noted) | (U.S.$)(1) | (U.S.$ million) | (mbbl, except as otherwise noted) | (U.S.$)(1) | (U.S.$ million) | (mbbl, except as otherwise noted) | (U.S.$)(1) | (U.S.$ million) |
Diesel | 365,510 | 116.50 | 42,586 | 359,266 | 115.30 | 41,435 | 343,063 | 112.39 | 38,558 |
Automotive gasoline | 226,230 | 104.80 | 23,702 | 215,419 | 109.00 | 23,470 | 208,695 | 111.54 | 23,277 |
Fuel oil (including bunker fuel) | 43,494 | 100.20 | 4,357 | 35,588 | 97.30 | 3,464 | 30,896 | 92.71 | 2,864 |
Naphtha | 59,443 | 94.60 | 5,622 | 62,520 | 94.10 | 5,885 | 60,331 | 95.23 | 5,745 |
Liquefied petroleum gas | 85,723 | 43.50 | 3,729 | 84,281 | 47.00 | 3,960 | 81,992 | 50.32 | 4,126 |
Jet fuel | 40,285 | 138.10 | 5,562 | 38,751 | 143.30 | 5,553 | 38,896 | 150.72 | 5,862 |
Other oil products | 76,567 | 75.40 | 5,771 | 74,068 | 77.80 | 5,760 | 72,969 | 81.67 | 5,958 |
Subtotal oil products | 897,252 | 101.80 | 91,329 | 869,893 | 102.90 | 89,527 | 836,842 | 103.20 | 86,392 |
Natural gas (boe) | 162,633 | 49.40 | 8,035 | 149,277 | 49.40 | 7,376 | 130,544 | 50.41 | 6,580 |
Ethanol, nitrogen products, renewables and other non-oil products | 36,181 | 106.70 | 3,862 | 33,346 | 146.00 | 4,868 | 30,369 | 132.60 | 4,027 |
Electricity, services and others | − | − | 8,384 | − | − | 4,693 | ‒ | ‒ | 3,498 |
Total domestic market | 1,096,066 | − | 111,610 | 1,052,516 | − | 106,464 | 997,755 | ‒ | 100,497 |
Exports | 143,423 | 97.10 | 13,930 | 144,111 | 105.30 | 15,172 | 203,234 | 109.99 | 22,353 |
International sales | 208,423 | 86.90 | 18,117 | 187,989 | 105.50 | 19,826 | 184,928 | 114.92 | 21,253 |
Total international market | 351,846 | − | 32,047 | 332,100 | − | 34,998 | 388,162 | ‒ | 43,606 |
Consolidated sales revenues | 1,447,912 | − | 143,657 | 1,384,616 | − | 141,462 | 1,385,917 | ‒ | 144,103 |
(1) Net average price calculated by dividing sales revenues by the volume for the year.
In addition to taxes paid on behalf of consumers to federal, state and municipal governments, such as the Domestic Value-Added Tax (Imposto sobre Circulação de Mercadorias eServiços, or ICMS), we are required to pay three main charges on our oil production activities in Brazil: royalties, special participation and retention bonuses. See Item 4. “Information on the Company—Regulation of the Oil and Gas Industry in Brazil—Taxation under Concession Regime for Oil and Gas” and Item 3. “Key Information—Risk Factors—Risks Relating to Brazil.”
These charges imposed by the Brazilian federal government are included in our cost of goods sold. In addition, we are subject to tax on our income at an effective rate of 34%, including 25% of corporate income tax and a social contribution tax at an effective rate of 9%, the standard corporate tax rates in Brazil.
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For further information about income taxes, other taxes payable, deferred income taxes and a reconciliation of income taxes calculated by applying a statutory tax rate and our tax expense, see Note 21 to our audited consolidated financial statements.
Inflation and Exchange Rate Variation
Inflation
Since the introduction of therealas the Brazilian currency in July 1994, inflation in Brazil has remained relatively stable. Inflation was 6.41% in 2014, 5.91% in 2013 and 5.84% in 2012 as measured by IPCA, the National Consumer Price Index. Inflation has had, and may continue to have, effects on our financial condition and results of operations. See Item 3. “Key Information—Risk Factors—Inflation, and the Brazilian government’s measures to combat inflation, may contribute significantly to economic uncertainty in Brazil, and may materially adversely affect us.”
Exchange Rate Variation
Our functional currency is the Brazilianreal and our presentation currency is the U.S. dollar. Therefore, we maintain our financial records inreais, 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 therealappreciates relative to the U.S. dollar, the effect is to generally increase both revenues and expenses when expressed in U.S. dollars. When thereal depreciates relative to the U.S. dollar, the effect is to generally decrease revenues and expenses when expressed in U.S. dollars.
From 2003 to 2011, considering the average exchange rates of each year, thereal appreciated against U.S. dollar each year (by an average of 7% per year), except for 2009 (when it depreciated by 9%). In 2014, thereal depreciated 9.1% against the U.S. dollar, compared to depreciation of 10.4% in 2013 and depreciation of 16.7% in 2012. Throughout 2015, therealhas continued to depreciate against the U.S. dollar. Through April 30, 2015, it has depreciated by 12.7% compared to December 31, 2014.
Fluctuations in exchange rate have multiple effects on our results of operations inreais. The relative pace at which our total revenues and expenses inreais increase or decrease with the exchange rate, and its impact on our margins, is affected by our pricing policy in Brazil. Absent changes in the international prices for crude oil, oil products and natural gas, when thereal appreciates against the U.S. dollar and we do not adjust our prices in Brazil, our margins generally improve. Absent changes in the international prices for crude oil, oil products and natural gas, when thereal depreciates against the U.S. dollar and we do not adjust our prices in Brazil, margins generally decline.
The depreciation of thereal against the U.S. dollar also increases our debt service inreais, as the amount ofreais necessary to pay principal and interest on foreign currency debt increases with the depreciation of thereal. A devaluation of thereal also increases our costs to import oil and oil products, imported goods and services necessary for our operations and our production taxes. Unless the depreciation of thereal is offset by higher prices for our products sold in Brazil, a devaluation increases our debt service relative to our cash flows while also reducing our operating margins.
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The foreign exchange variations on foreign-denominated assets and liabilities of entities for which thereal 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 thereal on our results and net income when expressed inreais also increases, thereby reducing the earnings available for distribution. Note 33.2(c) to our audited consolidated financial statements provides further information about our foreign exchange exposure related to assets and liabilities.
Since mid-May 2013 we have designated cash flow hedging relationships in which (a) the hedged items are portions of our highly probable future monthly export revenues in U.S. dollars, (b) the hedging instruments are portions of our long-term debt obligations denominated in U.S. dollars, and (c) the risk hedged is the effect of changes in exchange rates between the U.S. dollar and our functional currency, the Brazilianreal. Both long-term debt obligations (hedging instruments) and future exports (hedged items) are exposed to thereal/U.S. dollar foreign currency risks at their respective spot exchange rate. Cash flow hedge accounting allows gains and losses arising from the effect of changes in the foreign currency exchange rate on the hedging instruments to be recognized in other comprehensive income in shareholders’ equity and then reclassified from equity to profit or loss in the periods during which the hedged transactions occur, rather than being immediately recognized as profits or losses. See Notes 4.3.6 and 33.2(a) to our audited consolidated financial statements for further information about our cash flow hedge.
Exchange rate variation also affects the amount of retained earnings available for distribution by us when expressed in U.S. dollars. Amounts reported as available for distribution in our statutory accounting records are calculated inreais and prepared in accordance with the IFRS and they may increase or decrease when expressed in U.S. dollars as thereal appreciates or depreciates against the U.S. dollar.
The differences in our operating results from year to year occur as a result of a combination of factors, including primarily: the volume of crude oil, oil products and natural gas we produce and sell; the price at which we sell our crude oil, oil products and natural gas and the relationship of those prices to the international prices; the level and cost of imports and exports needed to satisfy our demand; production taxes; and the differential between Brazilian and international inflation rates, adjusted by the depreciation or appreciation of thereal against the U.S. dollar.
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The table below shows the amount by which each of these variables has changed during the last three years. Production volumes presented in this table are prepared in accordance with SPE criteria, which are the criteria we apply to analyze our operating results:
| 2014 | 2013 | 2012 |
Crude oil and NGL production (mbbl/d): |
|
|
|
Brazil | 2,034 | 1,931 | 1,980 |
International | 85 | 109 | 139 |
Non-consolidated international production(1) | 31 | 19 | 7 |
Total crude oil and NGL production | 2,150 | 2,059 | 2,126 |
Change in crude oil and NGL production | 4.4% | (3.2)% | (2.0)% |
Average sales price for crude (U.S.$/barrel): |
|
|
|
Brazil | 87.84 | 98.19 | 104.60 |
International | 82.93 | 89.86 | 94.37 |
Natural gas production (mmcf/d)(2): |
|
|
|
Brazil | 2,556 | 2,334 | 2,250 |
International | 558 | 546 | 582 |
Total natural gas production | 3,114 | 2,880 | 2,832 |
Change in natural gas production (sold only) | 8.1% | 1.7% | 4.4% |
Average sales price for natural gas (U.S.$/mcf)(2): |
|
|
|
Brazil | 7.99 | 7.95 | 8.08 |
International | 3.53 | 3.51 | 3.00 |
Year-end exchange rate (reais/U.S.$) | 2.66 | 2.34 | 2.04 |
Appreciation (depreciation) during the year(3) | (13.4)% | (14.6)% | (8.9)% |
Average exchange rate for the year (reais/U.S.$) | 2.35 | 2.16 | 1.96 |
Appreciation (depreciation) during the year(4) | (9.1)% | (10.4)% | (16.7)% |
Inflation rate (IPCA) | 6.41% | 5.91% | 5.84% |
(1) Non-consolidated companies in Venezuela and in Africa.
(2) Amounts were converted from bbl to cubic feet in accordance with the following scale: 1 bbl = 6 cubic feet.They do not include LNG but include reinjected gas.
(3) Based on year-end exchange rate (R$/U.S.$.)
(4) Based on average exchange rate for the year (R$/U.S.$.)
Virtually all of our revenues and expenses for our Brazilian operations are denominated and payable inreais. When the U.S. dollar strengthens relative to thereal, as it did in 2014 and 2013 (with an appreciation of 9.1% and 10.4%, respectively), revenues and expenses decrease when translated into U.S. dollars. The appreciation of the U.S. dollar against thereal affects the line items discussed below in different ways. As a consequence, the following comparison between our results of operations in 2014 and in 2013, and between our results of operations in 2013 and 2012, are impacted by the depreciation of thereal against the U.S. dollar during that period. See Note 2 of our audited consolidated financial statements for the year ended December 31, 2014 for more information about the translation ofreal amounts into U.S. dollars.
Results of Operations—2014 compared to 2013
Sales Revenues
Sales revenues increased by 2% to U.S.$143,657 million in 2014 from U.S.$141,462 million in 2013, primarily driven by:
• Higher oil product prices in the domestic market, due to diesel and gasoline price increases applied in 2013 and 2014, and to the impact of the appreciation of the U.S. dollar against thereal (9%) on the price (inreais) of oil products that are adjusted to reflect international prices (such as jet fuel and naphtha), as well as higher electricity and natural gas prices;
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• A 3% increase in the domestic demand for oil products, mainly diesel (2%), gasoline (5%) and fuel oil (21%), and an increase in crude oil export volumes (12%), partially offset by a decrease in oil product export volumes (15%); and
• Foreign currency translation effects (appreciation of the U.S. dollar against thereal), which reduced the increase of sales revenues in U.S. dollars. Excluding those effects, sales revenues increased by 11% when expressed inreais.
Cost of Sales
Cost of sales increased by 1% to U.S.$109,477 million in 2014 from U.S.$108,834 million in 2013, mainly due to:
• Higher import costs and production taxes attributable to the depreciation of thereal;
• Increased domestic oil products sales volumes (3%) and increased LNG import volumes to meet the demand; and
• Higher electricity costs as a result of increased electricity prices in the spot market.
Excluding the impact of foreign currency translation effects (appreciation of the U.S. dollar against thereal), cost of sales increased by 9% when expressed inreais.
Selling Expenses
Selling expenses increased by 39% to U.S.$6,827 million in 2014 from U.S.$4,904 million in 2013, mainly due to an allowance for impairment of trade receivables from the isolated electricity sector in the Northern region of Brazil (amounting to U.S.$1,948 million) primarily to cover certain trade receivables due by Eletrobras’s subsidiaries. See Note 8.4 to our audited consolidated financial statements.
General and Administrative Expenses
General and administrative expenses decreased by 5% to U.S.$4,756 million in 2014 from U.S.$4,982 million in 2013 mainly due toforeign currency translation effects. Excluding those effects,general and administrative expenses increased by 4% when expressed inreais, mainly as a result of higher employee compensation expenses arising from the 2013 and 2014 collective bargaining agreements. See Item 6. “Directors, Senior Management and Employees—Employees and Labor Relations.”
