SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

FORM 6-K

 

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of the

Securities Exchange Act of 1934

 

For the month of March, 2017

 

Commission File Number 1-15106

 

 

 

PETRÓLEO BRASILEIRO S.A. - PETROBRAS

(Exact name of registrant as specified in its charter)

Brazilian Petroleum Corporation - PETROBRAS

(Translation of Registrant's name into English)

Avenida República do Chile, 65 

20031-912 - Rio de Janeiro, RJ

Federative Republic of Brazil

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F. 

 

Form 20-F ___X___ Form 40-F _______

 

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

 

Yes _______ No___X____

 

 

 

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FINANCIAL

STATEMENTS

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December 31, 2016, 2015 and 2014

with report of independent registered

public accounting firm

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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To the Board of Directors and Shareholders

Petróleo Brasileiro S.A. - Petrobras

In our opinion, the accompanying consolidated statement of financial position and the related consolidated statements of income, comprehensive income, cash flows and changes in shareholders’ equity present fairly, in all material respects, the financial position of Petróleo Brasileiro S.A. – Petrobras and its subsidiaries (the “Company”) at December 31, 2016 and December 31, 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

 

As discussed in Note 3 to the financial statements, in 2014, the Company wrote off US$ 2,527 million of overpayments on the acquisition of property plant and equipment incorrectly capitalized according to testimony obtained from Brazilian criminal investigations.

 

 

 

/s/

PricewaterhouseCoopers

Auditores Independentes

CRC 2SP000160/O-5 “F” RJ

 

Rio de Janeiro, Brazil

March 21, 2017

 

 

 

 

 

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Petróleo Brasileiro S.A. – Petrobras

 

 

 

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Petróleo Brasileiro S.A. – Petrobras

 

 

 

 

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Petróleo Brasileiro S.A. – Petrobras

 

 

 

 

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Petróleo Brasileiro S.A. – Petrobras

 

 

 

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Petróleo Brasileiro S.A. – Petrobras

 

 

 

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Petróleo Brasileiro S.A. - Petrobras is a company controlled by the Brazilian government dedicated, directly or through its subsidiaries (referred to jointly as “Petrobras”, “the Company”, or “Petrobras Group”), either independently or through joint ventures or similar arrangements with third parties, to prospecting, drilling, refining, processing, trading and transporting crude oil from producing onshore and offshore oil fields and from shale or other rocks, as well as oil products, natural gas and other liquid hydrocarbons. In addition, Petrobras carries out energy related activities, such as research, development, production, transport, distribution and trading of all forms of energy, as well as other related or similar activities. The Company’s head office is located in Rio de Janeiro – RJ, Brazil.

 

These consolidated financial statements have been prepared and are being presented in accordance with the International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), and presents all relevant information related to the financial statements.

These financial statements have been prepared under the historical cost convention, except for available-for-sale financial assets, financial assets and financial liabilities measured at fair value and certain current and non-current assets and liabilities, as set out in the summary of significant accounting policies.

The annual consolidated financial statements were approved and authorized for issue by the Company’s Board of Directors in a meeting held on March 21, 2017.

The functional currency of Petrobras and all of its Brazilian subsidiaries is the Brazilian Real. The functional currency of most of the Petrobras entities that operate outside Brazil is the U.S. dollar.

Petrobras has selected the U.S. Dollar as its presentation currency. The financial statements have been translated from the functional currency (Brazilian Real) into the presentation currency (U.S. Dollar) in accordance with IAS 21 – “The effects of changes in foreign exchange rates”. All assets and liabilities are translated into U.S. dollars at the closing exchange rate at the date of the financial statements. Income and expenses, as well as cash flows are translated into U.S. dollars using the average exchange rates prevailing during the year. Equity items are translated using the exchange rates prevailing at the dates of the transactions. All exchange differences arising from the translation of the consolidated financial statements from the functional currency into the presentation currency are recognized as cumulative translation adjustments (CTA) within accumulated other comprehensive income (loss) in the consolidated shareholders’ equity.

 

For the preparation of the financial statements for the year ended December 31, 2016, the Company has corrected certain amounts from prior periods to conform to current period presentations. The Company concluded that these corrections are not material and they did not affect the income statement and the shareholders’ equity, as described below:

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In 2009, the Brazilian Federal Police (Polícia Federal) 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 the country and sectors of the Brazilian economy.

Beginning in 2014, the Brazilian Federal Prosecutor’s Office focused part of its investigation on irregularities involving Petrobras’s contractors and suppliers and uncovered a broad payment scheme that involved a wide range of participants, including former Petrobras personnel. Based on the information available to Petrobras, the payment scheme involved a group of companies that, between 2004 and April 2012, colluded to obtain contracts with Petrobras, overcharge the Company under those contracts and use the overpayment received under the contracts to fund improper payments to political parties, elected officials or other public officials, individual contractors and suppliers personnel, former Petrobras personnel and other individuals involved in the scheme. Petrobras refers to this scheme as the “payment scheme” and to the companies involved in the scheme as “cartel members”. The Company did not make any improper payment.

In addition to the payment scheme, the investigations identified specific instances of other contractors and suppliers that overcharged Petrobras and allegedly used the overpayment received from their contracts with the Company to fund improper payments, unrelated to the payment scheme, to certain former Petrobras personnel. Those contractors and suppliers are not cartel members and acted individually. Petrobras refers to these specific cases as the “unrelated payments.”

Certain former executives of Petrobras were arrested and/or charged for certain crimes such as money-laundering and passive corruption. Other former executives of the Company as well as executives of Petrobras contractors and suppliers were or may be charged as a result of the investigation.

The amounts paid by Petrobras related to contracts with contractors and suppliers involved in the payment scheme were included in historical costs of its property, plant and equipment. However, the Company believes that, under International Accounting Standard IAS 16 – Property, Plant and Equipment, the portion of the payments made to these companies and used by them to make improper payments, which represents additional charges incurred as a result of the payments scheme, should not have been capitalized. Thus, in the third quarter of 2014, the Company wrote off US$2,527 of capitalized costs representing amounts that Petrobras overpaid for the acquisition of property, plant and equipment in prior years.

The Company has continuously monitored the investigations for additional information and to assess any potential impact on the adjustments made. No additional information has been identified that impacted the adopted calculation methodology and the recorded adjustment in 2014 for the preparation of the financial statements for the year ended December 31, 2016.

Petrobras will continue to 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.

The Company has been closely monitoring the investigations and cooperating fully with the Brazilian Federal Police (Policía Federal), the Brazilian Public Prosecutor’s Office (Ministério Público Federal), Federal Auditor’s Office (Tribunal de Contas da União – TCU), and the Ministry of Transparency, Supervision and Control (Ministério da Transparência , Fiscalização e Controle) in the investigation of all crimes and irregularities. We have responded to numerous requests for documents and information from these authorities.

The Company has also cooperated with the U.S. Securities and Exchange Commission (SEC) and the United States Department of Justice (DOJ), which, since November 2014, have been investigating potential violations of U.S. law based on information disclosed as a result of the Lava Jato investigation.

We have been formally recognized as a victim of the crimes identified under the Lava Jato investigation by the Brazilian Federal Prosecutor’s Office, the lower court hearing the case and also by the Brazilian Supreme Court. As a result, we have entered into 29 criminal proceedings as an assistant to the prosecutor. In addition, we have entered into five criminal proceedings as an interested party. We have also renewed our commitment to continue cooperating with authorities to clarify the issues and report them regularly to our investors and to the public in general.

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We do not tolerate corrupt practices and illegal acts perpetuated by any of our employees. Accordingly, in 2016, the Company continued to implement several measures as a response to the facts uncovered in the “Lava Jato” investigation and to improve its corporate governance and compliance systems as described below.

As part of the process of strengthening the internal control structure, among the measures taken in 2016, the Company approved its new Corporate Compliance Policy, performed training programs with personnel and executives focused on the prevention of corruption, reviewed the “Compliance Agents” initiative and adapted its findings to the new organization structure, conducted nearly 12,000 integrity due diligence procedures, and performed background checks as part of the decision making for appointing personnel to key positions.

Internal investigations are still in progress and are being carried out by two independent firms hired in October 2014, which report directly to a Special Committee that serves as a reporting line to the Board of Directors. The Special Committee is composed of our Governance and Compliance Officer, João Adalberto Elek Junior and two other independent and recognized experts: Ellen Gracie Northfleet, former Chief Justice of the Brazilian Supreme Court, who is recognized internationally as a jurist with great experience in analyzing complex legal issues; and Andreas Pohlmann from Germany, former Chief Compliance Officer of Siemens AG (2007-2010), who has broad experience in compliance and corporate governance matters.

We established Internal Investigative Committees (Comissões Internas de Apuração) to investigate instances of non-compliance with corporate rules, procedures or regulations. The Committees’ investigation results are shared with the Brazilian authorities as they progress.

In addition, the Company has been taking the necessary procedural steps to seek compensation for damages suffered from the improper payments scheme, including those related to its reputation.

Accordingly, the Company joined 12 public civil suits addressing acts of administrative misconduct filed by the Brazilian Public Prosecutor’s Office and the Federal Government, including demands for compensation for reputation damages.

In order to secure future compensation to Petrobras for each civil action related to misconduct, the courts granted cautionary orders in certain actions to impound defendants’ property.

To the extent that any of the proceedings resulting from the Lava Jato investigation involve leniency agreements with cartel members or plea agreements with individuals pursuant to which they agree to return funds, the Company may be entitled to receive a portion of such funds. Nevertheless, the Company is unable to reliably estimate further recoverable amounts at this moment. Any recoverable amount will be recognized as income when received or when their economic benefits become virtually certain.

In 2016, the Company recognized the amount of US$ 131 as compensations for damages relating to the “Lava Jato” Operation (US$ 72 up to 2015) pursuant to leniency and cooperation agreements.

As it is not possible to specifically identify the amounts of each overpayment to contractors and suppliers, or periods over which such payments occurred, Petrobras developed a methodology to estimate the aggregate amount that it overpaid under the payment scheme, in order to determine the amount of the write-off representing the overstatement of its assets resulting from overpayments used to fund improper payments.

As it is impracticable to identify the periods and amounts of overpayments incurred, the Company developed a methodology to estimate the adjustment incurred in property, plant and equipment in the third quarter of 2014 using the five steps described below:

(1) Identify contractual counterparties: the Company listed all the companies identified as cartel members, and using that information the Company identified all of the contractors and suppliers that were either so identified or were part of consortia including entities so identified.

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

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

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

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

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

For more information on the approach adopted by the Company to estimate the write-off for overpayments incorrectly capitalized, see note 3 to the Company’s audited consolidated financial statements for 2014.

The Company considered all available information for purposes of the preparation of the financial statements for the year ended December 31, 2016 and did not identify any additional information that would impact the adopted calculation methodology and consequently require additional write-offs.

Petrobras has closely monitored the progress of both the investigation by Brazilian authorities and the independent law firms and no new facts that could impact the Company's previously recorded adjustments or change the methodology adopted were discovered. The Company will continuously monitor these investigations for additional information and will review their potential impact on the adjustment made.

Petrobras is not a target of the Lava Jato investigation and is formally recognized as a victim of the improper payments scheme by the Brazilian Authorities.

On November 21, 2014, Petrobras received a subpoena from the U.S. Securities and Exchange Commission (SEC) requesting certain documents and information about the Company.  The Company has been complying with the subpoena and intends to continue to do so, working with the independent Brazilian and U.S. law firms that were hired to conduct an independent internal investigation.

On December 15, 2015, the State of São Paulo Public Prosecutor’s Office issued the Order of Civil Inquiry 01/2015, establishing a civil proceeding to investigate the existence of potential damages caused by Petrobras to investors in the stock market. The Company has provided all relevant information required by the authorities.

Note 30 provides information about class actions and other material legal proceedings.

 

The accounting policies set out below have been consistently applied to all periods.

The consolidated financial statements include the financial information of Petrobras and the entities it controls (subsidiaries), joint operations and consolidated structured entities.

Control is achieved when Petrobras: i) has power over the investee; ii) is exposed, or has rights, to variable returns from involvement with the investee; and iii) has the ability to use its power to affect its returns.

Subsidiaries are consolidated from the date on which control is obtained until the date that such control no longer exists, by using accounting policies consistent with those adopted by Petrobras.

Note 11 sets out the consolidated entities and other direct investees.

Petrobras has no equity interest in its consolidated structured entities, but control is determined by the power the Company has over the relevant activities of such entities. Consolidated structured entities are set out below:

 

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The consolidation procedures involve combining assets, liabilities, income and expenses, according to their function and eliminating all intragroup balances and transactions, including unrealized profits arising from intragroup transactions.

The information related to the Company’s operating segments (business areas) is prepared based on items directly attributable to each segment, as well as items that can be allocated to each segment on a reasonable basis. This information reflects the views of the Company’s Board of Executive Officers (Chief Operating Decision Maker – CODM).

The measurement of segment results includes transactions carried out with third parties and transactions between business areas, which are charged at internal transfer prices defined by the relevant areas using methods based on market parameters.

The Company’s operating segments comprises the following business areas:

a) Exploration and Production (E&P): this segment covers the activities of exploration, development and production of crude oil, NGL (natural gas liquid) and natural gas in Brazil and abroad, for the primary purpose of supplying its domestic refineries and the sale of surplus crude oil and oil products produced in the natural gas processing plants to the domestic and foreign markets. The E&P segment also operates through partnerships with other companies;

b) Refining, Transportation and Marketing (RT&M): this segment covers the refining, logistics, transport and trading of crude oil and oil products activities in Brazil and abroad, exports of ethanol, extraction and processing of shale, as well as holding interests in petrochemical companies in Brazil;

c) Gas and Power: this segment covers the activities of transportation and trading of natural gas produced in Brazil and abroad, imported natural gas, transportation and trading of LNG (liquid natural gas), generation and trading of electricity, as well as holding interests in transporters and distributors of natural gas and in thermoelectric power plants in Brazil, in addition to being responsible for the fertilizer business;

d) Biofuels: this segment covers the activities of production of biodiesel and its co-products, as well as the ethanol-related activities: equity investments, production and trading of ethanol, sugar and the surplus electric power generated from sugarcane bagasse; and

e) Distribution: this segment covers the activities of Petrobras Distribuidora S.A, which sells oil products, ethanol and vehicle natural gas in Brazil. This segment also includes distribution of oil products operations abroad (South America).

The corporate segment comprises the items that cannot be attributed to the other segments, notably those related to corporate financial management, corporate overhead and other expenses, including actuarial expenses related to the pension and medical benefits for retired employees and their dependents.

Assets and the statement of income by business area are presented in note 29.

Cash and cash equivalents comprise cash in hand, term deposits with banks and short-term highly liquid financial investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and have a maturity of three months or less from the date of acquisition.

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

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Subsequent changes attributable to interest income or changes in foreign exchange rates or inflation indexation (price indexes) are recognized in the statement of income for all categories, when applicable.

Trade receivables are initially measured at the fair value of the consideration to be received and, subsequently, at amortized cost using the effective interest rate method and adjusted for allowances for impairment or uncollectible receivables.

The Company recognizes an allowance for impairment of trade receivables when there is objective evidence that a loss event occurred after the initial recognition of the receivable and has an impact on the estimated future cash flows, which can be reliably estimated. Impairment losses on trade receivables are recognized in the statement of income in selling expenses.

Loans and financing are initially recognized at fair value less transaction costs incurred and subsequently measured at amortized cost using the effective interest rate method.

Derivative financial instruments are recognized in the statement of financial position as assets or liabilities and are initially and subsequently measured at fair value.

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

The Company qualifies certain transactions for cash flow hedge accounting.

Hedging relationships qualify for cash flow hedges when they involve the hedging of the exposure to variability in cash flows that is attributable to a particular risk associated with a recognized asset or liability or a highly probable forecasted transaction that may impact the statement of income.

Gains or losses relating to the effective portion of the hedge are recognized in other comprehensive income, in the shareholders’ equity and recycled to the statement of income in finance income (expense) in the periods when the hedged item affects the statement of income. The gains or losses relating to the ineffective portion are immediately recognized in the statement of income.

When the hedging instrument expires or settled in advance, no longer meets the criteria for hedge accounting or the Company revokes the designation, the cumulative gain or loss on the hedging instrument that has been recognized in other comprehensive income from the period when the hedge was effective is recorded separately in equity until the forecast transaction occurs. When the forecast transaction is no longer expected to occur, the cumulative gain or loss on the hedging instrument that has been recognized in other comprehensive income is immediately reclassified from shareholders’ equity to the statement of income.

Inventories are determined by the weighted average cost method and mainly comprise crude oil, intermediate products and oil products, as well as natural gas, LNG, fertilizers and biofuels, stated at the lower of the average cost, and their net realizable value.

Crude oil and LNG inventories can be traded or used for production of oil products and/or electricity generation, respectively.

Intermediate products are those product streams that have been through at least one of the refining processes, but still need further treatment, processing or converting to be available for sale.

Biofuels mainly include ethanol and biodiesel inventories.

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Materials, supplies and others mainly comprise production supplies and operating materials used in the operations of the Company, stated at the average purchase cost, not exceeding replacement cost.

Net realizable value is the estimated selling price of inventory in the ordinary course of business, less estimated cost of completion and estimated expenses to complete its sale.

The amounts presented in the categories above include imports in transit, which are stated at their cost of purchase.

An associate is an entity over which the Company has significant influence. Significant influence is the power to participate in the financial and operating policy decisions of the investee but not the ability to exercise control or joint control over those polices. The definition of control is set out in note 4.1.

A joint arrangement is an arrangement over which two or more parties have joint control (pursuant to contractual provisions). A joint arrangement is classified either as a joint operation or as a joint venture depending on the rights and obligations of the parties to the arrangement.

In a joint operation, the parties have rights to the assets and obligations for the liabilities related to the arrangement, while in a joint venture the parties have rights to the net assets of the arrangement.

Profit or loss, assets and liabilities related to joint ventures and associates are accounted for by the equity method. In a joint operation the Company recognizes the amount of its assets, liabilities and related income and expenses.

Accounting policies of joint ventures and associates have been adjusted, where necessary, to ensure consistency with the policies adopted by Petrobras. Distributions received from an investee reduce the carrying amount of the investment.

Acquisitions of businesses are accounted for using the acquisition method when control is obtained. Combinations of entities under common control are not accounted for as business combinations.

The acquisition method requires that the identifiable assets acquired and the liabilities assumed be measured at the acquisition-date fair value. Amounts paid in excess of the fair value are recognized as goodwill. In the case of a bargain purchase, a gain is recognized in the statement of income when the acquisition cost is lower than the acquisition-date fair value of the net assets acquired.

Changes in ownership interest in subsidiaries that do not result in loss of control of the subsidiary are equity transactions. Any excess of the amounts paid/received over the carrying value of the ownership interest acquired/disposed is recognized in shareholders’ equity as changes in interest in subsidiaries.

The costs incurred in connection with the exploration, appraisal and development of crude oil and natural gas production are accounted for using the successful efforts method of accounting, as set out below:

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Property, plant and equipment are measured at the cost to acquire or construct, including all costs necessary to bring the asset to working condition for its intended use and the estimated cost of dismantling and removing the asset and restoring the site, reduced by accumulated depreciation and impairment losses.

