Petróleo Brasileiro S.A. - Petrobras CORRESP Correspondence with SEC

August 3, 2010

VIA FACSIMILE AND EDGAR TRANSMISSION

Mr. H. Roger Schwall

Division of Corporation Finance

Securities and Exchange Commission

100 F Street, N.E.

Washington, D.C. 20549

Re: Petróleo Brasileiro S.A.—Petrobras

Form 20-F for the Fiscal Year Ended December 31, 2009

Filed May 20, 2010

File No. 1-15106

Petrobras International Finance Company

Form 20-F for the Fiscal Year Ended December 31, 2009

Filed May 20, 2010

File No. 1-33121

Dear Mr. Schwall:

By letter dated July 20, 2010, the Securities and Exchange Commission (the “Commission”) provided certain comments related to the annual reports on Form 20-F filed on May 20, 2010 (the “2009 Form 20-F”), by Petróleo Brasileiro S.A.—Petrobras (“Petrobras”) and Petrobras International Finance Company (“PifCo,” and together with Petrobras, the “Companies”). The Companies are submitting herewith, via EDGAR and facsimile, responses to the C ommission’s comments. For convenience, we have reproduced in italics the staff’s comments and have provided responses immediately below the comments. Because Comments 1 and 9 both relate to the third party engineering reports prepared by DeGolyer and MacNaughton, we combined our responses to those comments under a single heading below.

Comment

General

1. Item 1202(a)(8) of Regulation S-K specifies disclosure items pertaining to third party engineering reports. Please obtain modification of these reports so that they present:

Mr. H. Roger Schwall

Page 2

· A discussion of the methods employed by the engineer to arrive at the conclusion that “the net proved reserves estimates prepared by Petrobras on the properties reviewed by us . . . when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by us”;

· The 12 month average benchmark product prices and the average adjusted prices used to determine reserves; and

· The aggregate percentage difference between your proved reserve estimates and those of your third party engineer.

Exhibits, page 164

Exhibit 99.1

9. The closing paragraphs of the DeGloyer and MacNaughten reports state the reports were prepared at the request of Petrobras and should not be used for purposes other than those for which it is intended. As Item 1202(a)(8) of Regulation S-K requires these reports, please obtain and file revised versions which retain no language that could suggest either a limited audience or a limit on potential investor reliance.

Response to Comments 1 and 9

DeGolyer and MacNaughton revised the third-party engineering reports originally included in the 2009 20-F to address the comments from the Commission as follows. For ease of reference, the revised report relating to DeGolyer and MacNaughton’s audit of Petrobras’ domestic reserves located onshore and offshore Brazil is attached as Exhibit A hereto, and the revised report relating to DeGolyer and MacNaughton’s audit of certain of Petrobras’ international reserves located in North America and South America (outside of Brazil) is attached as Exhibit B hereto.

With respect to the report relating to Petrobras’ domestic reserves located onshore and offshore Brazil, DeGolyer and MacNaughton revised its original report to present 12-month average adjusted and benchmark price information for oil (U.S.$51.55 per barrel average adjusted product price, U.S.$60.20 per barrel average benchmark price) used to determine reserve volumes as shown on page 8 of the attached revised report. With respect to natural gas reserve volumes, page 7 of DeGolyer and MacNaughton’s revised report includes a 12-month average adjusted price of U.S.$3.18 per thousand cubic feet based on a 12-month average internal product transfer price of U.S.$3.80 per thousand cubic feet. The third-party engineer further revised its original report to explain that its conclusion that there was no mater ial difference between the net proved reserve estimates prepared by Petrobras and DeGolyer and MacNaughton is based on DeGolyer and MacNaughton’s detailed and independent reserves evaluation of over 96 percent of Petrobras’ reserves in Brazil using the methodology described in the section of the report entitled “Methodology and Procedures,” as shown on page 2 of the revised report. Finally, DeGolyer and MacNaughton revised its original report to state that the aggregate percentage difference between the net proved reserve estimates of Petrobras and DeGolyer and MacNaughton is less than 1 percent as shown on page 8 of the revised report.

Mr. H. Roger Schwall

Page 3

DeGolyer and MacNaughton’s report relating to its audit of Petrobras’ international reserves located at certain selected properties in North America and South America (outside of Brazil) has been revised to include the 12-month average adjusted and benchmark pricing information for oil (average adjusted product price of U.S.$53.00 per barrel in South America and U.S.$61.02 per barrel in North America; average benchmark price of U.S.$61.02 per barrel for both regions) used to determine oil reserve volumes as shown on page 8 of the revised report. With respect to natural gas reserve volumes, page 7 of DeGolyer and MacNaughton’s revised report includes a 12-month average adjusted product price of U.S.$2.10 per thousand cubic feet in South America based on the 12-month weighted average of contract prices in th is region provided by Petrobras, and a 12-month average adjusted product price of U.S.$3.83 per thousand cubic feet in North America based on a 12-month average benchmark price of U.S.$3.83 per thousand cubic feet in North America).

