Exhibit 4.8





Exhibit 4.8




DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244




January 10, 2011




Petrobras Argentina S.A.

Maipú 1, 21st Floor

(C1084ABA) Buenos Aires

Argentina




Gentlemen:



Pursuant to your request, we have conducted a reserves evaluation of the net proved crude oil,
condensate, natural gas liquids (NGL), and natural gas reserves, as of December 31, 2010, of
certain selected properties in Argentina owned by Petrobras Argentina S.A. Petrobras Argentina S.A.
has represented that these properties account for 71 percent on a net equivalent barrel basis of
Petrobras Argentina S.A.’s net proved reserves as of December 31, 2010. These reserves represent
100 percent of properties operated by Petrobras Argentina S.A. 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 audit, completed on January 10, 2011, 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, 2010. Net
reserves are defined as that portion of the gross reserves attributable to the interests owned by
Petrobras Argentina S.A. after deducting all interests owned by others.



Estimates of oil, condensate, NGL, and natural gas 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.



 












 







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Data used in this evaluation were obtained from reviews with Petrobras Argentina S.A.
personnel, Petrobras Argentina S.A. 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 Argentina S.A. 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 appropriate geologic, petroleum engineering,
and evaluation principals 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.



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.


 


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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.



Definition of Reserves




Petroleum reserves estimated by us included in this report are classified as proved. Only
proved reserves have been evaluated for this report. Reserves classifications used by us 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.


 


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(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.


 


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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.


 


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Primary Economic Assumptions




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




Oil, Condensate, and Natural Gas Liquids Prices




Petrobras Argentina S.A. has represented that the oil, condensate, and NGL
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. Petrobras Argentina
S.A. provided these 12-month average prices by property, each including
differentials to the Brent reference price. The 12-month average adjusted
oil and condensate price and NGL price for these properties was $52.09/bbl
and $29.76/bbl, respectively. The volume-weighted average price
attributable to estimated proved reserves was U.S.$51.06 per barrel of oil
and condensate and $29.76 per barrel of NGL. These prices were not
escalated for inflation.




Natural Gas Prices




Petrobras Argentina S.A. 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 12-month average adjusted
product price was U.S.$2.21 per thousand cubic feet based on the 12-month
average of contract prices provided by Petrobras Argentina S.A. The
volume-weighted average price attributable to estimated proved reserves
was U.S.$2.57 per Mcf. These prices were not escalated for inflation.


 


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Operating Expenses and Capital Costs




Operating expenses and capital costs, based on information provided by
Petrobras Argentina S.A., 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, 2010, estimated oil and gas volumes. The reserves estimated in this report can be
produced under current regulatory guidelines.



Our estimates of Petrobras Argentina S.A.’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):



	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Estimated by DeGolyer and MacNaughton	 
	 	 	Net Proved Reserves	 
	 	 	as of	 
	 	 	December 31, 2010	 
	 	 	Oil and	 	 	 	 	 	 	Natural	 	 	Oil	 
	 	 	Condensate	 	 	NGL	 	 	Gas	 	 	Equivalent	 
	 	 	(MMbbl)	 	 	(MMbbl)	 	 	(MMcf)	 	 	(MMboe)	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Proved Developed
	 	 	38.152	 	 	 	1.564	 	 	 	366,597	 	 	 	100.816	 
	Proved Undeveloped
	 	 	12.766	 	 	 	2.212	 	 	 	362,371	 	 	 	75.373	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Total Proved
	 	 	50.918	 	 	 	3.776	 	 	 	728,968	 	 	 	176.189	 








	 	 	 
	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), and 1203(a) of Regulation
S—K of the Securities and Exchange Commission.


 


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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.



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 Argentina S.A. Our
fees were not contingent on the results of our evaluation. This letter report has been prepared at
the request of Petrobras Argentina S.A. 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






	 	 	 	 	 
	[SEAL]

	 	/s/ Thomas C. Pence, P.E.
 

Thomas C. Pence, P.E.
	 	 
	 

	 	Senior Vice President	 	 
	 

	 	DeGolyer and MacNaughton	 	 






 


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CERTIFICATE of QUALIFICATION




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




	 	1.	 	That I am a Senior Vice President with DeGolyer and MacNaughton, which company did
prepare the report addressed to Petrobras Argentina S.A. dated January 10, 2011, and that
I, as Senior Vice President, was responsible for the preparation of this report.

	 
	 	2.	 	That I attended Texas A&M University, and that I graduated with a degree in Petroleum
Engineering in the year 1982; 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 28 years of experience in the oil and gas reservoir studies and reserves
evaluations.







 


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