A condition of continuing to operate certain items of property, plant and equipment, such as industrial plants, offshore plants and vessels is the performance of regular major inspections and maintenance. Those expenditures are capitalized if a maintenance campaign is expected to occur, at least, 12 months later. Otherwise, they are expensed when incurred. The capitalized costs are depreciated over the period through the next major maintenance date.

Spare parts are capitalized when they are expected to be used during more than one period and can only be used in connection with an item of property, plant and equipment. These are depreciated over the useful life of the item of property, plant and equipment to which they relate.

Borrowing costs directly attributable to the acquisition or construction of qualifying assets are capitalized as part of the costs of these assets. General borrowing costs are capitalized based on the Company’s weighted average cost of borrowings outstanding applied over the balance of assets under construction. Borrowing costs are amortized during the useful lives of the assets or by applying the unit-of-production method to the related assets. In general, the Company suspends capitalization of borrowing to the extent investments in a qualifying asset hibernates during a period greater than one year or whenever the asset is prepared for its intended use.

Whenever an asset is directly associated to oil and gas production and its estimated lifecycle is equal or greater than the estimated length of reserves depletion, the depreciation of this asset will be accounted for pursuant to the unit-of-production method.

Assets depreciated based on the straight line method include: (i)assets related to oil and gas production with useful lives shorter than the life of the field; (ii) floating platforms; and  (iii) assets that are unrelated to oil and gas production.

The unit-of-production method of depreciation (amortization) is computed based on a unit-of-production basis (monthly production) over the proved developed oil and gas reserves, applied on a field-by-field basis.

Amortization of amounts paid for obtaining concessions for exploration of oil and natural gas of producing properties, such as signature bonuses (capitalized acquisition costs) is recognized using the unit-of-production method, computed based on the units of monthly production over the total proved oil and gas reserves, applied on a field-by-field basis.

Except for land, which is not depreciated, other property, plant and equipment are depreciated on a straight-line basis over its useful life. Note 12.2 provides further information on the estimated useful life by class of assets.

Intangible assets are measured at the acquisition cost, less accumulated amortization and impairment losses and comprise rights and concessions, including the signature bonus paid for obtaining concessions for exploration of oil and natural gas (capitalized acquisition costs), public service concessions, trademarks, patents, software and goodwill.

Signature bonuses paid for obtaining concessions for exploration of oil and natural gas are initially capitalized within intangible assets and are transferred to property, plant and equipment upon the declaration of commerciality. They are not amortized before their transference to property, plant and equipment. Intangible assets with a finite useful life, other than amounts paid for obtaining concessions for exploration of oil and natural gas of producing properties, are amortized over the useful life of the asset on a straight-line basis.

Internally-generated intangible assets are not capitalized and are expensed as incurred, except for development costs that meet the recognition criteria related to the completion and use of assets, probable future economic benefits, and others.

Intangible assets with an indefinite useful life are not amortized but are tested annually for impairment. Their useful lives are reviewed annually.

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Property, plant and equipment and intangible assets with definitive lives are tested for impairment when there is an indication that the carrying amount may not be recoverable. Assets are assessed for impairment at the smallest identifiable group that generates largely independent cash inflows from other assets or groups of assets (the cash-generating unit - CGU).

Assets related to development and production of oil and gas and (fields or group of fields) assets that have indefinite useful lives, such as goodwill acquired in business combinations, are tested for impairment annually, irrespective of whether there is any indication of impairment, or when any indication of impairment occurs.

The impairment test is performed through the comparison of the carrying amount of an individual asset or a cash-generating unit (CGU) with its recoverable amount. Whenever the recoverable amount is less than the carrying amount, an impairment loss is recognized to reduce the carrying amount to the recoverable amount. The recoverable amount of an asset or a cash-generating unit is the higher of its fair value less costs of disposal and its value in use. Considering the existing synergies between the Company’s assets and businesses, as well as the expectation of the use of its assets for their remaining useful lives, value in use is generally used by the Company for impairment testing purposes, except when specifically indicated.

Value in use is estimated based on the present value of the risk-adjusted (for specific risks) future cash flows expected to arise from the continuing use of an asset or cash-generating unit, discounted at a pre-tax discount rate. This rate is obtained from the Company’s post-tax weighted average cost of capital (WACC). Cash flow projections are mainly based on the following assumptions: prices based on the Company’s most recent business and management plan and strategic plan; production curves associated with existing projects in the Company's portfolio, operating costs reflecting current market conditions, and investments required for carrying out the projects.

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

The Company assesses its investments in associates and joint ventures (equity-accounted investments) for impairment whenever there is an indication that their carrying amounts may not be recoverable.

By performing impairment testing of an equity-accounted investment, goodwill, if exists, is also considered part of the carrying amount to be compared to the recoverable amount.

Except when specifically indicated, value in use is generally used by the Company for impairment testing purposes in the proportion to the Company’s interests in the present value of future cash flow projections via dividends and other distributions.

Reversals of previously recognized impairment losses are permitted.

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

For finance leases, when the Company is the lessee, assets and liabilities are recognized at the lower of the fair value of the leased property or the present value of the minimum lease payments, both determined at the inception of the lease.

Capitalized lease assets are depreciated on a systematic basis consistent with the depreciation policy the Company adopts for property, plant and equipment that are owned. Where there is no reasonable certainty that the Company will obtain ownership by the end of the lease term, capitalized lease assets are depreciated over the shorter of the lease term or the estimated useful life of the asset.

When the Company is the lessor, a receivable is recognized at the amount of the net investment in the lease.

If a lease does not transfer substantially all the risks and rewards incidental to ownership of the leased item, it is classified as an operating lease. Operating leases are recognized as expenses over the period of the lease.

Contingent rents are recognized as expenses when incurred.

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Non-current assets, disposal groups and liabilities directly associated with those assets are classified as held for sale if their carrying amounts will, principally, be recovered through the sale transaction rather than through continuing use.

The Company has an effective divestment program and is considering opportunities for divestments in several areas where it operates. The divestment portfolio is dynamic because changes in market conditions and/or in the Company’s evaluation of its different businesses may affect any ongoing negotiation or potential transaction.

The condition for classification as held for sale is met only when the sale is approved by the Company’s Board of Directors and the asset or disposal group is available for immediate sale in its present condition and there is the expectation that the sale will occur within 12 months after its classification as held for sale. In addition, the sale should be expected to qualify for recognition as a completed sale within one year from the date of its classification as held for sale. However, an extended period required to complete a sale does not preclude an asset (or disposal group) from being classified as held for sale if the delay is caused by events or circumstances beyond the Company’s control and there is sufficient evidence that the Company remains committed to its plan to sell the assets (or disposal groups).

Assets (or disposal groups) classified as held for sale and the associated liabilities are measured at the lower of their carrying amount and fair value less costs to sell. Assets and liabilities are presented separately in the statement of financial position.

Decommissioning costs are future obligations to perform environmental restoration, dismantle and remove a facility when the Company terminates its operations due to the exhaustion of the area or economic feasibility.

Costs related to the abandonment and dismantling of areas are recognized as part of the cost of an asset (with a corresponding liability) based on the present value of the expected future cash outflows, discounted at a risk-adjusted rate when a future legal obligation exists and can be reliably measured.

Decommissioning costs estimates for oil and natural gas producing properties are initially recognized after a field is declared to be commercially viable.

The part of the cost of an asset relating to decommissioning costs estimates is depreciated on the same basis of its corresponding property, plant and equipment. Unwinding of the discount on the corresponding liability is recognized as a finance expense, when incurred. Decommissioning costs estimates are revised annually, at least.

Provisions are recognized when there is a present obligation that arises from past events and for which it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation, which must be reasonably estimable.

Contingent assets and liabilities are not recognized, but contingent liabilities are disclosed whenever the likelihood of loss is considered possible, including those for which the amount outflow of resources are not reasonably estimable.

Income tax expense for the period includes current and deferred taxes.

Since 2015, the Company has adopted the provisions of law 12.973/14 in order to determine its taxable profit for the year. This law superseded the Transition Tax Regime (Regime Tributário de Transição-RTT).

Current tax expense is computed based on taxable profit for the year, calculated using tax rates that have been enacted or substantively enacted at the end of the reporting period.

Current income taxes are offset when they relate to income taxes levied on the same taxable entity and by the same tax authority , when a legal right and intention to set off current tax assets and current tax liabilities exists.

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Deferred income taxes are recognized on temporary differences between the tax base of an asset or liability and its carrying amount. Deferred income tax liabilities are generally recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary differences and carryforward of unused tax losses or credits to the extent that it is probable that taxable profit will be available against which those deductible temporary differences can be utilized. When there are insufficient taxable temporary differences relating to the same taxation authority and the same taxable entity, a deferred tax is recognized to the extent that it is probable that the entity will have sufficient taxable profit in future periods, based on projections approved by management and supported by the Company’s Business and Management Plan.

Deferred tax assets and deferred tax liabilities are measured at the tax rates that have been enacted or substantively enacted by the end of the reporting period, and they are offset when they relate to income taxes levied on the same taxable entity, when a legally enforceable right to set off current tax assets and current tax liabilities exists and when the deferred tax assets and deferred tax liabilities relate to taxes levied by the same tax authority on the same taxable entity.

Actuarial commitments related to post-employment defined benefit plans and health-care plans are recognized as liabilities in the statement of financial position based on actuarial calculations which are revised annually by an independent qualified actuary (updating for material changes in actuarial assumptions and estimates of expected future benefits), using the projected unit credit method, net of the fair value of plan assets, when applicable, from which the obligations are to be directly settled.

Actuarial assumptions include demographic assumptions, financial assumptions, medical costs estimates, historical data related to benefits paid and employee contributions.

Under the projected credit unit method, each period of service gives rise to an additional unit of benefit entitlement and each unit is measured separately to determine the final obligation.

Changes in the net defined benefit liability (asset) are recognized when they occur, as follows: i) service cost and net interest cost in the statement of income; and ii) remeasurements in other comprehensive income.

Service cost comprises: (i) current service cost, which is the increase in the present value of the defined benefit obligation resulting from employee service in the current period; (ii) past service cost, which is the change in the present value of the defined benefit obligation for employee service in prior periods, resulting from a plan amendment (the introduction, modification, or withdrawal of a defined benefit plan) or a curtailment (a significant reduction by the entity in the number of employees covered by a plan); and (iii) any gain or loss on settlement.

Net interest on the net defined benefit liability (asset) is the change during the period in the net defined benefit liability (asset) that arises from the passage of time.

Remeasurement of the net defined benefit liability (asset) is recognized in shareholders’ equity, in other comprehensive income, and comprises: (i) actuarial gains and losses and; (ii) the return on plan assets, less interest income earned on these assets.

The Company also contributes amounts to defined contribution plans, that are expensed when incurred and are computed based on a percentage of salaries.

Share capital comprises common shares and preferred shares. Incremental costs directly attributable to the issue of new shares (share issuance costs) are presented (net of tax) in shareholders’ equity as a deduction from the proceeds.

To the extent the Company proposes distributions to shareholders, such dividends and interest on capital are determined in accordance with the limits defined in the Brazilian Corporation Law and in the Company’s bylaws.

Interest on capital is a form of dividend distribution, which is deductible for tax purposes in Brazil to the entity distributing interest on capital. Tax benefits from the deduction of interest on capital are recognized in the statement of income.

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Other comprehensive income includes: i)changes in fair value of available-for-sale financial instruments; ii) effective portion of cash flow hedge; iii) remeasurement of defined benefit plans; and iv) cumulative translation adjustment.

A government grant is recognized when there is reasonable assurance that the grant will be received and the Company will comply with the conditions attached to the grant.

Revenue is recognized when it is probable that the economic benefits associated with the transaction will flow to the Company and the amount of revenue and the costs incurred or to be incurred in the transaction can be measured reliably. Revenue is measured at the fair value of the consideration received or receivable for products sold and services provided in the normal course of business, net of returns, discounts and sales taxes.

Revenues from the sale of crude oil and oil products, petrochemical products, natural gas, biofuels and other related products are recognized when the Company retains neither continuing managerial involvement nor effective control over the products sold and the significant risks and rewards of ownership have been transferred to the customer, which is usually when legal title passes to the customer, pursuant to the terms of the sales contract. Sales revenues from freight and other services provided are recognized based on the stage of completion of the transaction.

Finance income and expense mainly comprise interest income on financial investments and government bonds, interest expense on debt, gains or losses on marketable securities measured at fair value, as well as net foreign exchange and inflation indexation charges. Finance expense does not include borrowing costs which are capitalized as part of the costs of these assets.  

Revenue, costs and expenses are recognized on the accrual basis.

The preparation of the consolidated financial information requires the use of estimates and judgments for certain transactions and their impacts on assets, liabilities, income and expenses. The assumptions are based on past transactions and other relevant information and are periodically reviewed by management, although the actual results could differ from these estimates.

Information about those areas that require the most judgment or involve a higher degree of complexity in the application of the accounting practices and that could materially affect the Company’s financial condition and results of operations is set out as follows:

Oil and gas reserves are estimated based on economic, geological and engineering information, such as well logs, pressure data and drilling fluid sample data and are used as the basis for calculating unit-of-production depreciation, depletion and amortization rates, impairment testing, decommissioning costs estimates and for projections of high probable future exports subject to cash flow hedge.

These estimates require the application of judgment and are reviewed at least annually based on a re-evaluation of already available geological, reservoir or production data and new geological, reservoir or production data, as well as changes in prices and costs that are used in the estimation of reserves. Revisions can also result from significant changes in the Company’s development strategy or in the production capacity.

The Company determines its oil and gas reserves both pursuant to the U.S. Securities and Exchange Commission - SEC and the ANP/SPE (Brazilian Agency of Petroleum, Natural Gas and Biofuels / Society of Petroleum Engineers) criteria. The main differences between the two criteria are: selling price of crude oil (ANP/SPE establishes the use of the Company’s forecasted price, while SEC determines the use of an average price considering each first day of the last 12 months); concession period (ANP permission for the use of reserve quantities after the concession period). Additionally, pursuant to the SEC criteria, only proved reserves are determined, while proved and unproved reserves are determined pursuant to the ANP/SPE criteria.

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According to the definitions prescribed by the SEC, proved oil and gas reserves are the estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved reserves are subdivided into developed and undeveloped reserves.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Although the Company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory aspects and significant changes in long-term oil and gas price levels.

Detailed information on reserves is presented as supplementary information.

Depreciation, depletion and amortization are measured based on estimates of reserves prepared by the Company’s technicians in a manner consistent with SEC definitions. Reviews to the Company’s proved developed and undeveloped reserves impact prospectively the amounts of depreciation, depletion and amortization recognized in the statement of income and the carrying amounts of oil and gas properties assets.

Therefore, considering all other variables being constant, a decrease in estimated proved reserves would increase, prospectively, depreciation, depletion and amortization expense, while an increase in reserves would reduce depreciation, depletion and amortization.

Notes 4.8 and 12 provide more detailed information on depreciation, amortization and depletion.

The Company assesses the recoverability of the carrying amounts of oil and gas exploration and development assets based on their value in use, as defined in note 4.10. In general, analyses are based on proved reserves and probable reserves pursuant to the ANP/SPE definitions.

The timing of abandonment and dismantling of on shore and offshore areas is based on the length of reserves depletion, in accordance with ANP/SPE definitions. Therefore, the review of the timing of reserves depletion may impact the provision for decommissioning cost estimates.

The Company estimates highly probable future exports in accordance with future exports forecasted in the scope of its  Business and Management Plan - BMP and its Strategic Plan projections, which are driven by proved and probable reserves estimates. Reviews in such reserves may impact future exports forecasts and, consequently, hedge relationship designations may also be impacted. For example, whenever future exports for which a hedging relationship has been designated are no longer considered as highly probable, the Company revokes this designation and the cumulative foreign exchange gains or losses recognized in other comprehensive income remain in shareholders’ equity until the forecast exports occur. Additionally, if the future exports are also no longer expected to occur, the cumulative foreign exchange recognized in other comprehensive income is immediately recycled from shareholders’ equity to the statement of income.

Impairment testing involves uncertainties mainly related to its key assumptions: average Brent prices and Real/U.S. dollar average exchange rate. These assumptions are relevant to virtually all of the Company’s business segments and a significant number of interdependent variables are derived from these key assumptions and there is a high degree of complexity in their application in determining value in use for impairment tests.

The markets for crude oil and natural gas have a history of significant price volatility and although prices can drop precipitously, industry prices over the long term tends to continue being driven by market supply and demand fundamentals.

Projections relating to the key assumptions are derived from the Business and Management Plan for the first five years and consistent with the Strategic Plan for the following years. These assumptions are consistent with market evidence, such as independent macro-economic forecasts, industry commentators and experts. Back testing analysis and feedback process in order to continually improve forecast techniques are also performed.

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The Company’s oil price forecast model is based on a nonlinear relationship between variables reflecting market supply and demand fundamentals. This model also takes into account other relevant factors, such as historical idle capacity, industry costs, oil and gas production forecasted by specialized firms, the relationship between the oil price and the U.S. dollar exchange rate, as well as the impact of OPEC on the oil market.

Changes in the economic environment may result in changing assumptions and, consequently, the recognition of impairment charges on certain assets or CGUs. For example, the Brent price directly impacts the Company’s sales revenue and refining margins, while the Real/U.S. dollar exchange rate mainly impacts our capital and operating expenditures.

Changes in the economic and political environment may also result in higher country risk projections that would increase discount rates for impairment testing.

In addition, changes in reserve volumes, production curve expectations and lifting costs could trigger the need for impairment assessment, as well as capital expenditure decisions, which are also affected by the Company’s plan to reduce its leverage, may result in postponement or termination of projects, reducing their economic feasibility.

The recoverable amount of certain assets was not substantially in excess of their carrying amounts and, therefore, it is reasonably possible that outcomes in future periods that are different from the current assumptions may result in the recognition of additional impairment charges on these assets, as described in note 14.1.1.

Further information on impairment testing is set out in notes 4.10, 5.3 and 14.

Identifying cash-generating units (CGUs) requires management assumptions and judgment, based on the Company’s business and management model.

Changes in the aggregation of assets into Cash-Generating units (CGUs) could result in additional impairment charges or reversals. Such changes may occur when investment, strategic or operational factors result in changes in the interdependencies between those assets and, consequently, alter the aggregation of assets into CGUs.

The assumptions set out below have been consistently applied by the Company:

Exploration and Production CGUs:

i) Crude oil and natural gas producing properties CGU: comprises exploration and development assets related to crude oil and natural gas fields and groups of fields in Brazil and abroad. In September 2016, the aggregations of assets for the Fazenda Cedro and Lagoa Suruaca groups, both located in Espírito Santo, were reviewed and impairment tests were run separately for those individual fields due to the discontinuation of a relevant shared infrastructure in the production process, as approved in the 2017-2021 BMP; and

The drilling rigs are not part of any grouping of assets and are assessed for impairment separately.