Unlike the report relating to Petrobras’ domestic reserves, DeGolyer and MacNaughton’s report on certain of Petrobras’ selected international reserves does not include a comparison between the net proved reserve estimates prepared by Petrobras and its third-party engineer. This is because Petrobras does not disclose its own reserve estimates for the selected properties in North America and South America that were reviewed by DeGolyer and MacNaughton. Instead, Petrobras incorporates the reserve estimates prepared by DeGolyer and MacNaughton directly in its Annual Reports on Form 20-F, including in its 2009 Form 20-F. The selected international properties reviewed by DeGolyer and MacNaughton account for 93.3% on a net equivalent barrel basis of Petrobras’ net proved reserves in op erated fields outside of Brazil as of December 31, 2009, as stated on the first page of the third-party report. These selected properties account for approximately 56% of Petrobras’ total net proved reserves in all fields outside of Brazil, including fields not operated by Petrobras.

Finally, DeGolyer and MacNaughton deleted the following sentence from the final paragraph of each of its revised third-party reports “This letter report has been prepared at the request of Petrobras and should not be used for purposes other than those for which it is intended” in order to remove any suggestion of a limited audience or limited potential investor reliance.

DeGolyer and MacNaughton will reissue its third-party engineering reports to include the modifications set forth above, and Petrobras will file those revised reports dated as of May 19, 2010 on its next Form 6-K.

Comment

Overview of the Group

Reserves, page 26

2. We note that you have provided a discussion of proved reserves and proved undeveloped reserves on a mmboe basis on pages 38 and 28, respectively, whereby it appears that you have converted natural gas into barrels of oil equivalent. However, we also note that you have not disclosed proved developed and proved undeveloped reserves on a mmboe basis by category in your tabular disclosure on page 26. If you choose to discuss certain aspects of your reserves on a mmboe basis, please tell us your consideration of disclosing your reserves by category on a mmboe basis to ensure consistent disclosure of your reserve volumes in you r filing.

Mr. H. Roger Schwall

Page 4

Response to Comment

Petrobras uses barrels of oil equivalent in certain portions of its annual report on Form 20-F in order to present aggregate volumes of oil and natural gas using a single unit of measure, as opposed to separately disclosing oil in barrels and natural gas in cubic feet or cubic meters. When appropriate, Petrobras uses this convention to simplify our reserves and production disclosure. As noted in the conversion table of the 2009 Form 20-F, one barrel of oil equivalent is equal to one barrel of oil or approximately 6,000 cubic feet of natural gas (burning 6,000 cubic feet of natural gas produces the energy equivalent of one barrel of oil).

For example, on page 28 of our 2009 Form 20-F we use barrels of oil equivalent to quantify total volumes of oil and natural gas classified as proved undeveloped reserves under a common unit of measurement. The same rationale supports our decision to present information about our aggregate proved reserves of oil and natural gas in Brazil in barrels of oil equivalent on page 38 of our 2009 Form 20-F. We also present our oil and natural gas production on a barrels of oil equivalent basis in certain areas of our 2009 Form 20-F, such as in the tabular disclosure on page 24 and in our discussion of our Brazilian production on page 32.

Petrobras’ tabular reserves disclosure on pages 26 and 28 of the 2009 Form 20-F is presented on a product-by-product basis, with oil and natural gas reserve quantities disclosed separately in barrels and cubic feet, respectively. To ensure consistency, in future annual reports on Form 20-F Petrobras will expand its tabular reserves disclosure to include aggregate oil and natural gas volumes on a barrels of oil equivalent basis in a new column entitled “total oil products.”

For convenience, we have updated our original tabular reserves disclosure on pages 26 and 28 of our 2009 Form 20-F below to show the inclusion of the new “total oil products” column expressed in millions of barrels of oil equivalent:

Mr. H. Roger Schwall

Page 5

The following table sets forth our estimated net proved developed and undeveloped reserves of crude oil and natural gas by region as of December 31, 2009.

Reserves category	Reserves
	Oil (mmbbl)		Natural gas (bncf)		Synthetic oil (mmbbl)(1)		Synthetic gas (bncf)(1)		Total oil products (mmboe)
Proved developed:
Brazil		6,121.4		5,382.8		6.84		5.62		7,026.3
International
South America (outside of Brazil)		139.9		485.6		0.0		0.0		220.8
North America		3.8		37.2		0.0		0.0		10.0
Africa		58.5		31.8		0.0		0.0		63.8
Total International		202.2		554.6		0.0		0.0		294.6
Total consolidated proved reserves		6,323.6		5,937.4		6.84		5.62		7,320.9
Equity and non-consolidated affiliates
South America (outside of Brazil)		22.2		32.5		0.0		0.0		27.6
Total proved developed reserves		6,345.8		5,969.9		6.84		5.62		7,348.6

