UNITED STATES

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, 2018

 

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

—

December 31, 2017 and 2016

with auditor’s report

 

(A free translation of the original

in Portuguese)

 

 

 

 

 

 

 

 

 

 

 

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The Notes form an integral part of these Financial Statements.

 

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The Notes form an integral part of these Financial Statements.

 

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The Notes form an integral part of these Financial Statements.

 

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The Notes form an integral part of these Financial Statements.

 

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The Notes form an integral part of these Financial Statements.

 

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The Notes form an integral part of these Financial Statements.

 

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Petróleo Brasileiro S.A. (Petrobras), hereinafter referred to as “Petrobras” or “Company,” is a partially state-owned enterprise, controlled by the Brazilian Federal Government, of indefinite duration, governed by the terms and conditions under the Brazilian Corporate Law (Law 6,404 of December 15, 1976) and its Bylaws.

The Company is dedicated 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.

Petrobras may perform any of the activities related to its corporate purpose, directly, through its wholly owned subsidiaries, controlled companies, alone or through joint venture with third parties, in Brazil or abroad.

Petrobras may have its activities, provided they are in compliance with its corporate purpose, guided by the Brazilian Federal Government to contribute to the public interest that justified its creation, aiming at meeting the objective of the national energy policy.

The Brazilian Federal Government may only guide the Company to assume obligations or responsibilities, including the implementation of investment projects and the assumption of specific operating costs/results, such as those relating to the sale of fuels, as well as any other related activities, under conditions different from those of any other private sector company operating in the same market, when:

I – established by law or regulation, as well as under provisions of agreements with a public entity that is competent to establish such obligation, abiding by the broad publicity of such instruments; and

II – the cost and revenues thereof have been broken down and disseminated in a transparent manner, including in the accounting plan.

Moreover, in the event of the Brazilian Federal Government guide the Company to meet the public interest under conditions different from market conditions, the Company’s Finance Committee and Minority Shareholders Committee, exercising their advisory role to the Board of Directors, shall assess and measure the difference between such market conditions and the operating result or economic return of the transaction, based on technical and economic criteria for investment valuation and specific operating costs and results under the Company's operations, In this case, for every financial year, the Federal Government shall compensate the Company.

 

The consolidated and individual (Parent Company) financial statements have been prepared and are presented in accordance with the International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), and with the pronouncements issued by the Brazilian Accounting Pronouncements Committee (Comitê de Pronunciamentos Contábeis - CPC) and released by the Brazilian Securities and Exchange Commission (Comissão de Valores Mobiliários – CVM).

All relevant information related to financial statements, and only them, are presented and corresponds to the information used by the Company’s Management.

The consolidated 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 preparation of the financial statements requires the use of estimates and assumptions for certain transactions and their impacts in assets, liabilities revenues and expenses. Although our management uses assumptions and judgments that are periodically reviewed, the actual results could differ from these estimates. For further information on accounting estimates, see note 5.

The annual consolidated financial statements were approved and authorized for issue by the Company’s Board of Directors in a meeting held on March 14, 2018.

The Brazilian corporate law requires the release of the Statement of added value as an integral part of the financial statements. This statement is presented as supplementary information under IFRS and was prepared in accordance with CPC 09 – Statement of Added Value, released by the CVM.

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The purpose of the statement of added value is to present information relating to the wealth created by the Company and how it has been distributed.

The functional currency of Petrobras and all of its Brazilian subsidiaries is the Brazilian Real, which is the currency of its primary economic environment of operation. The functional currency of most of the entities that operate in the international economic environment is the U.S. dollar.

The income statements and statement of cash flows of non-Brazilian Real functional currency subsidiaries, joint ventures and associates in stable economies are translated into Brazilian Real using the monthly average exchange rates prevailing during the year. Assets and liabilities are translated into Brazilian Real at the closing rate at the date of the financial statements and the equity items are translated using the exchange rates prevailing at the dates of the transactions.

All exchange differences arising from the translation of the financial statements of non-Brazilian Real subsidiaries, joint ventures and associates are recognized as cumulative translation adjustments (CTA) within accumulated other comprehensive income in the shareholders’ equity and transferred to profit or loss in the periods at the disposal of the investments.

 

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, denounced and in certain cases charged for 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 R$ 6,194 (R$ 4,788 in the Parent Company) of capitalized costs representing amounts that Petrobras overpaid for the acquisition of property, plant and equipment in prior years.

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 below should be adjusted, Petrobras will evaluate whether the adjustment is material and, if so, recognize it.

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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.

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.

Petrobras has continuously monitored the progress of both the investigation by Brazilian authorities and the independent law firm. As a result, on the preparation of the financial statements for the year ended December 31, 2017, the Company has not identified any additional information that would impact the adopted calculation methodology and consequently require additional write-offs. The Company will continue to monitor these investigations for additional information and will review their potential impact on the adjustment made.

The Company has been closely monitoring the investigations and cooperating fully with the Brazilian Federal Police (Polícia Federal), the Brazilian Public Prosecutor’s Office (Ministério Público Federal), Federal Auditor’s Office (Tribunal de Contas da União – TCU), the Ministry of Transparency (Ministério da Transparência) and the General Federal Inspector’s Office (Controladoria Geral da União) 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 45 criminal proceedings as an assistant to the prosecutor. In addition, we have entered into four 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.

We do not tolerate corrupt practices and illegal acts perpetuated by any of our employees. Accordingly, since 2015, 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.

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As part of the process of strengthening integrity procedures to prevent and detect frauds or any illegal act, the Company has taken continuous measures aiming at enhancing its corporate governance and compliance systems, thereby applying corporate governance best practices aligned with new corporate governance requirements.

In this respect, among other measures, 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. In 2017, the Company created the position of Deputy Officer for Governance and Compliance, reviewed its Code of Best Practices, released the Annual Letter of Public Policies and Corporate Governance, implemented the Manager Training Program and continued to conduct integrity due diligence procedures of suppliers of goods and providers of services ( conducted nearly 17,000 through 2017), as well as integrity background checks as part of the decision making for appointing personnel to key positions. By reviewing its Bylaws, the Company also extended the Minority Committee duties with the aim of higher transparency in related party transactions assessment, indications to key management personnel and determination of investment thresholds under the public policies scope.

The continuous process of strengthening corporate governance practices resulted in the certification of Petrobras in the State Governance Highlight (Destaque em Governança das Estatais) program. Petrobras also obtained the maximum score in the IG-SEST governance index for state-owned companies of the Ministry of Planning and enabled the Company to require the adherence to a market tier in the Brazilian stock exchange (B3) for companies with high level of corporate governance (B3 governance level 2).

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.

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 15 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.

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.

The total funds collected through December 31, 2017, with respect to compensation for damages resulting from leniency agreements, amount to R$ 1,476, recorded as other income and expenses (R$ 661 until December 31, 2016).

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 with respect to, among other things, the Lava Jato investigation and any allegations regarding a violation of the U.S. Foreign Corrupt Practices Act. The U.S. Department of Justice (DoJ) is conducting a similar inquiry, and the Company is cooperating with both investigations 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.

The internal investigation and related government inquiries concerning these matters remain ongoing, and to date it is not possible to estimate the duration, scope or results of the internal investigation or related inquiries by relevant authorities. As a result, the Company is unable to make a reliable estimate about amounts and probability of penalties that may be required or if other financial relief may be provided in connection with any SEC or DoJ 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.

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

 

4.Summary of significant accounting policies

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, not including investments structured through a separate vehicle.

Investments structured through a separate vehicle are conceived so that the voting rights, or similar rights, are not the dominant factor to determine who controls the entity.

At December 31, 2017, Petrobras controls and consolidates the following structured entities:

 

 

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 is prepared based on available financial information directly attributable to each segment, or items that can be allocated to each segment on a reasonable basis. This information is presented by business activity, as used by the Company’s Board of Executive Officers (Chief Operating Decision Maker – CODM) on the decision-making process of resource allocation and performance evaluation.

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:

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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:

Trade receivables are initially measured at the fair value of the consideration to be received and, subsequently, at amortized cost using the effective interest method, less any impairment loss on 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 presented in the statement of income within 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.

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When a debt instrument is replaced by another one, between the same parties, but containing substantially different terms, the original financial instrument is derecognized and a new one is recognized. Similarly, substantial changes to the terms of the existing financial instrument, or part of it, are accounted as extinction of the original financial liability and recognition of a new financial liability.

The terms of the financial instrument are considered substantially modified if the present value of their cash flows under the new terms, including any commissions paid (net of any commissions received) and discounted using the original effective interest rate method, is at least 10% different from the present value of the remaining cash flows of the original financial instrument.

Changes in the terms of the financial instrument that are not considered substantial do not affect the statement of income at the moment they occur. In this case, the effective interest rate of the instrument is recalculated and applied prospectively.

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.

In addition, when a financial instrument designated as a hedging instrument expires or settled, the Company may replace it with another financial instrument in a manner such that the hedge relationship continues to occur. Likewise, whenever a hedged transaction effectively occurs, its financial instrument previously designated as a hedging instrument may be designate for a new hedge relationship.

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, adjusted to the net realizable value when it is lower than its carrying amount.

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.

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.

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.

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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. Certain of the Company's activities in the E&P segment are conducted through joint operations.

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

In the parent company’s financial statements, investments in associates, subsidiaries and joint ventures are accounted for by the equity method from the date on which they become an associate, a joint venture or a subsidiary. In the parent company’s financial statements, only joint operations structured through separate vehicles are accounted for by the equity method. For other joint operations the Company recognizes the amount of its share of assets, liabilities and related income and expenses.

Accounting policies of joint ventures and associates have been 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 accounted for at cost.

The acquisition method requires that the identifiable assets acquired and the liabilities assumed be measured at the acquisition-date fair value, with limited exceptions.

Goodwill is measured as the excess of the aggregate amount of: (i) the consideration transferred; (ii) the amount of any non-controlling interest in the acquiree; and (iii) in a business combination achieved in stages, the fair value of the acquirer’s previously held equity interest in the acquiree at the acquisition-date; over the net of the amounts of the identifiable assets acquired and the liabilities assumed. When this aggregate amount is lower than the net of the amounts of the identifiable assets acquired and the liabilities assumed, a gain on a bargain purchase is recognized in the statement of income.

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, including directly attributable costs, 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. The useful life is reviewed at each year end.

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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 concessions and production sharing agreements for exploration and production 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 crude oil and natural gas are initially capitalized within intangible assets and are transferred to property, plant and equipment when the technical and commercial feasibility can be demonstrated. 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. In the event a signature bonus encompasses an area in which exploration activities occur in different locations, whenever the technical and commercial feasibility can be demonstrated for a specific location, a portion of the signature bonus is transferred to property, plant and equipment based on the ratio between the oil in place at this location and total reservoir volume of the area.

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.

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.

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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.

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 active 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.

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

Current income taxes are computed based on taxable profit for the year, determined in accordance with the rules established by the taxation authorities, 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 there is a legal right and the entity has the intention to set off current tax assets and current tax liabilities, simultaneously, and they are recognized in the statement of income of the period, except to the extent that the tax arises from a transaction or event which is recognized directly in equity.

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, excluding amounts included in net interest on the net defined benefit liability (asset).

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

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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.

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 from the sale of goods, including, among others, crude oil, oil products, natural gas, biofuels, electric energy, is recognized when all the following conditions are satisfied:

(a) the Company has transferred to the buyer the significant risks and rewards of ownership of the goods, which usually happens at the delivery, in accordance with the terms of the sales contract;

(b) the Company retains neither continuing managerial involvement to the degree usually associated with ownership nor effective control over the goods sold. The amount of revenue can be measured reliably, consisting of 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;

(c) it is probable that the economic benefits associated with the transaction will flow to the Company; and

(d) the costs incurred or to be incurred in respect of the transaction can be measured reliably.

Revenue is measured at the fair value of the consideration received or receivable for sales of products or services rendered, net of discounts, sales taxes and returns.

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 significant judgment or involve a higher degree of complexity in the application of the accounting policies 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.

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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.

According to the definitions prescribed by the SEC, proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscientific 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 regulation. Proved reserves are subdivided into developed and undeveloped reserves.

Proved developed oil and gas reserves are those that can be expected to be recovered through: (i) existing wells with existing equipment and operating methods; (ii) extraction technology installed and operational at the time of the reserves estimate, extracting oil and gas in other ways than using wells.

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 unaudited 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.

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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 operating 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.

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.

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 due to a review of investment, strategic or operational factors result in changes in the interdependencies between those assets and, consequently, alter the aggregation or breakdown of assets into CGUs. The assumptions set out below have been consistently applied by the Company:

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. At December 31, 2017, the Guriatã and Guriatã Sul fields were grouped as one CGU, the Guriatã group, since both fields share the same reservoir. Based on the same reason, Canário da Terra and Canário da Terra Sul fields were also groped in a single CGU, so named Canário da Terra group. In addition, on November 30, 2017, the company submitted to the ANP the declaration of commerciality of the Mero field and it has been regarded as a single CGU. Accordingly, E&P CGUs include 40 groups of fields comprising 179 fields.

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

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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.

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 the 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. Since December 2016, these assets have not been aggregated as a CGU following their reclassification to assets held for sale.

v) Transportation CGU: comprises assets relating to Transpetro’s fleet of vessels. In December 2017, Transpetro's management decided to postpone the completion of three vessels under construction that were PANAMAX class (EI-512, EI-513 and EI-514) for an indefinite period of time and, thus, these assets are no longer part of Transportation CGU and were reviewed and tested for impairment separately;

vi) Hidrovia CGU: comprises the fleet of vessels of the Hidrovia project (transportation of ethanol along the Tietê River) that are under construction. In 2016, they were removed from the Transportation CGU since the project was delayed for an extended period of time;

vii) SIX CGU: shale processing plant; and

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

i) Natural gas CGU: comprises natural gas pipelines and natural gas processing plants. Reflecting the Business and Management Plan – BMP 2018-2022 approved in December 2017 that foresees the entire withdrawal from petrochemical interests, along with the lower expectation of a successful sale of fertilizers and nitrogen products plants, all of the nitrogen products plants that were still grouped into this CGU started to be assessed for impairment separately;

ii) CGU UFN III: comprises assets under construction of the fertilizer plant Unidade de Fertilizantes e Nitrogenados III (UFN III). Since 2014, the Company has decided to postpone this project for an extended period of time;

iii) Power CGU: comprises the thermoelectric power generation plants; and

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

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

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i) Biodiesel CGU: 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.

ii) Quixadá CGU: comprises the assets of Quixadá Biofuel Plant. In September 2016, it was removed from the Biodiesel CGU following the decision to discontinue its operations.

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

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

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:

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

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

The Company is defendant in arbitrations and in legal and administrative proceedings involving civil, tax, labor and environmental issues arising from the normal course of its business, and makes use of estimates to recognize the amounts and the probability of outflow of resources, based on reports and technical assessments from  legal advisors and on the management’s assessment.

These estimates are performed individually, or aggregated if there are cases with similar characteristics, primarily considering factors such as assessment of the plaintiff’s demands, consistency of the existing evidence, jurisprudence on similar cases and doctrine on the subject. Specifically for actions of outsourced employees, the Company estimates the expected loss based on a statistical procedure, due to the amount of actions with similar characteristics.

Arbitral, legal and administrative decisions against the Company, new jurisprudence and changes on the existing evidences can result in changes regarding the probability of outflow of resources and on the estimated amounts, according to the assessment of the legal basis.

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.

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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 21.5.

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, limited to a threshold based on a historical percentage of the oil production that is usually sold abroad. 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 R$ 6,194 of capitalized costs representing the estimated amounts that Petrobras had overpaid for the acquisition of property, plant and equipment.

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.

Allowance for impairment of trade receivables is recognized when there is objective evidence that trade receivables are impaired. 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.

IFRS 9 – Financial Instruments

The International Financial Reporting Standard 9 - Financial Instruments (IFRS 9), issued by the IASB, is mandatorily effective for annual periods beginning on or after January 1, 2018 and supersedes IAS 39 – Financial Instruments: Recognition and Measurement (IAS 39).

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IFRS 9 sets out, among others, new requirements for: classification and measurement of financial assets, measurement and recognition of expected credit losses on financial assets, changes in the terms of financial assets and financial liabilities, hedge accounting and related disclosures.

As permitted by IFRS 9, the company does not intend to restate prior periods with respect to classification and measurement (including impairment and modification of financial assets and liabilities) changes. Differences in the carrying amounts of financial assets and financial liabilities resulting from the adoption of IFRS 9 will be recognized in retained earnings at January 1, 2018. New hedge accounting requirements should generally be applied prospectively.

The impacts arising from IFRS 9 on the Company’s equity at January 1, 2018 are immaterial. The principal impacts that IFRS 9 will have on the Company’s financial statements are shown below:

Classification and measurement

IFRS 9 establishes a new classification approach for financial assets that reflects the business model in which assets are managed and their contractual cash flow characteristics.

Modification of contractual cash flow of financial assets and liabilities

IFRS 9 establishes that if a financial asset or liability measured at amortized cost has its terms modified and this change is not substantial, its gross carrying amount should reflect the discounted present value of its cash flows under the new terms using the original effective interest rate.

Impairment of Financial Assets

IFRS 9 replaces the ‘incurred loss’ model in IAS 39 with an ‘expected credit loss’ model.

The Company will apply the practical expedient of calculating the expected credit losses on short-term trade receivables using a provision matrix.

Hedge Accounting

IFRS 9 provides for new requirements with respect to hedge accounting such as the prohibition of voluntary discontinuation of the hedge accounting, changes in the measurement of hedge effectiveness that must take into account the time value of money, as well as certain disclosure requirements were expanded.

All cash flow hedging relationships of highly probable future exports designated under IAS 39 also qualify for hedge accounting under IFRS 9 and are regarded as continuing hedging relationships.

IFRS 9 does not change the criteria for accounting for cash flow hedge.