Exploration Costs
Exploration costs increased by 3% to U.S.$3,058 million in 2014 from U.S.$2,959 million in 2013, primarily due to an increase in write-offs of dry or sub-commercial wells. A breakdown of exploration costs by category is set out in Note 15 to our audited consolidated financial statements.
Research and Development Expenses
Research and development expenses decreased by 3% to U.S.$1,099 million in 2014 from U.S.$1,132 million in 2013, mainly due to foreign currency translation effects. Excluding those effects, research and development expenses were 7% higher when expressed inreais. That increase was due to an increase in gross revenues from high productivity oil fields in Brazil, since the ANP requires that we invest at least 1% of our gross revenues originating from those fields in research and development projects, and also a result of higher expenditures in research and development for projects in Brazil. See Item 5. ”Operating and Financial Review and Prospects” for further details about our research and development activities.
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Impairment of Assets
We recognized impairment charges of U.S.$16,823 million in 2014, mainly related to the following assets:
· Domestic refineries (U.S.$11,662 million): These charges resulted from individualized impairment testing of the second refining unit of Refinaria Abreu e Lima (RNEST) and Complexo Petroquímico do Rio de Janeiro (Comperj) conducted due to the postponement of each of these projects for an extended period of time. Those postponements were implemented as part of our measures to preserve cash and in response to the difficulties created for our suppliers by the “Lava Jato” investigation. The impairment charges are mainly attributable to project planning deficiencies, the use of a higher discount rate (reflecting a specific risk premium for the postponed projects), a delay in expected cash inflows resulting from postponing these projects and lower projected economic growth in Brazil;
· Domestic and international assets related to exploration and production of crude oil and natural gas (U.S.$3,766 million): these charges mainly result from lower international crude oil prices; and
· Petrochemical assets (U.S.$1,121 million): these charges are mainly attributable to changes in market assumptions and forecasts resulting from a decrease in economic activity, lower margins in the international market and modifications in tax regulations.
See Notes 4.10, 5.2 and 14 to our audited consolidated financial statements for more information about the impairment of these assets.
Write-Offs of Overpayments Incorrectly Capitalized
In the quarter ended September 30, 2014, we wrote off U.S.$2,527 million of capitalized costs representing amounts that Petrobras overpaid for the acquisition of property, plant and equipment in prior years resulting from a payment scheme uncovered by the Brazilian Federal Prosecutor’s Office in connection with the Lava Jato investigation. See Note 3 to our audited consolidated financial statements for a detailed description of this investigation, the overpayments charged by certain contractors and suppliers to Petrobras and our response to it, sources of information available to us, our methodology to estimate the overstatement of our assets and the impact of these overpayments on our financial statements.
Other Expenses, Net
Other expenses, net increased by 376% to U.S.$5,293 million in 2014 from U.S.$1,113 million in 2013. This U.S.$4,180 million increase primarily relates to:
· The write-off of the capitalized costs of Premium I and Premium II refineries due to our decision to abandon these projects (U.S.$1,236 million). See Note 12.4 to our audited consolidated financial statements;
· The impact of our Voluntary Separation Incentive Plan – PIDV (U.S.$1,035 million). See Note 22.8 to our audited consolidated financial statements;
· Higher decommissioning costs related to returned and abandoned areas (U.S.$501 million);
· The write-off of exploration and production areas returned to ANP and cancelled exploration and production projects (U.S.$249 million); and
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· Higher actuarial expenses related to retirees due to the review of our pension and medical benefit obligations (U.S.$130 million).
Other expenses were also higher in 2014 when compared to 2013, primarily because we recognized gains from the disposal of 50% of our interest in assets in Africa and of block BC-10 in Brazil in 2013 (which did not occur in 2014). Those effects were partially offset by a gain on disposal of our interest in Petrobras Energia Peru S.A. in 2014.
Net Finance Income (Expense)
Net finance expense was U.S.$1,635 million in 2014, a U.S.$1,156 million decrease compared to 2013 (U.S.$2,791 million) resulting from:
• A decrease in foreign exchange variation charges, because a smaller portion of our liabilities in U.S. dollars was exposed to exchange rate variation due to the extension of our cash flow hedge accounting policy to highly probable future exports, beginning in May 2013. For further information about our cash flow hedge accounting, see Notes 4.3.6 and 33.2(a) to our audited consolidated financial statements;
• Foreign exchange gains attributable to the appreciation of the U.S. dollar against other currencies, mainly the Euro;
• Inflation indexation gains on a contingent asset related to undue finance income – PIS and COFINS taxes paid by us from February 1999 to December 2002; and
• Inflation indexation gains on debt acknowledgement agreements with respect to trade receivables due by Eletrobras’s subsidiaries.
Finance expenses were also lower in 2014 when compared to 2013, mainly because in 2013 we recognized the effects of the settlement of certain of our tax debts and disputes through our participation in a federal tax refinancing/settlement program (REFIS), which increased our finance expense significantly in 2013 and was not recurring in 2014.
Those effects were partially offset by higher interest expenses resulting from an increase in our debt.
Income Taxes
We reported a loss for the fiscal year ended December 31, 2014, and consequently recognized tax loss carry-forwards for that period. See Note 21.3 to our audited consolidated financial statements for a reconciliation of statutory tax rates and our tax expense.
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Net Income (Loss) by Business Segment
We measure performance at the business segment level based on net income. The following is a discussion of the net income of our six business segments for 2014, compared to 2013. See Item 4. “Information on the Company” and Notes 4.2 and 29 to our audited consolidated financial statements for more information about our business segments.
| Year Ended December 31, | ||
| 2014(1) | 2013(1) | Percentage Change |
| (U.S.$ million) | ||
Exploration and Production | 14,133 | 19,523 | (28)% |
Refining, Transportation and Marketing | (15,405) | (8,150) | 89% |
Gas and Power | (410) | 631 | (165)% |
Biofuel | (127) | (117) | 9% |
Distribution | 499 | 863 | (42)% |
International | (1,145) | 1,729 | (166)% |
Corporate(2) | (5,359) | (3,331) | 61% |
Eliminations | 447 | (54) | (928)% |
Net income | (7,367) | 11,094 | (166)% |
_________________ |
|
|
|
(1) Excluding non-controlling interests. | |||
(2) Our Corporate segment comprises our financing activities not attributable to other segments, including corporate financial management, central administrative overhead and actuarial expenses related to our pension and medical benefits for retirees. | |||
Exploration and Production
Net income in ourExploration and Production segment decreased by 28% to U.S.$14,133 million in 2014 compared to U.S.$19,523 million in 2013, mainly due to (i) impairment charges recognized in 2014 (U.S.$2,133 million - see Note 14 to our audited consolidated financial statements); (ii) write-offs of overpayments incorrectly capitalized (U.S.$804 million – see Note 3 to our audited consolidated financial statements); (iii) the impact of our voluntary separation incentive plan (PIDV) (U.S.$415 million); (iv) higher decommissioning costs on returned and abandoned areas (U.S.$501 million); (v) write-offs of exploration and production areas returned to the ANP (U.S.$249 million) and (vi) higher operating costs, such as equipment depreciation, equipment maintenance, interventions on wells, oil platform chartering, materials and increased employee compensation costs.
These effects were partially offset by higher crude oil and NGL production (5%) and, when compared to 2013, by the fact that in 2013 we recognized a gain on the disposal of Parque das Conchas offshore project (BC-10).
The spread between the average domestic oil price (sale/transfer) and the average Brent price increased from U.S.$10.47/bbl in 2013 to U.S.$11.15/bbl in 2014.
See Item 4. “Information on the Company—Overview of the Group—Changes in Proved Reserves” for information on changes in our proved reserves.
Refining, Transportation and Marketing
Net losses in ourRefining, Transportation and Marketing segment increased by 89% to U.S.$15,405 million in 2014 compared to U.S.$8,150 million in 2013, as a result of: (i) impairment charges recognized in 2014 (U.S.$12,782 million – see Note 14 to our audited consolidated financial statements); (ii) write-offs of overpayments incorrectly capitalized (U.S.$1,398 million – see Note 3 to our audited consolidated financial statements); (iii) the write-off of capitalized costs in Premium I and Premium II refineries (U.S.$1,236 million – see Note 12.4 to our audited consolidated financial statements); and (iv) the impact of our voluntary separation incentive plan (PIDV). Those effects were partially offset by higher average oil product selling prices attributable to diesel and gasoline price increases in 2013 and 2014, and by an increase in oil product production (2%).
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Gas and Power
Our Gas and Power segment reported a loss of U.S.$410 million in 2014 compared to a net incomeofU.S.$631 million in 2013, resulting from:
· Higher LNG and natural gas import costs to meet thermoelectric demand in Brazil;
· The impact of an agreement with YPFB to settle contractual disputes regarding several aspects of the GSA. See Item 4. “Information on the Company—Overview of the Group—Gas and Power—Long-Term Natural Gas Commitments” and Note 31 to our audited consolidated financial statements;
· An allowance for impairment of trade receivables from companies that operate in the isolated electricity sector in the Northern region of Brazil (see Note 8.4 to our audited consolidated financial statements);
· Write-offs of overpayments incorrectly capitalized; and
· The impact of our voluntary separation incentive plan (PIDV).
These effects were partially offset by higher average electricity prices in the spot market, as a result of lower water reservoir levels in Brazil, and by a U.S.$274 million gain from the disposal of 100% of our interest in Brasil PCH S.A.
Biofuel
Biofuel segment net losses increased by 9% to U.S.$127 million in 2014 compared to U.S.$117 million in 2013, mainly due to the higher share of losses from biodiesel investees and to the impact of our voluntary separation incentive plan (PIDV). These effects were partially offset by lower losses on biodiesel operations and by a decrease in inventory write-downs to net realizable value (market value).
Distribution
Net income in ourDistribution segment decreased by 42% to U.S.$499 million in 2014 compared to U.S.$863 million in 2013, mainly due to higher selling expenses attributable to an allowance for impairment of trade receivables from companies that operate in the isolated electricity sector in the Northern region of Brazil (see Note 8.4 to our audited consolidated financial statements) and to the impact of our voluntary separation incentive plan (PIDV), partially offset by an increase in sales volumes and higher average margins in fuel trading.
International
Our International segment reported a loss of U.S.$1,145 million in 2014 compared to a net income of U.S.$1,729 million in 2013, mainly attributable to:
· Impairment charges recognized on exploration and production activities, mostly in the United States and on our Japanese refinery, mainly resulting from a decrease in international crude oil and oil product prices. See Note 14 to our audited consolidated financial statements;
· An allowance for losses on net investments in exploration and production operations in Venezuela, Ecuador and Africa;
· Higher inventory write-downs to net realizable value (market value) in Japan; and
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· Lower gross profit, mainly in international exploration and production operations, due to assets disposed of in 2014 and 2013 and to a decrease in international crude oil and oil product prices.
These effects were partially offset by gains on the disposal of our interest in Peruvian operations and of onshore assets in Colombia in 2014, compared to the gain we recognized in 2013 on the disposal of 50% of the Company’s assets in Africa.
See Note 29 to our audited consolidated financial statements for further information regarding our business segments.
Results of Operations—2013 compared to 2012
Sales Revenues
Sales revenues decreased by 2% to U.S.$141,462 million from U.S.$144,103 million in 2012, driven primarily by foreign currency translation effects (the appreciation of the U.S. dollar against thereal). Excluding foreign currency exchange effects, local currency sales revenues increased by 8%, primarily driven by:
· Higher oil product prices in the domestic market, mainly derived from adjustments in gasoline and diesel prices, higher electricity prices and the impact of the appreciation of the U.S. dollar (10%) on oil product prices that are adjusted to reflect international prices;
· A 4% increase in domestic oil product sales volumes, mainly of diesel (5%), gasoline (4%) and fuel oil (17%), offset by lower crude oil export volumes (43%), attributable to lower production levels and higher feedstock processed.
Cost of Sales
Cost of sales increased by 1% to U.S.$108,834 million from U.S.$108,276 million in 2012, due to:
· A 4% increase in domestic sales volumes of oil products, met by higher oil product output from our refineries;
· An increase in natural gas import volumes to meet thermoelectric demand and higher crude oil import volumes attributable to the increase in feedstock processed in our refineries;
· The impact of the appreciation of the U.S. dollar on our unit costs; and
· Increased crude oil production costs, attributable to the higher number of well interventions and to the production start-up of new systems, which are still not producing at full capacity.
Excluding foreign currency translation effects, the local currency cost of sales was 11% higher in 2013.
Selling Expenses
Selling expenses were relatively flat in 2013 (U.S.$4,904 million) when compared to 2012 (U.S.$4,927 million) expressed in U.S. dollars. Excluding foreign currency translation effects, selling expenses were 10% higher in 2013 when expressed inreais, primarily as a result of higher freight expenses, driven by increased domestic sales volumes.