Proved undeveloped:
Brazil		3,797.9		4,476.4		0.0		0.0		4,544.0
International
South America (outside of Brazil)		84.7		554.2		0.0		0.0		177.1
North America		3.5		14.3		0.0		0.0		5.9
Africa		52.5		0.0		0.0		0.0		52.5
Total International		140.7		568.5		0.0		0.0		235.5
Total consolidated proved reserves		3,938.6		5,044.9		0.0		0.0		4,779.4
Equity and non-consolidated affiliates
South America (outside of Brazil)		17.6		30.7		0.0		0.0		22.7
Total proved undeveloped reserves		3,956.2		5,075.6		0.0		0.0		4,802.1
Total proved reserves (developed and undeveloped)		10,302.0		11,045.5		6.84		5.62		12,150.7

____________

(1)	Volumes of synthetic oil and synthetic gas from oil shale deposits in the Paraná Basin in Brazil have been included in our proved reserves for the first time in accordance with the new SEC rules for estimating and disclosing reserve quantities.

Mr. H. Roger Schwall

Page 6

The table below summarizes information about the changes in total proved reserves for 2009, 2008 and 2007:

	Total Proved Developed and Undeveloped Reserves (consolidated entities only)
	Oil (mmbbl)			Synthetic oil (mmbbl)			Gas (bncf)			Synthetic gas (bncf)			Total oil products (mmboe)
Reserves quantity information for the year ended December 31, 2009
January 1, 2009		9,105.5			0.0			12,139.4			0.0		11,128.7
Revisions of previous estimates		1,734.8			0.0			(521.7	)		0.0		1,647.9
Improved recovery		21.7			0.0			0.8			0.0		21.8
Purchases of minerals in situ		99.4			0.0			110.3			0.0		117.8
Extensions and discoveries		135.5			8.1			146.7			6.6		169.2
Production		(735.3	)		(1.2	)		(782.8	)		(1.0	)	(867.1	)
Sales of minerals in situ		(99.4	)		0.0			(110.3	)		0.0		(117.8	)
December 31, 2009		10,262.2			6.9			10,982.4			5.6		12,100.5

Reserves quantity information for the year ended December 31, 2008
January 1, 2008		9,552.8			0.0			12,479.8			0.0		11,632.8
Revisions of previous estimates		130.2			0.0			195.2			0.0		455.5
Improved recovery		29.8			0.0			7.5			0.0		31.1
Purchases of minerals in situ		12.3			0.0			123.1			0.0		32.8
Extensions and discoveries		76.2			0.0			152.7			0.0		101.7
Production		(685.1	)		0.0			(818.9	)		0.0		(821.6	)
Sales of minerals in situ		(10.7	)		0.0			0.0			0.0		(10.7	)
December 31, 2008		9,105.5			0.0			12,139.4			0.0		11,128.7

Reserves quantity information for the year ended December 31, 2007
January 1, 2007		9,418.1			0.0			11,765.9			0.0		11,379.1
Revisions of previous estimates		666.8			0.0			586.1			0.0		764.5
Improved recovery		25.3			0.0			11.5			0.0		27.2
Purchases of minerals in situ		2.4			0.0			0.0			0.0		2.4
Extensions and discoveries		102.3			0.0			852.9			0.0		244.5
Production		(659.7	)		0.0			(736.6	)		0.0		(782.5	)
Sales of minerals in situ		(2.4	)		0.0			0.0			0.0		(2.4	)
December 31, 2007		9,552.8			0.0			12,479.8			0.0		11,632.8

_______________
Natural gas production volumes used in the calculation of this table are the net volumes withdrawn from Petrobras’ proved reserves, including flared and reinjected gas volumes and gas consumed in operations. As a result, the natural gas production volumes in this table are different from those shown in the production table above, which shows the production volumes of natural gas available for sale.

Mr. H. Roger Schwall

Page 7

Comment

Overview of the Group

Reserves, page 26

3. Please clarify why the proved reserve volumes disclosed on page 26 do not agree to the proved reserve volumes disclosed on page 38. In this respect, the disclosure on page 26 states that you have 10,302.0 mmbbl of proved oil reserve volumes, while your disclosure on page 38 states that you have 9.92 billion barrels of crude oil and natural gas liquids.

Response to Comment

The 10,302.0 mmbbl of proved oil reserves disclosed on page 26 of our 2009 20-F refers to our total company-wide proved oil reserve volumes, including proved developed and proved undeveloped reserves in Brazil, outside of Brazil and in our equity and non-consolidated affiliates. In contrast, the 9.92 billion barrels of proved oil reserves disclosed on page 38 of our 2009 20-F under the heading “Item 4—Exploration and Production—Proved Reserves” refers exclusively to Petrobras’ proved oil reserves in Brazil. The 9.92 bnbbl of proved domestic oil reserves disclosed on page 38 of the 2009 20-F is consistent with our tabular disclosure on page 26, where we report 6,121.4 mmbbl of proved developed reserves in Brazil and 3,797.9 mmbbl of proved undeveloped reserves in Brazil, for a total o f 9,919.3 mmbbl of proved oil reserves in Brazil.