IFRS 15 – Revenue from Contracts with Costumers

On January 1, 2018, the International Financial Reporting Standard 15 - Revenue from Contracts with Customers (IFRS 15) became effective.  This Standard, issued by the IASB, supersedes a number of Standards and Interpretations, including IAS 18 - Revenue.

The objective of this Standard is to establish the principles that an entity shall apply to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue and cash flows arising from a contract with a customer. This Standard should be applied to all contracts with customers, except to non-monetary exchanges between entities in the same line of business to facilitate sales to customers or potential customers, or when the transaction is within the scope of another Standard.

The requirements of IFRS 15 establish a comprehensive approach to determine when and in what amount of revenue from a contract with a customer that should be recognized. To achieve this, the newly enacted standard uses the following five step approach: 1) identify the contract with a customer; 2) identify the separate performance obligations in the contract; 3) determine the transaction price; 4) allocate the transaction price to the separate performance obligations in the contract, 5) recognize revenue when the entity satisfies a performance obligation. A performance obligation is satisfied when the customer obtains control of that good or service.  

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For the purposes of the transition requirements an entity shall apply this Standard using one of the following two methods: (i) retrospectively to each prior reporting period presented in accordance with IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors, subject to the practical expedients; or (ii) retrospectively with the cumulative effect of initially applying this Standard recognized at the date of initial application.  The company intends to apply the second method as of January 1, 2018, and so far no cumulative effects have been identified to be recognized.

The changes in the Company's accounting policies arising from IFRS 15 only affect the way certain revenues from contracts with customers are disclosed within the statement of income and do not impact net income/loss. In 2017, it would be equivalent to a 1.7% reduction in revenues. The main changes are the following:

The Company acting as an agent

In accordance with accounting policies at December 31, 2017, the Company is regarded as the principal in certain transactions. Therefore, the revenues from these sales, cost of the product sold and sales expenses are presented separately in the statement of income. However, under the new standard’s requirements, the company acts as an agent because it does not obtain control of goods or services provided by another party before it is transferred to the customer. From January 1, 2018, revenues from these sales will be presented in the statement of income net of their cost of sales and sales expenses.

Non-exercised right Income (breakage)

In accordance with accounting policies at December 31, 2017, the Company regards the income from rights not exercised by customers in certain take or pay and ship or pay contracts as penalties revenue and presents it as other income and expenses in the statement of income. However, according to the new standard’s requirements, the Company will account for and present its income from rights not exercised by customers as sales revenues in the statement of income, as from January 1, 2018.

IFRIC 22 – Foreign Currency Transactions and Advance Consideration

As of January 1, 2018, the IFRIC Interpretation 22 - Foreign Currency Transactions and Advance Consideration (IFRIC 22), issued by the IASB, became mandatorily applicable.

IFRIC 22 applies to a foreign currency transaction (or part of it) when an entity recognizes a non-monetary asset or non-monetary liability arising from the payment or receipt of advance consideration before the entity recognizes the related asset, expense or income (or part of it). IFRIC 22 clarifies that the date of the transaction for the purpose of determining the exchange rate to use on initial recognition of the related asset, expense or income (or part of it) is the date on which an entity initially recognizes the non-monetary asset or non-monetary liability arising from the payment or receipt of advance consideration.

Based on the transition provisions of IFRIC 22, the Company will apply the new requirements prospectively from the effective date of the interpretation and did not identified any material impact on its financial statements.

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 the following standards and related interpretations: IAS 17 - Leases; IFRIC 4 - Determining whether an Arrangement contains a Lease; SIC-15 - Operating Leases – Incentives; and SIC-27 - Evaluating the Substance of Transactions Involving the Legal Form of a Lease.

IFRS 16 sets out the principles for the recognition, measurement, presentation and disclosure of leases, from the lessees and lessors’ perspectives.   This Standard shall be applied to all leases, except for:

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Among the changes for lessees, IFRS 16 eliminates the classification of leases as either operating leases or finance leases as is required by IAS 17. Instead, it introduces a single lessee accounting model, in which all leases result in the recognition of a right to use an asset at the start of the lease. If lease payments are made over time, a financial liability will also be recognized. Accordingly, the adoption of IFRS 16 may cause a significant increase in assets and liabilities presented in statement of financial position.

Following the adoption of IFRS 16, lease payments under operating leases will not be charged to results on accrual basis. Instead, depreciation of the right to use a leased asset, as well as the finance expenses and foreign exchange gains or losses over the finance liability will affect the results. Finance expenses may qualify for borrowing costs capitalization in accordance with IAS 23 and foreign exchange gains and losses may be first recognized within equity if designated as hedge instrument, as set out in IFRS9.

For lessors, IFRS 16 substantially carries forward the lessor accounting requirements in IAS 17. Accordingly, a lessor continues to classify its leases as operating leases or finance leases, and to account for those two types of leases differently.

The Company is assessing the impacts that IFRS 16 will have on its financial statements and is unable to make a reasonable estimation of those impacts at this stage of the implementation process. Once the estimated impact can be evaluated with sufficient reliability, it may result in the need to renegotiate the terms of certain debt instrument with BNDES (Brazilian Development Bank) and other financial institutions, especially regarding the covenants clauses related to debt level.

The CPC issue accounting pronouncements and interpretations equivalent to the IFRS issued by IASB. The following table sets out the main pronouncements and interpretations issued by the CPC not effective as of December 31, 2017, which the Company did not adopt them in advance:

 

 

The transitional provisions and the effects of the initial adoption of the aforementioned pronouncements and interpretations are the same presented in note 6.1.

 

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The principal uses of funds in 2017 were for debt service obligations (R$ 137,386) including pre-payment of debts, and for capital expenditures (R$ 43,614), and they were principally provided by operating activities (R$ 86,467), proceeds from financing (R$ 86,467) and disposal of assets (R$ 14,813).

Short-term financial investments in Brazil primarily consist of investments in funds holding Brazilian Federal Government Bonds and related repo investments that mature within three months as of the date of their acquisition. Short-term financial investments abroad comprise time deposits that mature in three months or less from the date of their acquisition, highly-liquid automatic investment accounts, interest checking accounts and other short-term fixed income instruments.

 

 

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.

Available-for-sale securities in Brazil refer substantially to São Martinho’s common shares granted to the wholly-owned subsidiary Petrobras Biocombustível S.A. - PBIO (24 million shares) as consideration for PBIO’s shares in Nova Fronteira. For further information on this transaction see note 10.3. Available-for-sale securities abroad refer to UK government bonds amounting to GBP 475 million and maturing in March 2018.

 

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As established in IFRS 9, from 2018 onwards, impairment of trade receivables will be based on the expected credit loss model, no longer on the incurred loss, as set out in note 6.

On May, 22 2017, the Company terminated a finance lease agreement relating to the Vitória 10,000 drilling rig, owned by the indirect wholly-owned subsidiary Drill Ship International BV – DSI BV and leased to the Deep Black Drilling LLP – DBD, an entity from Schahin group. On July 19, 2017, a court ruling confirmed this contract termination and, shortly after, Schahin filed a request to suspend its effects, which was denied by the court on July 28, 2017.

Due to the finance lease agreement termination, the Company assessed the value in use of the drilling rig based on the cash flows projected to arise from its commitment to certain Petrobras Group projects, and compared it to the carrying amount of the finance lease receivable at June 30, 2017. As result, the Company wrote-down R$ 818 as other income and expenses in the second quarter of 2017.

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In addition, on August 9, 2017, measures were adopted to obtain possession of this drilling rig, which effectively occurred on August 16, 2017. As a result of this matter, in the third quarter of 2017 the Company added R$ 76 to the allowance for impairment due to additions to the finance lease receivable and contractual fine, as well as derecognized the finance lease receivable and recognized the drilling rig as equipment within property, plant and equipment in the amount of R$ 1,224.

 

 

The Company supplies fuel oil, natural gas, and other products to entities that operate in the city of Manaus and 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.

The total cost of power generation to Manaus and the isolated electricity system includes the costs to products supplied by the Company. Local consumers partially cover these costs based on a threshold comprising the average cost of the energy and potency traded in the Regulated Procurement Environment (Ambiente de Contratação Regulada – ACR). Most of the funds for the payment for these costs comes from the Fuel Consumption Account (Conta de Consumo de Combustível – CCC), a component of the Brazilian Energy Development Account (Conta de Desenvolvimento Energético ‐ CDE).

The regulation of CCC and CDE underwent some changes in the last few years, notably the ones arising from Provisional Measure 579/2012, signed into Law No. 12,783/2013, and to Provisional Measure 735/2016, signed into Law No. 13,360/2016.

These changes, along with supervision procedures carried out run by the Brazilian National Electricity Agency (Agência Nacional de Energia Elétrica - ANEEL) over these accounts and its beneficiaries (power plants controlled by Eletrobras) caused instability and decrease in amount of funds transferred from CCC since 2013, which increased the default rate of those customers to the Company, notably relating to Eletrobras Distribuição Amazonas (AME-D).

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 debt acknowledgement agreements with subsidiaries of Eletrobras with respect to the balance of its receivables as of November 30, 2014. Eletrobras acknowledged it owed R$ 8,601 to the Company, of which R$ 7,380 were collateralized by payables from the CDE to the CCC. This amount has been adjusted by the Selic interest rate (Brazilian short-term interest rate) on a monthly basis and the first of 120 monthly installments was paid in February 2015.

The contractual amortization clauses in the debt acknowledgement agreements establish 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, which did not happen until December 31, 2017 due to the characteristics of its initial amortizations along with its indexation. Despite some periodic delays, these payments have continued.

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Considering the restructuring of the electricity sector and the expected effects arising from the Normative Instruction 679/2015 enacted by ANEEL, the Company expected a decrease on these defaults rates, which actually had not occurred.

 

Accordingly, the Company has adopted measures to reduce the default rate, mainly:

In 2017, the Company accounted for allowances for impairment of trade receivables, net of reversals, totaling R$ 681 (R$ 1,242 in 2016) primarily due to partial defaults relating to supplies of natural gas, partially offset by overdue receivables paid by CELPA.

Moreover, the Company has negotiated with Eletrobras the settlement of the receivables relating to Eletrobras Group. The Company is assessing the provisions approved at Eletrobras’ Shareholder’s General Meeting, held on February 8, 2018, primarily the segregation of operating segments and the privatization of companies controlled by Eletrobras.

 

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The amount of inventories is presented net of R$ 4 reducing inventories to net realizable value (R$ 92 as of December 31, 2016), primarily due to changes in international prices of crude oil and oil products. In 2017, the Company recognized as cost of sales R$ 211 reducing inventories to net realizable value, net of reversals (R$ 1,320 in 2016).

At December 31, 2017, the Company had pledged crude oil and oil products volumes as collateral for the Terms of Financial Commitment (TFC) signed by Petrobras and Petros in 2008, in the amount of R$ 13,454 (R$ 6,449 at December 31, 2016), as set out in note 22. In the third quarter of 2017, the amount of collateral was revised and updated in order to reflect the increase in commitments undertaken
under TCF.

 

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The Company has an active partnership and divestment program which takes into account opportunities for divestments in several areas in which it operates. The divestment portfolio is dynamic, meaning that market conditions, legal matters and negotiations may affect the Company’s evaluation of ongoing and potential transactions. This program is an essential initiative in the Company’s 2018-2022 Business and Management Plan (2018-2022 BMP) which, along with other initiatives, will enable the Company to reduce and improve its indebtedness and debt profile, respectively. For the period 2017-2018, the target of proceeds from divestments is US$ 21 billion.

On December 7, 2016, the Brazilian Federal Auditor’s Office (Tribunal de Contas da União – TCU) filed a civil action prohibiting the Company from commencing additional divestment projects and entering into sales agreements, except for transactions in their final stages at that time.

After the TCU’s assessment of the divestments decision-making methodology and the Company’s review of its divestment policies, the TCU’s civil action was dismissed, allowing the partnership and divestment program to continue based on the Company’s revised methodology.

Accordingly, the Company’s Executive Board approved the new divestment portfolio on March 30, 2017, consisting of projects that follow the revised divestment methodology in compliance with the TCU’s decision.

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), a group entity from the distribution business segment, held through Petrobras Caribe Ltda.

This transaction was concluded on January 4, 2017 and the net proceeds from this sale were US$ 470 million, of which US$ 90 million was received via distribution of dividends after taxes on December 9, 2016 and the remaining US$ 380 million was paid by Southern Cross Group at the transaction closing. Accordingly, the Company recognized a gain of R$ 2 as other income and expenses, in the first quarter of 2017, taking into account the impairment of R$ 266 at December 31, 2016.

In addition, a R$ 248 loss was recycled from shareholders’ equity to other income and expenses within the income statement, reflecting the reclassification of cumulative translation adjustments resulting from the depreciation of the Chilean Peso against the U.S. Dollar from the time of the acquisition of this investment to its disposal (see note 23.4).

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

On September 22, 2016, the Company’s Board of Directors approved the sale of a 90% interest in Nova Transportadora do Sudeste - NTS, a group entity from the gas and power business segment, 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 disposal occurred after a corporate restructuring intended to concentrate the transportation assets of the southeastern region in NTS.

The corporate restructuring of NTS comprised an increase in its share capital in the amount of R$ 2,310, through net assets of the Company’s subsidiary Transportadora Associada de Gás S.A. – TAG.  Subsequently TAG had a reduction in its share capital, in the amount of its investment in NTS (R$ 2,600), which was transferred to Petrobras. This restructuring maintained the same terms of the Firm Gas Transportation Agreements associated to the assets involved on the transaction.

On April 4, 2017, after performing all conditions precedent and adjustments provided for in the purchase and sale agreement, this transaction was completed in the amount of US$ 5.08 billion upon the payment of US$ 4.23 billion on this date, made up of: US$ 2.59 billion from the sale of shares, of which US$ 109 million was allocated to an escrow account pledged as collateral for charges associated with the repair of pipelines; and US$ 1.64 billion relates to the issuance of convertible debentures by NTS, maturing in 10 years, as a replacement of the debt to PGT. The remaining balance (US$ 850 million, also relating to the sale of shares) will be paid in the fifth year, bearing annual interests at a fixed rate, as established in the purchase and sale agreement.

At the transaction closing, the Company recognized a gain on this transaction in the amount of R$ 6,977 accounted for as other income and expenses, which includes a R$ 698 gain on the remeasurement at fair value of the remaining 10% interest in NTS.

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On October 10, 2017, the final price adjustment was settled, in the amount of R$ 63, totaling a gain of R$ 7,040 on this transaction.

Disposal of Guarani

On December 28, 2016, the Company’s wholly-owned subsidiary Petrobras Biocombustível S.A. (PBIO), in the biofuels business segment, 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.

On February 3, 2017, this transaction was concluded pursuant to the payment of US$ 203 million, after all conditions precedent were performed by Tereos Participations S.A. In, 2016, impairment losses amounting to R$ 578 were accounted for as results in equity-accounted investments with respect to Guarani.

Additionally, a gain of R$ 132 was recycled from shareholders’ equity to other income and expenses within the income statement, reflecting the reclassification of cumulative translation adjustment resulting from the appreciation of Mozambican Metical against the Brazilian Real from the acquisition of this investment to its disposal (see note 23.4). This gain was partially offset by a R$ 69 loss also recycled from shareholders’ equity to other income and expenses, reflecting cumulative losses relating to cash flow hedge accounting.

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, a group entity from the RT&M business segment (Refining, Transportation and Marketing), to Companhia Ultragaz S.A., a subsidiary of Ultrapar Participações S.A. In January 2017, this sale was approved at Ultrapar’s and Petrobras’ Shareholders’ Meetings in the amount of R$ 2,666.

According to an official statement released by the General Superintendence of CADE (SG) on June 30, 2017, additional diligence was required in order to make a decision regarding on market concentration aspects of this sale. On August 28, 2017, the SG reported some concerns about market concentration that may result from this transaction and submitted its opinion to the CADE court.

Based on pending conditions precedent to the transaction, including CADE approval, the related assets and liabilities remained classified as held for sale as of December 31, 2017.

On February 28, 2018, the CADE court ruled on this matter and dismissed this sale. This decision is object to a termination clause within the sales and purchase agreement that provides for compensation to the Company, received on March 13, 2018, amounting to R$ 286.

Disposal of Suape and Citepe petrochemical plants

On December 28, 2016, the Company’s Board of Directors approved the disposal of the interests in the wholly-owned subsidiaries Companhia Petroquímica de Pernambuco (PetroquímicaSuape) and Companhia Integrada Têxtil de Pernambuco (Citepe), both from the RT&M business segment, to Grupo Petrotemex S.A. de C.V. and to 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 million, which will be fully disbursed at the transaction closing. This amount remains subject to adjustments relating to working capital, net debt and recoverable taxes.

On February 21, 2017, the transaction was approved at the Grupo Alfa’s Board of Directors Meeting and, on March 27, 2017, at Petrobras’ Shareholders’ Meeting.

According to an official statement released by the General Superintendence of CADE (SG) on October 10, 2017, additional diligence was required in order to conclude on market concentration aspects of this sale. On December 15, 2017, the SG concluded its opinion, recommending to the CADE Court the approval of this transaction subject to the execution of an Agreement on Concentration of Control (Acordo de Controle de Concentração – ACC).

Due to some customary conditions precedent to its closing, including the CADE approval, the related assets and liabilities remained classified as held for sale at December 31, 2017.

On February 7, 2018, the CADE approved this transaction, however, other customary conditions precedent are still pending to date.

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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 E&P 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 purchase and sale agreements with respect to the aforementioned assets. Total will pay to the Company the amount of US$ 1,675 million in cash for assets and services, subject to price adjustments, as well as contingent payments in the amount of US$ 150 million, associated with the production volume in Lapa field. In addition, a long-term line of credit in the amount of US$ 400 million will be provided by Total, which may be used to fund the Company’s investments in the Iara fields.