Refining, transportation and marketing CGUs:

i) Downstream CGU: comprises refineries and associated assets, terminals and pipelines, as well as logistics assets operated by Transpetro, with a combined and centralized operation of logistical and refining assets in Brazil.  These assets are managed with a common goal of achieving efficiency, profitability and strategic value long term on a nationwide basis.  They are not operated for the generation of profit by asset/location. The operational planning is made in a centralized manner and these assets are not managed, measured or evaluated by their individual results. The refineries do not have autonomy to choose the oil to be processed, the mix of oil products to produce, the markets in which these products will be traded, which amounts will be exported, which intermediaries will be received and to decide the sales prices of oil products. The operational decisions are analyzed through an integrated model of operational planning for market supply. This model evaluates the solutions to supply the market considering all the options for production, importing, exporting, logistics and inventories seeking a comprehensive optimum of Petrobras and not the profit of each unit. The decision regarding a new investment is not based on the profitability of the project for the asset where it will be installed, but for the Petrobras Group. The model in which the entire planning is based, used in the studies of technical and economic feasibility of new investments in refining, may, in its indications, allocate a lower economic kind of oil to a certain refinery or define a lower economic mix of products to it, or even force it to supply more distant markets (area of influence), leading it to operate with reduced margins if seen individually, in case this is the best for the integrated system as a whole. Pipelines and terminals are an integral part and interdependent portion of the refining assets, required to supply the market.

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ii) CGU Comperj – comprises assets under construction of the first refining unit of Petrochemical Complex of Rio de Janeiro. In 2014, the Company decided to postpone this project for an extended period of time;

iii) CGU Second Refining Unit of RNEST – comprises assets under construction of second refining unit of Abreu e Lima refinery. In 2014, the Company decided to postpone this project for an extended period of time;

iv) Petrochemical CGU: This CGU was composed of the PetroquímicaSuape and Citepe petrochemical plants until November 2016. In December 2016, the Company’s Board of Directors approved the sale of these plants and, consequently, these assets were not aggregated as a CGU as of December 31, 2016, pursuant to their reclassification to assets held for sale.  

v) Transportation CGU: comprises assets relating to Transpetro’s fleet of vessels. Recurrent delays in the construction of support vessels for transporting ethanol over the Tietê River led the management of the wholly-owned subsidiary Transpetro, in September 2016, to terminate the construction contracts for a new group of support vessels in the scope of Hidrovias project. As a result, this project was postponed and its completed assets were reviewed and tested for impairment separately;

vi) SIX CGU: shale processing plant; and

vii) Other operations abroad defined as the smallest group of assets that generates independent cash flows.

Gas & Power CGUs:

i) Natural gas CGU: comprises natural gas pipelines, natural gas processing plants and fertilizers and nitrogen products plants other than the Fertilizer Plant UFN III, which is assessed for impairment separately. In September 2016, the Board of Directors approved the disposal of interest in the subsidiary NTS and, as a consequence, its pipelines were removed from this CGU.

ii) CGU UFN III: comprises assets under construction of the fertilizer plant Unidade de Fertilizantes e Nitrogenados III (UFN III). The Company decided to postpone this project for an extended period of time ;

iii) Power CGU: comprises the thermoelectric power generation plants. In December 2016, the Company’s Board of Directors approved the strategic alliance with Total that, among other matters, outlines the share of 50% interests in the power plants Celso Furtado and Rômulo Almeida. Accordingly, these assets were removed from this CGU; and

iv) Other CGUs: operations abroad defined as the smallest group of assets that generates largely independent cash flows.

Distribution CGU:

Mainly comprises the distribution assets related to the operations of Petrobras Distribuidora S.A.

Biofuels CGUs:

An integrated unit of biodiesel plants defined based on the production planning and operation process, that takes into consideration domestic market conditions, the production capacity of each plant, as well as the results of biofuels auctions and raw materials supply. Due to the decision to discontinue operations of Quixadá Biofuel Plant, as approved by the Board of Directors of the subsidiary Petrobras Biocombustível in September 2016, impairment test for this Biofuel Plant was run separately.

Investments in associates and joint ventures, including goodwill, are assessed for impairment separately.

The actuarial obligations and net expenses related to defined benefit pension and health care post-retirement plans are computed based on several financial and demographic assumptions, of which the most significant are:

Discount rate: comprises the projected future inflation in addition to an equivalent real interest rate that matches the duration of the pension and health care obligations with the future yield curve of long-term Brazilian Government Bonds; and

Medical costs: comprise the projected growth rates based on per capita health care benefits paid over the last five years, which are used as a basis for projections, converged to the general price inflation index within 30 years.

These and other estimates are reviewed at least annually and may differ materially from actual results due to changing market and financial conditions, as well as actual results of actuarial assumptions.

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The sensitivity analysis of discount rates and changes in medical costs as well as additional information about actuarial assumptions are set out in note 22.

The Company is a defendant in numerous legal proceedings involving tax, civil, labor, corporate and environmental issues arising from the normal course of its business for which it estimates the amounts of the obligations and the probability that an outflow of resources will be required. Those estimates are based on legal counsel and management’s best estimates.

Note 30 provides further detailed information about contingencies and legal proceedings.

The Company has legal and constructive obligations to remove equipment and restore onshore and offshore areas at the end of operations at production sites. Its most significant asset removal obligations involve removal and disposal of offshore oil and gas production facilities in Brazil and abroad. Estimates of costs for future environmental cleanup and remediation activities are based on current information about costs and expected plans for remediation.

These estimates require performing complex calculations that involve significant judgment since: i) the obligations are long-term; ii)the contracts and regulations contain subjective definitions of the removal and remediation practices and criteria involved when the events actually occur; and iii) asset removal technologies and costs are constantly changing, along with regulations, environmental, safety and public relations considerations.

The Company is constantly conducting studies to incorporate technologies and procedures to optimize the operations of abandonment, considering industry best practices. However, the timing and amounts of future cash flows are subject to significant uncertainty.

Notes 4.14 and 20 provide further detailed information about the decommissioning provisions.

The recognition of deferred tax liabilities and deferred tax assets involves significant estimates and judgments by the Company. Deferred tax assets are recognized to the extent that it is probable that taxable profit will be available against which a deductible temporary difference can be utilized or it is probable that the entity will have sufficient taxable profit in future periods. In evaluating whether it will have sufficient taxable profit in future periods to support the recognition of deferred tax assets, the Company uses future projections and estimates based on its Business and Management Plan (BMP), which is approved by the Board of Directors annually. Future taxable profits projections are mainly based on the following assumptions: i) Brent crude oil prices; ii) foreign exchange rates; and iii) the Company’s projected net finance expenses (income).

Changes in deferred tax assets and liabilities are presented in note 21.6.

The Company determines its future exports as “highly probable future exports” based on its Business and Management Plan - BMP and its Strategic Plan. The highly probable future exports are determined by a percentage of projected exports revenue over the mid and long term, taking into account the Company’s operational and capital expenditure optimization model which considers future uncertainties, such as oil price and production, as well as products demand. Future exports forecasts are reviewed whenever the Company reviews its BMP and Strategic Plan assumptions. The approach for determining exports as highly probable future exports is reviewed annually, at least.

See note 33.2 for more detailed information about cash flow hedge accounting and a sensitivity analysis of the cash flow hedge involving future exports.

As described in note 3, in the third quarter of 2014, the Company wrote off US$2,527 of capitalized costs representing the estimated amounts that Petrobras had overpaid for the acquisition of property, plant and equipment.

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To account for these overpayments, the Company developed an estimation methodology, as set out in note 3. Petrobras acknowledges the degree of uncertainty involved in the estimation methodology and continues to monitor the ongoing investigations and the availability of other information concerning the amounts it may have overpaid in the context of the payment scheme. If reliable information becomes available that indicates with sufficient precision that the Company’s estimate should be modified, it will evaluate materiality and, if so, adjust.

However, as previously discussed, the Company believes it has used the most appropriate methodology and assumptions to determine the amounts of overpayments incorrectly capitalized and there is no evidence that would indicate the possibility of a material change in the amounts written-off.

Management continuously assesses whether there is objective evidence that trade receivables are impaired and recognizes allowances for impairment of trade receivables to cover losses. Such evidence includes insolvency, defaults, judicial recovery claims, a significant probability of a debtor filing for bankruptcy and others.

See note 8 for more detailed information about allowance for impairment of trade receivables.

 

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The main standards issued by the IASB and not effective as of December 31, 2016 are set out below. The Company did not adopt those standards early.

IFRS 16 – “Leases”

On January 13, 2016, the IASB issued IFRS 16 "Leases", which will become effective for the financial report period beginning on or after January 1, 2019, superseding IAS 17 "Leases" and related interpretations.

IFRS 16 provides requirements for leases identification, recognition, measurement, presentation and disclosure according to the lessee and lessor perspectives.

Among the changes for lessees, IFRS 16 eliminates classification between financial and operating leases, required by IAS 17. Therefore, it will be a single model in which all leases will result in the recognition of assets related to the use of rights of assets leased. If the payments provided for in the commercial lease are due over time, financial liabilities should be recognized as well.

For lessors, IFRS 16 will maintain the classification as either financial or operating leases as required by IAS 17. IFRS 16 will not substantially change the way leases will be accounted for lessors when compared to IAS 17.

The Company is assessing the impacts of this new standard and believes that the adoption of IFRS 16 may cause a significant increase in assets and liabilities presented in its consolidated statement of financial position. Accordingly, the Company may also need to negotiate some covenants in its loan agreements with BNDES – (Brazilian Development Bank) when a reliable estimate of these impacts can be made.

 

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Cash and cash equivalents

 

 

Short-term financial investments in Brazil comprise investment in funds, with maturities of three months or less, holding Brazilian Federal Government Bonds. Short-term financial investments abroad comprise time deposits with maturities of three months or less, highly-liquid automatic investing accounts, interest checking accounts and other short-term fixed income instruments, including U.S. Treasury bills.

 

Marketable securities

 

 

Trading securities refer mainly to investments in Brazilian Federal Government Bonds. These financial investments have maturities of more than three months and are mostly classified as current assets due to their maturity or the expectation of their realization in the short term.

 

 

 

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The Company supplies fuel oil, natural gas, and other products to entities that operate in the isolated electricity system in the northern region of Brazil, such as thermoelectric power plants controlled by Eletrobras, state-owned natural gas distribution companies and independent electricity producers (Produtores Independentes de Energia – PIE). The isolated electricity system provides the public service of electricity distribution in the northern region of Brazil, as the Brazilian National Interconnected Power Grid (Sistema Interligado Nacional) has not yet met the demand for electricity due to technical or economic reasons.

A significant portion of the funds used by those companies to pay for products supplied by the Company came from the Fuel Consumption Account (Conta de Consumo de Combustível – CCC), which provides funds to cover a portion of the costs related to the supply of fuel to thermoelectric power plants located in the northern region of Brazil (operating in the isolated electricity system). However, as a result of changes in the CCC regulations over time, principally relating to the Provisional Measure 579/2012 which significantly changed the sources of funds that were used to cover the cost of electricity generated in the Isolated Electricity System, funds transferred from the CCC to these electricity companies have not been sufficient for them to meet their financial obligations and, as a result, some have not been able to pay the total amount for the products supplied by the Company, increasing the default rate of those customers to the Company.

The Company intensified negotiations with the state-owned natural gas distribution companies, the independent electricity producers (PIEs), other private companies and entities controlled by Eletrobras. As a result, on December 31, 2014, the Company entered into a debt acknowledgement agreement with subsidiaries of Eletrobras with respect to the balance of its receivables as of November 30, 2014. Eletrobras acknowledged it owed US$ 2,202 to the Company, of which US$ 1,889 were collateralized by payables from the Brazilian Energy Development Account (Conta de Desenvolvimento Energético - CDE) to the CCC. This amount has been adjusted by the Selic interest rate (Brazilian short-term interest rate) on a monthly basis. Under this agreement, the first of 120 monthly installments was paid in February 2015 and these payments have continued.

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In order to mitigate an increase in default rates, on September 1, 2015 the Brazilian National Electricity Agency (Agência Nacional de Energia Elétrica - ANEEL) enacted the Normative Instruction 679 enabling the Company to receive funds directly from the CCC, as these funds would be paid directly from the CCC for products supplied in the prior month with a limit of 75% of the average payments made by the CCC in the previous three months.

The Company had expected that the abovementioned rule would have strengthened the financial situation of the companies in the electricity sector. However, this has not occurred and the level of these defaults increased. Accordingly, in 2015 the Company recognized US$ 564 as allowance for impairment of trade receivables (net of reversals) with respect to uncollateralized receivables outstanding as of December 31, 2015.

In 2016, the Company recognized an allowance for impairment of trade receivables (net of reversals) in the amount of US$ 345 mainly relating to new supplies of: (i) fuel oil by legal enforcement (injunction) in the first quarter of 2016; and (ii) natural gas. Accordingly, the Company has adopted the following measures:

Excluding the effects of foreign exchange translation, the amount of trade receivables from the electricity sector remained relatively flat mainly due to contractual clauses of amortization established in the debt acknowledgement agreement, which determine the payment of 15% of the amount of renegotiated debt within 36 months and the remaining 85% to be paid in 84 installments beginning in January 2018. Therefore, the Company expects the balance of trade receivables from the electricity sector will decrease from 2018 onwards as the amounts to be received will be higher than sales and inflation indexation on debt acknowledgement agreements.

 

 

 

Inventories are presented net of a US$ 28 allowance reducing inventories to net realizable value (US$ 155 as of December 31, 2015), mainly due to changes in international prices of crude oil and oil products. In  2016, the Company recognized as cost of sales a US$ 343 allowance charge (net of reversals) reducing inventories to net realizable value (US$ 430 in  2015).

A portion of the crude oil and/or oil products inventories have been pledged as security for the Terms of Financial Commitment (TFC) signed by Petrobras and Petros in the amount of US$ 1,979 (US$ 1,719 as of December 31, 2015), as set out in note 22.1.

 

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Termination of the contract for the sale of Bijupirá and Salema fields (BJS)

On February 26, 2016, Petro Rio S.A. terminated the contracts signed with the Company on July 1, 2015, for the sale of 20% interest in Bijupirá and Salema concessions (BJS) and in the Dutch joint operation BJS Oil Operations B.V. (BJSOO BV). Accordingly, the amounts relating to these fields were reclassified from assets and liabilities held for sale back to property, plant and equipment (US$ 148) and to provision for decommissioning costs (US$ 126), respectively.

Due to the aforementioned reclassification, the respective assets were depreciated based on their historical data and their recoverable amounts were reassessed. As a result, the Company recognized, in the first quarter of 2016, an impairment loss as set out in note 14.1.

Sale of Petrobras Argentina

On May 12, 2016, the Board of Directors approved the disposal of the Company’s entire 67.19% interest in Petrobras Argentina - PESA, owned through the subsidiary Petrobras Participaciones S.L. (“PPSL”), to Pampa Energía.

On July 27, 2016, the amount of US$ 897 was disbursed by Pampa Energia and, on December 14, 2016, additional US$ 3 was paid due to contractual clauses. Accordingly, the Company recognized a gain of US$ 207 on this sale, as other expenses, net. In addition, the amount of US$ 1,428 was reclassified from shareholders’ equity to other expenses within the income statement, reflecting the reclassification of cumulative translation adjustment resulting from the depreciation of Argentinian Peso against the U.S Dollar from the acquisition of this investment to its disposal (see note 23.4).

On October 28, 2016, as expected, the Company concluded this transaction with the acquisition of 33.6% of the concession of Rio Neuquén in Argentina and 100% of Colpa Caranda asset in Bolivia for the amount of US$ 56, after adjustments relating to Colpa Caranda asset.

Disposal of distribution assets in Chile

On July 22, 2016, the Company signed a sale and purchase agreement with the Southern Cross Group for the sale of 100% of Petrobras Chile Distribución Ltda (PCD), held through Petrobras Caribe Ltda.

Pursuant to this disposal approved by the Board of Directors, the respective assets were classified as held for sale and measured at their estimated exit price and, as a result, the Company recognized impairment charges as set out in note 14.2.

This transaction was concluded on January 4, 2017 and the net proceeds from this deal were US$ 470, of which US$ 90 were received via distribution of dividends after taxes on December 9, 2016 and the remaining US$ 380 were paid by Southern Cross in the transaction closing.

Disposal of interest in exploratory block BM-S-8

On July 28, 2016 the Board of Directors of Petrobras approved the disposal of the Company’s 66% interest in the exploratory block BM – S-8 to Statoil Brasil Óleo e Gás Ltda, which includes the Carcará area located in the pre-salt layer of Santos Basin, for the amount of US$ 2.5 billion.

The Brazilian Antitrust Regulator (Conselho Administrativo de Defesa Econômica – CADE) and the Brazilian Agency of Petroleum, Natural Gas and Biofuels (Agência Nacional de Petróleo, Gás Natural e Biocombustíveis) – ANP approved this transaction on September 8, 2016 and November 10, 2016, respectively.

After performing all conditions precedent established in the agreement, on November 22, 2016 the Company received the first installment in the amount of US$ 1.25 billion, corresponding to 50% of the transaction and, as a result of the transaction closing, the Company recognized a gain in the amount of US$ 881 as other expenses, net. The remaining amount will be recognized based on two contingent payments relating to future events: the bid for an extended adjacent area of the Carcará reservoir (US$ 300) and the signing of the unitization agreement (US$ 950).

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Disposal of interest in Nova Transportadora do Sudeste (NTS) and related changes in organizational structure

After a corporate restructuring intended to concentrate the transportation assets of the southeastern region in NTS (Rio de Janeiro, Minas Gerais and São Paulo), the Company’s Board of Directors approved on September 22, 2016 the sale of 90% interest in Nova Transportadora do Sudeste (NTS) to Brookfield Infrastructure Partners (BIP) and its affiliates, through a Private Equity Investment Fund (FIP) whose other shareholders are British Columbia Investment Management Corporation (BCIMC), CIC Capital Corporation (wholly-owned subsidiary of China Investment Corporation - CIC) and GIC Private Limited (GIC).

The following changes in organizational structure occurred as part of this process:

The Shareholder’s General Meeting held on November 30, 2016 approved this transaction in the amount of US$ 5.19 billion, of which US$ 3.55 billion correspond to 90% interest in NTS and US$ 1.64 billion correspond to the NTS debt settlement with the Company’s wholly-owned subsidiary PGT. FIP will subscribe convertible debentures issued by NTS for the replacement of this debt. The first installment, in the amount of US$ 4.34 billion will be paid at the closing of the transaction, and the remaining amount (US$ 850) will be paid in the fifth year, bearing annual interests at a fixed rate, as established in the purchase and sale agreement.

This transaction prescribes the maintenance of charge capacity and also the same terms of five Firm Gas Transportation Agreements including 100% ship-or-pay clauses. These agreements have terms of 20 years from 2016 and their rates are indexed to the Brazilian General Market  Price  Index (IGP-M) and regulated by Brazilian Petroleum, Natural Gas and Biofuels Agency (ANP).

The completion of the transaction is subject to certain customary conditions precedent, including approval by relevant regulators. Thus, the related assets and liabilities were classified as held for sale as of December 31, 2016.

On February 10, 2017, the federal court in the state of Sergipe determined the interruption of this disposal by ordering an injunction based on a civil action.  However, on March 9, 2017, this injunction was dismissed, enabling the progress of this transaction.

Disposal of Nansei Sekiyu (NSS)

On October 17, 2016 the Company’s Board of Directors approved the disposal of the Company’s interests in Nansei Sekiyu Kabushiki Kaisha (NSS) to Taiyo Oil Company ("Taiyo").