Comment

Proved Undeveloped Reserves, page 28

4. You state here that 714.3 mmboe of proved undeveloped reserves were converted to proved developed reserves in 2009. You discuss the net addition of 499.0 mmboe in Brazil, but not the total gross mmboe added company-wide. Please tell us your consideration of disclosing in more detail the reasons for the material increases to your PUDs that occurred during the year.

Response to Comment

In our 2009 Form 20-F, we erroneously stated that we added a net total of 499.0 mmboe to our proved undeveloped reserves in Brazil. In fact, we added a net total of 342.0 mmboe to our company-wide (consolidated and non-consolidated entities) proved undeveloped reserves at year-end 2009 compared to year-end 2008. Thus, Petrobras had a total of 4,802.1 mmboe of proved undeveloped reserves company-wide at December 31, 2009, compared to 4,460.2 mmboe at December 31, 2008. Proved undeveloped reserves in Brazil increased by 461.6 mmboe, while outside of Brazil proved undeveloped reserves decreased by 119.6 mmboe, resulting in a net addition of 342.0 mmboe company-wide. The 119.6 mmboe net reduction of undeveloped reserves outside Brazil was mainly a result of the write-down of our undeveloped rese rves in Bolivia, as discussed in “Changes in Proved Reserves” on page 27 and “International” on page 61 of our 2009 Form 20-F. The primary factors responsible for the net addition to our proved undeveloped reserves in Brazil in 2009 compared to 2008 were higher oil prices and technical revisions, which together accounted for 397.3 mmboe of the total net increase in Brazil and, to a lesser extent, new reservoirs located in the offshore Campos Basin, new discoveries in the onshore Potiguar and Sergipe-Alagoas basins, and well extensions in the Santos and Campos basins.

Mr. H. Roger Schwall

Page 8

We would also like to clarify that all the reserves volumes described above are “net” to the extent they only include Petrobras proportional participation in the reserve amounts and exclude any amount of reserves attributed to our partners. When calculating the net additions to our undeveloped reserves we also exclude any amounts of undeveloped reserves that were converted into developed reserves throughout the year because we believe this allows for a better comparability of our undeveloped reserves volumes. Thus, the 714.3 mmboe of proved undeveloped reserves that were converted to proved reserves in 2009 did not impact our calculation of net additions to our undeveloped reserves.

In future filings on Form 20-F, Petrobras will disclose additional details regarding the material changes in its company-wide proved undeveloped reserves that occurred during the year along the lines set forth above.

Comment

Proved Undeveloped Reserves, page 28

5. We note your disclosure that approximately 9% of your proved undeveloped reserves have remained undeveloped for five years or more. With a view towards disclosure, please explain how you determined that these PUDs qualify as proved reserves considering the length of time required to develop the reserves.

Response to Comment

The majority of the 430 mmboe of our proved undeveloped reserves that have remained undeveloped for five years or more are located in the Parque das Baleias (Whales Park) area of the Campos Basin offshore Brazil. These proved undeveloped reserves contain heavy crude oil and are located at a water depth of approximately l,500 meters (approximately 4,921 feet). We originally disclosed these reserves as proved undeveloped reserves between 2003 and 2004 after completing a development plan for the Parque das Baleias region. However, Petrobras deliberately postponed production from these proved undeveloped reserves due to the discovery of more valuable light crude oil located in pre-salt reservoirs in the Parque das Baleias area in 2007. This discovery led us to create a new integrated strategy for t he Parque das Baleias region that will allow us to develop both our existing proved undeveloped reserves of heavy crude oil and our recently discovered pre-salt light crude oil simultaneously. In accordance with this new strategy, Petrobras postponed the startup of production of heavy oil from the Parque das Baleias area until we could allocate the necessary ultra-deep water infrastructure and production resources to develop the light pre-salt crude oil as well.

We initiated an extended well test in the pre-salt reservoirs of the Parque das Baleias region in 2008 and in 2010 we started production from the Cachalote and Baleia Franca fields. As a result, we will reclassify a portion of the proved undeveloped reserves in the Parque das Baleias region that have remained undeveloped for five years as proved developed reserves in the year-end 2010.

Mr. H. Roger Schwall

Page 9

Comment

North America, page 62

6. We note that on July 12, 2010, the Bureau of Energy Management, Regulation, and Enforcement, issued a moratorium that applies to all drilling operations that use subsea blowout preventers (BOP) or surface BOPs on floating facilities. Please tell us the impact such a planned moratorium in the Gulf of Mexico will have or has had on your exploratory and/or production drilling activities, and please also disclose any resulting impact that this will have on your production from wells in the Gulf of Mexico. In this regard, we note your disclosure on page 62 that you expect to begin production in the Cascade and Chinook fields in mid 2010.