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

At December 31, 2017, these transactions were still subject to approval by the relevant authorities, the potential exercise of preemptive rights by current Iara partners, and other customary conditions precedent. Accordingly, the related assets and liabilities were classified as held for sale at December 31, 2017.

On January 15, 2018, Petrobras and Total closed the aforementioned transfers of interests of Iara and Lapa fields, after performing all conditions precedent to this transaction.

This transaction totaled US$ 1.95 billion, including price adjustments, but not including the long-term line of credit and the contingent payments.

The closing of the power plants deal is still subject to approval by the relevant authorities and other customary conditions precedent.

Initial public offering (IPO) of Petrobras Distribuidora (BR)

On July 11, 2017, the Company’s Board of Directors approved an IPO of its subsidiary Petrobras Distribuidora (BR) through a secondary public offering of common shares, aiming at joining the market tier in the Brazilian stock exchange that requires the highest level of corporate governance, so named New Market (Novo Mercado).

Accordingly, on September 5, 2017, the Extraordinary General Shareholder’s Meeting of BR approved the changes in its bylaws taking into account relevant rules governing the requirements needed to join the New Market tier (Law 13,303/2016 and Decree 8,945/2016).

On December 14, 2017, the Brazilian Securities and Exchange Commission (CVM) accepted the registration of the public offering of secondary distribution of common shares for Petrobras Distribuidora (BR), held the following day in Brazil, in the non-organized over-the-counter market, pursuant to applicable rules.

The Final Prospectus of the Offering reported the sale of 291,250,000 common shares ("Base Lot") at the price of R$ 15.00 per share. This offering was increased by an additional lot of 43,687,500 shares, as allowed for in the Final Prospectus, under the same conditions and at the same price of issue as initially offered ("Additional Lot").

The offering was closed on December 22, 2017, with a total distribution of 334,937,500 shares, in the total amount of R$ 5,024, representing a 28.75% stake of BR equity. Considering the book value of the investment, in the proportion of the disposed shares, and the transaction costs, the final gain totaled R$ 2,399, R$ 1,597 net of tax, accounted for in equity within additional paid in capital, since the Company keeps the control of BR, as set out in note 23.2.

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Sale of Azulão field

On November 22, 2017, the Company entered into an agreement with Parnaíba Gás Natural S.A., a subsidiary of Eneva S.A, concerning the assignment of its entire participation in the Azulão Field (Concession BA-3), located in the state of Amazonas. The total amount of the operation is US$ 54.5 million and will be paid at the transaction closing.

The completion of this deal is subject to the fulfillment of usual conditions precedent, including approval by ANP. Accordingly, the related assets and liabilities were classified as held for sale at December 31, 2017.

Strategic alliance with Statoil

On December 18, 2017, the Company entered into agreements with the Norwegian company Statoil relating to the assets of the strategic partnership, in continuity with the Heads of Agreement (“HoA”) signed and disclosed on September 29, 2017. The main signed contracts are:

(i) Strategic Alliance Agreement ("SAA") - agreement describing all documents related to the strategic partnership, covering all negotiated initiatives.

(ii) Sale and Purchase Agreement ("SPA") - sale of 25% of Petrobras’ interest in the Roncador field to Statoil.

(iii) Strategic Technical Alliance Agreement ("STAA") - strategic agreement for technical cooperation aiming at maximizing the value of the asset and focusing on increasing the recoverable oil volume (recovery factor), including the extension of the useful life of the field;

(iv) Gas Term Sheet - Statoil may hire a certain processing capacity of natural gas at the Cabiúnas Terminal (TECAB) for the development of the BM-C-33 area, where the companies already are partners and Statoil is the operator.

The strategic alliance, among other goals, aims at applying the Statoil’s expertise in mature fields in the North Sea towards increasing the recovery factor of Roncador field. Accordingly, the parties signed the STAA for technical cooperation and the joint development of projects.

The SPA has a total amount of US$ 2.9 billion, made up of US$ 117.5 million paid at the signature date of the agreement, contingent payments relating to investments in projects to increase the recovery factor of the field, limited to US$ 550 million, and the remaining amount will be paid at the transaction closing. Accordingly, the related assets and liabilities remained classified as held for sale at December 31, 2017 and, as a result, an impairment charge was recognized, as set out in note 14.1.

On March 13, 2018, the CADE approved this transaction. However, its closing still depends on the fulfillment of other conditions precedent, such as the approval of ANP.

 

 

 

 

 

 

 

 

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The major classes of assets and liabilities classified as held for sale are shown in the following table:

 

 

At December 31, 2017, the amounts mainly refer to assets and liabilities transferred following the approvals of the disposal of Liquigás, Petroquímica Suape and Citepe, interests in the concession areas named as Iara and Lapa, as well as interests in the thermoelectric power generation plants Rômulo Almeida and Celso Furtado, 25% interest in Roncador field and 100% interest in Azulão field. At December 31, 2016, the amounts also comprise assets and liabilities transferred following the approvals of the disposals of NTS, Petrobras Chile Distribución Ltda (PCD), Guarani and Nova Fronteira.

Corporate restructuring in Petrobras Distribuidora (BR)

In preparation for the IPO of BR, on August 25, 2017, the Company’s Board of Directors approved the corporate restructuring of BR through the following transactions:

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Sale and merger of Nova Fronteira Bioenergia

On December 15, 2016, the Company’s wholly-owned subsidiary PBIO (biofuels business segment) entered into an agreement with the São Martinho group to merge PBIO’s interests in Nova Fronteira Bioenergia S.A. (49%) into São Martinho.

On February 23, 2017, São Martinho granted to PBIO additional 24 million of its common shares, corresponding to 6.593% of its total capital. These shares were accounted for as available-for-sale securities, as set out in note 7.

On December 27, 2017, the Extraordinary General Shareholder’s Meeting of PBIO approved the sale of these shares through a block trade.

On February 16, 2018, PBIO disposed, through a public auction held in the Brazilian stock exchange, these 24 million of shares, at the share price of R$ 18.51. The settlement of the transaction occurred on February 21, 2018, closing the complete disposal of PBIO’s interests in São Martinho’s capital.

Incorporation of Downstream

On November 7, 2017, Extraordinary General Meeting of Petrobras approved the incorporation of Downstream Participações Ltda (“Downstream”) in Petrobras Parent Company, without share capital increase.

As shown in note 10.1, among other transactions in the scope of the Divestment and Venture Plan, in 2017 the Company disposed of its interest in certain subsidiaries over which control was lost. The following table summarizes cash flows arising from losing control in subsidiaries:

 

 

 

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The main investees of PNBV are: Tupi BV (65%), Guará BV (45%), Agri Development BV (90%), Libra (40%), Papa Terra BV (62.5%). They are dedicated to construction and lease of equipment and platforms for Brazilian E&P consortiums and are incorporated under the law of The Netherlands. PNBV’s interests in these entities comprise the voting rights. In addition, Tupi BV and Guará BV have 100% interest in Iara BV and Lapa BV, respectively.

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The main investees of PIB BV are the wholly-owned subsidiaries Petrobras Global Trading B.V. – PGT, Petrobras Global Finance B.V. - PGF; Petrobras America Inc. – PAI. PGT is incorporated under the law of The Netherlands and is dedicated to the trade of oil, oil products, biofuels and LNG (liquefied natural gas), as well as to the funding of its activities in light of Petrobras Group. PGF also is incorporated under the law of The Netherlands and is the finance subsidiary of Petrobras Group, raising funds through bonds issued in the international market. PAI is incorporated under the law of United Sates and is dedicated to E&P and refining activities (Pasadena). In addition, Petrobras Oil & Gas B.V. – PO&G is a joint venture incorporated under the law of The Netherlands dedicated to E&P business in Africa, of which PIB BV has 50% stake.

Petrobras has a 51% stake of Gaspetro, which holds interests in several state distributors of natural gas in Brazil that carry out, by means of concessions, public service of distribution of piped natural gas.

 

 

The investments were made, mainly, for debt repayments (PIB BV), investment projects (PNBV), BR Distribuidora restructuring as set out in note 10.3, and loan repayment to BNDES (TAG).

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Since July 2017, the Company has begun negotiations with Odebrecht S.A. to revise the terms and conditions of the Braskem S.A. Shareholder's Agreement, signed on February 8, 2010. This revision aims to improve Braskem’s corporate governance and the corporate relationship between the parties, with the purpose of creating value for all Braskem shareholders. The negotiations are in still in their preliminary stages and they aim at a corporate restructuring with a unification of Braskem’s shares classes.

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

The main estimates used in the cash flow projections to determine the value in use of Braskem are set out in Note 14 to the Financial Statements as of December 31, 2017.

The total amount of non-controlling interest at December 31, 2017 is R$ 5,624 (R$ 2,513 in 2016), primarily comprising R$ 2,620 of Petrobras Distribuidora, R$ 957 of Gaspetro (R$ 917 in 2016), R$ 251 of TBG (R$ 213 in 2016), and R$ 940 refers to Consolidated Structured Entities (R$ 570 in 2016).

Condensed financial information is set out as follows:

 

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Petrobras Distribuidora (BR) is a company which has as its corporate purpose the distribution, transportation, trade and industrialization of oil products, other fuels and several forms of energy, and is controlled by Petrobras, which holds a 71.25% interest. See note 10.1 for information on the public offering of BR in December 2017.

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.

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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In 2017, additions to property, plant and equipment primarily relate to E&P projects in pre-salt fields of Santos basin, such as Búzios, Lula and Atapu as well as Libra block. The Company also made investments aiming at maintaining the production in mature fields and at improving operational efficiency of the production, especially in Campos basin, and in projects relating to the infrastructure for transporting and processing natural gas from the pre-salt layer in the Santos Basin (Route 1, 2 and 3).

Moreover, important platforms started operating in 2017, such as the FPSOs Libra Pioneer, in Mero field, and P-66, in South of Lula field, as well as the interconnection of new wells to FPSOs Cidade de Saquarema, Cidade de Maricá and Cidade de Itaguaí, in pre-salt fields of Santos basin.

In addition to the capital commitments previously reported and in line with the investments foreseen in the Strategic Plan and the 2017-2021 Business and Management Plan, in 2017, the Company entered into agreements for the acquisition and construction of property, plant and equipment, especially the contract for the conclusion of the hull conversion of FPSO P-76, in the amount of R$ 1,644, and the contract for the supply of flexible pipelines for the production, gas lifting and water injection in many pre-salt projects, in the total amount of R$ 1,970, expiring in March 2018 and May 2022, respectively.

At December 31, 2017, consolidated and Parent Company property, plant and equipment include assets under finance leases of R$ 390 and R$ 5,969, respectively (R$ 407 and R$ 6,004 at December 31, 2016).

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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 prospecting and drilling activities for oil, natural gas and other liquid hydrocarbons located in the pre-salt area, subject to a maximum production of five billion barrels of oil equivalent. The agreement has a term of forty years and is renewable for a further five years subject to certain conditions. As of December 31, 2017, the Company’s property, plant and equipment include the amount of R$ 74,808 related to the Assignment Agreement.

Petrobras has already declared commerciality in fields of all six blocks under 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 its review procedures will commence immediately after the declaration of commerciality for each area and must be based on reports by independent experts engaged by Petrobras and the ANP.

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 in order to match with the amount originally paid. 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 information gathered after drilling over 50 exploratory wells and performing extended well tests in this area, as well as the extensive knowledge acquired on the pre-salt layer of Santos Basin, made possible the identification of volumes exceeding five million barrels of oil equivalent.

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 renegotiation of: (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.

In November 2017, the Company set up an internal commission responsible for the negotiation with the Brazilian Federal Government, composed of representatives of the Chief Exploration and Production Officer and the Chief Financial Officer.

In January 2018, the Brazilian Federal Government established, through the Interministerial Ordinance No. 15/2018, the Interministerial Commission responsible to negotiate and conclude the terms of this review, within 60 days, extendable for the same period.

The negotiations are ongoing and have taken into account appraisals by independent experts engaged by both parties and their respective reports. As at the date of issue of these financial statements, the final amount to be established for this agreement is not defined.

The Company considers that this surplus provides an opportunity to enter into an agreement concerning the compensation to the Company arising from this review. Therefore, aiming to support an eventual negotiation where this compensation would be paid through the right over exceeding volume, the Company is complementing its assessment based on reports issued by the independent experts it has engaged.

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This review process of the Assignment Agreement has been monitored by the Minority Shareholders Committee, which is composed of two board members elected by the minority shareholders and by a third independent member with knowledge in technical-financial analysis of investment projects. This Committee will provide support to the board’s decisions through opinions about related matters.

In 2017 the following oil and gas fields were returned to ANP: Mosquito, Siri and Saíra. These fields were returned to ANP mainly due to their economic feasibility. However, due to impairment losses recorded for these assets in prior years, these write-offs amounted to R$ 240 thousand.

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 R$ 12 as other income and expenses, in addition to impairments recognized in prior years.

 

 

 

During 2017, the Company participated on bids realized by ANP, with the following accomplishments:

Following the determination of economic feasibility of the Northwest area of Libra block, which resulted in declarations of commerciality such as the one relating to Mero field, a portion of signature bonus thereof, in the amount of R$ 5,240, was transferred from intangible assets to property, plant and equipment.

At December 31, 2017, no impairment was identified on goodwill.

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Exploration areas returned to the ANP in 2017, totaling R$ 10 (R$ 27 in 2016) are set out below:

 

 

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 Libra P1 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.

The signature bonus (acquisition cost) of R$ 15 billion was paid by the consortium. The Company paid R$ 6 billion relating to its 40% share of the acquisition cost paid by the consortium, recognized in its intangible assets as Rights and Concessions.

Within the initial stage of the exploration phase (4 years), the minimum work program was concluded in 2017, when the extended well test (EWT) was performed. In addition to EWT, the minimum work program also includes a 3D seismic acquisition for the whole block, and the drilling of two exploratory wells.

The EWT has been performed by the FPSO Libra Pioneer, which continues to produce on the same well after the declaration of commerciality, through an early production system. In the second half of 2018, this FPSO is expected to move to another location and to produce on another well. In January 2018, the Company performed the first loading of oil from Libra.

On November 30, 2017, ANP was informed about the declaration of commerciality of the Northwest area of Libra, confirming the potential of the area and its economic viability. In total, twelve wells have been drilled in Libra block, of which nine in the Northwest area. Following the declaration of commerciality, the Northwest area of Libra is now named Mero field (Campo de Mero). The results confirmed oil reservoirs at thickness of up to 410 meters with high porosity and permeability. The production tests confirmed the high productivity and oil quality of these reservoirs. Following this declaration of commerciality, R$ 5,240 was transferred to property, plant and equipment with respect to a portion signature bonus relating to the Northwest area of Libra.

In December 2017, the Company charted the FPSO of Mero 1 for the Northwest area, with expected start-up in 2021 and capacity of producing 180 thousands of barrels per day and processing 12 million cubic meters of gas.

The consortium was granted by the Ministry of Mines and Energy with an extension of the exploration phase by 27 months to the Central and Southeast areas of the block, where new assessments will be performed to evaluate the economic viability of these areas.

As of December 31, 2017, intangible assets include service concession agreements related to piped natural gas distribution in Brazil, in the amount of R$ 565 (R$ 578 in 2016), 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.

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.

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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.  The law states that a bidding process is required for this concession, or the establishment of a state-run company to provide this service, which would receive compensation pursuant to this law, which was appealed by the Company.

Accordingly, the Company entered into an agreement with the State of Espírito Santo, through a Memorandum of Understanding signed on August 12, 2016, aiming to evaluate the establishment of a state-run company of that state, to provide the public service of distributing piped natural gas. The evaluation is ongoing as of December 31, 2017.

This concession is accounted for as intangible assets totaling R$ 270 as of December 31, 2017 (R$ 274 as of December 31, 2016) and the Company has not recognized any provision on this matter based on indemnity established by law.

The Company annually tests its assets for impairment on December 31 or when there is an indication that their carrying amount may not be recoverable. In 2017, impairment losses and reversals were primarily recognized in the last quarter following the management of investment portfolio and updates of mid and long-term assumptions used in the recent Company’s Business and Management Plan (BMP 2018-2022) concluded and approved in December 2017.

The enhanced risk perception of Brazilian market (Brazil’s risk premium) decreased the discount rates applied for impairment testing purposes, and along with the better operational efficiency of certain E&P fields, resulted in reversals of impairment previously recognized following the 2017 annual review, mainly for the North Group CGU in Campos basin.

The Company accounted for impairment losses for certain assets in the scope of the partnership and divestment program, mainly with respect to oil and gas production and drilling equipment in Brazil and to the sale of a portion of Roncador field in Campos basin. The higher costs of raw materials and the lower refining margin, as set forth in BMP 2018-2022, were the main reasons for impairment losses on Second refining unit in RNEST.

The work in progress relating to the infrastructure shared by Comperj’s first refining unit and the natural gas processing plant (UPGN), as well as the decision of hibernating the hulls construction of 3 vessels of PANAMAX project, that triggered their separate impairment testing from the Transportation, also resulted in impairment losses in 2017. In addition, the Company’s plan to withdrawal its entire interest in petrochemical business, as set forth in BMP 2018-2022, along with the lower expectation of a successful sale of fertilizers and nitrogen products plants, triggered an impairment testing for these assets separately form the Natural Gas CGU in the last quarter of 2017, thereby accounting for impairment losses with respect to them.

 

 

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The table below shows the impairment losses, net of reversals, recognized within the statement of income in 2017 and 2016:

 

 

 

For impairment testing of its property, plant and equipment and intangible assets, assessed individually or grouped into cash-generating units – CGUs, 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.