On December 28, 2016, this disposal was closed after the fulfillment of all conditions precedent in the sales and purchase agreement. Accordingly, Taiyo disbursed US$ 165 to the Company and, as a result, the Company recognized as other expenses, net a gain on this transaction amounting to US$ 132. This transaction is still subject to price adjustments.  

In addition, a loss of US$ 29 was reclassified from shareholders equity to other expenses within the income statement reflecting the reclassification of cumulative translation adjustment resulting from the depreciation of Japanese Yen against the U.S Dollar from the time of the acquisition of this investment to its disposal (see note 23.4).

Disposal of Liquigás

On November 17, 2016 the Company’s Board of Directors approved the disposal of its wholly-owned subsidiary Liquigás Distribuidora S.A. to Companhia Ultragaz S.A., a subsidiary of Ultrapar Participações S.A.

At December 31, 2016, the related assets and liabilities were classified as held for sale as conditions precedent were not yet performed, such as the transaction approval at Shareholders’ Meetings of Ultrapar and Petrobras, as well as the approval of the Brazilian Antitrust Regulator (CADE).

On January 31, 2017, the sale of Petrobras’s entire interests in Liquigás in the amount of US$ 828 was approved at Petrobras’ Shareholders’ Meeting.

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Disposal of Guarani

On December 28, 2016, the Company’s wholly-owned subsidiary Petrobras Biocombustível S.A. (PBIO) disposed of its interests in the associate Guarani S.A. (45,97%  of share capital) to Tereos Participations SAS, an entity of the French group Tereos.

As of December 31, 2016, this investment was classified as held for sale as this transaction was still subject to certain conditions precedent. As a result, the Company recognized an impairment charge in the amount of US$ 67 accounted for within results in equity-accounted investments.

On February 3, 2017 this transaction was concluded pursuant to the payment of US$ 203, after all conditions precedent were performed by Tereos Participations SAS.

Disposal of Suape and Citepe petrochemical plants

On December 28, 2016, the Company’s Board of Directors approved the disposal of its interests in the wholly-owned subsidiaries Companhia Petroquímica de Pernambuco (PetroquímicaSuape) and Companhia Integrada Têxtil de Pernambuco (Citepe) to Grupo Petrotemex S.A. de C.V. and Dak Americas Exterior, S.L., both subsidiaries of Alpek, S.A.B. de C.V., which is a company from Grupo Alfa S.A.B. de C.V. (a Mexican public company), in the amount of US$ 385, which will be totally disbursed pursuant to the transaction closing. This amount is still subject to adjustments relating to working capital, net debt and recoverable taxes.

This transaction closing is subject to the approval at Petrobras Shareholder’s General Meeting, Grupo Alfa’s Board of Directors and Brazilian Antitrust Regulator (CADE), as well as to the fulfillment of certain other customary conditions precedent.

As the conditions precedent to this transaction were not performed at December 31, 2016, the respective assets were reclassified as held for sale and measured at their estimated exit price. As a result, the Company recognized impairment losses as described in notes 14.1 and 14.2.

On January 31, 2017, the federal court in the state of Sergipe determined the interruption of this disposal by ordering an injunction based on in a civil action.  However, on February 22, 2017, this injunction was dismissed, enabling the progress of this transaction.

Strategic alliance with Total

On December 21, 2016, the Company entered into a master agreement with Total, in connection with the Strategic Alliance established in the Memorandum of Understanding signed on October 24, 2016. Accordingly, certain assets were classified as held for sale at December 31, 2016 due to the share of interests established in this agreement, as described below:

On February 28, 2017, the Company and Total signed the purchase and sale agreements with respect to the aforementioned assets. Total will pay to the Company the total amount of US$ 2,225 with respect to these transactions, comprising US$ 1,675 in cash for assets and services, a line of credit in the amount of US$ 400 that can be used by the Company for investments in the Iara fields, as well as US$ 150 relating to contingent payments.

These transactions are still subject to the relevant authorities’ approvals, to the potential exercise of preemptive rights by current Iara partners, as well as other customary conditions precedent.

The aforementioned agreements adds up to the ones already executed on December 21, 2016, such as: (i) option for Petrobras to purchase a 20% interest in block 2 of the Perdido Foldbelt area, in the Mexican sector of the Gulf of Mexico, (ii) joint exploration studies in the exploratory areas of Equatorial Margin and in Santos Basin; and (iii) Technological partnership agreement in the areas of digital petrophysics, geological processing and subsea production systems.

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Merger of Nova Fronteira Bioenergia

On December 15, 2016, the Company’s wholly-owned subsidiary Petrobras Biocombustível S.A. (PBIO) entered into an agreement with São Martinho group which establishes the merger of PBIO interests in Nova Fronteira Bioenergia S.A. (49%) into São Martinho.

As of December 31, 2016, the related assets were classified as held for sale due to certain conditions precedent and the Company recognized a loss on this transaction in the amount of US$ 30 within results in equity-accounted investments.

On February 23, 2017, this transaction was concluded as São Martinho granted to PBIO an additional 24 million of its common shares, corresponding to 6.593% of its voting and total paid in capital, in exchange and in proportion to the shares that PBIOs held in Nova Fronteira. These shares will not be subject to any kind of lock-up and their sale will occur in 4 years through a structured process.

On December 7, 2016, the Brazilian Federal Audit Court (Tribunal de Contas da União – TCU) filed a civil action prohibiting Petrobras from commencing additional divestment projects and entering into sales agreements relating to the ongoing disposal projects while it assesses the Company’s divestments decision-making methodology. This action does not impact five deals which were under their final stages of negotiation when this civil action was filed, including the sale of Guarani, sale of Suape and Citepe petrochemical plants, as well as the merger of Nova Fronteira Bioenergia, as described in note 10.1.

The Company reviewed its divestments decision-making methodology and, on March 15, 2017, this civil action was dismissed, which enabled the Company to progress with two ongoing deals (sale of interests in Baúna and Tartaruga Verde fields and Saint Malo field located in U.S. Gulf of Mexico) and also to commence new divestment projects based on the reviewed methodology.

 

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The market value of these shares does not necessarily reflect the realizable value upon sale of a large block of shares.

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The total amount of non-controlling interest at December 31, 2016 is US$ 771 (US$ 819 in 2015), of which US$ 281 and US$ 99 relate to non-controlling interest of the subsidiaries Gaspetro and Transportadora Brasileira Gasoduto Brasil-Bolívia (TBG), respectively (US$ 234, US$ 55 and US$ 367 related to Gaspetro, TBG and Petrobras Argentina, respectively, at December 31, 2015) and US$ 175 refer to Consolidated Structured Entities (US$ 39 at December 31, 2015).

Condensed financial information is set out as follows:

 

 

Gaspetro, a Petrobras’ subsidiary, holds interests in several state distributors of natural gas in Brazil. Petrobras concluded the sale of 49% of its interest in Gaspetro on December 28, 2015.

TBG is an indirect subsidiary which operates in natural gas transmission activities mainly through Bolivia-Brazil Gas Pipeline. The Company holds 51% of interests in this indirect subsidiary.

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The Company invests in joint ventures and associates in Brazil and abroad, whose activities are related to petrochemical companies, gas distributors, biofuels, thermoelectric power plants, refineries and other activities. Condensed financial information is set out below:

 

 

 

 

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At December 31, 2016, property, plant and equipment include assets under finance leases of US$ 125 (US$ 48 as of December 31, 2015).

 

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Petrobras and the Brazilian Federal Government entered into the Assignment Agreement in 2010, which grants the Company the right to carry out prospection and drilling activities for oil, natural gas and other liquid hydrocarbons located in the pre-salt area limited to the production of five billion barrels of oil equivalent in up to 40 years and renewable for a further five years subject to certain conditions. As of December 31, 2016, the Company’s property, plant and equipment include the amount of US$ 22,954 related to the Assignment Agreement (US$ 19,158 as of December 31, 2015).

Petrobras has already declared commerciality in fields of all six blocks in the scope of this agreement: Franco (Búzios), Florim (Itapu), Nordeste de Tupi (Sépia), Entorno de Iara (Norte de Berbigão, Sul de Berbigão, Norte de Sururu, Sul de Sururu, Atapu), Sul de Guará (Sul de Sapinhoá) and Sul de Tupi (Sul de Lula).

The agreement establishes that the review procedures of the agreement will commence immediately after the declaration of commerciality for each area and must be based on reports by independent experts engaged by Petrobras and ANP. The review of the Assignment Agreement will be concluded after the assessment of all the areas.

If the review of the Assignment Agreement determines that the value of acquired rights is greater than the amount initially paid, the Company may be required to pay the difference to the Brazilian Federal Government, or may proportionally reduce the total volume of barrels acquired under the agreement. If the review determines that the value of the acquired rights is lower than initially paid by the Company, the Brazilian Federal Government will reimburse the Company for the difference by delivering cash or bonds or equivalent means of payment, subject to budgetary regulations.

The formal review procedures for each block are based on costs incurred over the exploration phase and estimated costs and production for the development period. The review of the Assignment Agreement may result in changes in: (i) the amount of the agreement; (ii) the total volume (in barrels of oil) to be produced; (iii) the term of the agreement; and (iv) the minimum percentages of local content.

Currently, the settlement form and the final amount to be established for this agreement are not defined. The beginning of negotiation with the Brazilian Federal Government still depends on the conclusion of the appraisals by independent experts engaged by both parties, and the issuance of the respective reports.

With respect to the negotiation with the Brazilian Federal Government, on October 21, 2016 the Company’s Board of Directors approved the creation of the minority shareholders committee responsible for monitoring the agreement review process and providing support to the board decisions through opinions about related matters. This committee will be composed of two members nominated by the minority shareholders and an independent member with recognized expertise in technical-financial analysis of investment projects.

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In 2016 the following oil and gas fields were returned to ANP: Tiziu, Japuaçu, Rio Joanes, part of Golfinho and part of Tambuatá. These fields were returned to ANP mainly due to their uneconomic feasibility and, as a consequence, the Company wrote off the amount of US$ 4 as other expenses, net.

In 2015, the oil and gas fields Itaparica, Camaçari, Carapicú, Baúna Sul, Salema Branca, Nordeste Namorado, part of Rio Preto, Pirapitanga, Piracucá, Catuá and part of Mangangá were returned to ANP and the Company wrote-off the amount of US$ 264 as other expenses, net.

In 2014, the oil and gas fields returned to ANP were: Cação, Carapiá, Moréia, Caravela, Cavalo Marinho, Estrela do Mar, Tubarão, Rio Mariricu, Rio Mariricu Sul, Lagoa Parda Sul, Urutau, Iraúna and Mosquito Norte and the Company wrote-off the amount of US$ 283 as other expenses.

 

 

 

Exploration areas returned to the ANP in 2016, totaling US$ 8 (US$ 25 in 2015) are set out below:

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Following the first pre-salt public auction held in October, 2013, the Libra consortium, composed of Petrobras (40% interest), Shell (20% interest), Total (20% interest), CNPC (10% interest), CNOOC (10% interest) and the Pré-Sal Petróleo S.A. (PPSA) as the manager of the agreement, entered into a production sharing contract with the Federal Government on December 2, 2013.

The contract granted rights and obligations to explore and operate oil and gas production in a strategic pre-salt area known as the Libra block, comprising an area of around 1,550 km², located in ultra-deep waters in the Santos Basin. This was the first oil and gas production sharing contract signed in Brazil. The contract is for 35 years and cannot be renewed.

Libra reservoir was discovered in 2010 following the drilling of 2-ANP-2A-RJS well. The Libra consortium offered a 41.65% stake of profit oil to the Brazilian Government, according to the rules of the first pre-salt public auction. This stake refers to the profit oil on a baseline scenario of price ranging from 100.01 US$/bbl to 120 US$/bbl, and production per producing well from 10 thousand bbl/d to 12 thousand bbl/d. This stake may vary with the international oil price and the productivity of the wells, as established by the Brazilian Agency of Petroleum, Natural Gas and Biofuels (ANP).

The signature bonus (acquisition cost) of US$ 6,589 was paid by the consortium. The Company paid US$ 2,636 relating to its share of the acquisition cost paid by the consortium, recognized in its intangible assets as Rights and Concessions.

Currently, the project is in its initial stage in the exploration phase (4 years), and its minimum work program have been partially performed and comprises a 3D seismic acquisition for the whole block, two exploratory wells and the extended well test (EWT) to be performed in 2017. The results confirmed oil reservoirs at depth of up to 410 meters with high porosity and permeability. The production tests confirmed the high productivity and oil quality of these reservoirs.

In September 2016, the Libra consortium commenced the process of hiring its second FPSO for the Northwest area (the FPSO of Libra Pilot Project), with expected start-up in 2020 and capacity of producing 180 thousands of barrels per day and processing 12 million cubic meters of gas.

A FPSO will be allocated to 3 parts in the Northwest area of this block in order to perform extended well tests and early production systems.

The start-up of Libra Pioneer is expected to occur in 2017 with capacity of processing 50 thousand barrels per day and compressing 4 million cubic meters per day of associated gas. The Company also intends to mitigate risks and optimize producing systems in Libra through this FPSO.

At the end of 2016, the first two wells completions of Libra Block were concluded. These wells have intelligent completion systems in two zones, enabling real time data monitoring and control and will commence operation in 2017 interconnected to Libra Pioneer.

In 2020, four definitive systems will be installed in Libra northwest. The pilot system is planned to be concluded in September 2020 and the remaining systems in the following 3 years. The size of wells and subsea systems to be concluded after the pilot project will be based on extended well test data.

As of December 31, 2016, intangible assets include service concession agreements related to piped natural gas distribution in Brazil, in the amount of US$ 177 (US$ 149 in 2015), maturing between 2029 and 2043, which may be renewed. According to the distribution agreements, service is provided to customers in the industrial, residential, commercial, automotive, air conditioning and transport sectors, among others.

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The consideration receivable is a factor of a combination of operating costs and expenses, and return on capital invested. The rates charged for gas distribution are subject to periodic reviews by the state regulatory agency.

The agreements establish an indemnity clause for investments in assets which are subject to return at the end of the service agreement, to be determined based on evaluations and appraisals.

On February 2, 2016, the state of Espírito Santo enacted the Law No. 10,493/2016 under which the service concession agreements related to piped natural gas distribution are considered ineffective pursuant Brazilian Federal Law 8,987/1995. This concession is accounted for as intangible assets totaling US$ 84 as of December 31, 2016 (US$ 69 as of December 31, 2015) and the Company has not recognized any provision on this matter based on indemnity established by law.

 

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The Company’s assets are tested for impairment on December 31, annually, or when there is an indication that their carrying amount may not be recoverable. During September 2016 such indication was identified for certain assets and triggered their impairment assessment due to changes mainly driven by a slower recovery of oil prices, a decrease in future capital expenditures, reflecting the Company’s plan to reduce current debt levels and optimize its investment portfolio, as well as changes in Brazilian political and economic scenario. These changes impacted the medium and long term assumptions used in our updated Business and Management Plan that was finalized and approved in the third quarter of 2016 and also impacted the key assumptions for impairment testing. Changes in the political and economic scenario in Brazil also resulted in increases in discount rates applied for impairment testing purposes in 2016.

At December 31, 2016, the company reassessed the existence of any new indication of impairment in assets previously tested in the third quarter of 2016. Accordingly, additional impairment charges were recognized in the last quarter of 2016 with respect to producing properties relating to oil and gas activities in Brazil, COMPERJ, Transpetro’s fleet of vessels, as well as reversals of impairment previously recognized for the Thermoelectric power generation plants, mainly as a result of: (i) Company’s annual review of oil and gas reserves; (ii) annual review of decommissioning cost estimates; (iii) the work in progress relating to the infrastructure shared by Comperj’s first refining unit and the natural gas processing plant (UPGN); (iv) changes in the Power CGU as described in note 5.3; and (v) the commencement of 5 vessels constructions, as part of Transportation CGU, following the signing of funding contracts which have enabled these projects funding.

In addition, the company also recognized in the last quarter of 2016 impairment charges relating to divestments and assets of certain subsidiaries that were tested for impairment based on their annual review at December 31, 2016.

For 2015, impairment losses were principally recognized in its fourth quarter pursuant to the annual tests in December, mainly due to changes in international crude oil prices, a downward review of proved and probable reserves estimates, a decrease in capex projections and an increase in Brazil’s risk premium.

For 2014, the company recognized impairment losses mainly as a result of higher specific risk premium, planning deficiencies and postponements of COMPERJ and the 2nd refining unit of RNEST, as well as the fall in international crude oil prices, which impacted the cash flows of E&P assets.

The table below shows the impairment losses, net of reversals, recognized within the statement of income in 2016, 2015 and 2014:

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For impairment testing purposes, the Company uses the value in use of its property, plant and equipment and intangible assets (individually or grouped into cash-generating units - CGUs) as their recoverable amount. In measuring value in use the Company bases its cash flow projections on:

Information on key assumptions for impairment testing and the definition of Company’s CGUs are presented in notes 5.2 and 5.3, respectively. Management assumptions and judgements, which are based on the Company’s business and management model, are required on these matters.