Response to Comment

The planned moratorium on all drilling operations that use subsea blowout preventers or surface blowout preventers on floating facilities in the Gulf of Mexico will not materially affect our exploratory or production drilling activities in this region.

We are currently participating as a non-operator in the drilling of two deep-water exploration wells in the U.S. Gulf of Mexico that have been postponed until drilling is permitted. The postponement will not have a short- or medium-term impact on our production forecasts for the area because we estimate that eight or more years will elapse between the potential discovery of oil at these wells and production of first oil.

Likewise, we do not expect the planned moratorium to affect our production activities in the Cascade and Chinook fields. We have already completed drilling at two producing wells in the Cascade and Chinook fields and we expect to begin production from these wells in the fourth quarter of 2010. We had planned to drill an additional development well in the Cascade field in the third quarter of 2010 but drilling will be delayed until the moratorium is lifted. We do not expect this delay to affect our production forecasts for the Cascade and Chinook fields in the short or medium term.

Although the U.S. Gulf of Mexico remains a strategically important region for us, production from this region currently accounts for only 0.2% of our company-wide production, with an expected increase to 1% in 2011 including anticipated production from the Cascade and Chinook fields. As a result, we do not expect the planned moratorium to have a material impact on our exploratory and production activities in the region.

Comment

Insurance, page 73

Mr. H. Roger Schwall

Page 10

7. In light of recent events involving the oil spill in the Gulf of Mexico, please review your disclosure to ensure that you have disclosed all material information regarding your potential liability in the event that one of your rigs is involved in an explosion or similar event in any of your offshore locations, such as occurred with respect to one of your production platforms over the Roncador field in 2001. For example, and without limitation, please address the following:

· Disclose the applicable policy limits related to your insurance coverage;

· Disclose whether your existing insurance would cover any claims made against you by or on behalf of individuals who are not your employees in the event of personal injury or death, and whether your customers would be obligated to indemnify you against any such claims; and

· Clarify your insurance coverage with respect to any liability related to any resulting negative environmental effects, including your coverage for operational third-party liability with respect to onshore and offshore activities, including environmental risk such as oil spills as referenced on page 73.

In this regard, discuss what remediation plans or procedures you have in place to deal with the environmental impact that would occur in the event of an oil spill or leak from of your offshore operations.

Response to Comment

Insurance:

We maintain insurance coverage for operational third-party liability with respect to our onshore and offshore activities in Brazil up to an aggregate policy limit of U.S.$250 million for a period of 12 months. We also maintain additional protection and indemnity (P&I) marine insurance against third-party liability related to our domestic offshore operations up to an aggregate policy limit of up to U.S.$500 million for a period of 12 months. In the event of an explosion or similar event at one of our offshore rigs in Brazil, these policies can provide combined third-party liability coverage of up to U.S.$750 million for a period of 12 months.

We operate in 24 countries outside Brazil and maintain varying levels of third-party liability insurance for our international operations based on a variety of factors, including our country risk assessments, whether we have onshore and offshore operations and legal requirements imposed by the various countries in which we operate. We also maintain separate “control-of-well” insurance policies at our international operations to cover liability arising from the uncontrolled eruption of oil, gas, water or drilling fluid with aggregate policy limits of up to U.S.$200 million for a period of 12 months. In the U.S. Gulf of Mexico, for example, we maintain third-party liability coverage up to an aggregate policy limit of U.S.$250 mill ion for a period of 12 months, and control-of-well liability insurance up to U.S.$200 million for a period of 12 months. Depending on the particular circumstances, either of these policies could apply in the event of an explosion or similar event at one of our offshore rigs in the U.S. Gulf of Mexico.

Our domestic and international operational third-party liability policies cover claims made against us by or on behalf of individuals who are not our employees in the event of personal injury or death, subject to the policy limits set forth above. As a general rule, our service providers are required to indemnify us for a claim we pay directly to a third party as a result of a court decision holding us liable for the actions of that service provider. Our service providers may be required to compensate injured third parties directly if the lawsuit is brought against that service provider, or if we join the service provider to a judicial proceeding brought against us, according to the terms of the underlying service contract.

Mr. H. Roger Schwall

Page 11

Our operational third-party liability policies in Brazil and outside of Brazil cover environmental damage from oil spills, including liability arising from an explosion or similar sudden and accidental event at one of our offshore rigs. These operational third-party insurance policies cover litigation, clean-up and remediation costs, but do not cover governmental fines or punitive damages. As mentioned above, we maintain “control-of-well” insurance policies for our international operations to cover claims for environmental damage from well blow-outs and similar events. We do not maintain control-of-well insurance for our domestic operations onshore and offshore Brazil.

In future annual reports on Form 20-F, Petrobras will expand its disclosure on its insurance coverage and potential liability in the event of a drilling rig explosion or similar event along the lines set forth above.