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The cash flow projections used to measure the value in use of the CGUs in 2017 were mainly based on the following estimates of key assumptions for impairment testing:

 

 

For comparative purposes, estimates of key assumptions for impairment testing in 2016 are shown below:

 

 

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

a1) Producing properties in Brazil – 2017

Impairment assessment for producing properties in Brazil under the concession regime for oil and gas resulted in a net reversal of impairment losses of R$ 2,824. 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 7.6% p.a. at December 31, 2017. This amount comprises:

a2) Producing properties in Brazil – 2016

Impairment losses of R$ 7,381 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 December 31, 2016. The impairment losses were related primarily to the following fields and groups of fields: North group (R$ 3,823), Ceará Mar Group (R$ 693), Guaricema (R$ 415), Bijupirá and Salema (R$ 317), Dourado (R$ 284), Maromba (R$ 281), Papa-Terra (R$ 234), Trilha (R$ 228), Pampo (R$ 216), Frade (R$ 213), Uruguá group (R$ 196), Badejo (R$ 183), Bicudo (R$ 160), Riachuelo (R$ 146), Fazenda Bálsamo (R$ 135) and Água Grande group (R$ 101). 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 R$ 1,347, 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.

b1) Transpetro’s fleet of vessels - 2017

An impairment reversal of R$ 11 was recognized for Transpetro’s fleet of vessels. Cash flow projections were based on: financial budgets/forecasts set forth in BMP 2018-2022; taking into account operating and unused vessels and vessels under construction; and post-tax discount rates (excluding inflation) ranging from 4.11% p.a. to 9.19% p.a. derived from the WACC for the transportation industry, considering financial leverage and the respective tax benefits.

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b2) Transpetro’s fleet of vessels - 2016

An impairment loss of R$ 798 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. 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.

c1) Second refining unit in RNEST - 2017

An impairment loss of R$ 1,507 was recognized for the second refining unit in RNEST. Cash flow projections were based on: financial budgets/forecasts approved by Management; and an 7.7% p.a. 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) higher costs of raw materials and ii) lower refining margin, as set forth in BMP 2018-2022.

c2) Second refining unit in RNEST - 2016

An impairment loss of R$ 2,531 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. 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.

d) Fertilizer Plants

Following the Company’s plan to withdrawal its entire interest in petrochemical business, as set forth in BMP 2018-2022 approved in December 2017, along with the lower expectation of a successful sale of fertilizers and nitrogen products plants, triggered an impairment testing for these assets separately form the Natural Gas CGU in the last quarter of 2017. As a result, impairment losses amounting to R$ 1,337 were recognized.

e1) Oil and gas production and drilling equipment in Brazil – 2017

In 2017, impairment losses for oil and gas production and drilling equipment in Brazil that were not directly related to oil and gas producing properties amounted to R$ 1,178 , as a result of: i) lower fair value of certain equipment related to the FPSO P-72 and P- 73 that could not be committed to other projects, when compared to their carrying amount (R$ 413); ii) decommissioning of a crane and launch ferry (R$ 370) and iii) hibernation of equipment of Inhaúma Shipyard excluded from the initial scope of Inhaúma logistic center (R$ 407).

e2) Oil and gas production and drilling equipment in Brazil – 2016

Impairment losses of R$ 2,772 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 R$ 1,925 as set out in note 14.4.

f) Producing properties abroad – 2017

In 2017, impairment losses of R$ 414 were recognized for E&P assets located in the United States, principally reflecting the expected cessation of production and definitive abandonment of operation in Hadrian South field. Cash flow projection were based on: financial budgets/forecasts approved by Management; 5.7% p.a. post-tax real discount rate (5.5% p.a. in 2016) derived from the WACC for the E&P business in United States.

g) Panamax vessels – Transpetro

In December 2017, the decision to hibernate the construction of three vessels of PANAMAX project (EI-512, EI-513 and EI-514) triggered their removal from the Transpetro’s fleet of vessels CGU. These assets were assessed for impairment separately and, as a result, the Company accounted for an impairment loss for the total carrying amounts of these assets (R$ 364).

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h1) Araucária - 2017

Indications of impairment were identified during this period, such as lower sales volume and prices, as well as higher production costs. Therefore, the Company assessed the related assets for impairment and, as a result, an impairment charge of R$ 226 was recognized primarily in the second quarter of 2017 due to negative cash flow projections that were based on financial budget and forecasts approved by the management and a post-tax real discount rate of 6.6% p.a. derived for the weighted average cost of capital (WACC) for the fertilizer business.

h2) Araucária - 2016

An impairment loss of R$ 453 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. 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.

i1) Comperj - 2017

As set out in BMP 2018-2022, the resumption of the Comperj project still depends on new partnerships. However, the construction of Comperj’s first refining unit facilities that will also support the natural gas processing plant (UPGN) are 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 R$ 167 in 2017.

i2) 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 R$ 1,315 of impairment losses in 2016.

j) Conecta and DGM – 2017

Following prices forecast and current agreements of natural gas supply in Uruguay, the Company recognized impairment losses for intangible assets, in the amount of R$ 122, with respect to concession agreements for natural gas distribution carried out by the subsidiaries Conecta and DGM.

k) Suape Petrochemical Complex - 2016

An impairment loss of R$ 2,011 was recognized for Companhia Integrada Têxtil de Pernambuco S.A. - CITEPE and Companhia Petroquímica de Pernambuco S.A. – PetroquímicaSuape at September 30, 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.

l) Fertilizer Plant - UFN III - 2016

An impairment loss of R$ 497 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 the Brazilian Real against the US Dollar.

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As set out in note 4.10, whenever the recoverable amount of an asset or CGU falls below the carrying amount, an impairment loss is recognized to reduce the carrying amount to the recoverable amount. The following table presents the assets and CGU most sensitive to future impairment losses as their recoverable amounts were close to their current carrying amount. Changes in material assumptions for impairment testing may result in the recognition of additional impairment charges on such assets in future periods.

 

 

For information on the main assumptions for impairment testing, see note 5.2.

Following the Company’s Board of Director approvals of disposal of certain assets in 2017, as described in note 10, impairment losses amounting to R$ 1,152 for assets held for sale were recognized, primarily attributable to the sale of 25% interest in Roncador field.

This transaction is aligned with the Company’s business and management plan and is part of the Strategic Alliance with Statoil for sharing technology and increasing the recovery factor of the field. Impairment loss of R$ 1,314 was recognized on this transaction, as its sales price was lower than carrying amount thereof.

In 2016, the Company recognized impairment losses amounting to R$ 1,935 due to certain sales of interests in investees approved by the Board of Directors, mainly related to Suape Petrochemical Complex (R$ 1,434), Petrobras Chile Distribución (R$ 266) and Power plants Romulo Almeida and Celso Furtado (R$ 156).

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, 2017 are set out below:

 

 

Braskem’s shares are publicly traded on stock exchanges in Brazil and abroad. As of December 31, 2017 the quoted market value of the Company’s investment in Braskem was R$ 12,489 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:

For 2017, the Company accounted for R$ 64 as results in equity-accounted investments, substantially attributable to the investees Logum, Belém Bioenergia Brasil and Refinaria de Petróleo Riograndense.

In 2016, impairment losses on equity-method investments in the amount of R$ 594 were as results in equity-accounted investments, substantially attributable to investees of biofuels segment, notably the former associate Guarani (R$ 578) and the former joint venture Nova Fronteira (R$ 100).

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 R$ 1,925 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.

Based on management evaluation, in 2016 the Company recognized allowances for impairment amounting to R$ 2,353 within other expenses, net with respect to the remaining balance of advances to these suppliers in the context of the escrow accounts (R$ 1,256) and debts assumption relating to Ecovix and Enseada (R$ 1,097), in which legal procedures to recover them are being assessed.

In addition, the Company wrote-off, in 2016,  capital expenditures related to the right of use the Rio Grande shipyard in the amount of R$ 505, as well as other investments related to the P-71, P-72 and P-73 amounting to R$ 480.

The FPSOs constructions have progressed significantly after restructuring the contracts and accessing the hull. The start -ups of P-67 to P-69 and P-74 to P-76 are expected to occur in 2018, while the start -ups of P-70 and P-77 are expected in the first semester of 2019. The P-66 have been in operation since May 2017. This scenario shows the effectiveness of the strategy to enable the continuity of the work in progress of these FPSOs with no impacts in the Company’s future production curve.

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

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 R$ 375 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 R$ 764.

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 R$ 480 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 R$ 505 and, as a consequence, these assets were written-off.

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 R$ 881 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 R$ 333 within other expenses in the third quarter of 2016.

In 2016, 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. In 2017, following a review in the scope of this logistic center implementation, impairment losses of R$ 407 were recognized as shown in note 14.1.

 

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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See note 13.1 for information on signatures bonuses paid and declarations of commerciality during 2017.

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:

 

 

In 2017, the Company recognized a provision in the amount of R$ 486 (R$ 162 in 2016), arising from potential contractual penalties for not complying with the minimum percentages of local content in 118 blocks which the exploratory phases are concluded.

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 R$ 14,590. Those costs relate to 54 projects comprising (i) R$ 13,772 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) R$ 818 relate to costs incurred to evaluate the reserves and their potential development.

 

 

 

 

In line with the Company’s Business and Management Plan and following its liability management strategy, recent funds have been raised in order to settle older debts, as well as aiming at improving the debt repayment profile taking into account its alignment with investments returns over the long run. These factors have enabled the use of cash flows from operating activities and from divestments and partnerships as the main source of funds for the investments portfolio.  

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The Company has covenants that were not in default at December 31, 2017 in its loan agreements and notes issued in the capital markets requiring, among other obligations i) 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, with a grace period ranging from 30 to 60 days, depending on the agreement; ii) Negative Pledge / Permitted Liens clause; iii) clauses of compliance with the laws, rules and regulations applicable to the conduct of its business including (but not limited to) environmental laws; (iv) clauses in financing agreements that require both the borrower and the guarantor to conduct their business in compliance with anti-corruption laws and anti-money laundering laws and to institute and maintain policies necessary for such compliance; (v) clauses in financing agreements that restrict relations with entities or even countries sanctioned primarily by the United States (including, but not limited to, the Office of Foreign Assets Control (OFAC), Department of State and Department of Commerce), the European Union and United Nations; and vi) covenants with respect to debt level in some of its loan agreements with the Brazilian Development Bank (Banco Nacional de Desenvolvimento Econômico e Social - BNDES).

In 2017, proceeds from financing amounted to R$ 86,647, principally reflecting: (i) global notes issued in the capital market in the amount of R$ 32,574 (US$ 10,218 million) maturing in 2022, 2025, 2027, 2028 and 2044; (ii) debentures issued in the domestic market amounting to R$ 4,989 and maturing in 2022 and 2024; and (iii) funds raised from the domestic and international banking market in the amount of R$ 41,645 with average term of five years.

In addition, the Company used R$ 137,386 for repayment of principal and interest, mainly attributable to: (i) R$ 24,356 (US$ 7,569 million) relating to repurchase of global bonds previously issued by the Company in the capital market maturing from 2018 to 2021, with premium paid to bond holders amounting to R$ 1,067 (ii) pre-payment of banking loans in the domestic and international market totaling R$ 52,000; (iii) pre-payment of finance debt with export credit agencies, in the amount of R$ 2,963; and (iv) pre-payment of R$ 9,531 with respect to financings with BNDES.

During this period, the Company also rolled over some debts through non-cash transactions, including: (i) exchange of old notes previously issued in the international capital market, maturing from 2019 to 2021, amounting to R$ 21,217 (US$ 6,768 million), to new notes with maturities in 2025 and 2028 in the amount of R$ 23,815 (US$ 7,597 million); (ii) exchange of some debts in the domestic and international banking market maturing from 2018 to 2020, to new similar financings amounting to R$ 13,577 (US$ 4,257 million) with maturities ranging from 2020 to 2024.

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As shown in note 6.1, the IFRS 9 provisions will govern the accounting treatment for modification of contractual cash flow from January 1, 2018.

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

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

 

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 2017, the capitalization rate was 6.16% p.a. (5.80% p.a. in 2016).

 

 

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) are also collateralized, as set in note 19.5.

The loans obtained by structured entities are collateralized based on the projects’ assets, as well as liens on receivables of the structured entities.

The Company’s capital market financing relates primarily to unsecured global notes.

 

 

 

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.

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At December 31, 2017, the balance of estimated future minimum lease payments under operating leases includes R$ 174,336 in the Consolidated and R$ 174,332 in the Parent Company (R$ 161,884 in the Consolidated and R$ 161,882 in the Parent Company at December 31, 2016) with respect to assets under construction, for which the lease term has not commenced.

In 2017, the Company recognized expenditures of R$ 32,674 in the Consolidated and R$ 48,825 in the Parent Company (R$ 34,438 in the Consolidated and R$ 53,228 in the Parent Company at December 31, 2016) for operating leases installments.

As shown in note 6.1, the IFRS 16 provisions will govern the accounting treatment for operating leases from January 1, 2019.

 

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

In order to ensure the goals of the Company are achieved and align them with transparency of processes and corporate governance best practices, this policy guides Petrobras and its workforce while entering into related-party transactions and dealing with potential conflicts of interest on these transactions, based on the following assumptions and provisions:

The Audit Committee must approve in advance transactions between the Company and its associates, the Brazilian Federal Government, including its agencies or similar bodies and controlled entities, taking into account the materiality established by this policy. The Audit Committee reports monthly to the Board of Directors.

Transactions with entities controlled by key management personnel or by their close family members are also approved in advance by the Audit Committee regardless of the amount involved.

Transactions with the Brazilian Federal Government, including its agencies or similar bodies and controlled entities, which are under the scope of Board of Directors approval, must be preceded by the Audit Committee and Minority Shareholders Committee assessment and must have prior approval of, at least, 2/3 of the board members.

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 Parent Company invests in the receivables investment fund FIDC-NP, which comprises mainly receivables and non-performing receivables arising from operations performed by subsidiaries of the Petrobras Group. Investments in FIDC-NP are recognized as other receivables.

The assignment of performing and non-performing receivables is recognized as current finance debt.

 

 

Petrobras guarantees certain financial operations carried out by its subsidiaries in Brazil and abroad.

Petrobras, based on contractual clauses that support the financial operations between the subsidiaries and third parties, offers guarantees, mainly fidejussory, to the payment of debt service in the event that a subsidiary defaults on a debt.

The outstanding balance of financial operations carried out by these subsidiaries and guaranteed by Petrobras is set out below:

 

 

Petrobras entered into 3 finance agreements with China Development Bank (CDB), maturing in 2019, 2026 and 2027 are also collateralized based on future oil exports for specific buyers limited to 400 thousand barrels per day up to 2019, 300 thousand barrels per day from 2020 to 2026, and 100 thousand barrels per day in 2027. This collateral may not exceed the amount of the related debt, amounting to R$ 35,775 (US$ 10,815 million) at December 31, 2017, and to R$ 30,011 (US$ 9,208 million) at December 31, 2016.

On January 30, 2018, the Company prepaid the remaining balance of the financing agreement with CDB maturing in 2019, in the amount of US$ 2.8 billion, as set out in note 35.1. After this settlement, the new limits for the collateralization based on future oil exports are 200 thousand barrels per day up to 2019, 300 thousand barrels per day from 2020 to 2026, and 100 thousand barrels per day in 2027.

In accordance with the Company’s Business and Management Plan (BMP 2018-2022), the extension of these terms is associated to a better indebtedness level, as set out in note 17.

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At December 31, 2017, a subsidiary of PIB BV had R$ 4,675 (R$ 10,389 at December 31, 2016) invested in an investment fund abroad that held debt securities of PGF, PDET and of consolidated structured entities, mainly with respect to the following projects: CDMPI and Charter.

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:

 

 

In addition to the aforementioned transactions, Petrobras and the Brazilian Federal Government entered into the Assignment Agreement, in 2010, which grants the Company the right to carry out prospecting and drilling activities for hydrocarbons located in the pre-salt area limited to the production of five billion barrels of oil equivalent.

For detailed information on Assignment Agreement, see note 12.3.

At December 31, 2017, the balance of receivables related to the Petroleum and Alcohol accounts is R$ 829 (R$ 875 at December 31, 2016). 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 provided all the information required by the National Treasury Secretariat (Secretaria do Tesouro Nacional - STN) in order to resolve disputes between the parties and conclude the settlement with the 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.

On July 18, 2017, the Brazilian Federal Government appealed the ruling and the court assessment of this appeal is pending.

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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 December 2017 and December 2016 were:

 

 

The total compensation of Executive Officers and Board Members of Petrobras parent company is set out as follows:

 

 

In 2017, the board members and executive officers of the Petrobras group received R$ 77.4 as total compensation (R$ 81.4 in 2016).

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 accordance with Brazilian regulation applicable to companies controlled by the Brazilian Government, Board members who are also members of the Audit Committee are only compensated with respect to their Audit Committee duties. The total compensation concerning these members totaled R$ 302 thousand in 2017 (R$ 362 thousand with social security and related charges).

The general meeting, held on April 27, 2017, fixed monthly compensation of Audit Committee members to 10% of monthly average executive officers’ compensation, excluding certain social security benefits and paid vacation.

 

 

 

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 and whenever an indication of significant change in the assumptions used in the estimates occurs.

In 2017, the adjustment to this provision in the amount of R$ 13,522 primarily reflected the decrease in the risk-adjusted discount rate from 7.42% p.a. in 2016 to 5.11% p.a. in 2017, which was affected by the improved market risk perception, as well as due to an acceleration of fields abandonment regarding certain projects.

 

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In 2017, the Company joined certain settlement programs created by the Brazilian Federal Government, which enabled the settlement of significant disputes in which the Company was a defendant (see note 30), with certain benefits, such as the use of tax loss carry forwards and reduction in interests, penalties and related charges. The settlement of disputes involving Brazilian Federal Tax Authorities, Brazilian Federal Agencies and similar bodies reduced tax disputes amounting to R$ 38,136 that as shown below:

 

 

The balances of respective liabilities carried on the statement of financial position as of December 31, 2017 are shown below:

 

 

The following table presents the settlement years of the outstanding amount of these programs:

 

The PRT enabled relief for the settlement of tax and non-tax debts overdue up to November 30, 2016 to the Brazilian Federal Tax Authorities (Brazilian Federal Revenue Service and National Treasury Attorney's Office).