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General and Administrative Expenses
General and administrative expenses decreased by 1% to U.S.$4,982 million in 2013 from U.S.$5,034 million in 2012. Excluding foreign currency translation effects, local currency general and administrative expenses increased by 9%, mainly as a result of higher employee compensation expenses arising from the 2012 and 2013 collective bargaining agreements.
Exploration Costs
Exploration costs were 26% lower in 2013 (U.S.$2,959 million) when compared to 2012 (U.S.$3,994 million), primarily due to lower write-offs of dry or sub-commercial wells. A breakdown of exploration costs by nature is set out in Note 15 to our audited consolidated financial statements.
Research and Development Expenses
Research and development expenses remained relatively flat in 2013 (U.S.$1,132 million) when compared to 2012 (U.S.$1,143 million). See Item 5. ”Operating and Financial Review and Prospects” for further details about our research and development activities.
Other Expenses, Net
The 66% decrease in our net other operating expenses in 2013 when compared to 2012 (U.S.$1,113 million as compared to U.S.$3,306 million) is attributable to gains on disposal of assets, including the disposal of 50% of our interest in assets in Africa and of block BC-10, as set out in Note 10 to our 2013 audited consolidated financial statements.
Net Finance Income (Expense)
Net finance expense was U.S.$2,791 million in 2013, a U.S.$865 million increase compared to 2012, resulting from:
· Lower finance income compared to 2012, when we benefited from the positive impact of gains on disposal of government bonds (National Treasury Notes – B Series) and interest income over judicial deposits (U.S.$1,280 million);
· Higher finance expense due to higher debt; and
· The settlement of certain of our tax debts and disputes through our participation in the federal tax settlement program (REFIS).
This increase in net finance expense was partially offset by lower exchange rate variation losses (U.S.$1,636 million) attributable to the extension of our cash flow hedge accounting, reducing by U.S.$5,924 million the impact of foreign currency effects on our finance expenses. For further information about our cash flow hedge accounting, see Notes 4.3.6 and 33.2 (a) to our audited consolidated financial statements.
Income Taxes
Income taxes were U.S.$984 million lower in 2013, when compared to 2012, due to the lower income before taxes and the impact of different jurisdictional tax rates applied for companies domiciled abroad, attributable to the disposal (and loss of control) of assets in Africa.
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Net Income (Loss) by Business Segment
We measure performance at the business segment level based on net income. The following is a discussion of the net income of our six business segments for 2013, compared to 2012. See Item 4. “Information on the Company” and Note 4.2 to audited consolidated financial statements for more information about our business segments.
| Year Ended December 31, | ||
| 2013(1) | 2012(1) | Percentage Change |
| (U.S.$ million) | ||
Exploration and Production | 19,523 | 23,406 | (17)% |
Refining, Transportation and Marketing | (8,150) | (11,718) | (30) % |
Gas and Power | 631 | 861 | (27)% |
Biofuel | (117) | (112) | 4% |
Distribution | 863 | 914 | (6)% |
International | 1,729 | 719 | 140% |
Corporate(2) | (3,331) | (2,565) | 30% |
Eliminations | (54) | (471) | (89)% |
Net income | 11,094 | 11,034 | 1% |
______________________ |
|
|
|
(1) Excluding non-controlling interests. | |||
(2) Our Corporate segment comprises our financing activities not attributable to other segments, including corporate financial management, central administrative overhead and actuarial expenses related to our pension and medical benefits for retirees. | |||
Exploration and Production
Exploration and Production (E&P) net income decreased by 17% in 2013, when compared to 2012, primarily due to a decrease in crude oil and NGL production (2%) resulting from the natural decline of fields (slightly offset by the production start-up of new systems), higher equipment depreciation costs, increased freight costs for oil platforms, higher employee compensation costs and higher well interventions and maintenance costs.
Higher domestic crude oil prices (sale/transfer, when expressed inreais), lower write-offs of dry or sub-commercial wells and a gain on the disposal of our total interest in block BC-10 partially offset this decrease in net income.
The spread between the average domestic oil price (sale/transfer) and the average Brent price increased to U.S.$10.47/bbl in 2013 from U.S.$6.98/bbl in 2012.
See Item 4. “Information on the Company—Overview of the Group—Changes in Proved Reserves” for information on changes in proved reserves.
Refining, Transportation and Marketing
In 2013, our RTM segment net losses decreased by 30% when compared to 2012, reflecting the diesel and gasoline price adjustments in the domestic market beginning in June 2012, and the higher feedstock processed in our refineries, reducing the share of oil product imports in our sales mix, partially offset by higher crude oil acquisition/transfer costs (when expressed inreais).
Gas and Power
Our Gas and Power segment net income decreased by 27% in 2013 due to higher LNG and natural gas import costs necessary to meet higher thermoelectric demand. This decrease was partially offset by higher thermoelectricity generation and higher average electricity prices, mainly attributable to lower water reservoir levels of hydroelectric power plants located in Brazil (caused by low rainfall), and thus increased difference settlement prices.
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Biofuel
Biofuel net losses increased by 4% in 2013, driven by lower biodiesel average sales prices (which fell by 11% compared to 2012). These net losses were partially offset by a decrease in our share of losses from ethanol investments, attributable to increases in ethanol, electricity and sugar sales volumes, as well as the higher average sales prices of ethanol and electricity.
Distribution
Our Distribution segment net income decreased by 6% in 2013 compared to 2012. Excluding foreign currency translation effects, local currency net income for our distribution segment increased due to a 7% increase in the average trade margins and a 4% increase in sales volumes. This increase was partially offset by higher selling and administrative expenses.
Distribution sales volumes increased in the fourth quarter of 2013, but we lost market share in 2013 (37.5%) when compared to 2012 (38.1%) due to a shift in our sales mix in order to achieve higher margins.
International
Our International segment net income increased by 140% due to gains on disposal of assets in accordance with our PRODESIN divestment program, mainly in Africa and in the United States, and to the recognition of tax credits in the Netherlands. Lower exploration costs and write-offs of wells also had a positive impact. This net income increase was partially offset by lower crude oil and NGL production.
See Note 29 to our audited consolidated financial statementsfor further information regarding our business segments.
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Additional Business Segment Information
Additional selected financial data by business segment for 2014, 2013 and 2012 is set out below:
| For the Year Ended December 31, | ||
| 2014 | 2013 | 2012 |
| (U.S.$ million) | ||
Exploration and Production |
|
|
|
Sales revenues to third parties(1)(2) | 500 | 1,114 | 843 |
Intersegment net revenues | 65,116 | 67,096 | 73,871 |
Total sales revenues(2) | 65,616 | 68,210 | 74,714 |
Net income (loss)(3) | 14,133 | 19,523 | 23,406 |
Capital expenditures and investments | 24,164 | 27,566 | 21,959 |
Property, plant and equipment | 135,671 | 126,716 | 102,779 |
Refining, Transportation and Marketing |
|
|
|
Sales revenues to third parties(1)(2) | 73,069 | 74,290 | 78,876 |
Intersegment sales revenues | 39,251 | 37,375 | 37,950 |
Total sales revenues(2) | 112,320 | 111,665 | 116,826 |
Net income (loss)(3) | (15,405) | (8,150) | (11,718) |
Capital expenditures and investments | 7,778 | 14,243 | 14,745 |
Property, plant and equipment | 49,662 | 66,522 | 63,822 |
Gas and Power |
|
|
|
Sales revenues to third parties(1)(2) | 16,187 | 12,826 | 10,515 |
Intersegment sales revenues | 1,695 | 1,191 | 1,288 |
Total sales revenues(2) | 17,882 | 14,017 | 11,803 |
Net income (loss)(3) | (410) | 631 | 861 |
Capital expenditures and investments | 2,545 | 2,716 | 2,113 |
Property, plant and equipment | 22,126 | 20,882 | 21,585 |
Biofuel |
|
|
|
Sales revenues to third parties(1)(2) | 28 | 64 | 90 |
Intersegment sales revenues | 238 | 324 | 365 |
Total sales revenues(2) | 266 | 388 | 455 |
Net income (loss)(3) | (127) | (117) | (112) |
Capital expenditures and investments | 112 | 143 | 147 |
Property, plant and equipment | 205 | 222 | 255 |
Distribution |
|
|
|
Sales revenues to third parties(1)(2) | 40,600 | 39,028 | 39,718 |
Intersegment sales revenues | 1,129 | 995 | 878 |
Total sales revenues(2) | 41,729 | 40,023 | 40,596 |
Net income (loss)(3) | 499 | 863 | 914 |
Capital expenditures and investments | 446 | 514 | 666 |
Property, plant and equipment | 2,284 | 2,350 | 2,374 |
International |
|
|
|
Sales revenues to third parties(1)(2) | 13,273 | 14,140 | 14,061 |
Intersegment sales revenues | 639 | 2,162 | 3,868 |
Total sales revenues(2) | 13,912 | 16,302 | 17,929 |
Net income (loss)(3) | (1,145) | 1,729 | 719 |
Capital expenditures and investments | 1,513 | 2,368 | 2,572 |
Property, plant and equipment | 6,058 | 7,971 | 10,882 |
(1) As a vertically integrated company, not all of our segments have significant third-party revenues. For example, our Exploration and Production segment accounts for a large part of our economic activity and capital expenditures, but has little third-party revenues.
(2) Revenues from commercialization of oil to third parties are classified in accordance with the points of sale, which could be either the Exploration and Production or Refining, Transportation and Marketing segments.
(3) Excluding non-controlling interests.
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Liquidity and Capital Resources
Overview
Our principal uses of funds in 2014 were for capital expenditures (U.S.$34,750 million) and payment of dividends (U.S.$3,918 million). We met these requirements with cash provided by operating activities (amounting to U.S.$26,632 million), net long-term financing (amounting to U.S.$15,024 million) and disposal of assets (amounting to U.S.$3,744 million). As of December 31, 2014, our cash flow from operations was less than the resources needed to fund our capital expenditures, interest expenditures and payment of dividends.
For 2015, our ability to invest available funds has been limited as a result of a decrease in expected future operating revenues following the decline of international crude oil prices, along with the devaluation of thereal, which has increased our cash outflows to service debt in the near term, most of which is denominated in foreign currencies. We have also recently had limited access to new sources of debt capital, largely as a result of the Lava Jato investigation. As a result, our management decided to postpone projects affected by difficulties faced by contractors or by the lack of available qualified suppliers in Brazil. See Note 3 to our audited consolidated financial statements for detailed information about the Lava Jato investigation.
We expect to regain regular access in 2015 to medium and long-term financing, including through the issuance of bonds in the international capital markets and bank financing.
In 2015, our major cash needs are to meet our budgeted capital expenditures for the year (amounting to U.S.$29 billion) and to make principal and interest payments of U.S.$16,042 million on our debt.
Financing Strategy
Our financing strategy is to fund the capital expenditures necessary to meet our long-term growth objectives for oil production and to preserve our cash balance and liquidity while meeting our principal and interest payment obligations.
In the short term, we will pursue our financing strategy by continuing to use cash flow from our operations, drawdown our cash balance, cash equivalents and marketable securities (which at December 31, 2014 amounted to U.S.$26 billion) and use the proceeds from the sale of certain of our assets under our divestment program announced in March 2015. We also expect to continue to raise debt capital through a variety of medium and long-term financing arrangements, including the issuance of bonds in the international capital markets, export credit financing and bank financing. In doing so, we also plan to extend our current debt maturity profile.
In 2014, a portion of our funding requirements was met by the disposal of assets through our divestment program. Proceeds from disposals of assets amounted to U.S.$3,744 million in 2014 (compared to U.S.$3,820 million in 2013). See Note 10 to our audited consolidated financial statements for further information regarding such disposals of assets.
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In 2015 and going forward, we intend to meet our funding requirements by supplementing our operating cash flow with a combination of divestments (that may amount to up to U.S.$13.7 billion across all of our business segments for the period between 2015 and 2016), new debt from a broad range of traditional funding sources, including BNDES, Brazilian and the international commercial banks, export credit agencies, non-Brazilian government development banks and international debt capital markets, as well as drawing down our year-end cash balances and existing credit facilities. As of April 30, 2015, we have entered into financing agreements (mainly lines of credit) with Brazilian and international commercial banks amounting to approximately U.S.$10 billion. See Note 35 to our audited consolidated financial statements.
Government Regulation
We are required to submit our annual capital expenditures budget (Plano de Dispêndios Globais, or PDG) to the MPBM and the MME. Following review by these governmental authorities, the Brazilian Congress must approve the budget. Although the total level of our annual capital expenditures is regulated, the specific application of funds is left to our discretion.