Environmental Remediation Plans and Procedures:

In 2000, Petrobras implemented a company-wide program for environmental management and safety (PEGASO) that is designed to identify risks to human life and the environment, control and monitor those risks with safety procedures that comply with best international practices, and maintain a permanent state of readiness for prompt and effective emergency response. Since 2000, under the PEGASO program, we also have focused our efforts on the prevention of oil spills and our investments in preventive measures have contributed to a 95.7% reduction of oil spills from 37,000 barrels in 2000 to 1,580 barrels in 2009. From 2001 through 2009, we have developed over 4,000 projects to improve safety and environmental protection under the PEGASO program both in Brazil and abroad at our international operations, with a total budge t of U.S.$5.3 billion for the period.

As part of these efforts, Petrobras has developed detailed response and remediation contingency plans to be implemented in the event of an oil spill or leak from our offshore operations. We have more than 400 trained workers available to respond to oil spills 24 hours a day, seven days a week, and we can mobilize an additional 2,000 trained workers for shoreline cleanups on short notice. While these workers are located in Brazil, they are also available to respond to an offshore oil spill outside of Brazil. We also have stockpiles of the equipment needed to quickly and effectively contain offshore spills or leaks, including over 170 miles of containment and absorbent booms, over 55,000 gallons of oil dispersants and 150 oil pumps. Petrobras has 30 dedicated oil spill recovery vessels (OSRVs) fu lly equipped for oil spill control and fire fighting, as well as 130 additional support and recovery boats and barges available to fight offshore oil spills and leaks 24 hours a day, seven days a week. In addition, we have contracts with local emergency responders Clean Caribbean and Americas Cooperative in North America and Oil Spill Response Limited in Africa and Asia. We also maintain relationships with major Oil Spill Response Organizations and other oil companies.

Mr. H. Roger Schwall

Page 12

Petrobras created ten environmental protection centers in strategic areas in which we operate throughout Brazil in order to ensure rapid and coordinated response to onshore or offshore oil spills. These regional facilities are supported by 13 local advance bases dedicated to oil spill prevention, control and response. Our environmental protection centers and their advance bases would be mobilized in the event of a spill or leak at one of our offshore operations. Each of our local and regional response centers is self sufficient and available to respond either individually or jointly together with neighboring facilities depending on the severity and scale of the emergency.

In future filings on Form 20-F, Petrobras will expand its oil spill response disclosure found on page 72 of the 2009 Form 20-F along the lines set forth above.

Comment

Operating and Financial Review and Prospects, page 73

Liquidity and Capital Resources, page 91

8. We note your disclosure that you entered into a U.S. $10 billion financing with China Development Bank in 2009 and, further, that you withdrew U.S. $4 billion of this amount as of May 10, 2010, in order to help meet your financing needs. Given that this appears to be a material contract upon which your business is substantially dependent, please file the financing agreement with your next Form 6-K, or tell us why you believe you need not file it. Refer to Instruction 4(b)(ii) in the Instructions as to Exhibits section of Form 20-F.

Response to Comment

The U.S.$10 billion bilateral loan from the China Development Bank is a contract made in the ordinary course of Petrobras’ business. We routinely enter into financing agreements with Brazilian and international government development banks to help us meet our financing needs. Such loans form only part of our overall financing strategy. We also raise debt capital from a variety of other traditional sources, including the issuance of bonds in the international capital markets, supplier financing, project financing, export credit facilities and loans from Brazilian and international commercial banks.

Furthermore, Petrobras does not consider the U.S.$10 billion bilateral loan from the China Development Bank to be a contract upon which our business is substantially dependent. In 2009, Petrobras drew down a total of U.S.$3 billion under the U.S.$10 billion loan from the China Development Bank. The U.S.$3 billion drawdown comprised approximately 9% of the total U.S.$33 billion of debt capital we raised in 2009 from our traditional financing sources mentioned above.

In 2010, Petrobras has drawn down an additional U.S.$4 billion from the China Development Bank. As disclosed in our 2009 20-F, we also plan to fund our financing needs in 2010 by issuing equity and, depending on the timing and amount of the equity issue, by contracting new debt from our traditional funding sources.

Petrobras believes that if it had not secured the U.S.$10 billion loan from the China Development Bank, it would have raised that amount from other traditional funding sources mentioned above.

Mr. H. Roger Schwall

Page 13

* * *

The Companies make the following acknowledgments:

·	the Companies are responsible for the adequacy and accuracy of the disclosure in their respective filings;

·	comments of the Commission staff, or changes to disclosure in response to staff comments, do not foreclose the Commission from taking any action with respect to the filings; and

·	the Companies may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

* * *

Mr. H. Roger Schwall

Page 14

If you have any questions or require any additional information with respect to the above, please do not hesitate to contact Nicolas Grabar at Cleary Gottlieb Steen & Hamilton LLP at (212) 225 2414 (direct) or (212) 225 3999 (facsimile).