The Company joined the program to settle, principally, proceedings at administrative level totaling R$ 1,660, for which outflow of resources were probable, related to disallowed tax credits applied for income taxes and other Brazilian Federal taxes computation.

After assessing the reliefs provided by the PRT, the Company decided to settle the total debt of these tax disputes (R$ 1,660) with the benefit of using tax loss carry forwards to pay R$ 1,328, of which R$ 821 was already used at December 31, 2017 and the remaining R$ 507 is expected to be used in up to 12 months. The amount of R$ 332 was settled in a lump sum payment.

After joining the PRT in May 2017, the Company recognized a reversal of provisions for legal proceedings previously recognized for this matter in the amount of R$ 1,560. The impacts of this program were accounted for in the second quarter of 2017 within the Company’s statement of income amounting to R$ 264 after tax effects, as shown in note 21.2.5.

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The PERT enabled relief for the settlement of tax and non-tax debts overdue up to April 30, 2017 to the Brazilian Federal Tax Authorities (Brazilian Federal Revenue Service and National Treasury Attorney's Office), including amounts under disputes involving these authorities.

The Company elected to join the PERT to settle the legal proceeding, in the amount of R$ 6,541, with respect to a notice of deficiency issued due to the use of expenses arising from the Terms of Financial Commitment (TFC), signed by Petrobras and Petros Plan in 2008, as deductible in determining taxable profit. The TFC represents a commitment to cover obligations due to participants’ accepted changes in the plan benefits and disputes resolved at that period.

The court ruled on this matter in the second quarter of 2017 granting the deduction of these expenses from the taxable profit computation, but limited the deduction to 20% of the payroll and compensation of key management participants in the plan. After assessing the fundamentals of this court ruling, the Company reassessed the probability of outflow of resources with respect to this dispute and estimated a portion of it as probable.

The Company was not able to use tax loss carry forwards to settle this amount as this tax dispute was in the scope of the National Treasury Attorney's Office. Accordingly, an assessment of the other reliefs was performed and, as a result, the Company decided to settle this tax dispute, totaling R$ 6,541, by paying R$ 4,356, which takes into account the benefits reliefs on interests, penalties and related charges. Of this amount, R$ 1,344 was settled up to December 2017, and the remaining amount will be settled through 145 monthly installments bearing interest from January 2018 onwards.

In addition, pursuant the law 13.496 enacted on October 24, 2017, which enabled incremental relief relating to this matter, the remaining amount was recalculated and decreased by R$ 779, reaching R$ 2,295 that bears interest at Selic interest rate (Brazilian short-term interest rate).

Pursuant to the Provisional Measure 807/2017 enacted on October 31, 2017, the period to join this program was extended from August 31 to November 14, 2017. Therefore, the Company decided in the third quarter of 2017 to settle other disputes relating to debts in the scope of the Brazilian Federal Revenue Service amounting to R$ 718, following unfavorable court rulings that changed the Company’s estimates about probability of outflow of resources to probable. After the relief under the PERT, the total amount of these disputes was reduced to R$ 394, of which R$ 325 was settled in January 2018 through a lump sum payment, and the remaining amount will be paid through 141 monthly installments. These disputes refer to:

Accordingly, the Company recognized the amount of R$ 5,905 within the statement of income in 2017, made up of tax debts after reliefs and tax effects amounting to R$ 3,582, reversals of deferred income tax assets for unused tax losses from 2012 to 2017 amounting to R$ 2,287 and indexation charges of R$ 71.

The PRD enabled relief for the settlement of non-tax debts overdue to the Brazilian Federal Agencies and similar bodies up to October 25, 2017, including amounts under disputes and debts in the scope of other settlement programs involving these authorities.

The Company joined the PRD to settle some legal proceedings involving ANP, with respect to production tax debts for which the likelihood of losses were deemed probable, following a court ruling in August 2017 granting to ANP its arguments.

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After assessing the benefits from relief on interest, penalties and related charges provided for by this program, the Company decided to settle these disputes, totaling R$ 1,076 by paying R$ 718, of which R$ 430 was settled payment in the fourth quarter of 2017 and the remaining amount in January 2018.

Accordingly, the Company recognized R$ 519 within the statement of income in December 31, 2017, after tax effects, as shown in note 21.2.5.

As presented in note 21.4, the law 13,586 enacted on December 28, 2017, formerly Provisional Measure 795/17, provided for the tax treatment of several relevant issues relating to the exploration and production of oil or natural gas. This law also established the settlement program of withholding income tax on remittances abroad related to charter contracts for vessels, enabling the regularization of events occurred in the period from 2008 to 2014.

The decision to join the program was based on the economic benefits thereof. Proceeding with the disputes would involve financial efforts to provide significant judicial deposits and this program gave rise to the possibility of ceasing disputes at administrative and judicial levels related to the period from 2008 to 2013 in the amount of R$ 28,141, as well as amounts relating to the 2014 not yet under dispute. The company will pay R$ 1,723 in 12 consecutive installments bearing interest at SELIC rate, of which the first was paid in January 2018.

Accordingly, the Company recognized R$ 1,137 within the statement of income in December 31, 2017, after tax effects, as shown in note 21.2.5.

 

 

In 2017, the Company elected to settle in cash VAT (ICMS) tax disputes concerning the states of Amazonas, Ceará, Minas Gerais and Pernambuco by joining states amnesty settlement programs, which exempted the company from having to pay interest and penalties. Accordingly, the Company charged R$ 376 as other taxes.

 

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On December 28, 2017, the Brazilian Federal Government signed the Provisional Measure No. 795 into Law. 13,586 which outlines tax requirements applicable to the oil and gas exploration and development activities and also establishes a special regime for exploration, development and production of oil, gas and other liquid hydrocarbons..

It is expected that there will be greater stability and legal security in the industry following this new tax regulation model, allowing an increase in investments and a reduction in litigation. The main provisions of this law are presented below:

As set out in note 21.2.4, this law established a tax settlement program relating to withholding income tax on remittances for payment of vessels charters through 2014, enabling the company to settle disputes thereof.

In addition, the Social Integration Program (PIS) and Contribution to Social Security Financing (COFINS) rates over diesel and gasoline sales were increased pursuant to the Decree 9,101 enacted in July 2017. This tax burden was taken into account in the sale prices and, as a consequence, there was a significant increase in these taxes charges in 2017.

Conversely, the Brazilian Federal Supreme Court, in October 2017, ruled on the inclusion of amount of VAT tax within the computation basis of PIS and COFINS. According to its decision, sales revenues do not include the amount of VAT. Therefore, VAT must not be taken into account in determining the amount of PIS and COFINS.

ANP Resolution 703/2017

ANP enacted the Resolution No. 703 on September 26, 2017, establishing new criteria for reference price for the calculation of production taxes. The new calculation will be effective on January 1, 2018 and will be applied gradually until 2022, starting from a percentage of 20% according to the new rules. The new reference price for production taxes calculation takes into account different characteristics of the product in each exploratory area.

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a) VAT (ICMS) tax and state rate over transactions involving crude oil operations State Law

On December 30, 2015, the state of Rio de Janeiro enacted laws that increased the tax burden on the oil industry since 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.

b) VAT (ICMS) tax incentives over the Repetro-Sped

Following the creation of Repetro-Sped pursuant to the new requirements provided for Provisional Measure No. 795 into Law. 13,586/2017 (see note 21.4.3), the Brazilian Federal Government authorized its states to provide tax incentives relating to VAT (ICMS)  tax with direct impacts on the oil and gas industry.

Pursuant to the ICMS Convention 03/2018 enacted on January 17, 2018, ratified on February 1, 2018, Brazilian Federal Government authorized its states to reduce the basis of VAT (ICMS) tax computation on imports or sale in the domestic market of goods with definitive permanence, as well as VAT (ICMS) exemption on import of goods with temporary permanence in Brazil. In addition, VAT (ICMS) exemption for goods migrating from the old to the new tax regime was also provided for.

At the date of issue of these financial statements, the State of Rio de Janeiro and the State of São Paulo were the only states enacting new regulations governing the tax incentives authorized by the Brazilian Federal Government.

 

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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. The changes in the deferred income taxes are presented as follows:

 

 

 

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Deferred tax assets were recognized based on projections of taxable profit in future periods supported by the Company’s 2018-2022 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 reversed and expected taxable events occur, based on its 2018-2022 BMP.

The estimated schedule of recovery/reversal of net deferred tax assets (liabilities) recoverable (payable) as of December 31, 2017 is set out in the following table:

 

 

At December 31, 2017, the Company had tax loss carryforwards arising from offshore subsidiaries, for which no deferred tax assets had been recognized. These tax losses totaling R$ 8,799 (R$ 8,252 at December 31, 2016) arose mainly from oil and gas exploration and production and refining activities in the United States of R$ 7,837 (R$ 7,416 at December 31, 2016), as well as activities in Spain in the amount of R$ 959 (R$ 834 at December 31, 2016).

An aging of the unrecognized tax carryforwards, from companies abroad 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:

 

 

 

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The following table presents the balances of post-employment benefits:

 

 

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

Petros Foundation has committees for assessing and resolving on risk management matters, mainly an Integrity Program Against Harmful Acts, established in 2017, with the purpose of improving its corporate governance.

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 Foundation 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.

As of December 31, 2017, the balance of the Terms of Financial Commitment (TFC), signed by Petrobras and Petros Foundation in 2008 is R$ 12,307 (R$ 11,902 in the Parent Company). The TFC 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 R$ 13,454, updated in the third quarter of 2017 to reflect the increase in the commitments assumed in the TFC.

The employers' expected contributions to the plan for 2018 are R$ 728 (R$ 692 in the Parent Company) and interest payments on TFC R$ 735 (R$ 710 in the Parent Company).

The average duration of the actuarial liability related to the plan, as of December 31, 2017, is 12.51 years (13.06 years as of December 31, 2016).

Deficit settlement plan – Petros Plan

Petros Foundation’s financial statements for 2016 were approved by the Executive Council of Petros Foundation on May 26, 2017 and presented an accumulated deficit of R$ 26.7 billion (R$ 22.6 billion accumulated until 2015) in the Petros Plan, according to the general accepted accounting standards for the post-retirement sector, regulated in Brazil by the Post-Retirement Benefit Federal Council – CNPC.

The deficit determined by Petros Foundation is annually calculated by an independent actuary and is already recognized in the Company’s financial statements in accordance with IFRS.

On June 19, 2017, the Superintendency of Post-retirement Benefits (PREVIC) issued the Conduct Adjustment Declaration (TAC) for Petros Plan, determining a deadline for the implementation of its plan for reduction of the accumulated deficit computed at the end of 2015.

On September 12, 2017, the Executive Council of Petros Foundation approved the deficit of the year 2015 amounting to R$ 22.6 billion. This amount was updated based on interest and inflation and reached R$ 27.3 billion at December 31, 2017.

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The Company and the Secretariat of Management and Governance for the State-owned Companies (Secretaria de Coordenação e Governança das Empresas Estatais – SEST) assessed the deficit settlement plan and additional contributions from participants and sponsors will commence in March 2018.

Pursuant to relevant regulation, the sponsors and participants will cover this deficit based on their respective proportions of regular contributions. Accordingly, the Parent Company and BR Distribuidora will cover approximately R$ 12.8 billion and R$ 0.9 billion, respectively, of this deficit and the contributions will occur for 18 years through decreasing values. The estimated amounts expected for the first year are R$ 1.4 billion and R$ 89, from these two companies.

The additional contributions of the participants during their employed and assisted phases were considered in the actuarial evaluation of 2017, reducing the present value of the obligation, in the amount of R$ 13.7 billion, while the additional contributions of the sponsor will reduce the actuarial obligation at the time of the disbursement, without impacting the income statement.

Split of Petros Plan

On February 15, 2018, the PREVIC authorized the split of Petros Plan, expected to occur on March 31, 2018, into two separate plans: Petros Plan – Renegotiated and Petros Plan – Non-renegotiated.

This split arises from the renegotiation procedures held in 2006-2007 period and in 2012, when 75% of the participants accepted the option to change to a model that sets forth solely inflation indexation on the annual adjustment of their benefits. The other participants’ benefits remained adjusted by the same rate as the Petrobras’ workforce had their salaries adjusted.

Petros Foundation will assess the effect of the split on the deficit settlement plan, whose additional contributions will commence in March 2018. The results of this study may trigger a revision of the settlement plan in 2019.

Reconciliation between results registered by Petros and the Company

The table below presents the reconciliation of the deficit of Petros Plan registered by Petros Foundation, according to the standards issued by CNPC, and by sponsor Petrobras, according to international accounting standards (IAS 19):

 

 

The main differences are:

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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, Petrobras Biocombustível and 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 R$ 936 in 2017 (R$ 809 in the Parent Company).

The defined benefit portion of the contributions was suspended from July 1, 2012 to June 30, 2018, as determined by the Executive Council of Petros Foundation, based on advice of the actuarial consultants from Petros Foundation. Therefore, the entire contributions are being applied to the individual accounts of plan participants.

For 2018 the employers' expected contributions to the defined contribution portion of the plan are R$ 922 (R$ 793 in the Parent Company).

The average duration of the actuarial liability related to the plan, as of December 31, 2017 is 43.53 years (43.20 at December 31, 2016).

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.

The actuarial liability of the subsidiary Liquigás is reclassified as held for sale, as set out in note in note 10.2.

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.

Petros Foundation 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 2018 and 2022 for the Petros Plan are 45% 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 5% in structured finance projects. Allocation limits for Petros 2 Plan for the same period are: 65% to 90% in fixed-income securities, 5% to 20% in variable-income securities, 0% to 5% in real estate, 2% to 8% in loans to participants, 0% to 5% 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, 2017, the investment portfolio included debentures of R$ 105, Company’s common and preferred shares in the amount of R$ 47 and R$ 67, respectively, and real estate properties leased by the Company in the amount of R$ 1,312.

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

In 2017, the Company improved its monitoring model over Petros Foundation, mainly: enhancement on internal controls over investment portfolio; establishment of specific committees to provide technical advisory for the members indicated by the Company to the Executive and Fiscal Councils of Petros Foundation, in accordance with relevant regulation establishing practices to be performed by the Board of Directors and Executive Officers of the sponsors.

Petrobras, Petrobras Distribuidora S.A., Petrobras Transporte S.A. – Transpetro, Petrobras Biocombustível, Transportadora Brasileira Gasoduto Brasil-Bolívia - TBG and Termobahia 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, of which the Company satisfies 70% of these costs as governed by the collective bargaining agreement.

The average duration of the actuarial liability related to this health care plan, as of December 31, 2017, is 22.08 years (22.04 as of December 31, 2016).

 

 

 

 

 

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CGPAR resolutions

On January 18, 2018, the Inter-ministerial Commission for Corporate Governance and Administration of Participations of the Union (CGPAR), through CGPAR Resolutions 22 and 23, established guidelines and parameters of governance and cost limits to health care plans operated by state-owned companies.

The main objective of the resolutions is to make feasible the sustainability and the economic, financial and actuarial balance of the health plans operated by state-owned companies.

The company has up to 48 months to adjust the AMS health plan to this new regulation provisions and is assessing the financial impacts it may cause, including among others, a possible decrease in its actuarial liability following the parity basis of contribution, between the Company and the participants, determined by this rule.

 

 

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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 R$ 8 in 2017 were recognized in the statement of income.

 

The Company’s profit sharing benefits comply with Brazilian legal requirements and those of the Brazilian Secretariat of Coordination and Governance of State‐Owned Enterprises (SEST), of the Ministry of Planning, Budget and Management, and of the Ministry of Mines and Energy, and are computed based on the consolidated net income attributable to the shareholders of Petrobras.

The amount of profit sharing benefits is computed based on the results of six corporate indicators, for which annual goals are defined by the Executive Board and approved by the Board of Directors pursuant to the review of the Business and Management Plan (BMP). The annual goals are based on the results of the following corporate indicators:

The results of the six individual goals are factored into a consolidated result that will determine the percentage of the profit to be distributed as a profit sharing benefit to employees. However, in the event the Company records a net loss for the period and all the annual goals are achieved, the profit sharing benefit will be half a month salary for each employee added to half of the lowest amount of profit sharing paid in the prior year, as established in the Company’s collective bargaining agreement in force until March 2019.

The consolidated entities Liquigás, FCC and Ibiritermo have specific methodology for their profit sharing computation, negotiated in their own collective bargaining agreement, apart from other consolidated entities of the group.

Although the loss attributable to shareholders of Petrobras recognized for 2017, the annual goals were achieved and, as a result, the company accounted for profit sharing benefits, within other income and expenses, in accordance with clauses of the collective bargaining agreements.

 

 

 

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From January 2014 to December 31, 2017, the Company implemented voluntary separation incentive plans (PIDV) as presented below:

 

 

As of December 31, 2017 changes in the provision are set out as follows:

 

As of December 31, 2017 and December 31, 2016, subscribed and fully paid share capital was R$ 205,432, 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.

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

It includes any excess of amounts paid/received over the carrying value of the interest acquired/disposed. Changes in interests in subsidiaries that do not result in loss of control of the subsidiary are equity transactions, such as the change in BR Distribuidora, as set out in note 10, which amounted to R$ 1,597, net of tax.

It 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.

 

 

 

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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 period from 2014 to 2017, to be allocated to the tax incentives reserve in upcoming periods, is R$ 129.

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 R$ 436 as of December 31, 2017 will be allocated to the profit retention reserve.

In 2017, 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 2017 and 2016, 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.

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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) are identical as the Company has no potential share in issue.