The MPBM controls the total amount of medium and long-term debt that we and our Brazilian subsidiaries can incur through the annual budget approval process. Before raising medium and long-term debt, we and our Brazilian subsidiaries must also obtain the approval of the National Treasury Secretariat. All of our foreign currency denominated debt, as well as the foreign currency denominated debt of our Brazilian subsidiaries, requires registration with the Central Bank. We also have to obtain an authorization from the Central Bank, in accordance with applicable law, in order to make any eventual remittances of funds abroad required by guarantee instruments we have entered into in connection with the incurrence of foreign currency denominated debt.
However, the incurrence of debt by our non-Brazilian subsidiaries, including PGF, is not subject to registration with the Central Bank or approval by the National Treasury Secretariat.
All medium and long-term debt incurred by Petrobras or its subsidiaries requires the approval of our board of executive officers, within the parameters established by our board of directors, except for the issuance of debentures, which require the approval of our board of directors.
Sources of Funds
Our Cash Flow
In 2014, the resources needed to fund our capital expenditures (U.S.$34,750 million) and payment of dividends (U.S.$3,918 million) were met by cash flow from operations (U.S.$26,632 million), net proceeds from long-term financing (U.S.$15,024 million) and cash provided by the disposal of assets (U.S.$3,744 million). We also had a cash surplus that allowed the increase of our balance of cash and cash equivalents, as well as government bonds and time deposits with maturities of more than three months, amounting to U.S.$25,957 million as of December 31, 2014 from U.S.$19,746 million in December 31, 2013.
Net cash provided by operating activities increased by 1% in 2014 compared to 2013. Excluding foreign currency translation effects, cash provided by operating activities increased by 11% when expressed inreais, as a result of higher gross profit and a decrease in inventories.
Proceeds from long-term financing, net of repayments, totaled U.S.$15,024 million in 2014. The principal sources of long-term financing were the issuance of global notes totaling U.S.$13.6 billion in the international capital markets, and long-term financing obtained in the domestic and international banking markets.
Proceeds in 2014 from disposals of assets totaled U.S.$3,744 million, mainly resulting from the sales of Petrobras Energia Peru, Brasil PCH, Innova and Gasmig.
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As of December 31, 2014, our balance of cash and cash equivalents amounted to U.S.$16,655 million, compared to U.S.$15,868 million as of December 31, 2013. Our balance of government bonds and time deposits with maturities of more than three months increased to U.S.$9,302 million as of December 31, 2014 from U.S.$3,878 million as of December 31, 2013.
Short-Term Debt
Our outstanding short-term debt serves many purposes, including supporting our working capital and our imports of crude oil and oil products. As of December 31, 2014, our total short-term debt amounted to U.S.$3,484 million and the current portion of our long-term debt amounted to U.S.$6,845 million, compared to U.S.$3,654 million and U.S.$3,118 million as of December 31, 2013, respectively.
Long-Term Debt
Our outstanding long-term debt consists primarily of securities issued in the international capital markets, funding from development banks (such as the BNDES), loans from Brazilian and international commercial banks and amounts outstanding under facilities guaranteed by export credit agencies and multilateral agencies. The non-current portion of our total long-term debt amounted to U.S.$120,218 million as of December 31, 2014, compared to U.S.$106,235 million as of December 31, 2013. This increase was primarily due to funding from the domestic and international banking markets and from the issuance of U.S. dollar, Euro and Pound Sterling denominated bonds. These financial resources will be used primarily to fund capital expenditures to develop crude oil and natural gas-producing properties, construct vessels and pipelines, and build and expand industrial plants, among other uses. See Note 17 to our audited consolidated financial statements for a breakdown of our debt, a roll-forward schedule of our non-current debt by source and other information.
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The following international debt issues are included in these figures at December 31, 2014:
Notes(*) | Carrying amount as of December 31, 2014 |
| (U.S.$ million) |
PGF’s 2.150% Japanese Yen Bonds due 2016(**)(1) | 290 |
PGF’s 3.875% Global Notes due 2016(**) | 2,497 |
PGF’s 6.125% Global Notes due 2016(**) | 885 |
PGF’s 2.000% Global Notes due 2016 | 1,247 |
PGF’s Floating Rate Global Notes due 2016(2) | 999 |
PGF’s 3.250% Global Notes due 2017 | 1,597 |
PGF’s 3.500% Global Notes due 2017(**) | 1,744 |
PESA’s 5.875% Notes due 2017 | 300 |
PGF’s Floating Rate Global Notes due 2017(3) | 1,397 |
PGF’s 2.750% Global Notes due 2018(4) | 1,815 |
PGF’s 4.875% Global Notes due 2018(**)(5) | 1,510 |
PGF’s 5.875% Global Notes due 2018(**) | 1,743 |
PGF’s 8.375% Global Notes due 2018(**) | 574 |
PGF’s 7.875% Global Notes due 2019(**) | 2,776 |
PGF’s 3.000% Global Notes due 2019 | 1,987 |
PGF’s 3.250% Global Notes due 2019(6) | 1,571 |
PGF’s Floating Rate Global Notes due 2019(7) | 1,497 |
PGF’s 4.875% Global Notes due 2020 | 1,494 |
PGF’s 5.750% Global Notes due 2020(**) | 2,482 |
PGF’s Floating Rate Global Notes due 2020(8) | 499 |
PGF’s 3.750% Global Notes due 2021(9) | 904 |
PGF’s 5.375% Global Notes due 2021(**) | 5,317 |
PGF’s 5.875% Global Notes due 2022(**) (10) | 723 |
PGF’s 4.250% Global Notes due 2023(11) | 836 |
PGF’s 4.375% Global Notes due 2023 | 3,457 |
PGF’s 6.250% Global Notes due 2024 | 2,488 |
PGF’s 4.750% Global Notes due 2025(12) | 962 |
PGF’s 6.250% Global Notes due 2026(**)(13) | 1,069 |
PGF’s 5.375% Global Notes due 2029(14) | 683 |
PGF’s 6.625% Global Notes due 2034(15) | 921 |
PGF’s 6.875% Global Notes due 2040(**) | 1,471 |
PGF’s 6.750% Global Notes due 2041(**) | 2,370 |
PGF’s 5.625% Global Notes due 2043 | 1,710 |
PGF’s 7.250% Global Notes due 2044 | 988 |
(*) Petrobras fully and unconditionally guarantees the notes issued by PGF.
(**) Originally issued by PifCo.
(1) Issued by PifCo on September 27, 2006 in the amount of ¥ 35 billion, with support from Petrobras through a standby purchase agreement.
(2) Floating rate equal to a three-month U.S. dollar LIBOR plus 1.620%.
(3) Floating rate equal to a three-month U.S. dollar LIBOR plus 2.360%.
(4) Issued by PGF on January 14, 2014 in the amount of €1.5 billion.
(5) Issued by PifCo on December 9, 2011 in the amount of €1.25 billion.
(6) Issued by PGF on October 01, 2012 in the amount of €1.3 billion.
(7) Floating rate equal to a three-month U.S. dollar LIBOR plus 2.140%
(8) Floating rate equal to a three-month U.S. dollar LIBOR plus 2.880%.
(9) Issued by PGF on January 14, 2014 in the amount of €750 million.
(10) Issued by PifCo on December 9, 2011 in the amount of €600 million.
(11) Issued by PGF on October 01, 2012 in the amount of €700 million.
(12) Issued by PGF on January 14, 2014 in the amount of €800 million.
(13) Issued by PifCo on December 12, 2011 in the amount of £700 million.
(14) Issued by PGF on October 01, 2012 in the amount of £450 million.
(15) Issued by PGF on January 14, 2014 in the amount of £600 million.
Off Balance Sheet Arrangements
As of December 31, 2014, we had no off-balance sheet arrangements that have, or are reasonably likely to have, a material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
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Uses of Funds
Capital Expenditures and Investments
We invested a total of U.S.$37,004 million in 2014, a 23% decrease, when compared to our investments of U.S.$48,097 million in 2013. Our investments in 2014 were primarily directed toward increasing oil and gas production. Of our total capital expenditures in 2014, U.S.$24,164 million was invested in exploration and development projects in Brazil and U.S.$1,336 million in exploration and development projects abroad.
The following table sets forth our consolidated capital expenditures for each of our business segments for 2014, 2013 and 2012:
| For the Year Ended December 31 | ||
| 2014 | 2013 | 2012 |
| (U.S.$ million) | ||
Exploration and Production | 24,164 | 27,566 | 21,959 |
Refining, Transportation and Marketing | 7,778 | 14,243 | 14,745 |
Gas and Power | 2,545 | 2,716 | 2,113 |
Biofuel | 112 | 143 | 147 |
Distribution | 446 | 514 | 666 |
International |
|
|
|
Exploration and Production | 1,336 | 2,126 | 2,347 |
Refining, Transportation and Marketing | 104 | 156 | 131 |
Gas and Power | 26 | 26 | 5 |
Distribution | 41 | 52 | 72 |
Others | 6 | 8 | 17 |
Corporate | 446 | 547 | 747 |
Total | 37,004 | 48,097 | 42,949 |
On April 22, 2015, we announced planned capital expenditures of U.S.$29 billion in 2015 and approximately U.S.$25 billion in 2016. We plan to meet our budgeted capital expenditures primarily through internally generated cash, structured facilities and project finance loans, commercial bank loans, divestments, issuances in the international capital markets and other sources of capital. Our actual capital expenditures may vary substantially from the projected numbers set forth above as a result of market conditions and the cost and availability of the necessary funds.
Dividends
Our board of directors proposed no distribution of dividends in 2015 for profits accrued in the year ended December 31, 2014 because we reported a net loss for the fiscal year. See Note 23.5 to our audited consolidated financial statements.
For more information on our dividend policy, including a description of the minimum dividend to which our preferred shareholders are entitled under our bylaws, see “Mandatory Distribution” and “Payment of Dividends and Interest on Capital” in Item 10. “Additional Information—Memorandum and Articles of Incorporation.”
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The following table summarizes our outstanding contractual obligations and commitments at December 31, 2014:
| Payments Due by Period | ||||
| Total | < 1 year | 1-3 years | 3-5 years | > 5 years |
| (U.S.$ million) | ||||
Contractual obligations |
|
|
|
|
|
Balance sheet items(1): |
|
|
|
|
|
Debt obligations(2) | 132,086 | 11,868 | 24,520 | 41,978 | 53,720 |
Finance lease obligations | 72 | 16 | 18 | 13 | 25 |
Provision for decommissioning costs | 8,267 | 445 | 540 | 55 | 7,227 |
Total balance sheet items | 140,425 | 12,329 | 25,078 | 42,046 | 60,972 |
Other long-term contractual commitments |
|
|
|
|
|
Natural gas ship-or-pay | 3,815 | 630 | 1,276 | 1,289 | 620 |
Service contracts | 90,495 | 29,093 | 20,780 | 16,897 | 23,725 |
Natural gas supply agreements | 12,487 | 1,786 | 3,263 | 3,378 | 4,060 |
Operating leases | 118,404 | 14,644 | 19,569 | 18,930 | 65,261 |
Purchase commitments | 31,981 | 16,356 | 13,964 | 678 | 983 |
Total other long-term commitments | 257,182 | 62,509 | 58,852 | 41,172 | 94,649 |
Total | 397,607 | 74,838 | 83,930 | 83,218 | 155,621 |
(1) Excludes the amount of U.S.$37,438 million related to our pension and medical benefits obligations, which are partially funded by U.S.$20,151 million in plan assets. Information on employees’ post-retirement benefit plans, including a schedule of expected maturity of pension and medical benefits obligations, is set forth in Note 22 to our audited consolidated financial.
(2) Includes accrued interest, short-term and long-term debt (current and non-current portions). Information about our future interest and principal payments (undiscounted) for the coming years is set forth in Note 33.6 to our audited consolidated financial statements.
Critical Accounting Policies and Estimates
Information about those areas that require the most judgment or involve a higher degree of complexity in the application of the accounting policies that currently affect our financial condition and results of operations is provided in Note 5 to our audited consolidated financial statements (comprising oil and gas reserves, depreciation and impairment; identifying cash-generating units for impairment testing; pension and other post-retirement obligations; contingent liabilities and provisions; dismantling of areas; derivative financial instruments; hedge accounting; the accounting approach to the Lava Jato Operation; and allowance for impairment of trade receivables). Additional information about our accounting policies and new amendments and standards are provided in Notes 4 and 6 to our audited consolidated financial statements. Further information about impairment of assets is provided in Note 14 to our audited consolidated financial statements. Additionally, we have expanded herein the discussion of some of the items addressed in the financial statements for certain topics, such as the estimation methodology for determining the write-off for overpayments incorrectly capitalized; dismantling of areas and environmental remediation; impairment testing of refining assets; pension and medical benefits; as well as allowance for impairment of trade receivables.