Very truly yours,

/s/ Almir Guilherme Barbassa

Petróleo Brasileiro S.A.—Petrobras

Name: Almir Guilherme Barbassa

Title: Chief Financial Officer

/s/ Sérvio Túlio da Rosa Tinoco

Petrobras International Finance Company

Name: Sérvio Túlio da Rosa Tinoco

Title: Chief Financial Officer

cc Nicolas Grabar

Cleary Gottlieb Steen & Hamilton LLP

Exhibit A

Third-Party Engineering Report for Domestic Reserves

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

May 19, 2010

Petróleo Brasileiro S.A.

Av. República de Chile 65

Sala 1702C

Rio de Janeiro-RJ-Brazil

CEP 20035-900

Gentlemen:

Pursuant to your request, we have conducted a reserves audit of the net proved crude oil, condensate, and natural gas reserves, as of December 31, 2009, of certain properties owned by Petróleo Brasileiro S.A. (Petrobras). The properties are located in Brazil and offshore from Brazil. Petrobras has represented that these properties account for 96.5 percent on a net equivalent barrel basis of Petrobras’ net proved reserves as of December 31, 2009, and that the net proved reserves estimates have been 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 to us by Petrobras that it represents to be Petrobras’ estimates of the net reserves, as of December 31 , 2009, for the same properties as those which we evaluated. The results of our reserves audit completed on February 17, 2010 are compared to Petrobras’ estimates of reserves and comments on such comparison are presented herein.

Reserves included herein are expressed as net reserves as represented by Petrobras. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2009. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Petrobras after deducting all interests owned by others.

Estimates of oil, condensate, and natural gas 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.

Data used in this audit were obtained from reviews with Petrobras personnel, Petrobras files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Petrobras with respect to property interests, 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.

Methodology and Procedures

Estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. 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. The assumptions, data, methods, and procedures we have relied on and used are appropriate for the purpose served by this report.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

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 the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Petroleum reserves estimated by Petrobras and by us are classified as proved and 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. Petrobras represents that its estimates of the proved reserves classifications used are in accordance with the reserves definit ions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC.

Definition of Reserves

Petroleum reserves included in this report are classified by degree of proof as proved and 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. Proved 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. 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.

(i) The area of the reservoir considered as proved includes:

(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 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.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil and Condensate Prices

Petrobras has represented that the oil and condensate prices were based on a 12-month average price, calculated as the unweighted 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 agreements. The 12-month average adjusted product price was U.S.$51.55 per barrel based on a 12-month average benchmark product price of U.S.$60.20 per barrel. Petrobras supplied differentials by field to a Brent reference price and the prices were held constant thereafter.

Natural Gas Prices

Petrobras has represented that the natural gas prices were based on a 12-month average price, calculated as the unweighted 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 agreements. The 12-month average adjusted product price was U.S.$3.18 per thousand cubic feet based on a 12-month average internal product transfer price of U.S.$3.80 per thousand cubic feet provided by Petrobras. The internal product transfer price is the agreed price of gas between Petrobras E&P (upstream division) and Petrobras Gas & Energy (downstream division). These prices were not escalated for inflation.

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Petrobras, were 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.

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 oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2009, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

Petrobras has represented that estimated net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves of the SEC. Petrobras represents that its estimates of the net proved reserves attributable to these properties which represent 96.5 percent of Petrobras’s reserves on a net equivalent basis are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalent (MMboe):

	Estimated by Petrobras Net Proved Reserves as of December 31, 2009
Properties reviewed by DeGolyer and MacNaughton	Oil and Condensate (MMbbl)	Natural Gas (Bcf)	Oil Equivalent (MMboe)

Brazil
Proved Developed	5,940.4	4,808.0	6,741.7
Proved Undeveloped	3,693.2	4,371.9	4,421.9

Total Proved	9,633.6	9,179.9	11,163.6

Note: Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 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, 1202(a) (1), (2), (3), (4), (8)(i), (ii), and (iv)–(x), and 1203(a) of Regulation S–K of the SEC.

In comparing the detailed net proved reserves estimates prepared by us and by Petrobras, we have found differences, both positive and negative. It is our opinion that the net proved reserves estimates prepared by Petrobras on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by us. This opinion is based on a detailed and independent reserves evaluation of over 96 percent of Petrobras’ net proved reserves in Brazil conducted in accordance with the methodology and procedures set forth above. The aggregate difference between our estimates of the net proved reserves of the fields evaluated is less than 1 percent compared to estimates prepared by Petrobras for the same fields.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. 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. DeGolyer and MacNaughton has used all data, procedures, assumptions, and methods that it considers necessary to prepare this report.

Submitted,

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

[STAMP]

/s/ R. M. Shuck, P.E.
R. M. Shuck, P.E.

Senior Vice President

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

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

That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the report addressed to Petrobras dated February 17, 2010, and that I, as Senior Vice President, was responsible for the preparation of this report.