 

 

 

Sales revenues increased in 2017 due to higher revenues in foreign market, reflecting the increase in crude oil volume exported as a result of a higher domestic production, along with the downturn in the sales volume of oil products in the domestic market due to the higher portion of products from importers. The higher international prices of crude oil and oil products were also a contributing factor to the increase in export revenues. This effect was partially offset by operations abroad, especially due to the sale of Petrobras Argentina S.A. (PESA) and Petrobras Chile Distribución Ltda (PCD).

The decrease in net revenues in the domestic market reflects the downturn in the sales volume of oil products and decrease in diesel and gasoline prices due to the aforementioned higher portion of products from importers.

This decrease was partially offset by: higher average realization prices for other oil products, such as liquefied petroleum gas and jet fuel following the increase in their international prices; higher electricity revenues due to higher thermoelectric dispatches with higher prices in the spot market, as a result of worsen hydrological conditions; and higher natural gas revenues, as a result of higher thermoelectric dispatches with higher prices.

In 2017, there was no customer whose sales revenues expressed 10% or more of the Company’s sales revenues. In 2016, sales from transactions with two customers reached approximately 10% or more of the Company’s sales revenue, totaling R$ 30,156 and R$ 26,743. These sales revenues mainly impacted the Refining, Transportation and Marketing (RT&M) business segment.

As shown in note 6.1, IFRS 15 provisions will govern the accounting treatment for revenues from contracts with customers from January 1, 2018.

 

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Other income and expenses increased when compared to 2016, mainly due to:

These effects were partially offset by:

 

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Decrease in cost of sales reflects:

These effects were partially offset by:

Selling expenses increased in 2017, mainly due to higher transportation charges by the use of third parties gas pipelines, following the sale of Nova Transportadora do Sudeste (NTS), partially offset by lower impairment of trade and other receivables, primarily relating to companies from the electricity sector, and the effects of the sale of PESA and PCD.

General and administrative expenses decreased in 2017, primarily due to lower personnel expenses, following the separations under the Voluntary Separation Incentive Plan 2014/2016, and to lower expenses with outsourced administrative services.

 

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Net finance expenses increased in 2017, mainly due to:

These effects were partially offset by lower financing expenses, due to pre-payment of debts (as set out in note 17).

 

 

 

 

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

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In 2017, the Company presented higher income before finance expense, results in equity-accounted investments and income taxes, due to the increase in oil exports and oil products at higher prices, reduction in personnel expenses, gain on the sale of interests in NTS, and the decrease in impairment of assets. Conversely, the agreement to settle the class action in the United States and the adherence to the Brazilian Federal Settlement Programs, important actions to reduce risks and uncertainty, offset the increase in income before finance expense, results in equity-accounted investments and income taxes. Most of the operating segments contributed to this increase.

The gross profit of the Exploration and Production segment increased due to higher oil prices and lower depreciation, partially offset by the increase in production taxes expenses. These factors, together with impairment reversals and lower idleness expenses, resulted in a significative increase in operational performance.

The gross profit of the Refining, Transportation and Marketing segment decreased mainly due to higher cost of sale, influenced by rise in Brent and domestic oil prices, as well as reduction in oil products sales volume in the domestic market. Because of these factors, the operational performance also presented a decrease, although partially offset by reduction in sales expenses, expenses associated to voluntary separation plans and impairment of assets.

The gross profit of the Gas & Power segment increased due to growth of natural gas sales, at higher prices, and increase in the participation of national gas in the sales mix. These factors, combined with the gain on the sale of Company’s interest in NTS, led to an increase in operational performance, although partially offset by increase in impairment of assets.

The gross profit of Distribution segment decreased reflecting the reduction in the sales volumes and market share of oil products, mainly due to the higher participation of third parties and to the decrease in the diesel sales volumes to thermoelectric plants, resulting from the strategy to keep the margins and maximize profitability, which led to a higher sales selectivity. Conversely, the operational performance presented an increase, mainly reflecting the reduction of allowance for impairment of trade receivables, reduction of provisions for legal proceedings, as well as the reversal of expenses with voluntary separation plan, charged in 2016.

 

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:

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Provisions for legal proceedings are set out as follows:

 

 

 

 

In preparing its financial statements for the period ended December 31, 2017, the Company considered all available information concerning legal proceedings in which the Company is a defendant, in order to estimate the amounts of obligations and probability that outflows of resources will be required.

Excluding foreign exchange translation effects (see note 2), the main changes in the provision for legal proceedings in 2017 were primarily attributable to the class action agreement provisioned in the last quarter, to unfavorable court rulings that changed probabilities of outflows of resources relating to certain claims to probable, as well as indexation charges over the balance of provision, as presented below:

Provision for labor claims increased R$ 518 mainly due to the assessment of court rulings on several labor disputes occurred during this period and to indexation charges over the balance of provision, partially offset by the reversion of a provision made to a claim filed by Sindipetro Norte Fluminense relating to the methodology used to consider overtime into the calculation of paid weekly rest following a favorable decision on the Company’s appeal granted by the Superior Labor Court ("Tribunal Superior do Trabalho - TST").

Provision for tax claims decreased R$ 916 primarily reflecting the reversion of a provision previously recognized in 2016 with respect to disallowed tax credits applied for income taxes and other Brazilian Federal taxes computation, following the Company’s decision to benefit from the Special Tax Settlement Program (Programa Especial de Regularização Tributária - PRT), as shown in note 21.2.1.

In addition, there were some provisions recognized and reversed during this period due to unfavorable court rulings and the decision to settle them along with the reliefs provided by the PRT, relating to:

 

 

 

 

 

 

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Provision for civil claims increased following the agreement to settle the Consolidated Securities Class Action, as set out in note 30.4.1, assessment of court rulings occurred in this period denying the Company’s appeals with respect to production taxes collection over gas production in Urucu field, fines imposed by ANP relating to measurement systems and other civil claims, as well as indexation charges over the balance of provisions.

In addition, there were some provisions recognized and reversed during 2017, due to settlements reached and unfavorable rulings payed and joined to PRD, in respect of:

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

 

 

 

 

In 2017, the Company made judicial deposits in the amount of R$ 5,155, mainly resulting from an unfavorable decision issued by the Regional Federal Court of Rio de Janeiro (Tribunal Regional Federal – TRT/RJ) in October 2017, which respect to withholding income tax on remittances for payments of vessel charters occurred from 1999 to 2002, as set out in note 30.3.

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 estimates of contingent liabilities for legal proceedings are indexed to inflation and updated by applicable interests. As of December 31, 2017, estimated contingent liabilities for which the possibility of loss is not considered remote are set out in the following table:

 

 

 

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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, Petrobras International Finance Company S.A. (“PifCo”), Petrobras Global Finance B.V. (“PGF,” and collectively with the Company and PifCo, the “Petrobras Defendants”), certain underwriters of debt securities (the “Underwriter Defendants”), among other defendants (the “Defendants”), in the United States District Court for the Southern District of New York (“SDNY” or the “District Court”). These actions were consolidated on February 17, 2015 (the “Consolidated Securities Class Action” or “Class Action”). The Court appointed a lead plaintiff, Universities Superannuation Scheme Limited (“USS”), on March 4, 2015. In sum and substance, the complaints in the Consolidated Securities Class Action asserted claims under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Securities Act of 1933, as amended (the “Securities Act”), alleging that in the Company’s press releases, filings with the U.S. Securities and Exchange Commission (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.

In addition to the Consolidated Securities Class Action, 33 lawsuits were filed by individual investors before the same judge in the SDNY, and one was filed in the United States District Court for the Eastern District of Pennsylvania (collectively, the “Individual Actions”), consisting of allegations similar to those in the Consolidated Securities Class Action.

Between August 2015 and December 2015, the Company and certain other defendants made motions to dismiss the complaints and amended complaints in the Consolidated Securities Class Action and certain of the Individual Actions. Certain, but not all, of the claims were definitively dismissed and others were dismissed but with leave to re-plead. Thus, the actions continued against the Company and other defendants with respect to certain claims. Following the motion to dismiss stage, the complaint that was then considered operative for the subsequent proceedings in the Class Action was the fourth consolidated amended complaint (“FAC”) filed on November 30, 2015 by plaintiff USS, Employees’ Retirement System of the State of Hawaii (“Hawaii”), North Carolina Department of State Treasurer (“North Carolina”) (collectively, “Class Plaintiffs”), and one other plaintiff whose claims were later dismissed.

The judge scheduled a consolidated trial for the Class Action and the Individual Actions to begin on September 19, 2016, except that the judge ordered that any Individual Actions filed in the SDNY after December 31, 2015 would be stayed in all respects until after the completion of the trial. Six of the Individual Actions have been stayed as a result of this order.

On February 2, 2016, the judge granted Class Plaintiffs’ motion for class certification, certifying a class under the Securities Act represented by Hawaii and North Carolina (the “Securities Act Class”) and a class under the Exchange Act represented by USS (the “Exchange Act Class”). The Securities Act Class was defined, in relevant part, as all purchasers who purchased or otherwise acquired debt securities issued by Petrobras, PifCo, and/or PGF, in domestic transactions, directly in, pursuant and/or traceable to public offerings on May 15, 2013 and March 11, 2014, and were damaged thereby. The Exchange Act Class was defined, in relevant part, as all purchasers who, between January 22, 2010 and July 28, 2015, purchased or otherwise acquired Petrobras securities, including debt securities issued by PifCo and/or PGF on the New York Stock Exchange or pursuant to other domestic transactions, and were damaged thereby.

On June 15, 2016, the United States Court of Appeals for the Second Circuit (“Second Circuit”) granted the Petrobras Defendants’ (and other defendants’) motion requesting interlocutory appellate review of the District Court’s class certification of the Class Action. The Petrobras Defendants (and other defendants) moved in District Court for a stay of all District Court proceedings, which the district judge denied on June 24, 2016 and, on June 27, 2016, the parties filed motions for summary judgment. The Petrobras Defendants (and other defendants) then moved in the Second Circuit for a stay of all District Court proceedings. On August 2, 2016, the Second Circuit granted the motion to stay all District Court proceedings during the pendency of the appeal.

Between on or about October 21, 2016 and September 13, 2017, Petrobras’ board of directors approved agreements to settle 21 of the Individual Actions (the “Settled Individual Actions”), leaving 13 remaining pending Individual Actions (six of which had been stayed since filed) (the “Pending Individual Actions”). The terms of the settlements for the Settled Individual Actions are confidential and Petrobras denies all allegations of wrongdoing. The settlements are aimed at eliminating the uncertainties, burdens and expense of ongoing litigation.

Based on the settlements reached in the Settled Individual Actions and advanced stages of negotiations in certain other Pending Individual Actions, the Company charged R$ 1,476 to statement of income as other income and expenses (R$ 261 in 2017 and R$ 1,215 in 2016).

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On July 7, 2017, the Second Circuit vacated, in part, the class certification decision in the Class Action and remanded the case to the District Court for further proceedings. The Second Circuit partially granted the appeal by the Petrobras Defendants (and other defendants), reversing some aspects of the District Court’s ruling and affirming others. Among other issues, the Second Circuit ruled that the district judge failed to consider whether the question of whether the transactions occurred in the United States could be determined through a common set of evidence, and whether, if not, common issues would predominate over individual ones. The effect of the Second Circuit’s decision was to vacate the classes certified by the District Court pending additional proceedings in the District Court on remand.

On July 21, 2017, the Petrobras Defendants (and other defendants) filed a request for rehearing or en banc rehearing with the Second Circuit regarding portions of the Second Circuit’s decision affirming the District Court’s order, which was denied on August 24, 2017.

On November 1, 2017, the Petrobras Defendants (and other defendants) filed a petition for writ of certiorari in the United States Supreme Court appealing the Second Circuit’s decision. On November 3, 2017, the Second Circuit granted the Company’s unopposed motion to stay the mandate, which was filed by Petrobras on August 30, 2017.  

At the end of December 2017, the Company signed an agreement to settle the Consolidated Securities Class Action, which is still subject to court approval (the “Class Action Settlement”).

The Class Action Settlement is intended to resolve all pending and prospective claims by purchasers of Petrobras securities in the United States and by purchasers of Petrobras securities that are listed for trading or that clear or settle through the Depository Trust Company in the United States, including the Pending Individual Actions. Under the Class Action Agreement, the parties have agreed to the certification, for settlement purposes only, of a new class defined as all persons who (i) during the time Period between January 22, 2010 and July 28, 2015, inclusive (the “Class Period”), purchased or otherwise acquired Petrobras Securities, including debt securities issued by PifCo and/or PGF, on the New York Stock Exchange or pursuant to other Covered Transactions; and/or (ii) purchased or otherwise acquired debt securities issued by Petrobras, PifCo, and/or PGF, in Covered Transactions, directly in, pursuant and/or traceable to a May 13, 2013 public offering registered in the United States and/or a March 10, 2014 public offering registered in the United States before Petrobras made available to its security holders an earnings statement covering a period of at least twelve months beginning after the effective date of the offerings (i.e. before August 11, 2014 in the case of the May 13, 2013 public offering and before May 15, 2015 in the case of the March 10, 2014 public offering). Covered Transactions is defined to mean (i) any transaction in a Petrobras Security listed for trading on the New York Stock Exchange (“NYSE”); (ii) any transaction in a Petrobras Security that cleared or settled through the Depository Trust Company’s book-entry system; or (iii) any transaction in a Petrobras Security that otherwise qualifies as “domestic” under the Supreme Court’s decision in Morrison v. National Australia Bank, 561 U.S. 247 (2010). Excluded from the definition of Covered Transaction are purchases of any Petrobras Security on the Brazilian Stock Exchange (B3).

If approved, the Class Action Settlement eliminates the risk of an adverse judgment which, as Petrobras has previously reported, could have a material adverse effect on the Company and its financial situation, and puts an end to the uncertainties, burdens and costs of protracted litigation.

Under the Class Action Settlement, Petrobras (together with its subsidiary PGF) has agreed to pay R$ 9,759 (US$ 2,950 million) to resolve claims in two installments of R$ 3,252 (US$ 983 million) and a further installment of R$ 3,255 (US$ 984 million). The first installment was paid on March 1, 2018. The second installment will be paid within 10 days of final approval of the Class Action Settlement. The third installment will be paid by the later of (i) six months after final approval, or (ii) January 15, 2019. Accordingly, the Company charged R$ 11,198 to its statement of income for the last quarter of 2017 as other expenses and income, taking into account the gross up of tax related to the Petrobras’s portion of the settlement.

On January 16, 2018, United States Supreme Court granted a joint motion to defer consideration of Petrobras’ petition for a writ of certiorari, pending final approval of the Class Action Settlement.

A stipulation between the settling parties containing the terms of the Class Action Settlement was submitted to the District Court for preliminary approval. On February 23, 2018, the District Court held a hearing on preliminary approval of the settlement, and subsequently granted preliminary approval on February 28, 2018. Notice will be provided to potential class members who will have an opportunity to opt out of the settlement and make any objections to the District Court, which the District Court will then review.

After the notice and objection period, the District Court is scheduled to hold a hearing on June 4, 2018 to determine whether to grant final approval of the Class Action Settlement. If final approval is not granted by the District Court, or if the settlement does not become final for any other reason, the Company will return to its position prior to the Class Action Settlement and, depending on the outcome of the subsequent litigation, the Company might 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.

Individuals are seeking measures against Petrobras in Brazil to annul and/or suspend the Class Action Settlement. No adverse action has been taken to date against the settlement.

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The plaintiffs in the Pending Individual Actions will be eligible to participate in the settlement. These plaintiffs will also have the option to opt out of the Class Action Settlement and, if they do, any such actions will continue.

The Pending Individual Actions 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, and analysis by retained experts. Except as set forth above,  the Company is unable to determine at this time whether the plaintiffs in the Pending Individual Actions will determine to participate or not in the Class Action Agreement or to make a reliable estimate of eventual loss, if any, arising from certain Pending Individual Actions if they determine to opt out of the Class Action Agreement.

The Company intends to defend these actions vigorously.

On January 23, 2017, the Stichting Petrobras Compensation Foundation (“Foundation”) filed a class action before the district court in Rotterdam, in the Netherlands, against Petrobras and its subsidiaries Petrobras International Braspetro B.V. (PIBBV) and Petrobras Global Finance B.V. (PGF); joint venture Petrobras Oil & Gas B.V. (PO&G), and some former managers of Petrobras.

This Foundation allegedly represents an unidentified group of investors and demands judicial remedies for alleged damages caused to investors who purchased securities issued by Petrobras and PGF outside the United States, before July 28, 2015, due to alleged illegal acts. The Foundation also alleges financial losses are connected to the facts uncovered by the Lava-Jato investigation and to purported false and misleading financial information released by the Company.

Petrobras, PGF, PIBBV and PO&G filed their first response to the claim on May 3, 2017 (first docket date), presenting the law firms that will defend these companies and requesting a hearing to discuss some aspects of the case.

On August 23, 2017, a hearing was held at the District Court in Rotterdam to establish the timeframe for proceedings. The next steps are: (i) initial arguments by defendants in November 2017, (ii) the Foundation’s reply in March 2018, and (iii) the oral hearing on June 28, 2018. The Court ruling is expected to be presented in September 2018. Petrobras (and other defendants) presented preliminary defenses in November 29, 2017.

This class action involves complex issues that are subject to substantial uncertainties and depend on a number of factors such as the legitimacy of the Foundation as the plaintiffs' attorney, the applicable rules to this complaint, the information produced in discovery, analysis by experts, the timing of court decisions and rulings by the court on key issues. Currently, it is not possible to determine if the Company will be responsible for the payment of compensation as a result of this action as this assessment depends on the outcome of these complex issues. Moreover, it is uncertain which investors are able to file complaints related to this matter against the Company.

In addition, the claims asserted are broad, span a multi-year period and involve a wide range of activities, and, at the current stage, the impacts of such claims are highly 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 this action. The Company is victim of the corruption scheme uncovered by the Lava-Jato investigation and aims to present and prove this condition before the Netherlands Authorities.