The accounting estimates we make in these contexts require us to make assumptions about matters that are highly uncertain. The aforementioned notes address only those estimates that we consider most important based on the degree of uncertainty and the likelihood of a material impact if we used a different estimate. There are many other areas in which we use estimates about uncertain matters, but the reasonably likely effect of changed or different estimates is not material to our financial presentation.
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Estimation Methodology for Determining Write-Off for Overpayments Incorrectly Capitalized
In the third quarter of 2014, we wrote off U.S.$2,527 million of capitalized costs representing amounts that Petrobras overpaid for the acquisition of property, plant and equipment in prior years.
According to testimony from Brazilian criminal investigations that became available beginning October 2014, senior Petrobras personnel conspired with contractors, suppliers and others from 2004 through April 2012 to establish and implement an illegal cartel that systematically overcharged Petrobras in connection with the acquisition of property, plant and equipment. Two Petrobras executive officers and one executive manager were involved in this payment scheme, none of whom has been affiliated with us since April 2012. The overpayments were used to fund improper payments to political parties, elected officials or other public officials, individual contractor personnel, the former Petrobras personnel and other individuals involved in the payment scheme. We did not receive or make the improper payments, which were made by the 27 contractors and suppliers and by intermediaries acting on behalf of the contractors and suppliers.
In addition to the payment scheme, the investigations identified several specific instances of other contractors and suppliers that allegedly overcharged Petrobras and used the overpayment received from their contracts with us to fund improper payments, unrelated to the payment scheme, to certain Petrobras employees, including the former Petrobras personnel and a former Chief International Officer.
We believe that under IAS 16, the amounts we overpaid pursuant to this payment scheme and the unrelated payments described above should not have been included in the historical costs of our property, plant and equipment. However, we cannot specifically identify either the individual contractual payments that include overcharges or the reporting periods in which overpayments occurred. The improper payments were made by outside suppliers and contractors so the exact amounts that we overpaid to fund these payments cannot be identified. The information to determine the amount by which we were overcharged by the cartel members (and applicable dates) is not contained within our accounting records, and we cannot identify the amounts of overpayments for specific contractual payments or in specific accounting periods. The money-laundering activities alleged to have occurred were designed to hide the origins and amounts of the funds involved, so a specific accounting should not be expected.
We concluded that the portion of the costs incurred to build our property, plant and equipment that resulted from contractors and suppliers in the cartel overcharging us to make improper payments should not have been capitalized. In order to account for the impact of overpayments, we developed an estimation methodology to serve as a proxy for the adjustment that should be made to property plant and equipment using the five steps described below:
(1) Identify contractual counterparties: we listed all the companies identified in public testimony, and using that information we identified all of the contractors and suppliers that were either so identified or were consortia including entities so identified.
(2) Identify the period: we concluded from the testimony that the payment scheme was operating from 2004 through April 2012.
(3) Identify contracts: we identified all contracts entered into with the counterparties identified in step 1 during the period identified in step 2, which included supplemental contracts when the original contract was entered into between 2004 and April 2012. We have identified all of the property, plant and equipment related to those contracts.
(4) Identify payments: we calculated the total contract values under the contracts identified in step 3.
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(5) Apply a fixed percentage to the amount determined in Step 4: we estimated the aggregate overpayment by applying a percentage indicated in the depositions (3%) to the total amounts for identified contracts.
For overpayments attributable to other contractors and suppliers, unrelated to the payment scheme, we included in the write-off for incorrectly capitalized overpayments the specific amounts of improper payments or percentages of contract values, as described in the testimony, which were used by those suppliers and contractors to fund improper payments.
We believe that this methodology produces the best estimate for the aggregate overstatement of our property, plant and equipment resulting from the payment scheme, in the sense that it represents the upper bound of the range of reasonable estimates. The estimate assumes that all contracts with the identified counterparties were affected and that 3% represents the amount by which we overpaid on those contracts. Both assumptions are supported by the testimony, even though some testimony indicated lower percentages with respect to certain contracts, a shorter period (2006 to 2011), or fewer contractors involved.
We acknowledge the degree of uncertainty involved in the estimation methodology and have, therefore, developed a sensitivity analysis taking into account that approximately 26% of the write-off of overpayments incorrectly capitalized relates to assets that were charged for impairment in the fourth quarter of 2014. Excluding these assets, an increase or decrease of 1% in the applicable percentage of the overcharge applied over total contract values would result in an increase or decrease of U.S.$603 million in the write-off of overpayments incorrectly capitalized. However, as discussed above, we believe we have used the most appropriate methodology and assumptions to determine the impact of the payment scheme based on the information available to us and there is no evidence that would indicate the possibility of a material change in the amounts that were written off.
The information available to us is generally consistent with respect to the existence of the payment scheme, the companies involved in the payment scheme, the former Petrobras personnel involved in the payment scheme, the period during which the payment scheme was in effect, and the maximum amounts involved in the payment scheme relative to the contract values of affected contracts. Petrobras will monitor the results of the investigations and the availability of other information concerning the payment scheme. If information becomes available that indicates with sufficient precision that the estimate described above should be adjusted, Petrobras will evaluate whether the adjustment is material and, if so, recognize it. However, we have no expectation that additional information bearing on these matters is or will be available from internal sources.
See Note 3 to our audited consolidated financial statements for a detailed description of the investigations, the payment scheme and our response to it, sources of information available to us, the estimation methodology and the impact of the improper payments on our financial statements.
Dismantling of Areas and Environmental Remediation
Under various contracts, permits and regulations, we have material legal obligations to remove equipment and restore the land or seabed at the end of operations at production sites. Our most significant asset removal obligations involve removal and disposal of offshore oil and gas wells and production facilities worldwide.
We accrue the estimated discounted decommissioning costs (for dismantling and removing these facilities) at the time of installation of the assets. We also estimate costs for future environmental clean-up and remediation activities based on current information on costs and expected plans for remediation. Estimating asset retirement, removal and environmental remediation costs requires performing complex calculations that necessarily involve significant judgment because our obligations are many years in the future, the contracts and regulation have vague descriptions of what removal and remediation practices and criteria will have to be met when the removal and remediation events actually occur and asset removal technologies and costs are constantly changing, along with political, environmental, safety and public relations considerations. Consequently, the timing and amounts of future cash flows are subject to significant uncertainty.
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We reviewed and revised our estimated costs associated with well abandonment and the demobilization of oil and gas production areas. As a result, for 2014, there was a U.S.$1.1 billion increase in the amounts related to the revision of the provision for decommissioning costs, mainly attributable to a U.S.$2.5 billion increase attributable to a revision of decommissioning estimates, adjusting forecasts to reflect previous experiences with respect to costs incurred and actual contracts for workover rigs.
Those effects were partially offset by a U.S.$1.5 billion decrease attributable to an increase of our risk adjusted discount rate (from 3.03% p.a. at December 31, 2013 to 3.76% p.a. at December 31, 2014). Other effects, like changes in timing of decommissioning cash flows were responsible for a U.S.$0.2 billion increase.
Petrobras regularly conducts studies to incorporate the most recent technologies and procedures to optimize the abandonment of areas, considering industry best practices and previous experiences with respect to costs incurred.
See Note 20 to our audited consolidated financial statementsfor more information about the annual changes in the provision for decommissioning costs.
Impairment Testing of Refining Assets
Until the third quarter of 2014, we grouped all refineries and associated assets, terminals and pipelines, as well as logistics assets operated by Transpetro, all located in Brazil, into a single cash generating unit ("CGU") referred to as the “Downstream Assets CGU.”
However, in the quarter ended December 31, 2014, changes in circumstances prompted a review of our planned projects and ultimately led Management to revise certain projects that were under construction.
Those circumstances include: (i) a decrease in expected future operating revenues following the decline of international crude oil prices; (ii) the devaluation of the Brazilianreal, and the increased cash outflow to service our debt in the near-term, most of which is denominated in foreign currencies; (iii) Petrobras’s current inability to access the capital markets; (iv) insolvency of contractors and suppliers and a consequent shortage of qualified contractors and suppliers (as a result of the difficulties created for suppliers by the Lava Jato investigation or otherwise).
As a result, we recently decided to postpone for an extended period of time the completion of the following refining projects: (i) Petrochemical Complex of Rio de Janeiro (Complexo Petroquímico do Rio de Janeiro - Comperj); and (ii) the second refining unit in the Abreu e Lima refinery (RNEST). For that reason, as of December 31, 2014, those assets under construction were removed from the “Downstream CGU” and were tested for impairment individually.
Except for the removal of these two projects, the “Downstream CGU” remains unchanged. This CGU was identified based on the concept of integrated optimization and performance management, which focuses on the global performance of the CGU, allowing a shift of margins from one refinery to another. All decisions concerning this CGU (operation, investments, and market strategy) seek to maximize the value of the whole system rather than improve the results of each constituent part. Pipelines and terminals are also an interdependent portion of the refining assets, required to supply the market.
We determined the recoverable amounts of the following assets based on their value-in-use: (i) the “Downstream CGU”; (ii) Comperj; and (iii) the second refining unit of RNEST. The assessment of the value-in-use involves the use of estimates on uncertain assumptions, such as future production curves, future commodity prices, sales revenue growth, operating margins, discount rates, foreign exchange rates, inflation rates and investments required for carrying out projects.
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The key assumptions on which we based our cash flow projections to determine the value in use were approved by our management, and are described below:
· estimated average exchange rate of R$2.85 to U.S.$1.00 in 2015 and 2016 (converging to R$2.61 to U.S.$1.00 in the long-term);
· Brent crude oil price of U.S.$52 for 2015, converging to U.S.$85 in the long-term;
· domestic sales volume growth based on projected Brazilian and global GDP growth;
· EBITDA margin reflecting the convergence of diesel and gasoline prices in Brazil with international benchmarks; and
· post-tax discount rates derived from our weighted average cost of capital (reviewed annually). The post-tax discount rate for Comperj and the second refining unit of RNEST also include specific risks related to these assets.
These assumptions are subject to changes that could affect the carrying amounts of assets, and eventually cause impairment charges and reversals that would affect profit or loss.
Future price assumptions do not consider short-term increases or decreases in price as indicative of long-term trend changes and therefore tend to be stable. Nonetheless, such prices are subject to change.
In the fourth quarter of 2014, we recognized impairment losses of U.S.$8.2 billion related to Comperj and U.S.$3.4 billion related to the second refining unit in RNEST. No impairment losses have been recognized for the “Downstream CGU.”
For more detailed information about our impairment policies and impairment test results, see Notes 4.10, 5.2 and 14 to our audited consolidated financial statements.
Pension and Other Post-Retirement Benefits
We provide post-retirement benefits to our employees mainly through the Petros and Petros 2 pension plans and AMS health care plan (Assistência Multidisciplinar de Saúde), as well as other pension and health care plans internationally, with defined benefit characteristics.
Net actuarial liabilities were U.S.$17,287 million as of December 31, 2014, a 37% increase from U.S.$12,573 million as of December 31, 2013, mainly due to the remeasurement of actuarial liabilities (U.S.$5,947 million) and to interest and service costs incurred during the year (U.S.$2,022 million), partially offset by contributions paid in 2014 (U.S.$648 million).
The remeasurement of actuarial liabilities, recognized in other comprehensive income in shareholders' equity, was mainly attributable to: i) a decrease in the discount rate (real rate, excluding inflation) and an increase in projected medical costs (U.S.$3,782 million), and ii) return on pension and medical plan assets exceeding expected interest income (U.S.$2,165million). Projected medical costs increased due to a higher use of medical procedures by participants, to an increase in our medical coverage (resulting from the current Collective Bargaining Agreement) and to a higher number of medicines included in the list of our assisted purchase program.
Our discount ratesused in calculating the actuarial liabilities forour pension and health care plansare determined based on the weighted average of Brazilian federal government long-term securities (NTN-B) for our post-retirement benefits obligations duration (i.e. considering the maturity profile of the actuarial obligations).
See Note 22 to our audited consolidated financial statements for more detailed information about our actuarial obligations, including our actuarial assumptions, and fora sensitivity analysis of the impact of a 100 basis point change in our discount rates, as well as the effect of changes in other actuarial assumptions.
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Allowance for Impairment of Trade Receivables from the Isolated Electricity Sector in the Northern Region of Brazil
We continuously assess whether there is objective evidence that trade receivables are impaired and recognize allowances for impairment of trade receivables to cover losses.
In 2014, we recognized an allowance for impairment of trade receivables of U.S.$1,948 million to cover uncollateralized receivables from the isolated electricity sector as of October 31, 2014.
Beginning in 2015, the Brazilian federal government implemented a new pricing policy for the electricity sector and allowed electricity distribution companies to implement price increases in the first quarter of 2015, which will strengthen their financial situation. No charges were recognized for companies that were not insolvent or for receivables from sales dated after November 1, 2014, because those amounts were included in the calculation of the new pricing policy.