The cash flow projections used to measure the value in use of the CGUs in 2016 were mainly based on the following estimates of key assumptions for impairment testing:

 

For comparative purposes, estimates of key assumptions for impairment testing in 2015 and 2014 are shown below:

 

 

 

 

Information on the main impairment losses of property, plant and equipment and intangible assets are described below:

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a1) Producing properties in Brazil – 2016

Impairment losses of US$ 2,268 were recognized for certain oil and gas fields in Brazil under E&P concessions. Cash flow projections were based on: financial budgets/forecasts approved by Management and the post-tax discount rates (excluding inflation) derived from the WACC for the E&P business of 9.1% p.a. at September 30, 2016, which decreased to 8.6% p.a. at December 31, 2016 mainly reflecting improvement in Brazil’s risk premium. The impairment losses were related primarily to the following fields and groups of fields: North group (US$ 1,178), Ceará Mar Group (US$ 210), Guaricema (US$ 126), Dourado (US$ 88), Maromba (US$ 86), Bijupirá and Salema (US$ 82), Papa-Terra (US$ 72), Trilha (US$ 69), Uruguá group (US$ 62), Pampo (US$ 67), Frade (US$ 65), Badejo (US$ 56), Bicudo (US$ 49), Riachuelo (US$ 44), Fazenda Bálsamo (US$ 41) and Água Grande group (US$ 31). These impairment losses were mainly due to the appreciation of the Brazilian Real against the U.S. Dollar, price assumptions review, Company’s annual reviews of oil and gas reserves and decommissioning cost estimates, as well a higher discount rate following the increase in Brazil’s risk premium. In addition, an impairment reversal relating to Centro Sul group, amounting to US$ 415, was recognized due to increased estimate of reserves and production, as well as lower operating expenses estimates based on a review of its fields operations, as set forth in 2017-2021 BMP, considering the decommissioning of a unit which had high operational costs and replacing another unit with an investment in a new processing plant which was committed to during the third quarter of 2016.

a2) Producing properties in Brazil - 2015

In 2015, impairment losses of US$ 8,653 were recognized for certain oil and gas fields in Brazil under E&P concessions. Cash flow projections were based on: financial budgets/forecasts approved by Management; and an 8.3% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the E&P business. The impairment losses were related primarily to the following fields: Papa-Terra (US$ 2,234), Centro Sul group (US$ 1,179), Uruguá group (US$ 986), Espadarte (US$ 593), Linguado (US$ 489), CVIT – Espírito Santo group (US$ 375), Piranema (US$ 341), Lapa (US$ 317), Bicudo (US$ 240), Frade (US$ 198), Badejo (US$ 190), Pampo (US$ 91) and Trilha (US$ 84). These impairment losses are mainly due to the impact of the decline in international crude oil prices on the Company’s price assumptions, the use of a higher discount rate, as well as the geological revision of Papa-Terra reservoir.

a3) Producing properties in Brazil - 2014

In 2014, impairment losses of US$ 1,562 were recognized, mainly with respect to certain oil and gas fields under E&P concessions, whose recoverable amount was determined to be below their carrying amount. Cash flow projections were based on: financial budgets/forecasts approved by Management; and a 7.2% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the E&P business. The impairment losses were mainly related to the impact of the decline in international crude oil prices on the Company’s price assumptions and were principally recognized for the following fields: Frade, Pirapitanga, Tambuatá, Carapicu and Piracucá.

b1) Oil and gas production and drilling equipment in Brazil – 2016

Impairment losses of US$ 854 were recognized for oil and gas production and drilling equipment which were not directly related to oil and gas producing properties. Cash flow projections were based on: financial budgets/forecasts approved by Management; and an 9.9% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the oil and gas services and equipment industry. These impairment losses were mainly related to uncertainties over the ongoing hulls construction of the FPSOs P-71, P-72 and P-73, amounting to US$ 593 as set out in note 14.4.

b2) Oil and gas production and drilling equipment in Brazil - 2015

In 2015, impairment losses of US$ 507 were recognized for oil and gas production and drilling equipment which were not directly related to oil and gas producing properties. Cash flow projections were based on: financial budgets/forecasts approved by Management; and a 9.2% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the oil and gas services and equipment industry. The impairment losses were mainly related to the planned idle capacity of drilling rigs in the future and the use of a higher discount rate.

b3) Oil and gas production and drilling equipment in Brazil - 2014

In 2014, impairment losses of US$ 536 were recognized in oil and gas production and drilling equipment, unrelated to oil and gas producing properties. Cash flow projections were based on: financial budgets/forecasts approved by Management; and an 8% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the oil and gas services and equipment industry. The impairment losses are mainly related to idle capacity of two drilling rigs in the future and to the demobilization of two oil platforms, which were not deployed in any oil and gas property as of December 31, 2014.

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c1) Second refining unit in RNEST - 2016

An impairment loss of US$ 780 was recognized for the second refining unit in RNEST. Cash flow projections were based on: financial budgets/forecasts approved by Management; and an 8.7% p.a. (8.1% p.a. in 2015) post-tax discount rate (excluding inflation) derived from the WACC for the refining business, reflecting a specific risk premium for the postponed project. The impairment loss was mainly attributable to: (i) the use of a higher discount rate and (ii) a delay in expected future cash inflows to 2023 resulting from postponing the project, considering the completion of this project with the Company’s own capital resources as set forth in the 2017-2021 Business and Management Plan.

c2) Second refining unit in RNEST - 2014

In 2014, an impairment loss of US$ 3,442 was recognized in the second refining unit in RNEST. Cash flow projections are based on: financial budgets/forecasts approved by Management; and a 7% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the refining business. The impairment loss was mainly attributable to: (i) project planning deficiencies; (ii) the use of a higher discount rate, reflecting a specific risk premium for the postponed projects; (iii) a delay in expected future cash inflows resulting from postponing the project; and (iv) the Company’s business context of lower projected economic growth.

d1) Suape Petrochemical Complex - 2016

An impairment loss of US$ 619 was recognized for Companhia Integrada Têxtil de Pernambuco S.A. - CITEPE and Companhia Petroquímica de Pernambuco S.A. – PetroquímicaSuape at September 31, 2016. Cash flow projections were based on: financial budgets/forecasts approved by Management; and a 7.5% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the petrochemical business. The impairment loss was mainly attributable to lower market projections and the appreciation of Brazilian real against the U.S. dollar. Following the disposal of Suape Petrochemical Complex in December 2016, the Company recognized an additional impairment charge as set out in note 14.2.

d2) Suape Petrochemical Complex - 2015

In 2015, an impairment loss of US$ 200 was recognized for Companhia Integrada Têxtil de Pernambuco S.A. - CITEPE and Companhia Petroquímica de Pernambuco S.A. – PetroquímicaSuape. Cash flow projections were based on: financial budgets/forecasts approved by Management; and a 7.2% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the petrochemical business. The impairment loss was mainly attributable to changes in market and price assumptions resulting from a decrease in economic activity in Brazil, a reduction in the spread for petrochemical products in the international market and the use of a higher discount rate.

d3) Suape Petrochemical Complex - 2014

In 2014, an impairment loss of US$ 1,121 was recognized in Companhia Integrada Têxtil de Pernambuco S.A. ‐ CITEPE and Companhia Petroquímica de Pernambuco S.A. – PetroquímicaSuape. Cash flow projections were based on: 30‐year period and zero‐growth rate perpetuity; financial budgets/forecasts approved by Management; and a 6.2% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the petrochemical business. The impairment loss is 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.

e1) Comperj - 2016

Following a reassessment of COMPERJ project in the second quarter of 2016 confirming the postponement of its first refining unit until December 2020, with continuous efforts to seek new partnerships to resume the project, the Company recognized an impairment charge on the remaining balance of this project. However, the construction of Comperj’s first refining unit facilities that will also support the natural gas processing plant (UPGN) are still in progress as the facilities are part of the infrastructure for transporting and processing natural gas from the pre-salt layer in Santos Basin. Nevertheless, due to the interdependence between such infrastructure and Comperj first refining unit, the Company recognized additional impairment charges, totaling US$ 403 of impairment losses in 2016.

e2) Comperj - 2015

In 2015, an impairment loss of US$ 1,352 was recognized for refining assets of Comperj. Cash flow projections were based on: financial budgets/forecasts approved by Management, and; an 8.1% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the refining business reflecting a specific risk premium for the postponed projects. This impairment loss was mainly attributable to: (i) the use of a higher discount rate; and (ii) the delay in expected future cash inflows resulting from postponing construction.

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e3) Comperj - 2014

In 2014, an impairment loss of US$ 8,220 was recognized in Comperj. Cash flow projections were based on: financial budgets/forecasts approved by Management; and a 7% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the refining business. The impairment loss was mainly attributable to: (i) project planning deficiencies; (ii) the use of a higher discount rate, reflecting a specific risk premium for the postponed projects; iii) a delay in expected future cash inflows resulting from postponing the project; and (iv) the Company’s business context of lower projected economic growth.

f1) Fertilizer Plant - UFN III - 2016

An impairment loss of US$ 153 was recognized for the fertilizer plant UFN III (Unidade de Fertilizantes e Nitrogenados III).  Cash flow projections were based on: financial budgets/forecasts approved by Management; and an 8.3% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the fertilizer business, reflecting a specific risk premium for the postponed projects. This impairment loss mainly relates to: (i) the use of a higher discount rate, (ii) the appreciation of Brazilian Real against the US Dollar.

f2) Fertilizer Plant - UFN III - 2015

In 2015, an impairment loss of US$ 501 was recognized for the fertilizer plant UFN III (Unidade de Fertilizantes e Nitrogenados III). Cash flow projections were based on: financial budgets/forecasts approved by Management; and a 7.1% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the Gas & Power business, reflecting a specific risk premium for the postponed projects. The impairment losses were mainly related to: (i) the use of a higher discount rate; and (ii) the delay in expected future cash inflows resulting from postponing the project.

g) Araucaria - 2016

An impairment loss of US$ 140 was recognized for Araucária Nitrogenados S.A. Cash flow projections were based on: financial budgets/forecasts approved by Management; and a 7.8% p.a. post-tax discount rate (excluding inflation) derived from the WACC for the fertilizer business (6.6% p.a. in 2015). The impairment loss was mainly attributable to (i) the use of a higher discount rate, (ii) the appreciation of Brazilian Real against the U.S. Dollar and (iii) an increase in estimated production costs.

h) Transpetro’s fleet of vessels - 2016

In 2016, an impairment loss of US$ 244 was recognized for Transpetro’s fleet of vessels. Cash flow projections were based on: financial budgets/forecasts approved by Management; and post-tax discount rates (excluding inflation) ranging from 4.53% p.a. to 9.97% p.a. (3.92% p.a. to 8.92% p.a. in 2015) derived from the WACC for the transportation industry, considering financial leverage and the respective tax benefits. The impairment loss recognized in the third quarter mainly relates to a group of support vessels of Hidrovias project that were removed from this CGU due to the postponements and suspension of constructions projects, as well as the use of a higher discount rate. In the last quarter of 2016, additional impairment charges were accounted for due to the commencement of construction on 5 vessels after securing the projects funding, which avoided the possibility of future claims by alleging breach of contracts, as well as a further increase in discount rate.

i1) Producing properties abroad – 2015

In 2015, impairment losses of US$ 637 were recognized in E&P assets abroad. Cash flow projections were based on: financial budgets/forecasts approved by Management; and 5.6% p.a. to 10.4% p.a. post-tax discount rates (excluding inflation) derived from the WACC for the E&P business in different countries. The impairment losses were mainly in producing properties located in the United States (US$ 448) and Bolivia (US$ 157), attributable to the decline in international crude oil prices.

i2) Producing properties abroad – 2014

In 2014, impairment losses of US$ 1,668 were recognized in international E&P assets. Cash flow projections were based on: financial budgets/forecasts approved by Management; and 5.4% p.a. to 11.2% p.a. post-tax discount rates (excluding inflation) derived from the WACC for the E&P business in different countries. The impairment losses were mainly in Cascade and Chinook producing properties located in the United States (US$ 1,567) and were mainly attributable to the decline in international crude oil prices.

In 2016, the recoverable amounts of certain mature producing fields in Brazil were not substantially in excess of their carrying amounts. The carrying amounts of these assets totaled US$ 143 as of December 31, 2016. Changes in material assumptions for impairment testing may result in the recognition of additional impairment charges on such assets in future periods.

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In 2016, the Company recognized impairment losses amounting to US$ 556 pursuant to certain sales of interests in investees approved by the Board of Directors, as described in note 10, mainly due to the following investments:

For 2015, impairment losses were recognized in E&P assets classified as held for sale. The Board of Directors approved the disposal of the Bijupirá and Salema fields, PI, PIII and PIV drilling rigs and PXIV platform. As their fair values were below their carrying amount, impairment losses in the amount of US$ 3 were recognized.

For 2014, impairment losses were recognized in E&P assets classified as held for sale. The Board of Directors approved the disposal of PI, PIII, PIV and PV drilling rigs and PXIV platform and their fair value was below their carrying amount. Therefore, impairment losses in the amount of US$ 35 were recognized.

Value in use is generally used for impairment test of investments in associates and joint ventures (including goodwill). The basis for estimates of cash flow projections includes: projections covering a period of 5 to 12 years, zero-growth rate perpetuity, budgets, forecasts and assumptions approved by management and a pre-tax discount rate derived from the WACC or the Capital Asset Pricing Model (CAPM), when applicable.

The carrying amount and the value in use of the investments in associates and joint ventures which include goodwill as of December 31, 2016 are set out below:

 

 

Braskem’s shares are publicly traded on stock exchanges in Brazil and abroad. As of December 31, 2016 the quoted market value of the Company’s investment in Braskem was US$ 2,751 based on the quoted values of both Petrobras’ interest in Braskem’s common stock (47% of the outstanding shares), and preferred stock (22% of the outstanding shares). However, there is extremely limited trading of the common shares, since non-signatories of the shareholders’ agreement hold approximately 3% of the common shares.

Given the operational relationship between Petrobras and Braskem, the recoverable amount of the investment for impairment testing purposes was determined based on value in use, considering future cash flow projections and the manner in which the Company can derive value from this investment via dividends and other distributions to arrive at its value in use. As the recoverable amount was higher than the carrying amount, no impairment losses were recognized for this investment.

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Cash flow projections to determine the value in use of Braskem were based on the following key assumptions:

In 2016, impairment losses on equity-method investments in the amount of US$ 182 were recognized in the statement of income as results in equity-accounted investments, substantially attributable to investees of biofuels segment, mainly relating to:

For 2015, impairment losses on equity-method investments in the amount of US$ 550 (US$ 251 in 2014) were recognized in the statement of income as results in equity-accounted investments, mainly due to (i) losses in investees abroad reflecting the fall in international crude oil price (US$ 276); (ii) higher discount rates and capital expenditure decisions relating to the biofuels segment (US$ 139); (iii) the deteriorated economic and financial conditions of the associate Sete Brasil (US$ 88); and (iv) losses relating to the associate Arpoador Drilling B.V, an entity indirectly controlled by Sete Brasil (US$ 14).

The Company entered into contracts with the suppliers Ecovix-Engevix Construções Oceânicas S.A and Enseada Industria Naval S.A. for supplying eight hulls for the FPSOs P-66 to P-73 and for hulls conversion of four FPSOs (P-74 to P-77), respectively.

Considering the relevance of these assets in the context of the Business and Management Plan and due to the financial difficulties faced by the suppliers, escrow accounts relating to these projects were created in the last quarter of 2015 in order to ensure the ongoing performance of the services hired.

These escrow accounts have comprised funds transferred in advance for payments to be made by the shipyards, restricted to the scope of the contracts and limited to their total balance. The deposits would be offset to the extent that services rendered or equipment delivered, with the remaining balance being reimbursed. This strategy was considered effective as the projects achieved significant progress up to September 2016, enabling the delivery of P-67 hull to a shipyard in China for integration services, the recommence of the work in progress of P-69 hull also in China, the continuity of the work in progress of P-68 hull in Rio Grande shipyard, as well as the progress on priority activities for the conclusion of minimum scope of P-74 and P-76 hulls, delivering these units to shipyards in China for integration services and for setting up topsides.

During the third quarter of 2016, the Company reassessed the progress of the hulls project and the continuity of the escrow accounts related to the projects. Consequently, significant delays on projects progress were detected and the Company concluded that this strategy, which in its beginning avoided the work in progress discontinuation, was not as effective as it was previously.

Due to uncertainties regarding the FPSOs P-71, P-72 and P-73 hulls construction continuity after significant delays on projects progress, the Company recognized, in the third quarter of 2016, impairment charges amounting to US$ 593 as set out in note 14.1. Impacts in the Company’s production curve are not expected in case of the discontinuation of this work in progress, as the 2017-2021 Business and Management Plan includes other options and additional budget funds.

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Based on management evaluation, the Company recognized allowances for impairment amounting to US$ 689 within other expenses, net with respect to the remaining balance of advances to these suppliers in the context of the escrow accounts (US$ 352) and debts assumption relating to Ecovix and Enseada (US$ 337), in which legal procedures to recover them are being assessed.

In addition, the Company wrote-off capital expenditures related to the right of use the Rio Grande shipyard in the amount of US$ 155, as well as other investments related to the P-71, P-72 and P-73 amounting to US$ 146.

The effects of the negotiation with each shipyard are presented below:

Negotiations with Ecovix

Pursuant the reassessment made by the Company in the third quarter of 2016 in order to verify the effectiveness of the escrow account approach implemented to ensure access to P-66 to P-73 hulls, a provision in the amount of US$ 115 was recognized within other expenses, net.

On December 9, 2016, the Company, through its investees TUPI BV and Petrobras Netherlands BV, entered into agreements with Ecovix Construções Oceânicas S.A establishing the termination of EPC contracts signed in 2010 for the construction of eight FPSO hulls. Therefore, the Company has assumed certain liabilities from Ecovix as the most adequate solution for Petrobras Group: ensure the access to the hulls of platforms P-66 to P-70 and the achievement of the 2017-2021 Business and Management Plan production targets. These debts were recognized in 2016 within other expenses, net in the amount of US$ 234.

Along with those agreements signed in the last quarter of 2016, the Company assessed investments carried out for the construction of the P-71, P-72 and P-73 hulls to determine the best option for their allocation. As a result, the amount of US$ 146 were written-off and accounted for as other expenses, net.

The negotiations with Ecovix in the last quarter of 2016 also resulted in a transfer of the right of use of Rio Grande shipyard from Ecovix to the Company pursuant to a finance lease agreement. The Company reassessed the recoverable amount of this right of use and related improvements totaling US$ 155 and, as a consequence, these assets were written-off.

Negotiations with Enseada

With the escrow accounts, the Company eliminated any risk of non-delivery of the P-74 to P-77 hulls. In 2016, PNBV transferred funds in advance amounting to US$ 237 for the payment in the name of Enseada of certain liabilities relating to the hull construction of these platforms. Due to financial difficulties faced by this supplier, the Company recognized a provision for impairment on this entire amount within other expenses, net.

In addition, as part of the Company’s strategy of ensuring the continuity of FPSOs P-75 and P-77 hulls construction, the Company approved the transfer of the contract entered into by Enseada and COSCO (Dalian) Shipyard Co., Ltd to its wholly-owned subsidiary Petrobras Netherlands B.V. (PNBV), resulting in the recognition of payables within the scope of this contract. As a result, the Company recognized a provision in the amount of US$ 103 within other expenses in the third quarter of 2016.

In addition, the Company also assessed the recoverable amount of improvements made for the hulls conversion of FPSOs P-74 to P-77 in the Inhaúma Shipyard, as well as the right of use of this shipyard. Accordingly, the Company did not accounted for any additional write-off related to these assets at December 31, 2016 based on the use of this location as a logistic center mainly dedicated to Santos Basin operations.

 

The exploration and evaluation activities include the search for oil and gas reserves from obtaining the legal rights to explore a specific area to the declaration of the technical and commercial viability of the reserves.

Changes in the balances of capitalized costs directly associated with exploratory wells pending determination of proved reserves and the balance of amounts paid for obtaining rights and concessions for exploration of oil and natural gas (capitalized acquisition costs) are set out in the following table:

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Exploration costs recognized in the statement of income and cash used in oil and gas exploration and evaluation activities are set out in the following table:

 

 

The following tables set out the amounts of exploratory well costs that have been capitalized for a period of one year or more after the completion of drilling, the number of projects whose costs have been capitalized for a period greater than one year, and an aging of those amounts by year (including the number of wells relating to those costs):

 

 

 

 

 

Exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling amount to US$ 4,327. Those costs relate to 57 projects comprising (i) US$ 4,094 for wells in areas in which there has been ongoing drilling or firmly planned drilling activities in the near term and for which an evaluation plan (“Plano de Avaliação”) has been submitted for approval by ANP; and (ii) US$ 233 relate to costs incurred to evaluate the reserves and their potential development.

 

 

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The Company obtains funding through debt financing for capital expenditures to develop crude oil and natural gas producing properties, construct vessels and pipelines, construct and expand industrial plants, among other uses.

The Company has covenants that were not in default at December, 31 2016 in its loan agreements and notes issued in the capital markets requiring, among other obligations, the presentation of interim financial statements within 90 days of the end of each quarter (not reviewed by Independent Registered Public Accounting Firm) and audited financial statements within 120 days of the end of each fiscal year. Non-compliance with these obligations do not represent immediate events of default and the grace period in which the Company has to deliver these financial statements ranges from 30 to 60 days, depending on the agreement. The Company also has covenants with respect to debt level in some of its loan agreements with the Brazilian Development Bank (Banco Nacional de Desenvolvimento - BNDES).

