EX-99.1

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2018, of the estimated net proved crude oil, condensate, and natural gas reserves of certain properties in which Petróleo Brasileiro S.A. (Petrobras) has represented it holds an interest. The properties are located in Brazil and offshore from Brazil. This evaluation was completed on February 20, 2019. Petrobras has represented that these properties account for 95 percent on a net equivalent barrel basis of Petrobras’ net proved reserves as of December 31, 2018, which represents 96 percent of Petrobras’ net proved reserves in Brazil. Petrobras has represented that the net proved reserves estimates were prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided by Petrobras that it represents to be Petrobras’ estimates of the net reserves, as of December 31, 2018, for the same properties as those which we evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Petrobras.

Reserves estimates included herein are expressed as net reserves as represented by Petrobras. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2018. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Petrobras after deducting all interests held by others.

Certain fields evaluated herein are subject to the terms of production sharing contracts (PSC). Net reserves for these fields are defined as that portion of the gross reserves attributable to the interest of Petrobras based on the terms of the PSCs. The terms of the PSCs generally allow for working interest participants to be reimbursed for capital costs and operating expenses, as well as to share in the profits. The reimbursements and profit proceeds, net to Petrobras based on its working interest share, are converted to a volumetric equivalent by dividing by product prices to estimate the Petrobras “entitlement quantities.” These entitlement quantities are equivalent, in principle, to net reserves and are used to calculate an equivalent net share, termed an “entitlement interest.” Petrobras has advised that royalties for these fields are paid in cash and has requested that the royalty volumes be included in the net reserves estimated herein.

Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was obtained from Petrobras. In the preparation of this report we have relied, without independent verification, upon information furnished by Petrobras with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

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

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in section 210.4–10 (a) Definitions, or by other evidence using reliable technology establishing reasonable certainty.

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by Petrobras, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

Petrobras has represented that its senior management is committed to the development plan provided by Petrobras and that Petrobras has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

The volumetric method was used to estimate the original oil in place and original gas in place for the fields, as required. When applicable, structure and isopach maps were prepared to aid in evaluating reservoir volumes. Electric logs, radioactive logs, core analyses, bottomhole pressures, and other available data were used to prepare these maps.

Estimates of ultimate recovery of fluids took into account the type of energy inherent in the reservoir, as well as reservoir and well performance. Reservoir fluid properties, relative permeability, and other reservoir data were analyzed, and appropriate characterizations were generated for this analysis. In certain fields, a review was made of reservoir simulation studies performed by Petrobras. The available data related to future field development were also examined. In reservoirs where enhanced recovery methods had been implemented or were scheduled, recovery efficiency was estimated by fractional flow analysis and other engineering methods. Where adequate data were available, ultimate recovery was estimated using the material-balance method.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships.

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

Estimates of reserves were limited to the economic limit as defined under the Definition of Reserves heading of this report or the expiration date of a production concession, whichever occurs first. In addition, reserves for the Atapu, Búzios, Itapu, Norte de Berbigão, Norte de Sururu, Sépia, Sul de Berbigão, Sul de Lula, and Sul de Sururu fields were also limited by the Cessão Onerosa terms as represented by Petrobras.

Petrobras has represented that the Cessão Onerosa (also known as Transfer of Rights) terms are part of an agreement between Petrobras and the Government of Brazil signed in September 2010 in which Petrobras made payment to the Government of Brazil for the rights to produce up to a total of 5 billion barrels of oil equivalent (boe) from the certain fields.

Data provided by Petrobras from wells drilled through December 31, 2018, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through October or November 2018. Estimated cumulative production, as of December 31, 2018, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. Oil and condensate reserves reported herein are expressed in millions of barrels (10⁶bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate have been estimated separately and are presented herein as a summed quantity.

Natural gas quantities estimated herein are expressed as marketable gas. Marketable gas is defined as the total gas to be produced from the reservoirs after reduction for injection, flare, and shrinkage resulting from field separation and processing but not from fuel usage. Gas reserves estimated herein are expressed at a temperature base of 20 degrees Celsius (°C) and at a pressure base of 1 atmosphere (atm). Gas reserves presented in this report are expressed in billions of cubic feet (10⁹ft³).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas includes both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

At the request of Petrobras, gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. This conversion factor was provided by Petrobras.

This report has been prepared using initial prices, expenses, and costs provided by Petrobras in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

Petrobras has represented that the oil and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Petrobras supplied differentials by field to a Brent reference price of U.S.$71.83 per barrel. The volume-weighted average adjusted product price attributable to estimated proved reserves for the fields that were evaluated was U.S.$68.54 per barrel. These prices were not escalated for inflation.

Petrobras has represented that the natural gas prices were based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. The volume-weighted average adjusted price for the fields that were evaluated was U.S.$7.01 per thousand cubic feet (10³ft³). This price was based on contract prices and the 12-month average regulation prices from the regulatory agency of Brazil (Agência Nacional do Petróleo, Gás Natural e Biocombistíveis (ANP)), as provided by Petrobras. The ANP regulation prices are the prices disclosed by the ANP to upstream operators for payment of royalties and taxes. These prices were not escalated for inflation.

Operating expenses and capital costs were based on information provided by Petrobras and used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation. Abandonment costs, which are those costs associated with the removal of equipment, plugging of the wells, and reclamation and restoration associated with the abandonment, were provided by Petrobras.

In our opinion, the information relating to estimated proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-7 and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202 (3), (4), (8) of Regulation S–K of the Securities and Exchange Commission.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Petrobras has represented that its estimated net proved reserves attributable to the reviewed properties were based on the definition of proved reserves of the SEC. Petrobras’ estimates of the net proved reserves, as of December 31, 2018, attributable to these properties, which represent 95 percent of Petrobras’ reserves on a net equivalent basis, are summarized as follows, expressed in millions of barrels (10⁶bbl), billions of cubic feet (10⁹ft³), and millions of barrels of oil equivalent (10⁶boe):

In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by Petrobras, differences have been found, both positive and negative, resulting in an aggregate difference of 2.3 percent when compared on the basis of net equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by Petrobras on the properties reviewed and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by DeGolyer and MacNaughton.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2018, estimated reserves.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Petrobras. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Petrobras. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

/S/ DEGOLYER AND MACNAUGHTON

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

I, Federico Dordoni, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:


				/S/ FEDERICO DORDONI
		SEAL		Federico Dordoni, P.E.
				Vice President DeGolyer and MacNaughton


		/S/ FEDERICO DORDONI
SEAL		Federico Dordoni, P.E.
		Vice President DeGolyer and MacNaughton