The uncertainties inherent in all such matters do not enable the Company to identify possible risks related to this action. Compensation for the alleged damages will only be determined by court rulings on complaints to be filed by individual investors, unless agreements to settle Opt-out Claims occur. The Foundation is not able to demand compensation for damages.  

Petrobras and its subsidiaries deny the allegations presented by the Foundation and intend to defend themselves vigorously.

Petrobras is also currently a party to arbitration and judicial proceedings in Brazil, all of which are currently in their initial stages. In each case, the proceedings were brought by investors that purchased Petrobras’ shares traded in Brazilian Stock Exchange (B3), alleging damages caused by facts uncovered in the Lava Jato Operation.

 

 

 

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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.

The court granted to the Company, in all the lawsuits, the definitive right to recover those taxes, but it requires previous examination and approval by the court of the settlement reports (court-ordered liquidation stage). In 2017, there were a settlement reports issued in favor of the Company relating to the most significant amount to be recovered, however their final approvals of the court are still pending.

As of December 31, 2017, the Company had non-current receivables of R$ 3,212 (R$ 3,193 as of December 31, 2016) related to PIS and COFINS, which are indexed to inflation.

 

The Company has an active GSA agreement (Gas Supply Agreement ) entered into with Yacimentos Petroliferos Fiscales Bolivianos – YPFB to purchase certain minimum volumes of natural gas at prices linked to the international fuel oil price through 2019, after which the agreement may be extended until all contracted volume has been delivered.

As of December 31, 2017, the total amount of the GSA for the 2018-2019 period is nearly 22 billion cubic meters of natural gas (equivalent to 30.08 million cubic meters per day) and corresponds to a total estimated value of US$ 3.42 billion. Based on the aforementioned extension clause, the Company foresees an extension of the GSA term to April 2020 on the same volume basis according to current indicators, representing an estimated additional amount of US$ 3.40 billion.

 

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 R$ 7,295 of which R$ 2,904 were still in force at December 31, 2017, net of commitments undertaken. The collateral comprises crude oil from previously identified producing fields, pledged as collateral, amounting to R$ 2,665 and bank guarantees of R$ 239.

 

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.

 

 

 

 

 

 

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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, 2017, as well as the amounts recognized in the statement of income and other comprehensive income and the guarantees given is set out as follows:

 

 

 

 

A sensitivity analysis of the derivative financial instruments for the different types of market risks as of December 31, 2017 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. However, derivatives may be used in specific circumstances depending on business environment analysis and assessment of whether the Business and Management targets are being met. The use of derivatives in 2017 as hedging instruments aimed 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.

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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.      

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 foreign exchange gain or loss from proportions of its long-term debt obligations (denominated in U.S. dollars) and  foreign exchange gain or loss of 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.

Foreign exchange gains and losses on proportions of cash flows from debt obligations (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 debts in the hedging relationships for which they had been designated.

Individual hedging relationships were designated in a one-to-one proportion, meaning that the highly probable future exports for each month and the proportions of cash flows from debt obligations, hedged in individual hedging relationship, an equal in US dollar amount. 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 their foreign exchange gains and losses 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 future exports, for foreign exchange gains and losses 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.

In addition, when a financial instrument designated as a hedging instrument expires or settled, the Company may replace it with another financial instrument in a manner in which the hedge relationship continues to occur. Likewise, whenever a hedged transaction effectively occurs, its financial instrument previously designated as a hedging instrument may be designate for a new hedge relationship.

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The carrying amounts, the fair value as of December 31, 2017, 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$ 3.3080 exchange rate are set out below:

 

 

 

 

The average ratio of future exports for which cash flow hedge accounting was designed to the highly probable future exports is 65.8%.

A roll-forward schedule of cumulative foreign exchange losses recognized in other comprehensive income as of December 31, 2017 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 BMP-2018-2022, would not indicate a reclassification adjustment from equity to the statement of income.

A schedule of expected reclassification of cumulative foreign exchange losses recognized in other comprehensive income to the statement of income as of December 31, 2017 is set out below:

 

 

IFRS 9 is effective from January 1, 2018 and provides for new requirements for hedge accounting. See note 6 for additional information on impacts of this new accounting standard on the Company’s financial statements.

In the first quarter of 2017, the Company, through its wholly owned subsidiary Petrobras Global Trading B.V. (PGT), entered into cross currency swaps maturing in 2026 and 2034, with notional amounts of £ 700 million and £ 600 million, respectively, in order to hedge its Pounds/U.S. Dollar exposure arising from bonds issued amounting to £ 1,300. The Company does not expect to settle these swaps before their expiration dates.

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.

In line with the assumptions in the 2018-2022 Business and Management Plan, the Company does not foresee net proceeds from financing for this period. 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. In 2017, the total debt decreased 6% and net debt decreased 11%, mainly as a result of repayments of principal and interest, and weighted average maturity of outstanding debt reached 8.62 years at December 31, 2017 (compared to 7.46 years at December 31, 2016).

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.

 

 

The ratio decreased 0.46 p.p. in 2017, due to the agreement to settle the Consolidated Securities Class Action.

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The partnership and divestment program for the 2017-2018 period, which foresees US$ 21 billion of proceeds 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 4.13.

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 with low credit risk.

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:

 

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 partnership and divestment program.

 

 

 

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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 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 million.

The main information concerning the insurance coverage outstanding at December 31, 2017 is set out below:

 

 

Petrobras does not have loss of earnings insurance or insurance related to 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:

Level 1: inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity can access at the measurement date.

Level 2: inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

Level 3: inputs are unobservable inputs for the asset or liability.

 

 

There are no material transfers between levels for the periods presented.

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

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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.

 

The production sharing agreement with respect to the Norte de Carcará area, entered into the Brazilian Federal Government, Statoil, Petrogal and Exxon, was made official through the Brazilian Federal Register (official gazette), on February 2, 2018. This fact completes the precedent conditions for the second payment of the exploratory block BM-S-8 sold by the Company in July 2016, in the amount of US$ 300 million.

The company expects to receive this amount before March 31, 2018, and the third installment of this sale, in the amount of US$ 900 million, is still pending certain future events related to the signing of a unitization agreement.

On March 1, 2018, the Company’s Board of Directors approved the key terms for a possible agreement in the context of the extrajudicial mediation procedure in progress with Sete Brasil Participações S.A. – Under Judicial Recovery (“Sete Brasil”).

The signing of the agreement between Petrobras and Sete Brasil is conditional upon presentation, by Sete Brasil, of an international-class drilling rig operator with experience in deep waters, in accordance with the approval criteria of Petrobras. This agreement is further conditioned to the success in the negotiation and approval, by the relevant bodies of both companies, of the final terms and conditions of the documents necessary to its implementation.

On March 7, 2018, the Company entered into a revolving credit facility (RCF) with a syndicate of 17 banks, in the amount of US$ 4.35 billion and maturing in March 2023. The company may use this line of credit up to the month prior to maturity and the maintenance of the limit with the banks will cost 0.51% p.a. In the case of use, funds raised will bear interest at 6M Libor + 1.3% p.a. rate if the Company is investment grade rated at the date of the withdrawal. Otherwise, it will bear interest at 6M Libor + 1.7% p.a. rate.

 

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Social Balance (unaudited)

 

 

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Social Balance (continuation)

 

 

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Additional information of general public concern – Law 13,303/16 (unaudited)

On June 30th, 2016 the Brazilian federal government enacted the Law 13,303 providing for new guidelines, rules and procedures applicable to the Company as it is a partially state-owned enterprise.

In compliance with the relevant rule, on June 29, 2017 the Company released the 2016 Annual Letter of Public Policies and Corporate Governance presenting the main information regarding commitments to the achievement of public policy objectives, which are summarized below:

I – Priority Thermoelectric Program – (Programa Prioritário de Termeletricidade- PPT)

On February 24, 2000, the Brazilian federal government enacted the Decree No. 3,371 governing the implementation of thermoelectric power plants in Brazil through the Priority Thermoelectric Program (PPT). The thermoelectric power plants in the scope of this program were entitled to supply natural gas for up to 20 years with a pre-established price indexed to the U.S. inflation. The gas supply for the program, in 2017, generated revenues of approximately R$ 1,121 and costs of R$ 2,314. As of December 31, 2017, the company had three plants in the scope of this program and one of which had its contract terminated in 2018.

II– National Program for Rationalization of the Use of Oil and Gas Products – (Programa Nacional de Racionalização do Uso dos Derivados do Petróleo e do Gás Natural – CONPET)

On February 18, 1991, the Brazilian federal government established the National Program for Rationalization of the Use of Oil and Gas Products (CONPET), which was intended to develop an anti-waste culture in the use of non-renewable natural resources. The Company is also a member of the Brazilian Labeling Program (Programa Brasileiro de Etiquetagem) in partnership with the National Institute of Metrology, Quality and Technology (INMETRO), which goal is to stimulate the production and use of gas appliances and vehicles with lower carbon emission. In 2017, the costs associated with CONPET, expensed by the Company’s budget, were immaterial.

III – Program for the Mobilization of National Oil and Natural Gas Industry – (Programa de Mobilização da Indústria Nacional de Petróleo e Gás Natural – PROMINP)

On December 19, 2003, the Brazilian federal government enacted the Decree 4,945 aiming at promoting enhancing operations of the domestic industry of goods and services, in a competitive and sustainable manner with respect to oil and gas projects in Brazil and abroad. In 2017, this project was discontinued.

 

 

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

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.

The Company, on December 31, 2017, maintains activities in Brazil; 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. However, the Company only estimates reserves in Brazil, the United States, Nigeria and Argentina.

As set out in note 4.7, the Company uses the successful efforts method of accounting for appraisal and development costs of crude oil and natural gas production. In addition, notes 4.8 and 4.9 presents the accounting policies applied by the Company for recognition, measurement and disclosure of property, plant and equipment and intangible assets.

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

 

 

The Company’s results of operations from oil and gas producing activities for the years ended December 31, 2017, 2016 and 2015 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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As presented in note 5.1, 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time. Reserves estimate involves a high degree of judgment and complexity and its application affects different items of these Financial Statements.

The Company’s estimated net proved oil and gas reserves and changes thereto for the years 2017, 2016 and 2015 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.

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 changes 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 summarizes 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 2017, 2016 and 2015:

 

 

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In 2017, we incorporated 670.1 million boe of proved reserves by revising of previous estimates, including 355.4 million boe due to economic revisions, mainly due to the increase in prices, and 314.7 million boe due to technical revisions, mainly due to better than forecasted behavior from reservoirs, in the pre-salt layer of Santos and Campos basins, both in Brazil.

In addition, we added 246.7 million boe in our proved reserves resulting from positive responses from improved recovery (water injection), and added 82.5 million boe in our proved reserves due to extensions and discoveries, mainly in the pre-salt layer of Santos basin.

Considering a production of 919.8 million boe in 2017, the company total proved reserves resulted in 9,751.7 million boe. This 919.8 million boe production does not consider the production of Extended Well Tests (EWTs) in exploratory blocks and production in Bolivia, since the Bolivian Constitution prohibits the disclosure and registration of its reserves.

In 2016, we incorporated 103 million boe of proved reserves from extensions and discoveries in Brazil (Santos Basin), and we added 131 million boe 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 layer of Santos and Campos Basins.

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.

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.

 

 

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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 existing 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, assuming continuing 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.

Information relating to the standardized measure of discounted future net flows, presented originally in U.S. dollars in Form 20-F of the SEC, were converted to reais for these financial statements. Therefore, in order to maintain consistency with the criteria used in measuring the estimates of future cash flows, as described above, the Exchange rate used for converting each period follows the average prices calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Exchange differences arising from translation are shown as cumulative translation adjustments in the following tables.

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The Board of Directors of

Petróleo Brasileiro S.A. – Petrobras

1. Introduction

 

The Statutory Audit Committee ("CAE" or "Committee") is a permanent body directly under the Board of Directors of Petróleo Brasileiro S.A. – Petrobras ("Company"), governed by CVM Instruction No. 308, dated of May 14, 1999, as amended by CVM Instruction No. 509, dated of November 16, 2011, and other applicable regulations, including the Sarbanes-Oxley Act ("SOx") and rules issued by the Securities and Exchange Commission ("SEC") and the New York Stock Exchange ("NYSE"), with its own Internal Rules ("Rules").

 

The purpose of the Statutory Audit Committee is to advise the Board of Directors in the exercise of their duties, working primarily on (i) the quality, transparency, and integrity of individual and consolidated financial statements (hereinafter the "financial statements"); (ii) the effectiveness of internal control processes for the production of financial reports; and (iii) the performance, independence, and quality of the work by Independent Auditors and Internal Auditors.

 

In fulfilling its responsibilities, the CAE is not responsible for planning or conducting audits or any assertion on the completeness and accuracy of the Company's financial statements, or are presented in accordance with the accounting practices adopted in Brazil issued by the Committee on Accounting Standards (Comitê de Pronunciamentos Contábeis) – CPC and with the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB). This is the responsibility of Management and the independent auditors. In fulfilling its responsibilities as described in its Internal Rules, the CAE members are not performing the duties of auditors or accountants.

 

The CAE is currently composed of the following Board of Directors members: Jerônimo Antunes (Chair), Marcelo Mesquita de Siqueira Filho and Durval José Soledade Santos, whereas Board member Jerônimo Antunes is the CAE’s financial and corporate accounting expert, as provided for in Brazilian and American law.

 

It should be noted that all current CAE members meet the independence criteria set forth in Law No. 13,303/16, article 22, paragraph 1, and CVM Instruction n° 308/99, article 31-C, paragraph 2, as amended by CVM Instruction No. 509/11, as well as the independence criteria required by American law as applicable to Petrobras and by the Brazilian Institute of Corporate Governance (Instituto Brasileiro de Governança Corporativa – IBGC).

 

2. Duties and Responsibilities

 

2.1 Company Management

 

Company Management is responsible for: (i) defining and implementing processes and procedures whose purpose is to collect data in the preparation of the financial statements, in compliance with corporate law, the accounting practices adopted in Brazil plus the practices issued by the IASB, the relevant regulatory acts of the Securities and Exchange Commission of Brazil ("CVM") and, because it is listed on the New York Stock Exchange, the standards issued by the SEC and the SOx; (ii) preparing and ensuring the integrity of financial statements, managing risks, maintaining an effective system of internal controls, and enforcing compliance of activities to meet legal and regulatory standards, and (iii) internal control processes, policies, and procedures that ensure the safeguard of assets, the timely recognition of liabilities, and the elimination or reduction to acceptable levels of risk factors.

 

2.2 Internal Audit

 

Internal Audit, which is directly subordinated to the Board of Directors, is technically supervised by the Statutory Audit Committee, and is responsible for carrying out periodic works focused on major risks, broadly and independently evaluating the actions to manage those risks and the adequacy of governance and internal controls, covering the areas and activities that present the most sensitive risks to Petrobras’ operations and strategy.

 

2.3 Independent Audit

 

Since  May 2017, KPMG is responsible for the independent audit of the annual financial statements published and for the review of quarterly information (ITRs) filed with CVM, issuing reports that reflect the result of its findings and present its independent opinion on the reliability of financial statements in relation to the accounting practices adopted in Brazil issued by the Committee on Accounting Standards (Comitê de Pronunciamentos Contábeis) – CPC and with the International Financial Reporting Standards (IFRS) , issued by the International Accounting Standards Board (IASB), in addition to compliance to CVM rules, the provisions in Brazilian corporate law, and American regulations applicable to Petrobras.

 

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2.4 Compliance and Internal Controls

 

The current Executive Office of Governance and Compliance ("DGC") started activities in 2015, and its mission is to ensure compliance with processes and mitigate risks, among which the risk of fraud and corruption, enforcing compliance to laws, norms, standards, and internal and external and rules.

 

The Executive Department for Compliance, which is part of DGC, is tasked with planning, steering, coordinating and assessing control and compliance activities, and reduction of fraud and corruption risks, reporting to Senior Management on compliance actions and results throughout the Petrobras System.  The investigation and examination of complaints is attribution of the General Management of Examination of Complaints.

 

Since creation in late 2014 of the Executive Office of Governance, Risk and Compliance ("DGRC” – currently Executive Office of Governance and Compliance, "DGC"), numerous actions have been implemented in Petrobras in order to ensure process compliance and risk reduction, in addition to enforce compliance with laws, norms, standards, and regulations, both internal and external to the Company.  In this sense, over 2017, the following stand out as important measures of improvement in governance and controls, as well as external awards in recognition of these measures:

 

 

2.5 Risk Management and Monitoring

 

The Executive Management of Corporate Risk, subordinated to the Executive Office for Strategy, Organization and Management System, is responsible for strengthening the integrated outlook of the business risks within the Petrobras System by identifying, assessing, monitoring and managing relevant risks, together with the different areas and companies in the Petrobras System.

 

2.6 Governance

 

The Executive Management of Governance is subordinated to the Deputy Board of Governance and Compliance, being responsible for ensuring compliance with Petrobras corporate governance models, as well as ensuring the administration of Petrobras' decision-making process, as well as  planning, performance evaluation and corporate optimization of the companies of the Petrobras System.

 

2.7 Ombudsman and Whistleblowing Channel

 

The General Ombudsman of Petrobras is subordinated to the Board of Directors, acting with independence, impartiality and confidentiality. It is responsible for the presentation and management of complaints received and processed, as well as requests made to the Citizen Information Service (Serviço de Informação ao Cidadão - SIC); reporting on its activities to the Board of Directors, through the Statutory Audit Committee, and to the Executive Board of Petrobras.

 

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The General Ombudsman of Petrobras is a direct channel between Petrobras' various publics of interest and top management. Complaints, including anonymous complaints, are received through a system supplied by a contractor company “Contato Seguro”, which guarantees the confidentiality required.