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A roll-forward schedule of non-current debt is set out as follows:

 

 

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The fair value of the Company's finance debts is mainly determined and categorized into a fair value hierarchy as follows:

Level 1- quoted prices in active markets for identical liabilities, when applicable, amounting to US$ 46,510 as of December 31, 2016 (US$ 42,929 as of December 31, 2015); and

Level 2 –discounted cash flows based on discount rate determined by interpolating spot rates considering financing debts indexes proxies, taking into account their currencies and also the Petrobras’ credit risk, amounting to US$ 72,258 as of December 31, 2016 (US$ 66,239 as of December 31, 2015). The fair value of finance debts categorized into level 2 were previously determined using a discounted cash flow based on a theoretical curve derived from the yield curve of the Company's most liquid bonds.

The sensitivity analysis for financial instruments subject to foreign exchange variation is set out in note 33.2.

 

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The capitalization rate used to determine the amount of borrowing costs eligible for capitalization was the weighted average of the borrowing costs applicable to the borrowings that were outstanding during the period, other than borrowings made specifically for the purpose of obtaining a qualifying asset. In 2016 the capitalization rate was 5.80% p.a. (5.03% p.a. in 2015).

 

 

Most of the Company’s debt is unsecured, but certain specific funding instruments to promote economic development are collateralized. In addition, financing agreements with China Development Bank (CDB) maturing in 2019 and 2026 are also collateralized based on future oil exports for specific buyers limited to 300 thousand barrels per day up to 2019 and 100 thousand barrels per day from 2020 to 2026. This collateral may not exceed the amount of the related debt.

The loans obtained by structured entities are collateralized based on the projects’ assets, as well as liens on receivables of the structured entities. Certain wholly-owned subsidiaries issue securities that are fully and unconditionally guaranteed by Petrobras.

The global notes issued by the Company in the capital market through its wholly-owned subsidiary Petrobras Global Finance B.V. – PGF are unsecured. However, Petrobras fully, unconditionally and irrevocably guarantees these notes, as set out in note 36.

 

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Operating leases mainly include oil and gas production units, drilling rigs and other exploration and production equipment, vessels and support vessels, helicopters, land and building leases.

 

 

As of December 31, 2016, the balance of estimated future minimum lease payments under operating leases includes US$  49,671 (US$ 60,628 as of December 31, 2015) with respect to assets under construction, for which the lease term has not commenced.

During 2016, the Company recognized expenditures of US$ 9,920 (US$ 9,898 in 2015) for operating leases installments.

 

The Company has a related-party transactions policy, which is applicable to all the Petrobras Group, in accordance with the Company’s by-laws.

This policy provides for guidance to Petrobras and its workforce while entering into related-party transactions and dealing with potential conflicts of interest on these transactions, in order to ensure the goals of the Company and align them with transparency of processes and corporate governance best practices, such as: (i) Audit Committee prior assessment of transactions between the Company and its associates, the Brazilian Federal Government (including its agencies or similar bodies and controlled entities),  as well as transactions with entities controlled by key management personnel or by their close family members; and (ii) prior approval of, at least, 2/3 of board members with respect to transactions with the Brazilian Federal Government.

The Related-Party Transactions Policy also aims to ensure an adequate and diligent decision-making process for the Company’s key management.

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The Company has engaged, and expects to continue to engage, in the ordinary course of business in numerous transactions with joint ventures, associates, pension plans, as well as with the Company’s controlling shareholder, the Brazilian federal government, which includes transactions with banks and other entities under its control, such as financing and banking, asset management and others.

The balances of significant transactions are set out in the following table:

 

 

As of December 31, 2016, the balance of receivables related to the Petroleum and Alcohol accounts was US$ 268 (US$ 219 as of December 31, 2015). Pursuant to Provisional Measure 2,181 of August 24, 2001, the Federal Government may settle this balance by using National Treasury Notes in an amount equal to the outstanding balance, or allow the Company to offset the outstanding balance against amounts payable to the Federal Government, including taxes payable, or both.

The Company has provided all the information required by the National Treasury Secretariat (Secretaria doTesouro Nacional - STN) in order to resolve disputes between the parties and conclude the settlement with the Brazilian Federal Government.

Following several negotiation attempts at the administrative level, the Company filed a lawsuit in July 2011 to collect the receivables.

On October 28, 2016, the court ruled in favor of the Company, disallowing the use of an alleged debt from the liquidated company of the group, Petrobras Comércio Internacional S.A. – Interbrás, by the Brazilian Federal Government, when offsetting the outstanding balance. However, the parties are still able to file appeals at this stage.

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The criteria for compensation of employees and officers are established based on the relevant labor legislation and the Company’s Positions, Salaries and Benefits Plan (Plano de Cargos e Salários e de Benefícios e Vantagens).

The compensation of employees (including those occupying managerial positions) and officers in the months of December 2016 and December 2015 were:

 

 

The total compensation of Petrobras’ key management personnel is set out as follows:

 

 

In 2016 the board members and executive officers of the Petrobras group received US$ 22.2 as compensation (US$  20.3 in  2015).

The compensation of the Advisory Committees to the Board of Directors is apart from the fixed compensation set for the Board members and, therefore, has not been classified under compensation of Petrobras’ key management personnel.

In 2016, the alternates of Board members, who were also members of these committees up to April 2016, received the amount of US$ 14 thousand as compensation in 2016 (US$ 17 thousand including related charges).

 

 

 

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The estimates for abandonment and dismantling of oil and natural gas producing properties are revised annually at December 31 along with the annual process of oil and gas reserves certification or whenever an indication of significant change in the assumptions used in the estimates occurs.

In 2016, the adjustment to this provision was mainly due to a higher risk-adjusted discount rate (7.42% and 6.73% for 2016 and 2015, respectively), partially offset by an increase in cost estimates mainly due to additional drilling wells and other equipments.

 

 

 

 

 

 

On July 16, 2015 Petrobras paid US$ 514 (US$ 385 in cash and US$ 129 using tax credits) to settle a definitive ruling at the administrative stage with respect to a tax deficiency notice issued by the Brazilian Federal Tax Authorities. The notice is related to the tax on financial operations (Imposto sobre operações financeiras - IOF) applied to intercompany loans made by Petrobras to foreign subsidiaries in 2008.

In addition, Joint Ordinance 1,064 (Portaria Conjunta RFB/PGFN 1.064) issued by the Brazilian Federal Tax Authorities and by the Brazilian Federal Tax Attorney General's Office, and Normative Instruction 1,576/15 (Instrução Normativa RFB 1.576/15) issued by the Brazilian Federal Tax Authorities, on August 3, 2015, provided taxpayers an option for partial relief from existing federal tax debts, through a tax amnesty program created under Law 12,996/14 – Programa de Recuperação Fiscal (REFIS). The Company elected to join the REFIS to settle the tax liabilities as follows:

a) Pay amounts due under the tax deficiency notices related to the tax on financial operations (IOF) applicable to intercompany loans made by Petrobras to its foreign subsidiaries in 2007, 2009 and 2010, and to pay amounts due related to the IOF applicable to similar intercompany loans made in other periods, for which a tax deficiency notice has not been issued (2011 and 2012), in the amount of US$ 1,049. The Company had modified its procedures with respect to the payment of the IOF applicable to transactions from 2013 and, therefore, does not expect any additional tax deficiency notices.

b) Pay the tax deficiency notices issued by the Brazilian Federal Tax Authorities related to the alleged failure to pay withholding income tax (Imposto de Renda Retido na Fonte- IRRF) on amounts Petrobras paid to its former subsidiary Petrobras International Finance Company (PifCo) with respect to crude oil and oil product imports between 1999 and 2002, 2004, 2005 and 2007 to 2012, in the amount of US$ 800.

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c) Penalties for noncompliance with customs clearance procedures on crude oil and oil product imports from 2008 to 2013, in the amount of US$ 13; and

d) Indexation charges related to REFIS balance of US$ 9 recognized in the last quarter of 2015.

The Company has agreed to pay those federal tax liabilities in 30 monthly installments, which are updated by the Selic interest rate, following an immediate down payment of 20% of the total amount due (after the discounts provided under the REFIS) and using tax credits (tax loss carryforwards) to pay for interest and penalties.

As a result, the Company recognized a total charge of US$ 2,334 in 2015, of which US$ 1,566 was recognized as other taxes expenses and US$ 768 as finance expenses, of which the Company has already settled a total amount of US$ 1,833: US$ 971 was paid in cash, US$ 509 by using tax credits and US$ 353 by using judicial deposits. The remaining amount was settled in January 2017.

In 2016, the Company elected to settle taxes in cash through an amnesty settlement programs administered by the State of São Paulo pursuant to the Decree No. 61,625/2015 and Decree No. 61,788/2016, as well as Complementary Law 333/2016 enacted by the State of Pernambuco. In 2015, the Company decided to benefit from tax amnesty programs relating to the states of Rio de Janeiro, Espirito Santo, Bahia, Pará and the Brazil Federal District.

In 2016 the Company charged to income US$ 44 (US$ 370 in 2015), of which US$ 34 (US$314 in 2015) was recognized as other taxes and US$ 8 (US$ 56 in 2015) as finance expense within Statement of Income.

On October 30, 2015, Petrobras joined the PRORELIT, established by Law No. 13,202 / 15 (Measure Conversion Act No. 685/15) paying US$ 17, US$ 5 in cash and US$ 12 in tax credits debts and customs fines against the Company from 2014 and 2015 and to tax penalties for improper deduction of tax bases in 2003 and 2004. In 2015 the Company charged to income US$ 17, of which US$ 7 was recognized in other taxes expenses and US$ 10 in finance expenses in the Statement of Income.

 

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On December 30, 2015, the state of Rio de Janeiro enacted two laws that increased the tax burden on the oil industry from March 2016, as follows:

The Company believes that the taxation established by both laws is not legally justifiable, and therefore, the Company has supported the Brazilian Association of Companies for the Exploration and Production of Oil and Gas (ABEP - Associação Brasileira de Empresas de Exploração e Produção de Petróleo e Gás), which has filed complaints challenging the constitutionality of such laws before the Brazilian Supreme Court.

The Brazilian Federal Attorney has expressed favorable opinions regarding the basis of the ABEP complaints and the granting of judicial injunctions in favor of the oil and gas industry, to avoid the associated tax burden imposed on it.

As the Brazilian Supreme Court has not ruled on the ABEP request for formal injunctions, the Company filed individual complaints before the State Court of Rio de Janeiro challenging both laws and, as a result, judicial injunctions were granted in favor of the Company in December 2016 and this tax burden has been suspended.

 

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Income taxes in Brazil comprise corporate income tax (IRPJ) and social contribution on net income (CSLL). Brazilian statutory corporate tax rates are 25% and 9%, respectively.

 

 

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Deferred tax assets were recognized based on projections of taxable profit in future periods supported by the Company’s 2017-2021 Business and Management Plan (BMP). The main goals and objectives outlined in its business plan include business restructuring, a divestment plan, demobilization of assets and reducing operating expenses.

Management considers that the deferred tax assets will be realized to the extent the deferred tax liabilities are reserved and expected taxable events occur, based on its 2017-2021 BMP.

The estimated schedule of recovery/reversal of net deferred tax assets (liabilities) recoverable (payable) as of December 31, 2016 is set out in the following table:

 

 

At December 31, 2016, the Company had tax loss carryforwards arising from offshore subsidiaries, for which no deferred tax assets had been recognized. These tax losses totaling US$ 2,532 (US$ 2,437 as of December 31, 2015) arose mainly from oil and gas exploration and production and refining activities in the United States of US$ 2,276 (US$ 2,002 as of December 31, 2015), as well as activities in Spain in the amount of US$ 256 (US$ 435 as of December 31, 2015).

An aging of the unrecognized tax carryforwards, from companies abroad, classified by lapse of the applicable statute of limitations is set out below:

 

 

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The following table provides the reconciliation of Brazilian statutory tax rate to the Company’s effective rate on income before income taxes:

 

 

 

 

 

 

The Company’s post-retirement plans are managed by Fundação Petrobras de Seguridade Social (Petros), which was established by Petrobras as a nonprofit legal entity governed by private law with administrative and financial autonomy.

The Petros Plan was established by Petrobras in July 1970 as a defined-benefit pension plan and currently provides post-retirement benefits for employees of Petrobras and Petrobras Distribuidora S.A., in order to complement government social security benefits. The Petros Plan has been closed to new participants since September 2002.

Petros performs an annual actuarial review of its costs using the capitalization method for most benefits. The employers (sponsors) make regular contributions in amounts equal to the contributions of the participants (active employees, assisted employees and retired employees), on a parity basis.

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On July 31, 2016, Petros Plan announced a deficit in the amount of US$ 6,934. The deficit exceeds by US$ 4,909 the ceiling amount of US$ 2,025 as established in the Resolution 22/2015 enacted by the Post-Retirement Benefit Federal Council - CNPC, which outlines the terms of equating plans. Accordingly, participants of the plan and their employers (sponsors) would be called to cover this deficit based on their respective proportions of regular contributions and in accordance with an equation plan guideline in a period totaling 1.5 times the duration of the liabilities under the plan, which is estimated to be 18 years.

Pursuant to the aforementioned rule, Petros should have developed and approved by December 31, 2016, an equating plan to be implemented within 60 calendar days following the Executive Council approval. However, due to managerial and technical reasons, the Pension Plan requested a Conduct Adjustment Declaration (TAC) before Superintendency of Post-retirement Benefits – PREVIC, in order to postpone the implementation of its equating plan for 2015 within approximately 210 calendar days after the TAC approval. Therefore, the Company, as sponsor of this pension plan, expects to make additional contributions only after the term established in the TAC.

As of December 31, 2016, the balance of the Terms of Financial Commitment (TFC), signed by Petrobras and Petros in 2008 is US$ 3,630. The TCF is a financial commitment agreement to cover obligations under the pension plan, which amounts are due in 20 years, with 6% p.a. semiannual coupon payments based on the updated balance. The Company has provided crude oil and oil products pledged as security for the TFC totaling US$ 1,979 which are being reviewed.

The employers' expected contributions to the plan for 2017 are US$ 191 and interest payments on TCF US$ 221.

The average duration of the actuarial liability related to the plan, as of December 31, 2016, is 11.42 years (10.06 years as of December 31, 2015).

Petros 2 Plan was established in July 2007 by Petrobras and certain subsidiaries as a variable contribution plan recognizing past service costs for contributions for the period from August 2002 to August 29, 2007. The Petros 2 Plan currently provides post-retirement benefits for employees of Petrobras, Petrobras Distribuidora S.A., Stratura Asfaltos, Termobahia, Termomacaé, Transportadora Brasileira Gasoduto Brasil-Bolívia S.A. – TBG, Petrobras Transporte S.A. – Transpetro and Petrobras Biocombustível and e Araucária Nitrogenados. The plan is open to new participants although there will no longer be payments relating to past service costs.

Certain elements of the Petros 2 Plan have defined benefit characteristics, primarily the coverage of disability and death risks and the guarantee of minimum defined benefit and lifetime income. These actuarial commitments are treated as defined benefit components of the plan and are accounted for by applying the projected unit credit method. Contributions paid for actuarial commitments that have defined contribution characteristics are accrued monthly in the statement of income and are intended to constitute a reserve for programmed retirement. The contributions for the portion of the plan with defined contribution characteristics were US$ 267 in 2016.

The defined benefit portion of the contributions was suspended from July 1, 2012 to June 30, 2017, as determined by the Executive Council of Petros, based on advice of the actuarial consultants from Petros. Therefore, the entire contributions are being applied to the individual accounts of plan participants.

For 2017 the employers' expected contributions to the defined contribution portion of the plan are US$ 262.

The average duration of the actuarial liability related to the plan, as of December 31, 2016 is 43.20 years (29.58 years as of December 31, 2015).

The Company also sponsors other pension and health care plans of certain of its Brazilian and international subsidiaries. Most of these plans are unfunded and their assets are held in trusts, foundations or similar entities governed by local regulations.

Following the disposals of Petrobras Argentina and Nansei Sekiyu, the Company is not a sponsor of their pension and health care plans at December 31, 2016. In addition, the Company’s Board of Directors approved the disposal of its interest in the subsidiary Liquigás and, accordingly, the related actuarial liabilities were reclassified as held for sale. Further information on these divestments is presented in note 10.1.

Pension plans assets follow a long term investment strategy based on the risks assessed for each different class of assets and provide for diversification, in order to lower portfolio risk. The portfolio profile must comply with the Brazilian National Monetary Council (Conselho Monetário Nacional – CMN) regulations.

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Petros establishes investment policies for 5-year periods, reviewed annually. Petros uses an asset liability management model (ALM) to address net cash flow mismatches of the benefit plans, based on liquidity and solvency parameters, simulating a 30-year period.

Portfolio allocation limits for the period between 2017 and 2021 for the Petros Plan of the Petrobras Group are 40% to 75% in fixed-income securities, 10% to 35% in variable-income securities, 4% to 8% in real estate, 2% to 8% in loans to participants, as well as 0% to 7% in structured finance projects. Allocation limits for Petros 2 Plan for the same period are: 60% to 100% in fixed-income securities, 0% to 20% in variable-income securities, 0% to 5% in real estate, 2% to 8% in loans to participants, 0% to 4% in structured finance projects and 0% to 2% in investments abroad.

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The pension plan assets by type of asset are set out as follows:

 

 

As of December 31, 2016, the investment portfolio included Petrobras’ common and preferred shares in the amount of US$ 11 and US$ 45, respectively, and real estate properties leased by the Company in the amount of US$ 457.

Loans to participants are measured at amortized cost, which is considered to be an appropriate estimate of fair value.

Petrobras, Petrobras Distribuidora S.A., Petrobras Transporte S.A. – Transpetro, Petrobras Biocombustível and Transportadora Brasileira Gasoduto Brasil-Bolívia - TBG operate a medical benefit plan for their employees in Brazil (active and retired) and their dependents: the AMS health care plan. The plan is managed by the Company based on a self-supporting benefit assumption and includes health prevention and health care programs. The plan is mainly exposed to the risk of an increase in medical costs due to new technologies, new types of coverage and to a higher level of usage of medical benefits. The Company continuously improves the quality of its technical and administrative processes, as well as the health programs offered to beneficiaries in order to hedge such risks.

The employees make fixed monthly contributions to cover high-risk procedures and variable contributions for a portion of the cost of the other procedures, both based on the contribution tables of the plan, which are determined based on certain parameters, such as salary and age levels. The plan also includes assistance towards the purchase of certain medicines in registered drugstores throughout Brazil. There are no health care plan assets. Benefits are paid and recognized by the Company based on the costs incurred by the participants.

The average duration of the actuarial liability related to this health care plan, as of December 31, 2016, is 22.04 years (21,54 as of December 31, 2015).

Aggregate information is presented for other plans, whose total assets and liabilities are not material.

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The effect of a 100 basis points (bps) change in the assumed discount rate and medical cost trend rate is as set out below:

 

 

 

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Petrobras, through its subsidiaries in Brazil and abroad, also sponsors other defined contribution pension plans for employees. Contributions paid of US$ 5 in 2016 were recognized in the statement of income.