See Notes 4.3.3, 5.9 and 8.4 to our audited consolidated financial statements for more detailed information about our accounting policies with respect to trade receivables and about the receivables from the isolated electricity system.
We are deeply committed to research and development as a means to extend our reach to new production frontiers and achieve continuous improvement in operations. We have a history of successfully developing and implementing innovative technologies, including the means to drill, complete and produce wells in increasingly deep water. We are one of the largest investors in research and development among the world’s major oil companies, and we spend a large percentage of revenues in research and development. Our Brazilian oil and gas concession agreements require us to invest at least 1% of our gross revenues originating from high productivity oil fields on research and development, of which up to half is invested in our research facilities in Brazil and the remainder is invested in research and development in Brazilian universities and institutions registered with the ANP for this purpose.
In 2014, we spent U.S.$1,099 million on research and development, equivalent to 0.76% of our sales revenues, while in 2013, we spent U.S.$1,132 million, equivalent to 0.8% of our sales revenues, and in 2012, we spent U.S.$1,143 million, equivalent to 0.8% of our sales revenues.
Our research and development activities are based on strategic choices that we make regarding technological development, which we call our “Technological Focus,” namely:
For Exploration & Production
- Exploration of New Frontiers;
- Assessment of new potential natural gas sources, both in conventional and non-conventional reservoirs, spread throughout onshore sedimentary basins located in Brazil´s countryside;
- Offshore wells building and maintenance optimization;
- Subsea Production Systems;
- Pre-Salt Production;
- Offshore Logistics; and
- Mature fields production optimization.
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For Downstream, Transport, Distribution, Biofuels and Petrochemical
- Gasoline and medium oil products production optimization;
- Pre-Salt Oils Refining;
- Optimization and integration of operating logistics;
- Innovative Products;
- Bioproducts; and
- More usage of both fossil and renewable streams as raw materials for petrochemicals.
For Gas and Energy
- Valuation of new potentials of natural gas in both conventional and non-conventional reservoirs spread throughout onshore sedimentary basins located in Brazil´s countryside regions;
- Integration and flexibility in the supply and demand of both energy and natural gas;
- Natural Gas Logistics;
- Cost Reduction;
- Value-adding to Natural Gas via methane chemistry; and
- Natural Gas Processing.
For all Business Segments and Sustainability
- Development of building and assembly technology for naval and industrial design;
- Optimization of productive processes;
- Integrity, safety and reliability of new materials and equipment available;
- Technology for mitigation of atmospheric emissions (CO2 and other emissions);
- Technology for disposal, treatment, reusage and reduction of water consumption; and
- Technology for recovery of environmentally affectedareas.
Forward-Thinking – 2030 Perspective
- Increased reliability of risk estimates through the integrated simulation of geological processes;
- Riserless Maritime Production Systems;
- Energy production, storage and distribution systems that are used in electric and hybrid vehicles, improving mobility;
- Nanotechnology applied to both processes and products;
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- Development of new materials suitable for use in extreme operating conditions; and
- Technologies used for improving gas hydrates prospection.
In the three-year period ended December 31, 2014, our research and development operations were awarded 100 patents in Brazil and 134 overseas. Our portfolio of patents covers all of our areas of activities.
We have operated a dedicated research and development facility in Rio de Janeiro, Brazil since 1963. As a result of its expansion in 2010, this is one of the largest facilities of its kind in the energy sector and the largest in the southern hemisphere, with laboratories especially dedicated to pre-salt technologies. As of December 31, 2014, this facility had 1,862 employees, 74.3% of which are exclusively dedicated to research, development and basic engineering.
We also have several semi-industrial scale prototype plants throughout Brazil that are in proximity to our industrial facilities and that are aimed at scaling up new industrial technologies at reduced costs. In 2014, we conducted research and development through joint research projects with more than 100 universities and research centers in Brazil and abroad and participated in technology exchange and assistance partnerships with several oilfield service companies, small technology companies and other operators.
Despite the recent deceleration of the demand for oil products and economic growth in Brazil, attributable to countercyclical macroeconomic policies, we expect that the demand for oil products in Brazil will continue to grow in the medium- and long-terms, driven primarily by economic growth and the increase in purchasing power of the Brazilian population. In recent years, we met this incremental growth in demand by increasing imports of oil and oil products and improving the throughput of our refineries, since our oil production and our refining capacity were not sufficient to meet the increased demand. Higher import of oil and oil products increased our cost of sales and decreased our distribution margins in recent years, because we have not fully adjusted our domestic prices to reflect the higher cost of oil and oil products and because of the devaluation of therealagainst the U.S. dollar.
The price we realize for the crude oil we export is determined by international oil prices, although we generally sell our crude oil at a discount compared to Brent and other light oil benchmark prices because it is heavier and thus more expensive to refine. In 2014, oil price trends were affected by supply and demand fundamentals as well as by fluctuations in macroeconomic conditions. The Brent benchmark price experienced higher variation in 2014 as compared to 2013, with a strong decline in the second half of the year due to an oversupply of oil. In 2014, the minimum price was U.S.$55.76/bbl, the maximum price was U.S.$115.00/bbl and the average price was U.S.$98.91/bbl. The response of oil supply and demand to the recent decline in oil prices will be the key determinant of oil price trends in the short term. A fast-paced increase in demand coupled with a strong downward adjustment in supply may result in higher prices in the medium term. On the other hand, if supply adjustments are not strong enough to rebalance the market, oil prices may drop below current levels. In addition, geopolitical concerns in Russia, the Middle East and North Africa may persist, potentially driving prices higher in the short term.
Each year, we review and revise our long-term Business and Management Plan in order to adapt to changing market conditions and to revise our investment levels in accordance with updated scenarios and projected cash flows.
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We are currently working on our updated business and management plan and we expect to release it following approval by our board of directors. Due to the recent changes in the global and the Brazilian macroeconomic environment, the substantial decrease in Brent crude oil prices, the depreciation of thereal against the U.S. dollar, as well as the impact of the ongoing Lava Jato investigations, our updated business andmanagement plan may reflect a reduction of our capital expenditures, a revision of our financial performance indicators and delay of our oil production targets as compared with those in our 2014-2018 Plan.
Item 6. Directors, Senior Management and Employees
Directors and Senior Management
Directors
Our board of directors, which we refer to as theconselho de administração, is composed of a minimum of five and maximum ten members and is responsible for, among other things, establishing our general business policies. The members of the board of directors are elected at the annual general meeting of shareholders, including the employee representative previously selected by means of a separate voting procedure.
Under Brazilian Corporate Law, shareholders representing at least 10% of the company’s voting capital have the right to demand that a cumulative voting procedure be adopted to entitle each common share to as many votes as there are board members and to give each common share the right to vote cumulatively for only one candidate or to distribute its votes among several candidates. Pursuant to regulations promulgated by the CVM, the 10% threshold requirement for the exercise of cumulative voting procedures may be reduced depending on the amount of capital stock of the company. For a company like Petrobras, the applicable threshold is 5%. Thus, shareholders representing 5% of our voting capital may demand the adoption of a cumulative voting procedure.
Our bylaws enable (i) minority preferred shareholders that together hold at least 10% of the total capital stock (excluding capital stock held by the controlling shareholders) to elect and remove one member to our board of directors; (ii) minority common shareholders to elect and remove one member to our board of directors, if a greater number of directors is not elected by such minority shareholders by means of the cumulative voting procedure; and (iii) our employees to elect one member to our board of directors by means of a separate voting procedure, pursuant to Law No. 12,353 and MPBM’s Act No. 26. Our bylaws provide that, regardless of the rights above granted to minority shareholders, the Brazilian federal government always has the right to elect the majority of our directors, independently of their number. In addition, under Law 10,683, one of the board members elected by the Brazilian federal government must be indicated by the Minister of Planning, Budget and Management. The maximum term for a director is one year, but re-election is permitted. In accordance with the Brazilian Corporate Law, the shareholders may remove any director from office at any time with or without cause at an extraordinary meeting of shareholders. Following an election of board members pursuant to the cumulative voting procedure, the removal of any board member by an extraordinary meeting of shareholders will result in the removal of all of the other members, after which new elections must be held.
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We currently have ten directors. The following table sets forth certain information with respect to these directors:
Name | Date of Birth | Position | Current Term Expires | Business Address |
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Murilo Pinto de Oliveira Ferreira(1) | June 22, 1953 | Chair | April 2016 | Av. Graça Aranha, 26 – 18th floor – Castelo – Rio de Janeiro ZIP code: 20030 900 |
Aldemir Bendine(1) | December 10, 1963 | Director | April 2016 | Avenida República do Chile, no. 65 23rd floor Rio de Janeiro – RJ ZIP code: 20.031-912 |
Luciano Galvão Coutinho(1) | September 29, 1946 | Director | April 2016 | Av. República do Chile, no. 100 22th floor Rio de Janeiro – RJ ZIP code: 20.031-917 |
Luiz Augusto Fraga Navarro de Britto Filho(1) | October 5, 1965 | Director | April 2016 | SCN Quadra 2 Bloco A - Edf.Corporate Financial Center 10th floor Brasília (Distrito Federal) ZIP code: 70712-900 |
Luiz Nelson Guedes de Carvalho(1) | November 18, 1945 | Director | April 2016 | Av. Prof. Luciano Gualberto, 908 – FEA3 – Cid. Universitária - São Paulo –SP ZIP code: 05508-010 |
Roberto da Cunha Castello Branco(1) | July 20, 1944 | Director | April 2016 | Praia de Botafogo 190, 11thfloor Rio de Janeiro – RJ ZIP code: 22250-900 |
Segen Farid Estefen(1) | January 20, 1951 | Director | April 2016 | COPPE - Universidade Federal do Rio de Janeiro Centro de Tecnologia - Bloco I - room 108 - Cidade Universitária Rio de Janeiro – RJ ZIP code: 21941-909 |
Guilherme Affonso Ferreira(2) | May 9, 1951 | Director | April 2016 | Rua Estados Unidos, 1342 São Paulo – SP ZIP code: 01427-001 |
Walter Mendes de Oliveira Filho(3) | December 7, 1955 | Director | April 2016 | Av. República do Chile, 65 – 24th floor - Rio de Janeiro – RJ ZIP code: 20031-170 |
Deyvid Souza Bacelar da Silva(4) | February 18, 1980 | Director | April 2016 | Rodovia BA 523, Km 4, Mataripe, São Francisco do Conde – BA ZIP code: 49170-000 |
(1) Appointed by the controlling shareholder.
(2) Appointed by the minority preferred shareholders.
(3) Appointed by the minority common shareholders.
(4) Appointed by our employees.
Murilo Pinto de Oliveira Ferreira—Mr. Ferreira has been the chairman of our board of directors sinceMay5, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A. He has been Vale S.A.’s Chief Executive Officer and member of Vale’s strategy and disclosure committees since May 2011. Mr. Ferreira has held different positions at Vale S.A., with responsibility over several different departments from 2005 to 2008, including Business Development, M&A, Steel, Energy, Nickel and Base Metals; Chief Executive Officer of Vale Canada from 2007 to 2008 and member of its board of directors from 2006 to 2007; chairman of the board of directors of Alunorte from 2005 to 2008, Mineração Rio Norte from 2006 to 2008 and Valesul Alumínio S.A., a subsidiary of Vale involved in the production of aluminum, from 2006 to 2008; and member of the board of commissioners of PT VaIe Indonésia Tbk, from 2007 to 2008. Mr. Ferreira has been a member of the board of directors of several companies, including Usiminas, a Brazilian steel company, from 2006 to 2008, and was a partner at Studio Investimentos, an asset management firm with a focus on the Brazilian stock market, from October 2009 to March 2011. Mr. Ferreira is currently a member of the CEO Advisory Board of the Massachusetts Institute of Technology (MIT) and also a member of the Wise Men Group. He received a bachelor’s degree in business management from Fundação Getúlio Vargas-FGV in São Paulo; a post-graduate degree in business management and finance from Fundação Getúlio Vargas-FGV in Rio de Janeiro and attended a senior executive education program at the IMD Business School in Lausanne, Switzerland.