 

2.7 Related-party transactions

 

The Statutory Audit Committee is in charge of assessing and monitoring together with Management and Internal Audit, the appropriateness of transactions with related parties carried out by the Company, as well as reviewing quarterly the summary of transactions with related parties by Petrobras involving the latter’s Executive Officers, Board members, as well as the spouse or direct or collateral relatives up to the third degree and, by affinity, up to the second degree, of said administrators, plus companies that employ any of its Executive Officers or Board members, in addition to any other related party relationship that is relevant, as defined by CVM and the SEC.

 

Since December 15, 2016, upon the Board of Directors’ approval of the revision of Petrobras’ Policy on Related Party Transactions, the CAE Internal Rules were changed so the Committee, besides assessing and monitoring transactions with related parties, prior assess those transactions that meet the materiality criteria set out in CVM Instruction 480/09, pursuant to the revision of the Policy on Related Party Transactions.

 

3. Summary of Activities in 2017 and 2018

 

In the period from March 15, 2017 (first ordinary meeting of the CAE after review of the Financial Statements of 2016) to March 12, 2018 (ordinary meeting of the CAE together with the Financial Committee and the Fiscal Council to examine the Financial Statements of 2017), Petrobras' Statutory Audit Committee held 42 meetings, which included 257 guidelines, involving Board Members, Fiscal Advisers, Members of the Special Investigation Committee, Executive Directors, Executive Managers, Ombudsman, Internal Auditors, Independent Auditors, Internal and External Lawyers and members of Audit Committees of companies of the Petrobras System, as follows:

 

 

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The Committee prepared the Annual Schedule for the fiscal year of 2018, including the guidelines and respective areas that comply with this Committee's regulatory obligations. This schedule allows, in advance, the planning and preparation of the matters to be assessed by the Committee, which must be sent by the areas with at least seven days in advance of the date of the meeting, unless specifically authorized by the Chairman of this Committee, as provided in item 6.3 of the Internal Regulation, approved by the Board of Directors on February 28, 2018. The Annual Schedule including the guidelines was formally forwarded to the responsible areas on February 5, 2018.

 

3.1 Independent Audit

 

Ten meetings were held to examine ten guidelines that addressed, among other topics, (i) the planning and execution of audit work on the quarterly and annual financial statements for the 2017 fiscal year, (ii) learn the nature, time and extent of the main audit procedures of selected and the materiality adopted, (iii) the audit risk analysis conducted, (iv) the significant deficiencies identified in the risk assessment of internal controls, (v) the points of attention identified and (vi) the conclusions of their audit tests. Information confirming the independence of auditors and the absence of conflicts of interest in work other than the auditing of the financial statements was also gathered.

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Additionally, the so-called Main Audit Topics were discussed with the independent auditors, reported in the Independent Auditor’s Report, namely: (i) "Operation Car Wash" and its consequences to the Company; (ii) Legal proceedings and contingencies; (iii) Impairment of assets; (iv) Employee benefits; (v) Accounts receivable – Electrical sector; (vi) Cash flow hedge accounting – Estimate of future exports and (vii) Provision for decommissioning costs.

 

3.2 Accounting and Tax

 

Twenty-four guidelines were assessed over fourteen meetings, whose object were the quarterly and annual financial statements for the 2017 fiscal period, addressing the main accounting practices adopted, accounting estimates made, plus the presentations of financial standing, financial results, cash flows and added value, and the explanatory notes to the financial statements. These items also involved the following areas in addition to Independent Audit: Legal, Compliance (Internal Controls) and Internal Audit.

 

The possible accounting effects in the financial statements as of 2017 and subsequent, regarding the changes resulting from the new pronouncements IFRS 9 - Financial Instruments, IFRS 15 - Revenue from Contracts with Customers (both effective on January 1, 2018) and IFRS 16 - Leases (effective on January 1, 2019), were analyzed and discussed by the CAE with those responsible for Accounting and Tax.

 

3.3 Internal Audit

 

Since September 2016, the Executive Manager of Internal Audit participates as a permanent guest in all CAE meetings.

 

Sixteen guidelines under Internal Audit’s responsibility were addressed in eleven meetings, during which the Statutory Audit Committee was informed of the points of attention and recommendations arising from the work of Internal Audit, and followed up on the corrective actions adopted by Management. These items addressed the quarterly and annual reports of Internal Audit work (RAINT), the Internal Audit Activity Plan (PAINT), the necessary actions for the ongoing process for Quality Assessment of the Internal Audit, in accordance with the International Auditing Standards (IIA), as well as the improvement of testing of SOx controls at Petrobras and its main subsidiaries.

 

In order to allow effective and adequate follow-up of the activities carried out by the Internal Audit, the CAE determined that, after the closing of each of its work, the Internal Audit requests a formal compulsory evaluation of the Executive Manager or the General Manager, responsible for the audited area, according to the issues previously agreed with this Committee, as a way to maintain an independent channel of the Executive Management audited directly with the CAE, to report any criticism or praise on the work of the Internal Audit.

 

These evaluations are confidential and with exclusive access to the area that advises the Committee in its activities, by delegation of the CAE, and the results are periodically consolidated and forwarded to the CAE members, with consolidated and periodic feedback to the Internal Audit, without identification of the opinions of the evaluators. For evaluations that, in the opinion of the CAE members, demand clarification or complements of information, or arbitration of possible conflicts of opinions, the evaluators are invited to participate in private meetings with the members of the CAE for further analysis and discussions with the Executive Manager of Internal Audit.

 

The practice of evaluating Internal Audit is one of the items foreseen in the Quality Certification Program of the Institute of Internal Auditors, which aims at the continuous improvement of the administration of the processes of this area to meet the expectations of the clients and deliver services that add value to your process and to the Company.

 

3.4 Compliance and Internal Controls Systems

 

Thirty-four guidelines were presented in sixteen meetings, whereas the following topics were subject to monitoring and recommendations, among others: (i) action plan regarding the points of attention and remediation of significant deficiencies reported in the 2017 Reference Form - 2016 fiscal year - filed with CVM (corresponding to the "Material Weaknesses” reported in the 2017 20-F Form - 2016 fiscal year - filed with the SEC), with rigorous monitoring by CAE on a monthly or weekly basis; (ii) internal control system; (iii) SOx/CVM risks; (iv) Integrity Due Diligence Process; and Quarterly reports on the activities of the Executive Management of Compliance (recently transformed into the named "Report of Activities of the Executive Offices Compliance, Governance and Examination of Complaints".

 

 

3.5 Risk Management and Monitoring

 

Ten Risk Management and Monitoring items were discussed over 9 meetings, with involvement of other company areas such as: Investor Relations, Governance, Compliance (Internal Controls) and Accounting and Tax. These items addressed the following subjects, among others: (i) governance for tax risks; (ii) fraud and corruption risk management matrix; (iii) inventory of SOx/CVM risks; (iv) review and update process for the risk factors included in the Reference Form and the 20-F Form; (V) map of strategic risks, labor risks and risk appetite; and (vi) mitigating measures for each of the risk factors of the fraud risk management matrix,  addressed in monthly guidelines in the Committee.

 

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3.6 Governance

 

Sixteen Governance guidelines were discussed during 12 meetings, involving other areas of the Company (such as: Legal,  business areas  named GIA-RGN, GIA-E & P, among others), for appreciation of topics such as: Petrobras System companies panorama; Annual Charter Public Policies and Corporate Governance 2016; application of Petrobras' limits of action matrix to the tax credits reduction processes; change in the table of limits of competence and delegation of authority; revision of the Corporate Reference Chart (TRS) for the managers indicated in the companies of the Petrobras System; proposal for the creation of Single CAE for the companies of the Petrobras System, in compliance with Law 13,303/16 and Decree 8,945 /16; plan for compliance with CVM Instruction 586/17 and the Brazilian Code of Corporate Governance; and revision of the Internal Regulations of the CAE.

 

3.7 Ombudsman and Whistleblowing Channel

 

Ten guidelines were addressed in nine meetings, in which very high and high risk complaints and quarterly reports covering all activities, complaints, and actions taken were presented in detail, as well as the revision of the Petrobras Ombudsman Policy and Guidelines. It should be noted that the quarterly report of the General Ombudsman's Office to the CAE, of the whistleblowing received by Petrobras'  direct channel, with a chapter dedicated to detailing the allegations of fraud and corruption, has the intention  to comply with the provisions of article 24, paragraph 2 of the Law 13,303/2016.

 

3.8 Related-party transactions

 

Fourteen meetings were held, assessing sixteen guidelines on transactions with related parties, including the revision of the Policy on Related Parties and, according to item 5.1 of the Internal Regulations of the Committee, the prior analysis of transactions with related parties that meet the criteria established in the Related Party Transactions Policy approved by the Board of Directors. In compliance with this requirement, the CAE had 10 guidelines (from a total of 16) for prior analysis of transactions with related parties, whose process has been improved and now has certifications related to commutativity and isonomy of the transaction, signed by Management (responsible for transaction) and by the Executive Management of Investor Relations, ensuring that the transactions followed the same procedures that govern the transactions with third parties that are not related parties and that were celebrated in compliance with market conditions.

 

3.9 Other activities

 

The Statutory Audit Committee met with the main executives of the Company and its main subsidiaries, in order to learn of the key business strategies and monitor the operating and systemic improvements to strengthen the processing and security of transactions.

 

The CAE also assessed guidelines on: (i) a semiannual update on the activities of the Executive Management, Intelligence and Corporate Security, which is responsible for normative activities and execution of intelligence, investigation, corporate security, information security and patrimonial security; (ii) actuarial assumptions of Petrobras and Petros Foundation, with actuarial experts and independent auditors; (iii) appraisal of the financial statements, activities and improvements of the internal controls and governance in progress of the Petros Foundation; and (iv) monitoring the implementation by the responsible areas of Petrobras of the recommendations of the Special Investigation Committee (with bimonthly guidelines in the presence of EY - Ernst & Young and TRW - Trench, Rossi and Watanabe Lawyers and Gibson Dunn), totaling 121 other activities.

 

Among other CAE activities, we mention meetings with the Finance Committee on the Financial Statements, and with the Audit Committee, where accounting issues were addressed such as impairment and hedge accounting; and meetings with the Safety, Environment and Health Committee, which addressed topics related to HSE indicators; integrated reporting, DJSI - Dow Jones Sustainability Index, ISE Bovespa, reports on HSE internal audits; and reports of serious accidents and fatalities in the Company.

 

The CAE also held meetings with the Strategic Committee and the Finance Committee, in which the following guidelines were considered: "Monitoring of the Portfolio of Divestment Projects", "Equalization of the Deficit of the Petros Plan Petrobras System (PPSP)", "Petrobras' bylaws: Definition of Public Interest "," Agreement with the Ministry of Finance of the Republic of Angola for Fiscal Regularization "and" Plans of Action of the Executive Managements Marketing and Commercialization, Acquisitions and Divestments, Supply of Goods and Services, Strategy, Communication, Controllership and Finance. "

 

Seeking continuous improvement and excellence in the processes, tools and activities of the CAE, for the third consecutive year, the Committee conducted a self-assessment of CAE maturity, which result will be presented to Petrobras' Board of Directors.

 

 

 

 

 

 

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4 Audit Committee Communications

 

4.1 Board of Directors

 

The Statutory Audit Committee reports monthly to the Board of Directors meetings, the issues discussed in its meetings, its positions and requests made to the different areas of the Company, as well as monitoring results of the activities by Internal Auditors, Independent Auditors, Related-party transactions, the Executive Management of Compliance (Internal Controls), Corporate Governance, Corporate Risks and General Ombudsman’, as well as the ones related to the whistleblower channel.

 

In addition, CAE issues specific recommendations to the Board of Directors on items submitted for resolution by this collegiate as part of its statutory duties, as well as presents summarized and detailed reports regarding its annual activities, of which the summarized report is incorporated to the financial statements.

 

4.2 Senior Management - Executive Board and Executive Managers

 

In all meetings held by the Statutory Audit Committee, the Executive Offices involved in the topics to be discussed are invited and indicate the participation of the Executive Managers or General Managers for the areas in charge of the items to be addressed.

 

In addition, the Executive Offices and Executive Departments submit items to the CAE, as relevant to the duties of this Committee, referring to issues to be submitted for assessment and final decision by the Board of Directors, so that the Committee can examine them and issue its recommendation to the Board.

 

4.3 Executive and General Managements

 

Whenever necessary, during the meetings the Audit Committee members issue recommendations/requests to the Executive Managements or General Managements through emails copying their respective Officers. The average of recommendations/requests is 7.8 per meeting. Accordingly, the Committee implemented a procedure to control the recommendations and their respective status are reported to its member on a monthly basis. The recommendations that are not met in a timely fashion are addressed to the Internal Audit in order to control and monitor them until their closing.

 

5. Recommendations to the Executive Officers

 

Among other recommendations, the Statutory Audit Committee recommended to the Executive Board to include in its regular meetings the monitoring of progress in measures to eliminate Material Weaknesses in internal controls identified in the fiscal year ending on December  31, 2016, as well as monitoring any new obstacles identified, including efforts to advance the deadlines for completion of their treatment; and to arrange for the necessary resources to implement the following Action Plans and policies highlighted below:

 

- Remediation Plan of Material Weaknesses;

 

- Harmonization of corporate policies between the holding and wholly-owned subsidiaries and controlled companies, regarding policies, Ombudsman performance and assessment standards, Internal Audit, HSE, Human Resources, Compliance, Legal, and Information Technology;

 

-Information Technology

 

- Completion and Implementation of the Work Plan for Review of Judicial and Administrative Litigation Classification Methodology, to be executed jointly by the Legal, Accounting and Tax, Internal Audit, and Corporate Risks departments, with its respective spread to the Petros Foundation and to the other companies of the Petrobras group.

 

- Review of the Petrobras Integrity System, improving the investigation process of complaints of fraud, corruption, nepotism, conflict of interests and CIA - Internal Evaluation Committee, promoting continuous improvement, with no damage o best practices and provisions of local and international regulatory bodies, implementing process improvements, technology and training of personnel, with actions to be implemented in accordance with the updated schedule, mainly those that depended on the approval of the Board of Directors, such as 1) Continuous monitoring of e-mail; 2) Analysis of equity evolution; and 3) Changes in the Correction Committee.

 

- Implementation of recommendations from the Special Investigation Committee, with an effort to anticipate deadlines.

 

 

 

 

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- Streamlining process (defining attributions, flow of information, calendar of meetings, review of the annual calendar of CAE guidelines and other necessary requirements) for full compliance with Circular Letter 575/2017 of the Ministry of Planning, Development and Management, which regulates the attributions of federal state-owned enterprises, as sponsors of pension plans, in the supervision and systematic supervision of the activities of their respective Closed Entities of Complementary Pension Plans (EFPC), addressing the responsibilities of the Board of Directors in relation to the performance of audits in the EFPC and the responsibilities of the Board of Executive Officers in relation to the action plan for correcting nonconformities identified in audits, among others.

 

The Statutory Audit Committee believes that the topics highlighted in "Recommendations" above, as well as all the dozens of other recommendations formulated during the period covered by this report of activities of the EBD - whose Plans of Action are concluded or are in progress - were surrounded by satisfactory mitigation procedures aimed at minimizing possible risks of internal controls that could impact the financial statements for the fiscal year ended December 31, 2017.

 

6. Conclusions and recommendation to the Board of Directors

 

The Statutory Audit Committee members, in the exercise of their duties and legal responsibilities, has completed the examination and analysis of the Financial Statements, together with the Independent Auditor’s Report and the Annual Management Report for the fiscal year ending on December 31, 2017 (“2016 Annual Financial Statements").

 

Considering all the assessment, studies and discussions carried out during the meetings and the monitoring and supervision work carried out by the CAE - aforementioned described in summarized form - as well as due to the information provided by the Petrobras Management and by KPMG Independent Auditors, the members of the Statutory Audit Committee believe that all relevant facts are properly disclosed in the Management Report and in the audited Financial Statements as of December 31, 2017, in Annual Report 2017 and in Sustainability Report 2017,

recommends its approval by the Board of Directors.

 

 

 

 

Rio de Janeiro, March 12, 2018.

 

 

 

____________________________________

Jeronimo Antunes

Chair, Statutory Audit Committee

Financial and corporate accounting expert

 

 

____________________________________

Marcelo Mesquita de Siqueira Filho

Member, Statutory Audit Committee

 

 

____________________________________

Durval Jose Soledade Santos

Member, Statutory Audit Committee

 

 

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The Fiscal Council of Petróleo Brasileiro S.A. - PETROBRAS, in the exercise of its legal and statutory responsibilities, at a meeting held on this date, examined the following documents issued by Petrobras: I - 2017 Annual Report; and ii) - the Financial Statements for the year ended December 31, 2017.

Based on the examinations carried out, considering the accounting practices adopted by the Company, the information provided by Management, as well as the Unqualified Opinion of KPMG Auditores Independentes dated on 03/14/18, the Fiscal Council, believes that the documents presented are able of being appraised at the Shareholders’ General Meeting of Petrobras, with dissenting votes of the members Reginaldo Ferreira Alexandre and Walter Luis Bernardes Albertoni.

 

Rio de Janeiro, Brazil

March 14, 2018

 

 

Marisete Fátima Dadald Pereira

Chair

 

 

Adriano Pereira de Paula

Member

 

 

Eduardo Cesar Pasa

Member

 

 

Reginaldo Ferreira Alexandre

Member

 

 

Walter Luís Bernardes Albertoni

Member

 

 

Antonio Roberto da Silva

Technical Advisor

CRC/RJ- 0550 19/0-5

 

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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 16, 2018.

 

PETRÓLEO BRASILEIRO S.A—PETROBRAS

By: /s/ Ivan de Souza Monteiro

___________________________________________

Ivan de Souza Monteiro

Chief Financial Officer and Investor Relations Officer