 

From January  2014 to December 31, 2016 the Company implemented voluntary separation incentive plans (PIDV) as described below:

Accordingly, 13,162 voluntary separations of employees who enrolled in these plans were made.

As of December 31, 2016 changes in the provision are set out as follows:

 

 

As of December 31, 2016 subscribed and fully paid share capital was US$ 107,380 and share issuance costs were US$ 279, represented by 7,442,454,142 outstanding common shares and 5,602,042,788 outstanding preferred shares, all of which are registered, book-entry shares with no par value.

Preferred shares have priority on returns of capital, do not grant any voting rights and are non-convertible into common shares.

Includes any transaction costs directly attributable to the issue of new shares, net of taxes.

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Includes any excess of amounts paid/received over the carrying value of the interest acquired/disposed. Changes in ownership interest in subsidiaries that do not result in loss of control of the subsidiary are equity transactions. Information on interest in subsidiaries is set out in note 11.

Represents 5% of the net income for the year, calculated pursuant to article 193 of the Brazilian Corporation Law.

Appropriated by applying a minimum of 0.5% of the year-end share capital and is retained to fund technology research and development programs. The balance of this reserve may not exceed 5% of the share capital, pursuant to article 55 of the Company’s bylaws.

Government grants are recognized in the statement of income and are appropriated from retained earnings to the tax incentive reserve in the shareholders’ equity pursuant to article 195-A of Brazilian Corporation Law. This reserve may only be used to offset losses or increase share capital.

The effect of the tax incentives in the north and northeast regions of Brazil from Superintendência de Desenvolvimento do Nordeste (SUDENE) and Superintendência de Desenvolvimento da Amazônia (SUDAM) were not allocated to the tax incentives reserve. However, the impact of tax incentives will be allocated to the tax incentives reserve in future periods, pursuant to Chapter I of Law 12,973/14.

The accumulated amount of tax incentives derived from the statements of income for the years 2014, 2015 and 2016, to be allocated to the tax incentives reserve in upcoming periods, is US$ 31 (US$ 16 for 2016, US$ 7.5 for 2015 and US$ 7.5 for 2014).

Includes funds intended for capital expenditures, primarily in oil and gas exploration and development activities, as per the capital budget of the Company, pursuant to article 196 of the Brazilian Corporation Law.

The accumulated deficit balance of US$ 4,838 as of December 31, 2016 will be allocated to the profit retention reserve.

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In 2016 the Company principally recognized as other comprehensive income the following effects:

Shareholders are entitled to receive minimum mandatory dividends (and/or interest on capital) of 25% of the adjusted net income for the year proportional to the number of common and preferred shares, pursuant to Brazilian Corporation Law. To the extent the Company proposes dividend distributions, preferred shares have priority in dividend distribution, which is based on the highest of 3% of the preferred shares’ net book value, or 5% of the preferred share capital. Preferred shares participate under the same terms as common shares in capital increases resulting from the capitalization of profit reserves or retained earnings.

Due to the loss recorded in 2016 and 2015, the Board of Directors did not propose dividend distributions for those years.

 

 

Basic earnings per share are calculated by dividing the net income (loss) attributable to shareholders of Petrobras by the weighted average number of outstanding shares during the period.

Diluted earnings (losses) per share are calculated by adjusting the net income (loss) attributable to shareholders of Petrobras and the weighted average number of outstanding shares during the period taking into account the effects of all dilutive potential shares (equity instrument or contractual arrangements that are convertible into shares).

Basic and diluted earnings (losses) represent the amount as the Company has no potential share in issue.

 

 

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In 2016, sales from transactions with two customers reached approximately 10 % or more of the Company’s sales revenue, totaling US$ 8,640 (US$ 9,793 in 2015 and US$ 14,171 in 2014) and US$ 7,691 (US$ 8,146 in 2015 and US$ 11,937 in 2014). These sales revenues mainly impacted the Refining, Transportation and Marketing (RT&M) business segment.

 

 

 

 

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The Extraordinary General Meeting held on April 28, 2016 approved adjustments to the Company’s organization structure and governance and management model, aiming to align the organization with the new conditions faced by the oil and gas industry and to prioritize profitability and capital discipline.

The current business segment information is reported in the manner in which the Company’s senior management assesses business performances and makes decisions regarding investments and resource allocation.

 

 

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The Company recognizes provisions based on the best estimate of the costs of proceedings for which it is probable that an outflow of resources embodying economic benefits will be required and that can be reliably estimated. These proceedings mainly include:

Provisions for legal proceedings are set out as follows:

 

 

 

 

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Judicial deposits made in connection with legal proceedings are set out in the table below according to the nature of the corresponding lawsuits:

 

 

Contingent liabilities for which either the Company is unable to make a reliable estimate of the expected financial effect that might result from resolution of the proceeding, or a cash outflow is not probable, are not recognized as liabilities in the financial statements but are disclosed in the notes to the financial statements, unless the likelihood of any outflow of resources embodying economic benefits is considered remote.

The estimated contingent liabilities for legal proceedings as of December 31, 2016, for which the possibility of loss is not considered remote, are set out in the following table:

 

 

A brief description of the nature of the main contingent liabilities (tax, civil, environmental and labor) is set out in the following table:

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Between December 8, 2014 and January 7, 2015, five putative securities class action complaints were filed against the Company in the United States District Court for the Southern District of New York (SDNY). These actions were consolidated on February 17, 2015 (the “Consolidated Securities Class Action”). The Court appointed a lead plaintiff, Universities Superannuation Scheme Limited (“USS”), on March 4, 2015. Together with two other plaintiffs—Union Asset Management Holding AG (“Union”) and Employees' Retirement System of the State of Hawaii (“Hawaii”)—USS filed a consolidated amended complaint (“CAC”) on March 27, 2015 that purported to be on behalf of investors who:

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

On April 17, 2015, Petrobras, Petrobras Global Finance - PGF and the underwriters of notes issued by PGF (the “Underwriter Defendants”) filed a motion to dismiss the CAC.

On July 9, 2015, the judge presiding over the Consolidated Securities Class Action ruled on the motion to dismiss, partially granting the Company’s motion. Among other decisions, the judge dismissed claims relating to certain debt securities issued in 2012 under the Securities Act of 1933 as time barred by the Securities Act’s statute of repose, and ruled claims relating to securities purchased on the Brazilian stock exchange must be arbitrated, as established in the Company’s bylaws. The judge rejected other arguments presented in the motion to dismiss the CAC and, as a result, the Consolidated Securities Class Action continued with respect to those other claims.

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As allowed by the judge, a second consolidated amended complaint was filed on July 16, 2015, a third consolidated amended complaint (“TAC”) was filed on September 1, 2015, among other things extending the Class Period through July 28, 2015 and adding Petrobras America, Inc. as a defendant, and a fourth consolidated amended complaint (“FAC”) was filed on November 30, 2015. The TAC and FAC, brought by lead plaintiff, Union, Hawaii, and an additional plaintiff, North Carolina Department of State Treasurer (“North Carolina”) (collectively, “class plaintiffs”)—brings those claims alleged in the CAC that were not dismissed or were allowed to be re-pleaded under the judge’s July 9, 2015 ruling.

Petrobras, PGF, Petrobras America, Inc. and the Underwriter Defendants filed motions to dismiss the TAC on October 1, 2015 and the FAC on December 7, 2015.

On December 20, 2015, the judge ruled on the motions to dismiss, partially granting the motions. Among other decisions, the judge dismissed the claims of USS and Union based on their purchases of notes issued by PGF for failure to plead that they purchased the notes in U.S. transactions. The judge also dismissed claims under the Securities Act of 1933 for certain purchases for which class plaintiffs had failed to plead the element of reliance. The judge rejected other arguments presented in the motion to dismiss the FAC and, as a result, the Consolidated Securities Class Action continued with respect to the remaining claims.

On October 15, 2015, class plaintiffs filed a motion for class certification in the Consolidated Securities Class Action, and on November 6, 2015, Petrobras, PGF, Petrobras America, Inc. and the Underwriter Defendants opposed the motion. On February 2, 2016, the judge granted plaintiffs’ motion for class certification, certifying a Securities Act Class represented by Hawaii and North Carolina and an Exchange Act Class represented by USS. On June 15, 2016, the United States Court of Appeals for the Second Circuit (“Second Circuit”) granted Petrobras’s motion requesting interlocutory appellate review of the class certification decision. The parties completed briefing the appeal on September 8, 2016. Petrobras and the other defendants moved in district court for a stay of all district court proceedings pending the Second Circuit’s decision on the merits of the appeal of the class certification, which the district judge denied on June 24, 2016. Defendants then moved in the Second Circuit for a stay of all district court proceedings pending a decision on the appeal of the class certification decision. On August 2, 2016, the Second Circuit granted Defendants’ motion and stayed all district court proceedings. Oral argument regarding the appeal was held before the Second Circuit on November 2, 2016.

On June 27, 2016, the parties filed motions for summary judgment. Further summary judgment briefing is stayed pursuant to the Second Circuit’s August 2, 2016 decision.

In addition to the Consolidated Securities Class Action, to date, 33 lawsuits have been filed by individual investors before the same judge in the SDNY (six of which have been stayed), and one has been filed in the United States District Court for the Eastern District of Pennsylvania (collectively, the “Opt-out Claims”), consisting of allegations similar to those in the Consolidated Securities Class Action. On August 21, 2015, Petrobras, PGF and underwriters of notes issued by PGF filed a motion to dismiss certain of the Opt-out Claims in the SDNY, and on October 15, 2015, the judge ruled on the motion to dismiss, partially granting the motion. Among other decisions, the judge dismissed several Exchange Act, Securities Act and state law claims as barred by the relevant statutes of repose. The judge denied other portions of the motion to dismiss and, as a result, these actions continued with respect to other claims brought by these plaintiffs.

In the action in the Eastern District of Pennsylvania, Petrobras and PGF filed a motion to dismiss on May 13, 2016, and the district judge denied the motion on November 1, 2016, allowing the action to continue. On January 26, 2017, the district judge set a schedule for discovery and dispositive motions, with a pre-trial conference scheduled for January 5, 2018.

On October 31, 2015, the SDNY judge ordered that the Opt-out Claims before him in the SDNY and the Consolidated Securities Class Action be tried together in a single trial not to exceed a total of eight weeks. On November 5, 2015, the judge scheduled the trial to begin on September 19, 2016; however, the trial is now stayed due to the stay imposed by the Second Circuit decision on August 2, 2016.

On November 18, 2015, the judge ordered that any Opt-out Claim filed before him in the SDNY after December 31, 2015 will be stayed in all respects until after the completion of the trial.

On October 21, 2016, Petrobras’ board of directors approved agreements to settle Opt-out Claims in four cases: Dodge & Cox Int’l Stock Fund, et al. v. Petróleo Brasileiro S.A. – Petrobras, et al., No. 15-cv-10111 (JSR), Janus Overseas Fund, et al. v. Petróleo Brasileiro S.A. – Petrobras, et al., No. 15-cv-10086 (JSR),PIMCO Funds: PIMCO Total Return Fund, et al. v. Petróleo Brasileiro S.A. – Petrobras, et al., No. 15-cv-08192 (JSR) and Al Shams Investments Ltd., et al. v. Petróleo Brasileiro S.A. – Petrobras, et al., No. 15-cv-6243 (JSR).  The terms of the settlements are confidential.

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On November 23, 2016, Petrobras’ board of directors approved agreements to settle Opt-out Claims in eleven cases:  Ohio Public Employees Retirement System v. Petróleo Brasileiro S.A. – Petrobras et al., No. 15-cv-03887 (JSR); Abbey Life Assurance Company Limited, et al. v. Petróleo Brasileiro S.A., et al., No. 15-cv-6661 (JSR); Aberdeen Emerging Markets Fund, et al. v. Petróleo Brasileiro S.A. – Petrobras, et al., No. 15-cv-3860 (JSR); Aberdeen Latin American Income Fund Limited, et al. v. Petróleo Brasileiro S.A. – Petrobras, et al., No. 15-cv-4043 (JSR); Delaware Enhanced Global Dividend and Income Fund, et al. v. Petróleo Brasileiro S.A. – Petrobras, et al., No. 15-cv-4043 (JSR); Dimensional Emerging Markets Fund, et al. v. Petróleo Brasileiro S.A. – Petrobras, et al., No. 15-cv-02165 (JSR); Manning & Napier Advisors, LLC, et al. v. Petróleo Brasileiro S.A. – Petrobras, No. 15-cv-10159 (JSR); Russell Investment Company, et al. v. Petróleo Brasileiro S.A. – Petrobras, No. 15-cv-07605 (JSR); Skagen, et al. v. Petróleo Brasileiro S.A. – Petrobras, et al., No.15-cv-2214 (JSR); State of Alaska Department of Revenue, Treasury Division, et al. v. Petróleo Brasileiro S.A. – Petrobras, No. 15-cv-8995 (JSR), and State Street Cayman Trust Co., Ltd., v. Petróleo Brasileiro S.A. – Petrobras, No. 15-cv-10158 (JSR).

On February 24, 2017, Petrobras’ board of directors approved agreements to settle Opt-out Claims in four cases:  New York City Employees Retirement System, et al.  v. Petróleo Brasileiro S.A. – Petrobras et al., No. 15-cv-2192 (JSR),  Transamerica Income Shares, Inc., et al v. Petróleo Brasileiro S.A. - Petrobras, et al., No. 15-cv-3733 (JSR), Internationale Kapitalanlagegesellschaft mbH v. Petróleo Brasileiro S.A. - Petrobras, et al., No. 15-cv-6618 (JSR) Lord Abbett Investment Trust – Lord Abbett Short Duration Income Fund, et al v. Petróleo Brasileiro S.A. - Petrobras, et al., No. 15-cv-7615 (JSR).  

Based on the settlements reached, and the status of certain other Opt-out Claims, the Company charged to statement of income the amount of US$ 372 in 2016. The terms of the settlements are confidential and Petrobras denies all allegations of wrongdoing and continues to defend itself vigorously in all pending actions. The settlements, the terms of which are confidential, are aimed at eliminating the uncertainties, burdens and expense of ongoing litigation.

The Consolidated Securities Class Action and certain Opt-out Claims involve highly complex issues that are subject to substantial uncertainties and depend on a number of factors such as the novelty of the legal theories, the information produced in discovery, the timing of court decisions, rulings by the court on key issues, analysis by retained experts, and the possibility that the parties negotiate in good faith toward a resolution.

In addition, the claims asserted are broad, span a multi-year period and involve a wide range of activities, and the contentions of the plaintiffs in the Consolidated Securities Class Action and certain Opt-out Claims concerning the amount of alleged damages are varied and, at this stage, their impact on the course of the litigation is complex and uncertain. The uncertainties inherent in all such matters affect the amount and timing of the ultimate resolution of these actions. As a result, the Company is unable to make a reliable estimate of eventual loss arising from the Consolidated Securities Class Action and certain Opt-out Claims.

Depending on the outcome of the litigation, we may be required to pay substantial amounts, which could have a material adverse effect on the Company’s financial condition, its consolidated results of operations or its consolidated cash flows for an individual reporting period.

The Company has engaged a U.S. firm as legal counsel and intends to defend these actions vigorously.

The Company filed civil lawsuits against the Federal Government claiming to recover PIS and COFINS paid over finance income and foreign exchange variation gains, claiming that paragraph 1 of article 3 of Law No. 9,718/98 is unconstitutional, comprising:

i) PIS: from February 1999 to November 2002; and

ii) COFINS: from February 1999 to January 2004.

Up to the year 2014, the court granted to the Company the definitive right to recover those taxes. Currently, these legal proceedings are in their court-ordered liquidation stage.

As of December 31, 2016, the Company had non-current receivables of US$ 980 (US$758 as of December 31, 2015) related to PIS and COFINS, which are indexed to inflation.

 

As of December 31, 2016, the total amount of the GSA agreement (Gas Supply Agreement ), entered into by Petrobras and Yacimentos Petroliferos Fiscales Bolivianos – YPFB, for the 2017 to 2019 period is approximately 32.94 billion cubic meters (m³) of natural gas (equivalent to 30.08 million cubic meters (m³) per day) and corresponds to a total estimated value of US$ 4.68 billion.

 

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The Company has granted collateral to the Brazilian Agency of Petroleum, Natural Gas and Biofuels (Agência Nacional de Petróleo, Gás Natural e Biocombustíveis -ANP) in connection with the performance of the Minimum Exploration Programs established in the concession agreements for petroleum exploration areas in the total amount of US$ 2,444 of which US$ 991 were still in force as of December 31, 2016, net of commitments undertaken. The collateral comprises crude oil from previously identified producing fields, pledged as collateral, amounting to US$ 797 and bank guarantees of US$ 194.

 

The Company is exposed to a variety of risks arising from its operations, including price risk (related to crude oil and oil products prices), foreign exchange rates risk, interest rates risk, credit risk and liquidity risk. Corporate risk management is part of the Company’s commitment to act ethically and comply with the legal and regulatory requirements of the countries where it operates. To manage market and financial risks the Company prefers structuring measures through adequate capital and leverage management. The Company takes account of risks in its business decisions and manages any such risk in an integrated manner in order to enjoy the benefits of diversification.

A summary of the positions of the derivative financial instruments held by the Company and recognized in other current assets and liabilities as of December 31, 2016, as well as the amounts recognized in the statement of income and other comprehensive income and the guarantees given is set out as follows:

 

 

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A sensitivity analysis of the derivative financial instruments for the different types of market risks as of December 31, 2016 is set out following:

 

 

Petrobras does not regularly use derivative instruments to hedge exposures to commodity price cycles related to products purchased and sold to fulfill operational needs. Derivatives are used as hedging instruments to manage the price risk of certain short-term commercial transactions.

The Company’s Risk Management Policy provides for, as an assumption, an integrated risk management extensive to the whole corporation, pursuing the benefit from the diversification of its businesses.

By managing its foreign exchange risk, the Company takes into account the group of cash flows derived from its operations. This concept is especially applicable to the risk relating to the exposure of the Brazilian Real against the U.S. dollar, in which future cash flows in U.S. dollar, as well as cash flows in Brazilian Real affected by the fluctuation between both currencies, such as cash flows derived from diesel and gasoline sales in the domestic market, are assessed in an integrated manner.

Accordingly, the financial risk management mainly involves structured actions by using natural hedges derived from the business of the Company.      

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The foreign exchange risk management strategy may involve the use of derivative financial instruments to hedge certain liabilities, minimizing foreign exchange rate risk exposure, especially when the Company is exposed to a foreign currency in which no cash inflows are expected, for example, Pound Sterling.

In the short-term, the foreign exchange risk is managed by applying resources in cash or cash equivalent denominated in Brazilian Real, U.S. Dollar or in another currency.    

Considering the natural hedge aforementioned, the Company designates hedging relationships to account for the effects of the existing hedge between a portion of its long-term debt obligations (denominated in U.S. dollars) and its highly probable U.S. dollar denominated future export revenues, so that gains or losses associated with the hedged transaction (the highly probable future exports) and the hedging instrument (debt obligations) are recognized in the statement of income in the same periods.