That I attended University of Houston, and that I graduated with a Bachelor of Science degree in Chemical Engineering in the year 1977; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers; and that I have in excess of 32 years of experience in the oil and gas reservoir studies and reserves evaluations.

[STAMP]

/s/ R. M. Shuck, P.E.
R. M. Shuck, P.E.

Senior Vice President

DeGolyer and MacNaughton

Exhibit B

Third-Party Engineering Report for International Reserves

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

May 19, 2010

Petróleo Brasileiro S.A.

Av. República de Chile 65

Sala 1702C

Rio de Janeiro-RJ-Brazil

CEP 20035-900

Gentlemen:

Pursuant to your request, we have conducted a reserves audit of the net proved crude oil, condensate, and natural gas reserves, as of December 31, 2009, of certain selected properties in North America and South America (outside of Brazil) owned by Petróleo Brasileiro S.A. (Petrobras). Petrobras has represented that these properties account for 93.3 percent on a net equivalent barrel basis of Petrobras’ net proved reserves in operated fields outside of Brazil as of December 31, 2009. The net proved reserves estimates prepared by us have been 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. The results of our reserves audits, completed on January 11, 2010 for the No rth American properties, January 15, 2010, and February 17, 2010 for the South American properties outside of Brazil, are presented herein.

Reserves included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2009. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Petrobras after deducting all interests owned by others.

Data used in this audit were obtained from reviews with Petrobras personnel, Petrobras files, from records on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by Petroleum Information/Dwights LLC; Copyright 2009 Petroleum Information/Dwights LLC. In the preparation of this report we have relied, without independent verification, upon such information furnished by Petrobras with respect to property interests, 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 necessar y for the purposes of this report.

DeGolyer and MacNaughton

Methodology and Procedures

Petroleum reserves estimated by Petrobras and by us are classified as proved and 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. Proved reserves classifications used by Petrobras are in accordance with the reserves definitions of Rule s 4-10(a) (1)–(32) of Regulation S–X of the SEC.

Definition of Reserves

DeGolyer and MacNaughton

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. Proved 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. 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.

(i) The area of the reservoir considered as proved includes: (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.

(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:

(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

DeGolyer and MacNaughton

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 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.

(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.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil and Condensate Prices

Petrobras has represented that the oil and condensate prices were based on a 12-month average price, calculated as the unweighted 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 agreements. The 12-month average adjusted product price in South America was U.S.$53.00 per barrel and the 12-month average adjusted product price in North America was U.S.$61.02 per barrel. The 12-month average adjusted product prices were based on a 12-month average West Texas Intermediate benchmark product price of U.S.$61.02 per barrel. These prices were not escalated for inflation.

Natural Gas Prices

Petrobras has represented that the natural gas prices were based on a 12-month average price, calculated as the unweighted 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 agreements. The 12-month average adjusted product price in South America was U.S.$2.10 per thousand cubic feet based on the 12-month weighted average of contract prices provided by Petrobras. The 12-month average adjusted product price in North America was

DeGolyer and MacNaughton

U.S.$3.83 per thousand cubic feet, based on a 12-month average Henry Hub benchmark product price of U.S.$3.83 per thousand cubic feet. These prices were not escalated for inflation.

Operating Expenses and Capital Costs

Our estimates of Petrobras’s net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves of the SEC and are as follows, expressed in millions of barrels (MMbbl), millions of cubic feet (MMcf), and millions of barrels of oil equivalent (MMboe):

DeGolyer and MacNaughton

	Net Proved Reserves as of December 31, 2009
	Oil and Condensate (MMbbl)	Natural Gas (MMcf)	Oil Equivalent (MMboe)

North America
Proved Developed	3.890	28,599	8.656
Proved Undeveloped	3.404	16,575	6.167

Total Proved	7.294	45,174	14.823

South America (outside of Brazil)
Proved Developed	97.758	487,746	179.049
Proved Undeveloped	61.867	452,216	137.236

Total Proved	159.625	939,962	316.285

Total Proved	166.919	985,136	331.108

Notes:

1.	Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

2.	Reserves estimated in Argentina include only PESA’s interest.

In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 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, 1202(a) (1), (2), (3), (4), (8)(i), (ii), and (iv)-(x), and 1203(a) of Regulation S-K of the Securities and Exchange Commission.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. 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. DeGolyer and MacNaughton has used all procedures and methods that it considers necessary to prepare this report.

Submitted,

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

[STAMP]

/s/ R. M. Shuck, P.E.
R. M. Shuck, P.E.

Senior Vice President

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

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

That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the reports addressed to Petrobras dated January 11, 2010, January 15, 2010, and February 17, 2010, and that I, as Senior Vice President, was responsible for the preparation of this report.

[STAMP]

/s/ R. M. Shuck, P.E.
R. M. Shuck, P.E.

Senior Vice President

DeGolyer and MacNaughton

Petróleo Brasileiro S.A. - Petrobras (PBR) CORRESPCorrespondence with SEC