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Aldemir Bendine—Mr. Bendine has been our Chief Executive Officer since February 2015, and he is also a member of our board of directors and of the board of directors of Petrobras Distribuidora S.A. From to April 2009 to January 2015, he served as Chief Executive Officer of Banco do Brasil S.A. Mr. Bendine joined Banco do Brasil in 1978, and from that time until earlier this year, he held several different positions, including as vice president of bank cards and new retail businesses (from July 2007 to April 2009), vice president of retail and distribution (from December 2006 to July 2007), executive secretary of the Banco do Brasil board of officers (from July to December 2006), manager of credit and debit cards, division manager and regional manager in Banco do Brasil São Paulo superintendence. Mr. Bendinewasa member of the board of officers of Banco Patagônia from October 2010 to early 2015 and Grupo Mapfre – BB SH1 Participações S.A. and Grupo Mapfre – BB SH2 Participações S.A.from June 2011 to early 2015. He served as executive officer of the Federação Brasileira de Bancos - Febraban (Brazilian Federation of Banks), president of theAssociação Brasileira de Empresas de Cartões e Serviços – Abecs from October 2008 to July 2009, chairperson of the board of directors of CBSS (Visa Vale) from February 2007 to March 2010, member of the board of directors of Banco Votorantim S.A. from September 2009 to February 2015 and chief executive officer of BB Administradora de Cartões S.A. and BB Administradora de Consórcios S.A., among others. Mr. Bendine holds a bachelor’s degree in business management as well as master’s degrees in business administration for senior executives from the Fundação Instituto de Pesquisas Contábeis, Atuariais e Financeiras - FIPECAFI at Universidade de São Paulo-USP and in finance from Pontifícia Universidade Católica do Rio de Janeiro-PUC-Rio.
Luciano Galvão Coutinho—Mr. Coutinho has been a member of our board of directors since April 2008, and he is also a member of the board of directors of Petrobras Distribuidora S.A. He has been the President of the BNDES since April 2007. In addition, Mr. Coutinho is a member of the board of directors of Vale S.A. (Vale), a member of the Curator Committee for the Fundação Nacional da Qualidade—FNQ (the Brazilian Quality Foundation), and the BNDES representative at the Fundo Nacional de Desenvolvimento Científico e Tecnológico—FNDCT (the Brazilian Fund for Scientific and Technological Development). Mr. Coutinho has a Ph.D. in economics from Cornell University, a master’s degree in economics from the Fundação Instituto de Pesquisas Econômicas—Fipe (the Institute of Economic Research) at Universidade de São Paulo-USP and a bachelor’s degree in economics from USP.
Luiz Augusto Fraga Navarro de Britto Filho—Mr. Navarro has been a member of our board of directors since February 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A. He has been a senior counsel at Veirano Advogados law firm since 2013 and consultant to the Brazilian Federal Senate since 2004. Mr. Navarro worked for 10 years in theControladoria Geral da União (General Federal Inspector’s Office), where he has held different positions, including Deputy Minister of State, Secretary for Corruption Prevention and General Inspector. From 2003 to 2006 he also served as Brazil’s expert to the Committee of Experts on the Mechanism for Follow-up on the Implementation of the Inter-American Convention against Corruption (MESICIC) and as a member of theConselho de Controle de Atividades Financeiras – COAF (Council for the Control of Financial Activities). Mr. Navarro is also a member of the Senior Advisory Board of the International Anti-Corruption Academy. Mr. Navarro has an LL.B degree from the Universidade de Brasília-UNB, a post-graduate course in Regulation in the Modern National Economy from George Washington University, a specialization degree in Law and State from Universidade de Brasília-UNB and a specialization degree in Public Policy and Government Management from theEscola Nacional de Administração Pública - ENAP (Brazilian National School of Public Administration).
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Luiz Nelson Guedes de Carvalho—Mr.Carvalho has been a member of our board of directors since May 4, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A. He has been a member of the board of directors of BMF&BOVESPA (and the coordinator of its audit committee) since 2013 and also the coordinator of Grupo Pão de Açucar audit committee since 2013. He is currently a professor at Universidade do Estado de São Paulo – Faculdade de Economia, Administração e Contabilidade, officer of theFundação Instituto de Pesquisas Contábeis, Atuariais e Financeiras - FIPECAFI, member of the Comitê de Pronunciamentos Contábeis CPC – Brasil, among others. Mr. Carvalho has previously served as a member of the board of directors of XBRL International Inc., member of the Financial Crisis Advisory Group – FCAG, the first independent president of the Standards Advisory Council – SAC at IASB (from July 2005 to December 2008), consultant at the World Bank, and has served as a member of the board of directors of Banco Nossa Caixa, Caixa Econômica Federal, Banco Bilbao Vizcaya Argentaria Brasil – BBVA, Vicunha Têxtil S.A., Banco Fibra S.A., among others. Mr. Carvalho also served as Deputy Governor and head of banking supervision of the Central Bank of Brazil (from 1991 to 1993) and as commissioner of the CVM (from 1990 to 1991).Mr. Carvalho received a bachelor’s degree in economics from Universidade de São Paulo – Faculdade de Economia e Administração e Contabilidade and in accounting from Faculdades São Judas Tadeu and a master’s and a Ph.D degree in accounting and controllership from Universidade de São Paulo – Faculdade de Economia e Administração e Contabilidade.
Roberto da Cunha Castello Branco—Mr.Castello Branco has been a member of our board of directors since April 30, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A. From June 1999 to January of 2014 he was the investor relations officer at Vale S.A. Mr. Castello Branco also served as a Deputy Governor of the Central Bank of Brazil (from March 1985 to September 1985), and he was executive director of Banco Boavista and Banco InterAtlântico, president of IBMEC, professor of the Graduate School of Economics at Fundação Getulio Vargas (EPGE/FGV), member of the board of trustees of the Fundação Getulio Vargas, president of theInstituto Brasileiro de Relações com Investidores, member of the board of directors of ABRASCA – the Brazilian Association of Public Companies, vice-president of the Chamber of Commerce Brasil-Canada and officer of the American Chamber of Commerce of the State of Rio de Janeiro. He is currently director of the Center for Growth and Economic Development (Centro de Estudos de Crescimento e Desenvolvimento Econômico) at Fundação Getulio Vargas. Mr. Castello Branco holds a bachelor’s degree in economics from Faculdade Brasileira de Ciências Econômicas, a Ph.D degree in economics from the graduate school of economics at Fundação Getulio Vargas – EPGE/FGV and a post-doctoral fellow degree in economics from the University of Chicago. He has also participatedin executive training programs from the Sloan School of Management, MIT, IMD Business Schools and the University of Chicago Booth School of Business.
Segen Farin Estefen—Mr. Estefen has been a member of our board of directors sinceMay6, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A. He has been an ocean structures and submarine engineering professor at Universidade Federal do Rio de Janeiro – COPPE, where he has been a professor since 1976 and held the position of dean from 1998 to 2001. He is also the general manager of the Submarine Technology Laboratory and the coordinator of the Ocean Renewable Energies Group, both at Universidade Federal do Rio de Janeiro – COPPE, and is a member of the Ocean, Offshore and Artic Engineering division of the American Society of Mechanical Engineers (ASME), a fellow at the Society for Underwater Technology – SUT, technical coordinator of the Embrapii COPPE unit for submarine engineering and member of theAcademia Nacional de Engenharia - ANE. He received a bachelor’s degree in civil engineering from Universidade Federal de Juiz de Fora, a master’s degree in ocean engineering from Universidade Federal do Rio de Janeiro – COPPE, a Ph.D degree in civil engineering from Imperial College of Science, Technology and Medicine (London) and has been a post-doctoral research fellow at the Institute for Marine Technology, Norwegian University of Science and Technology.
Guilherme Affonso Ferreira—Mr. Ferreira has been a member of our board of directors sinceMay4, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A., Sul America S.A, Gafisa S.A., Valid S.A, Arezzo S.A. and T4F S.A. and a member of the board of directors of non-governmental organizations such as the Institute of Citizenship, AACD, Solidarity Sport, among others. Mr. Ferreira received a bachelor’s degree in engineering from the Polytechnic School of the Universidade de São Paulo-USP and a post-graduate degree in political science from Macalester College.
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Walter Mendes de Oliveira Filho—Mr.Mendes has been a member of our board of directors sinceMay4, 2015, and he is also a member of the board of directors of Petrobras Distribuidora S.A, the managing director of the Brazilian Takeover Panel (Comitê de Aquisições e Fusões – CAF) since September 2014 and a member of the Supervisory Board of Investment Analysts at APIMEC- Association of Analysts and Capital Market Professionals since 2011. Previously, Mr. Mendes was a partner and fund manager at Cultinvest Asset Management Ltd (2010-2014). From 2003 to 2010, he was the head of equity funds management of Banco ItauUnibanco S.A. Mr. Mendes worked for Schroder Investment Management for nine years (1994-2003), six of them as the managing officer of its Brazilian office and the remaining years as the managing officer of its Latin America investments, based in London. Mr. Mendes started his career at Unibanco S.A, where he became head of research in 1987. Mr. Mendes holds a bachelor’s degree in economics and he also holds a post-graduate degree in economics.
Deyvid Souza Bacelar da Silva—Mr.Bacelar has been a member of our board of directors since April 29, 2015 and he is the representative of our employees. Mr. Bacelar has been a Safety Junior Technician at Petrobras since May 2006 and he is also the General Coordinator of theSindicato dos Petroleiros da Bahia (Oil Workers’ Union of the State of Bahia) for the 2014-2017 term. From April 2008 to July 2008, he was an instructor in CETEB –Centro de Educação Tecnológica do Estado da Bahia and from November 2007 to February 2008, he was an instructor inSENAI – Serviço Nacional de Aprendizagem Industrial. Mr. Bacelar holds a bachelor’s degree in business from Universidade Federal da Bahia - UEFS and a specialization degree in human resources from Universidade Federal da Bahia.
Executive Officers
Our board of executive officers, which we refer to as thediretoria, is composed of the Chief Executive Officer (CEO) and seven executive officers, and is responsible for our day-to-day management. Our executive officers are Brazilian nationals and reside in Brazil. Pursuant to our bylaws, the board of directors elects the executive officers, including the CEO, and in electing executive officers to their respective areas, must consider personal qualification, knowledge and specialization. The maximum term for our executive officers is three years, but re-election is permitted. The board of directors may remove any executive officer from office at any time with or without cause. Four of our current executive officers are experienced Petrobras career managers, engineers or technicians.
On November 25, 2014, our board of directors approved the termination of the Chief International Officer position. and the creation of a new executive officer position: Chief Governance, Risk and Compliance Officer. The Chief Governance, Risk and Compliance Officer is charged with ensuring that Petrobras’s procedures and guidelines are being observed by Petrobras’s management and employees, that Petrobras complies with applicable laws and regulations and that risks of fraud and corruption are mitigated. Besides participating in the decision-making process of our board of executive officers, the Chief Governance, Risk and Compliance Officer must approve any matter submitted to our board of executive officers related to governance, risk and compliance. The Chief Governance, Risk and Compliance Officer will serve for a three-year term, which may be renewed, and such officer can only be removed by the majority of our board of directors, including the vote of at least one director appointed by either the minority preferred shareholders or the minority common shareholders. On January 13, 2015, Mr. João Adalberto Elek Junior was elected to this position by our board of directors, and he was appointed on January 19, 2015.
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The following table sets forth certain information with respect to our executive officers:
Name | Date of Birth | Position | Current Term |
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Aldemir Bendine | December 10, 1963 | Chief Executive Officer | March 2017 |
Ivan de Souza Monteiro | November 15, 1960 | Chief Financial Officer and Chief Investor Relations Officer | March 2017 |
Roberto Moro | November 8, 1962 | Chief Engineering, Technology and Procurement Officer | March 2017 |
Solange da Silva Guedes | November 22, 1960 | Chief Exploration and Production Officer | March 2017 |
Jorge Celestino Ramos | October 11, 1956 | Chief Downstream Officer | March 2017 |
Hugo Repsold Júnior | July 23, 1959 | Chief Gas and Power Officer | March 2017 |
José Eduardo de Barros Dutra | April 11, 1957 | Chief Corporate and Services Officer | March 2017 |
João Adalberto Elek Junior | November 26, 1958 | Chief Governance, Risk and Compliance Officer | January 2018 |
Aldemir Bendine—Mr. Bendine has been our Chief Executive Officer since February 2015. For biographical information regarding Mr. Bendine, see “—Directors.”
Ivan de Souza Monteiro—Mr.Monteiro has been our Chief Financial Officer and Chief Investor Relations Officer since February 2015. Mr. Monteiro previously served as the vice-president of Financial Management and Investor Relations of Banco do Brasil S.A. from June 2009 to February 2015, where he has held different positions, including the position of Chief Commercial Officer and vice-president of Finance, Capital Markets and Investor Relations. He was also president of the Supervision Committee of BB AG, a Banco do Brasil subsidiary in Austria, from April 2014 to February 2015 and president of BB Banco de Investimentos S.A. from June 2009 to February 2012 (and vice-president from February 2012 to February 2015). Mr. Monteiro was also a member of the board of directors of Banco Votorantim Participações S.A. from September 2009 to February 2015, Ultrapar Participações S.A. from March 2013 to February 2015, BB Seguridade Participações S.A. from August 2013 to February 2015 and an alternate member of the board of directors of Mapfre BB SH-2 Participações S.A. from June 2013 to February 2015. Mr. Monteiro holds a degree in electronic engineering and telecommunications from INATEL-MG and an MBA in finance from IBMEC-RJ and in management from the Pontifícia Universidade Católica do Rio de Janeiro – PUC-Rio.