A portion of principal amounts and accrued interest (non-derivative financial instruments), as well as foreign exchange rate forward contracts (derivative financial instruments) have been designated as hedging instruments. Derivative financial instruments expired during the year were replaced by principal and interest amounts in the hedging relationships for which they had been designated.

Individual hedging relationships were designated in a one-to-one proportion, meaning that a portion of the highly probable future exports for each month will be the hedged transaction of an individual hedging relationship, hedged by a portion of the company’s long-term debt. Only a portion of the Company’s forecast exports are considered highly probable.

Whenever a portion of future exports for a certain period for which a hedging relationship has been designated is no longer highly probable, the Company revokes the designation and the cumulative foreign exchange gains or losses that have been recognized in other comprehensive income remain separately in equity until the forecast exports occur.

If a portion of future exports for which a hedging relationship has been designated is no longer expected to occur, any related cumulative foreign exchange gains or losses that have been recognized in other comprehensive income from the date the hedging relationship was designated to the date the Company revoked the designation is immediately recycled from equity to the statement of income.

Mainly due to the decrease in international oil prices, a portion of future exports for which a hedging relationship had been designated was no longer expected to occur or did not occur in 2016. Therefore, a hedging relationship was revoked and a portion was reclassified to the statement of income in the amount of US$ 299 in 2016.

The carrying amounts, the fair value as of December 31, 2016, and a schedule of expected reclassifications to the statement of income of cumulative losses recognized in other comprehensive income (shareholders’ equity) based on a US$ 1.00 / R$ 3,2591 exchange rate are set out below:

 

 

 

 

 

The ratio of highly probable future exports to debt instruments for which a hedging relationship has been designated in future periods is set out below:

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A roll-forward schedule of cumulative foreign exchange losses recognized in other comprehensive income as of December 31, 2016 is set out below:

 

 

 

Additional hedging relationships may be revoked or additional reclassification adjustments from equity to the statement of income may occur as a result of changes in forecast export prices and export volumes following a review of the Company’s business plan. Based on a sensitivity analysis considering a US$ 10/barrel decrease in Brent prices stress scenario, when compared to the Brent price projections in our most recent update of the 2017-2021 Business and Management Plan (Plano de Negócios e Gestão – PNG), a US$ 31 reclassification adjustment from equity to the statement of income would occur.

A schedule of expected reclassification of cumulative foreign exchange losses recognized in other comprehensive income to the statement of income as of December 31, 2016 is set out below:

 

 

The Company had cross currency swap to fix in U.S. dollars for the payments related to bonds denominated in Japanese yen, which matured on September 23, 2016.The relationship between the derivative and the bonds was designated for cash flow hedge accounting.

A sensitivity analysis is set out below, showing the probable scenario for foreign exchange risk on financial instruments, computed based on external data along with stressed scenarios (a 25% and a 50% change in the foreign exchange rates), except for assets and liabilities of foreign subsidiaries, when transacted in a currency equivalent to their respective functional currencies.

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The Company considers that interest rate risk does not create a significant exposure and therefore, preferably does not use derivative financial instruments to manage interest rate risk, except for specific situations encountered by certain subsidiaries of Petrobras.

The Company’s objectives in its capital management is to achieve an adequate level of return on its capital structure in order to safeguard its ability to continue as a going concern, adding value to its shareholders and investors. Its main sources of funding have been cash provided by its operating activities, divestments, loan agreements with commercial banks and debt issuance in the international capital markets.

In line with the assumptions in the 2017-2021 Business and Management Plan, the Company does not foresee net proceeds from financing for the two year period 2017-2018. However, the Company has continually assessed options of funding following its liability management strategy, aiming at improving its debt repayment profile and achieving a lower cost of its debt along with an indebtedness level matching the capital expenditures. Currently, the average repayment term is approximately 7 years.

Net debt is calculated as total debt (short-term debt and long-term debt) less cash, cash equivalents and government bonds from Brazil, U.S.A., Germany and England, as well as time deposits with maturities higher than three months. Adjusted EBITDA is computed by using the EBITDA (net income before net finance income (expense), income taxes, depreciation, depletion and amortization) adjusted by results in equity-accounted investments, impairment of assets and reversals, cumulative foreign exchange adjustments reclassified to the income statement and gains and losses on disposal and write-offs of assets. These measures are not defined by the International Financial Reporting Standards – IFRS (non-GAAP measures) and should neither be considered in isolation or as substitutes for profit, indebtedness and cash flow provided by operating activities as defined by the IFRS, nor be compared to those measures of other companies.

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The venture and divestment program for the 2017-2018 period, with forecasted divestments of US$ 21 billion and the Net debt/Adjusted EBITDA ratio reaching 2.5 in 2018, is part of the Company's financial planning, aimed at reducing leverage, preserving cash and prioritizing capital expenditures, primarily in oil and gas production in Brazil in highly productive and profitable areas.

However, this divestment portfolio is dynamic and the occurrence of the transactions depend on business conditions, market conditions and the Company’s continuing assessment of its businesses, due to these reasons the rating conditions for assets available for sale were not fulfilled as set out in note 4.12.

Credit risk management in Petrobras aims at minimizing risk of not collecting receivables, financial deposits or collateral from third parties or financial institutions through efficient credit analysis, granting and management based on quantitative and qualitative parameters that are appropriate for each market segment in which the Company operates.

The commercial credit portfolio is broad and diversified and comprises clients from the domestic and foreign markets. Credit granted to financial institutions is related to collaterals received, cash surplus invested and derivative financial instruments. It is spread among “investment grade” international banks rated by international rating agencies and Brazilian banks.

Most of the company’s customers have no credit agency ratings. Thus, credit commissions assess creditworthiness and define credit limits, which are regularly monitored, based on the customer´s main activity, commercial relationship and credit history with Petrobras, solvency, financial situation and external market assessment of the customer.

Credit quality of cash and cash equivalents, as well as marketable securities is based on external credit ratings provided by Standard & Poor’s, Moody’s and Fitch. The credit quality of those financial assets, that are neither past due nor have been impaired, are set out below:

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Liquidity risk is represented by the possibility of a shortage of cash or other financial assets in order to settle the Company’s obligations on the agreed dates and is managed by the Company based on policies such as: centralization of cash management, optimization of the level of cash and cash equivalents held and reduction of working capital; maintenance of an adequate cash balance to ensure that cash needed for investments and short-term obligations is met even in adverse market conditions; increase in the average debt maturity, increase in funding sources from domestic and international markets, and developing a strong presence in the capital markets and also searching for new funding sources (such as new markets and financial products), as well as funds under the venture and divestment program.

In 2016, the Company used traditional funding sources (export credit agencies – ECAs, banking market, capital markets and development banks) to obtain the necessary funding to repay debt and fund its capital expenditures. The Company raised approximately US$ 18.8 billion through proceeds from long-term financing, mainly from the international capital markets. The Company used part of these funds (US$ 17.9 billion) to repurchase global notes previously issued, to settle certain debts with the Brazilian Development Bank (BNDES) in advance and also to push forward other debts.

In December 2016, the Company raised funds through financing agreements with China Development Bank CDB in the amount of US$ 5 billion, maturing in 10 years.

A maturity schedule of the Company’s finance debt (undiscounted), including face value and interest payments is set out as follows:

 

 

 

The Company’s insurance strategy involves acquiring insurance to cover risks that may produce material impacts and also to cover risks that are subject to compulsory insurance coverage (pursuant to legal or contractual requirements). The remaining risks are self-insured and Petrobras intentionally assumes the entire risk by abstaining from contracting insurance.

The Company assumes a significant portion of its risk, by entering into insurance policies that have deductible clauses up to the equivalent to US$ 180 (US$ 25 as of December 31, 2015). The higher amount related to deductible clauses was based on a reassessment of the Company’s adverse events historical data, which resulted in economic benefits through a decrease in the amount of insurance premiums.    

The Company’s risk assumptions for insurance are not part of the audit scope of the financial statements audit and therefore were not examined by the Company’s Independent Registered Public Accounting Firm.

The main information concerning the insurance coverage outstanding at December 31, 2016 is set out below:

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Petrobras does not have loss of earnings insurance or insurance related to well control, automobiles and pipeline networks in Brazil.

 

Fair values are determined based on market prices, when available, or, in the absence thereof, on the present value of expected future cash flows.

The hierarchy of the fair values of the financial assets and liabilities, recorded on a recurring basis, is set out below:

 

 

There are no material transfers between levels.

The estimated fair value for the Company’s long term debt as of December 31, 2016, computed based on the prevailing market rates is set out in note 17.1.

The fair values of cash and cash equivalents, short-term debt and other financial assets and liabilities are equivalent or do not differ significantly from their carrying amounts.

 

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Global notes issued in international capital market

 

On January 17, 2017, the Company concluded, through its wholly-owned subsidiary Petrobras Global Trading – PGF, a US$ 4 billion global notes issuance in the international market. This issuance comprises two series of notes each in the amount of US$ 2 billion, maturating in 5 and 10 years and bearing interest at the rates of 6.125% and 7.375% per annum, respectively.

The net proceeds of this issuance were entirely used to repurchase global notes previously issued by the Company through a tender offer that expired on February 8, 2017. Old notes accepted for purchase amounted to US$ 4,899 and € 632 million (US$ 676) in accordance with the tender cap.

Legal Proceeding in the Netherlands

On January 24, 2017, the Stichting Petrobras Compensation Foundation, which is not a Petrobras entity, filed a complaint before the district court in Rotterdam, in Netherlands, against the wholly-owned subsidiaries Petrobras International Braspetro B.V. and Petrobras Global Finance B.V.

This foundation represents a group of investors alleging damages from fraud and bribery schemes perpetrated by Company. These investors purchased shares or bonds issue by Company and traded outside U.S.A. before July 28, 2015.

This action is at an early stage, and the Company did not have access to the allegations and claims in this complaint.

Cross currency swap

In the first quarter of 2017, the Company, through its wholly-owned subsidiary Petrobras Global Trading B.V. (PGT), entered into a £ 700 million notional amount cross currency swap maturing in 2026, in order to hedge its Pounds/U.S. Dollar exposure arose from the Company’s debt denominated in Pounds.

Formal Notice from CVM – Hedge accounting

On March 07, 2017, the Company received from the Brazilian Securities and Exchange Commission (Comissão de Valores Mobiliários – CVM) a Formal Notice (Ofício CVM) requesting the Company to restate its Annual Financial Statements and Interim Financial Reporting filed since the second quarter of 2013. This formal notice requested the restatement of the effects of the hedge accounting policy application relating to the cash flow hedge involving the Company's future exports as described in note 33.2.  The CVM does not believe the foreign exchange losses and gains should have been deferred. The Company believes its accounting policy complies with the applicable literature. The Company filed before CVM a request to suspend the effects of this notice, which was granted by the authority’s collegiate body.

The Company appealed the CVM decision on March 17, 2017 and has taken all the measures to safeguard its interests.

 

 

Petróleo Brasileiro S.A. - Petrobras fully and unconditionally guarantees the debt securities issued by Petrobras Global Finance B.V. (PGF), a 100-percent-owned finance subsidiary of Petrobras. There are no significant restrictions on the ability of Petrobras to obtain funds from PGF.

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Supplementary information on Oil and Gas Exploration and Production (unaudited)

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

 

 

 

Supplementary information on Oil and Gas Exploration and Production (unaudited)

In accordance with Codification Topic 932 - Extractive Activities – Oil and Gas, this section provides supplemental information on oil and gas exploration and production activities of the Company. The information included in items (i) through (iii) provides historical cost information pertaining to costs incurred in exploration, property acquisition and development, capitalized costs and results of operations. The information included in items (iv) and (v) presents information on Petrobras’ estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proven reserves, and changes in estimated discounted future net cash flows.

Beginning in 1995, the Federal Government of Brazil undertook a comprehensive reform of the country’s oil and gas regulatory system. On November 9, 1995, the Brazilian Constitution was amended to authorize the Federal Government to contract with any state or privately owned company to carry out the activities related to the upstream and downstream segments of the Brazilian oil and gas sector. This amendment eliminated Petrobras’ effective monopoly. The amendment was implemented by the Oil Law, which liberated the fuel market in Brazil beginning January 1, 2002.

The Oil Law established a regulatory framework ending Petrobras’ exclusive agency and enabling competition in all aspects of the oil and gas industry in Brazil. As provided in the Oil Law, Petrobras was granted the exclusive right for a period of 27 years to exploit the petroleum reserves in all fields where the Company had previously commenced production. However, the Oil Law established a procedural framework for Petrobras to claim exclusive exploratory (and, in case of success, development) rights for a period of up to three years with respect to areas where the Company could demonstrate that it had “established prospects”. To perfect its claim to explore and develop these areas, the Company had to demonstrate that it had the requisite financial capacity to carry out these activities, alone or through financing or partnering arrangements.

The Company, on December 31, 2016, maintains activities in South America, which includes Argentina, Colombia and Bolivia; North America, which includes Mexico and the United States of America; and Turkey (others). The equity-accounted investments are comprised of the operations of Petrobras Oil and Gas B.V. (PO&G) in Africa, mainly Nigeria, as well as Venezuelan companies involved in exploration and production activities, over which the Company had significant influence until July 2016. However, the Company only estimates reserves in the United States, Nigeria and Argentina.

 

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i) Capitalized costs relating to oil and gas producing activities

The following table summarizes capitalized costs for oil and gas exploration and production activities with the related accumulated depreciation, depletion and amortization, and asset retirement obligations:

 

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ii) Costs incurred in oil and gas property acquisition, exploration and development activities

Costs incurred are summarized below and include both amounts expensed and capitalized:

(iii) Results of operations for oil and gas producing activities

The Company’s results of operations from oil and gas producing activities for the years ended December 31, 2016, 2015 and 2014 are shown in the following table. The Company transfers substantially all of its Brazilian crude oil and gas production to the Refining, Transportation & Marketing segment in Brazil. The internal transfer prices calculated by the Company’s model may not be indicative of the price the Company would have realized had this production been sold in an unregulated spot market. Additionally, the prices calculated by the Company’s model may not be indicative of the future prices to be realized by the Company. Gas prices used are those set out in contracts with third parties.

Production costs are lifting costs incurred to operate and maintain productive wells and related equipment and facilities, including operating employees’ compensation, materials, supplies, fuel consumed in operations and operating costs related to natural gas processing plants.

Exploration expenses include the costs of geological and geophysical activities and projects without economic feasibility. Depreciation and amortization expenses relate to assets employed in exploration and development activities. In accordance with Codification Topic 932 – Extractive Activities – Oil and Gas, income taxes are based on statutory tax rates, reflecting allowable deductions. Interest income and expense are excluded from the results reported in this table.

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(iii) Results of operations for oil and gas producing activities

 

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(iv) Reserve quantities information

The Company’s estimated net proved oil and gas reserves and changes thereto for the years 2016, 2015 and 2014 are shown in the following table. Proved reserves are estimated by the Company’s reservoir geoengineers in accordance with the reserve definitions prescribed by the Securities and Exchange Commission.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time.

Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is done by means not involving a well.

In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves and are named proved undeveloped reserves. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.

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A summary of the annual changes in the proved reserves of oil is as follows (in millions of barrels):

 

 

 

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A summary of the annual changes in the proved reserves of natural gas is as follows (in billions of cubic feet):

 

 

 

 

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The tables below summarize information about the changes in total proved reserves of crude oil and natural gas, in millions of barrels of oil equivalent, in our consolidated entities and non consolidated affiliate for 2016, 2015 and 2014:

 

 

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In 2016, we incorporated 103 million boe of proved reserves from extensions and discoveries in Brazil (Santos Basin), and we added 131 mmboe to our proved reserves due to revisions of previous estimates, as a result of drilling of new production development wells and better reservoir response in onshore and offshore post-salt fields, in Brazil and the USA, and as result of positive answers from the reservoirs, recovery mechanisms (water injection) and operating efficiency of production systems in operation, as well as the growing drilling activities and tie-back activities, in the pre-salt fields, in Santos and Campos Basin, both in Brazil.

We reduced 169 mmboe of our proved reserves due to sales of minerals in situ and increased 16 mmboe in our proved reserves due to purchases of minerals in situ, resulting in a net effect of a decrease of 153 mmboe in our proved reserves. The net result of these additions and disposals, excluding production, was an increase of 81 mmboe to our proved reserves in 2016. Considering a production of 925 mmboe in 2016, our decrease of proved reserves was 844 mmboe. This volume production does not take into account the production of Extended Well Tests (EWTs) in exploratory blocks in Brazil, and production in Bolivia, since the Bolivian Constitution prohibits the disclosure and registration of its reserves.

We had a total of 4,441.1 mmboe of proved undeveloped reserves company-wide at December 31, 2016, approximately 7.4% (329.1 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-deep water development projects, particularly in the Santos Basin and in the Campos Basin, in which we are making investments to develop necessary infrastructure.

In 2015, our proved reserves decreased by 2,186 mmboe due to revisions of previous estimates, mostly as result of the decrease in oil prices during fiscal year of 2015, and decreased by 22 mmboe due to sales of proved reserves. This decrease was partially offset by the incorporation of 494 mmboe of proved reserves from discoveries of new accumulations and extensions in Brazil, specifically in the Santos, Campos and Espírito Santo Basins, and in Argentina, in the Neuquina Basin, and the incorporation of 22 mmboe due to improved recovery. The net result (excluding production) was a decrease of 1,692 mmboe in our proved reserves in 2015. Considering a production of 932 mmboe in 2015, our net decrease of proved reserves was 2,625 mmboe. This volume production does not take into account the production of Extended Well Tests (EWTs) in exploratory blocks in Brazil, and production in Bolivia, since the Bolivian Constitution prohibits the disclosure and registration of its reserves.

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In 2014, 1,097 mmboe were added to our proved reserves, excluding synthetic oil and synthetic gas, while we (i) returned to the ANP eleven fields in Brazil (four with proved reserves) and (ii) we divested from fields in which we had interests in Peru, Colombia, Argentina and United States, representing aggregate proved reserves of 193 mmboe. The net result of these additions and dispositions was an increase of 904 mmboe to our proved reserves in 2014. Considering a production of 896 mmboe in 2014, our net increase of proved reserves was 8 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.

 

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(v) Standardized measure of discounted future net cash flows relating to proved oil and gas quantities and changes therein

The standardized measure of discounted future net cash flows, related to the above proved oil and gas reserves, is calculated in accordance with the requirements of Codification Topic 932 – Extractive Activities – Oil and Gas.

Estimated future cash inflows from production in Brazil are computed by applying the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indications, assuming continuation of year-end economic conditions. Estimated future income taxes (including future social contributions on net income - CSLL) are calculated by applying appropriate year-end statutory tax rates. The amounts presented as future income taxes expenses reflect allowable deductions considering statutory tax rates. Discounted future net cash flows are calculated using 10% mid-period discount factors. This discounting requires a year-by-year estimate of when the future expenditures will be incurred and when the reserves will be produced.

The valuation prescribed under Codification Topic 932 – Extractive Activities – Oil and Gas requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of Petrobras’ future cash flows or the value of its oil and gas reserves.

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

Date: March 21, 2017

PETRÓLEO BRASILEIRO S.A—PETROBRAS

 

By: /s/ Ivan de Souza Monteiro

____________________________________

Ivan de Souza Monteiro

 

Chief Financial Officer and Investor Relations Officer