Roberto Moro—Mr. Moro has been our Chief Engineering, Technology and Procurement Officer since February 2015. Mr. Moro joined Petrobras in 1981 and has held various positions in Petrobras’s E&P business segment, including the position of General Manager for the Implementation of E&P Projects and Executive Manager of Subsea Projects from October 2013 to February 2015. Mr. Moro holds a degree in mechanical engineering from Universidade Gama Filho and a specialization in project management from Fundação Getúlio Vargas-FGV.
Solange da Silva Guedes—Ms.Guedes has been our Chief Exploration and Production Officer since February 2015. Ms. Guedes joined Petrobras in 1985 and has held various positions in Petrobras’s E&P business segment, including the position of Executive Manager of Petrobras’s upstream activities in Northern and Northeastern Brazil from February 2003 to April 2008, Executive Manager of Engineering Production in the E&P business segment from April 2008 to December 2013 and Corporate Executive Manager in E&P from December 2013 to February 2015. Ms. Guedes holds a degree in Civil Engineering from the Universidade Federal de Juiz de Fora – UFJF, a master’s degree in civil engineering from the Universidade Federal do Rio de Janeiro – UFRJ, a PhD in oil engineering from the Universidade Estadual de Campinas – UNICAMP and an MBA in management from COPPEAD/UFRJ.
Jorge Celestino Ramos—Mr. Ramos has been our Chief Downstream Officer since February 2015. Mr. Ramos joined Petrobras in 1983 and has held various positions in Petrobras’s distribution and refining segments, including the position of Executive Manager of Logistics in Downstream from April 2014 to February 2015 and Executive Manager of Operations of Petrobras Distribuidora S.A. from February 2007 to April 2014. Mr. Ramos holds a degree in chemical engineering from the Universidade do Estado do Rio de Janeiro–UERJ and he holds anMBA in marketing from Escola Superior de Propaganda e Marketing - ESPM and in management from Fundação Getúlio Vargas-FGV.
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Hugo Repsold Júnior—Mr. Repsold has been our Chief Gas and Power Officer since February 2015. Mr. Repsold joined Petrobras in 1985 and has held various positions at Petrobras, including the position of Executive Manager of Strategy and Corporate Performance from January 2011 to May 2012 and Corporate Executive Manager of Gas and Power from May 2012 to February 2015. Mr. Repsold holds a degree in Mechanical Engineering from the Universidade Federal Fluminense-UFF, a degree in economics from the Universidade do Estado do Rio de Janeiro-UERJ and a master’s degree in energy planning and economics from the Universidade Federal do Rio de Janeiro (Coppe/PPE-UFRJ).
José Eduardo de Barros Dutra—Mr.Dutra has been our Chief Corporate and Services Officer since March 2012. In 1994, he was elected Senator of the Republic with a mandate from 1995 to 2002. He was the CEO of Petrobras from January 2003 to July 2005, and held the position of director of Petrobras and director of Petrobras Distribuidora S.A. during such time. He was CEO of Petrobras Distribuidora S.A. from September 2007 to August 2009, and also worked as a geologist at Petrobras Mineração S.A. – Petromisa from 1983 to 1990 and at Vale from 1990 to 1994. In addition, Mr. Dutra was chairman of the board of directors of Gaspetro, Transpetro, Petroquisa, Petrobras Energia S.A. – Pesa and Liquigás. Mr. Dutra received a degree in geology from the Universidade Federal Rural do Rio de Janeiro (the Federal Rural University of Rio de Janeiro) in 1979.
João Adalberto Elek Junior —Mr. Elek Junior has been our Chief Governance, Risk and Compliance Officer since January 2015. Mr. Elek Junior was Chief Financial Officer at Fibria from August 2010 to February 2012. He also held several positions at Telmex and AT&T in Brazil and Latin America, from May 2000 to July 2010, and he served as Chief Financial and Investor Relations Officer at the telecommunications firm NET Serviços from April 2007 to July 2010. Mr. Elek Junior also worked for 20 years at Citibank, where he was Chief Financial Officer for retail services from November 1996 to May 2000. Mr. Elek Junior holds an bachelor’s degree in electronic engineering from the Pontifícia Universidade Católica do Rio de Janeiro – PUC-Rio, an MBA in marketing planning from COPPEAD/UFRJ and graduate studies in mergers and acquisitions from the Columbia Business School.
For 2014, the aggregate amount of compensation we paid to all members of the board of directors and executive officers was U.S.$7.1 million. As of December 31, 2014 we had seven executive officers and ten board members. See Note 19.3 to our audited consolidated financial statements for further information regarding compensation of our employees and officers.
In addition, the members of our board of directors and executive officers receive medical assistance benefits, as it is generally provided to our employees and their families. Our executive officers also receive supplementary social security benefits and housing allowance.
We have no service contracts with members of our board of directors providing for benefits upon termination of employment. We have a remuneration and succession committee in the form of an advisory committee. See “—Other Committees.”
As ofApril30, 2015, the members of our board of directors, our executive officers, and the members of our fiscal council, as a group, beneficially held a total of 5,148 common shares and 73,894 preferred shares of our company. Accordingly, on an individual basis, and as a group, our directors, executive officers, and fiscal council members beneficially owned less than one percent of any class of our shares. The shares held by our directors, executive officers, and fiscal council members have the same voting rights as the shares of the same type and class that are held by our other shareholders. None of our directors, executive officers, and fiscal council members holds any options to purchase common shares or preferred shares nor any other person has any option topurchase our common or preferred shares. Petrobras does not have a stock option plan for its directors, officers or employees.
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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 Brazilianfederalgovernment has the right to appoint the majority of the members of the fiscal council and their alternates. One of these members and his respective alternate are appointed by the Minister of Finance, representing the Brazilian Treasury. The members of the fiscal council are elected at our annual general shareholders’ meeting for a one-year term and re-election is permitted.
The following table lists the current members of our fiscal council:
Name | Year of First Appointment |
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Paulo José dos Reis Souza | 2012 |
César Acosta Rech | 2008 |
Marisete Fátima Dadald Pereira | 2011 |
Reginaldo Ferreira Alexandre | 2013 |
Walter Luis Bernardes Albertoni | 2013 |
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The following table lists the alternate members of our fiscal council:
Name | Year of First Appointment |
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Paula Bicudo de Castro Magalhães | 2015 |
Symone Christine de Santana Araújo | 2015 |
Agnes Maria de Aragão da Costa | 2015 |
Mário Cordeiro Filho | 2013 |
Roberto Lamb | 2013 |
We have an Audit Committee that advises our board of directors, composed exclusively of members of our board of directors.
On June 17, 2005, our board of directors approved the appointment of our Audit Committee to satisfy the audit committee requirements of the Sarbanes-Oxley Act of 2002 and Rule 10A-3 under the Securities Exchange Act of 1934.
The Audit Committee is responsible for, among other matters:
· making recommendations to our board of directors with respect to the appointment, compensation and retention of our independent auditor;
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· assisting our board of directors with analysis of our financial statements and the effectiveness of our internal controls over financial reporting in consultation with internal and independent auditors;
· assisting in the resolution of conflicts between management and the independent auditor with respect to our financial statements;
· conducting an annual review of related party transactions involving interested members of our board of directors and executive officers and companies that employ any of these people, as well any other material transactions with related parties; and
· establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal control and auditing matters, including procedures for the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters.
The current members of our Audit Committee are Luiz Nelson Guedes de Carvalho, Luiz Augusto Fraga Navarro de Britto Filho and Roberto da Cunha Castello Branco. All members of our Audit Committee satisfy the requirements set forth in Rule 10A-3 under the Exchange Act.
Our board of directors has two additional advisory committees: theComitê de Remuneração e Sucessão(Remuneration and Succession Committee), responsible for advising our board of directors with respect to the compensation of members of our senior management and with respect to Petrobras’s general compensation policies and mechanisms, among other matters, and theComitê de Segurança, Meio Ambiente e Saúde(Health, Safety and Environmental Committee), responsible for advising our board of directors with respect to global policies related to the strategic management of health, safety and environmental issues, among other matters.
On December 23, 2014, our board of directors announced the formation of a special committee that serves as a reporting line for the internal investigations led by two independent law firms: U.S. firm Gibson, Dunn & Crutcher LLP and Brazilian firm Trench, Rossi e Watanabe Advogados (the “Special Committee”). These internal investigations are focused on collecting evidence regarding the nature, extent and impact of alleged illegal acts that may have been committed against Petrobras, as have been reported in testimony under plea bargain agreements provided to Brazilian courts, as well as to investigate related facts and circumstances that may have a significant impact on our business and results of operations.
This Special Committee acts independently, but it has a direct reporting line to our board of directors. It is responsible for: (i) the approval of independent law firms’ plan for the internal investigation; (ii) receiving and analyzing information produced by the independent law firms; (iii) ensuring that the independence of the investigations is not compromised; (iv) analyzing, approving and enabling the implementation of the recommendations made by the independent law firms; (v) communicating and/or authorizing communication between the independent law firms and the competent authorities, including regulators, regarding the investigation status, its results, as well as measures taken by us in connection with such investigations; (vi) preparing a final report about the results of the independent law firms investigations, as well as providing us with the Special Committee´s recommendations to improve our internal policies and procedures.
The Special Committee is composed of three members: two independent individuals from outside the company, a Brazilian and a non-Brazilian, with notable technical expertise, in addition to Petrobras’s Chief Governance, Risk and Compliance Officer.
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The following table sets forth certain information with respect to the members of the Special Committee:
Name | Date of Birth | Position |
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Ellen Gracie Northfleet | February 16, 1948 | Member of the Special Committee |
Andreas Pohlmann | January 24, 1958 | Member of the Special Committee |
João Adalberto Elek Junior | November 26, 1958 | Member of the Special Committee |
Ellen Gracie Northfleet—Chief Justice Northfleet has been a member of our Special Committee since December 2014. She has served as Chief Justice of the Brazilian Supreme Court from 2006 to 2008 and was a Justice of the Brazilian Supreme Court from December 2000 to August 2011. Ms. Northfleet was also a Justice of the Regional Federal Court of Appeals -4th Region (Tribunal Regional Federal – 4ª Região) from 1989 to 2000 and a Federal Prosecutor (Procuradora da República) from 1973 to 1989. Ms. Northfleet is recognized in Brazil and abroad for her expertise and experience with complex legal issues. Ms. Northfleet has an LL.B degree from the Universidade Federal do Rio Grande do Sul-UFRGS and a post-graduate degree in social anthropology from UFRGS as well.
Andreas Pohlmann—Dr. Pohlmann has been a member of our Special Committee since December 2014 and a partner at Pohlmann & Company since February 2012. Dr. Pohlmann has served as Chief Compliance Officer of Siemens AG from September 2007 to May 2010 and from May 2010 until November 2011 as a member of the executive board of Ferrostaal AG, responsible for compliance and administration. Dr. Andreas Pohlmann was also the Chief Compliance Officer and member of the Executive Committee of SNC-Lavalin Group Inc. in Montreal, Canada, from 2013 to 2014. Dr. Andreas Pohlmann holds a law degree from Goethe University in Frankfurt and a PhD in law from Tuebingen University.
João Adalberto Elek Junior—Mr.Elek Junior has been a member of our Special Committee since January 2015. For biographical information regarding Mr. Elek Junior, see “—Executive Officers”.
The Petrobras General Ombudsman’s Office has been an official part of our corporate structure since October 2005, when it became directly linked to the board of directors. The General Ombudsman’s Office is the official channel for receiving and responding to denunciations and information regarding possible irregularities in accounting, internal controls and auditing. The General Ombudsman’s Office reports directly to the Audit Committee and guarantees the anonymity of informants.
In December 2007, the board of directors approved the Policies and Directives of the Petrobras Ombudsman, which was an important step in aligning the General Ombudsman’s practices with those of the other ombudsmen office in the system, contributing to better corporate governance. In April 2010, the board of directors approved a two-year renewable term for the Ombudsman Officer, during which he cannot be discretionarily dismissed by the management, ensuring its independence in performing his duties.
In May 2012, the Public Access to Information Law (Law No. 12,527/2011), which regulates the constitutional right for people to have access to public information became effective. This law states that all information produced or held in custody by the government and not classified as confidential must become accessible to all citizens.
The extension of this law encompasses public entities that are directly or indirectly controlled by the Brazilian federal government, which includes Petrobras. In April 2012, the General Ombudsman was appointed by our management as the authority responsible for implementing this law within Petrobras. In this respect, the General Ombudsman's Office ensures compliance with the rules on access to information by the public, monitors the implementation of this law and submits periodic reports to the board of directors, as well as makes recommendations and provides guidance to Petrobras’s business units with respect to the enforcement of the law.
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