Edgar Filing: YPF SOCIEDAD ANONIMA

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F/A

(Amendment No. 2)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007

Commission file number: 1-12102

YPF Sociedad Anónima

(Exact name of registrant as specified in its charter)

Republic of Argentina

(Jurisdiction of incorporation or organization)

Avenida Pte. R. Sáenz Peña 777

C1035AAC Ciudad Autónoma de Buenos Aires, Argentina

(54-11) 4329-2000

(Address of principal executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of Each Class		Name of Each Exchange on Which Registered
American Depositary Shares, each representing one Class D Share, par value 10 pesos per share		New York Stock Exchange
Class D Shares		New York Stock Exchange*

___________

*	Listed not for trading but only in connection with the registration of American Depositary Shares.

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

The number of outstanding shares of each class of stock of YPF Sociedad Anónima as of December 31, 2007 was:

Class A Shares	3,764
Class B Shares	7,624
Class C Shares	105,736
Class D Shares	393,195,669
	393,312,793

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.		Yes No S

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 OR 15(d) of the Securities Exchange Act of 1934.		Yes No S

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.		Yes S No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer x Non-accelerated filer o

Indicate by check mark which financial statement item the registrant has elected to follow.	Item 17 Item 18 S

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)		Yes No S

EXPLANATORY NOTE

This Annual Report on Form 20-F/A (“Form 20-F/A”) is being filed by us as Amendment No. 2 to our Annual Report on Form 20-F for the fiscal year ended December 31, 2007 (the “2007 Form 20-F”). This Form 20-F/A is filed solely for the purpose of (1) including all information and sections that were previously included in our 2007 Form 20-F filed on April 15, 2008 and in Amendment No. 1 to our 2007 Form 20-F filed on April 16, 2008, (2) addressing the filing to the Commission’s current address, (3) modifying a statement regarding the effectiveness of our disclosure controls and procedures to remove any ambiguity regarding the effectiveness of our disclosure controls and procedures at a reasonable assurance level, and (4) removing the subtotal of “Future net cash flows, before income taxes” in the standardized measure of discounted future net cash flows in the “Supplemental Information on Oil and Gas Producing Activities (Unaudited)” section of our financial statements. Other than as stated above, this Form 20-F/A does not amend, update or restate the information in any other item or section of the 2007 Form 20-F as originally filed on April 15, 2008 or reflect any events that have occurred after the original filing of the 2007 Form 20-F on April 15, 2008.

TABLE OF CONTENTS

Page

Conversion Table	1
References	1
Disclosure of Certain Information	1
Forward-Looking Statements	1
Oil and Gas Terms	3
PART I	9
ITEM 1. Identity of Directors, Senior Managers and Advisers	9
ITEM 2. Offer Statistics and Expected Timetable	9
ITEM 3. Key Information	9
Selected Financial Data	9
Risk Factors	13
ITEM 4. Information on the Company	23
History and Development of YPF	23
The Argentine Market	26
History of YPF	26
Business Segments	26
Exploration and Production	28
Exploration and Development Activities	31
Refining and Marketing	47
Chemicals	53
Research and Development	54
Competition	55
Environmental Matters	55
Property, Plant and Equipment	57
Regulatory Framework and Relationship with the Argentine Government	58
ITEM 4A. Unresolved Staff Comments	74
ITEM 5. Operating and Financial Review and Prospects	75
Overview	75
Presentation of Financial Information	76
Segment Reporting	76
Factors Affecting Our Operations	77
Critical Accounting Policies	85
Principal Income Statement Line Items	90

Results of Operations	92
Liquidity and Capital Resources	98
Off-Balance Sheet Arrangements	103
ITEM 6. Directors, Senior Management and Employees	104
Board of Directors	104
The Audit Committee	110
Independence of the Members of our Board of Directors and Audit Committee	112
Disclosure Committee	112
Executive Officers	114
Compliance with NYSE Listing Standards on Corporate Governance	114
Compensation of Directors and Officers	115
Supervisory Committee	115
Employee Matters	118
ITEM 7. Major Shareholders and Related Party Transactions	120
Share Purchase Agreement and Related Financing Agreements	120
Option Agreements	121
Shareholders’ Agreement	121
Registration Rights and Related Agreements	123
Related Party Transactions	124
Argentine Law Concerning Related Party Transactions	124
ITEM 8. Financial Information	126
Financial Statements	126
Legal Proceedings	126
Dividends Policy	139
ITEM 9. The Offer and Listing	140
Shares and ADSs	140
Argentine Securities Market	142
ITEM 10. Additional Information	145
Memorandum and Articles of Association	145
Directors	145
Foreign Investment Legislation	146
Dividends	147
Amount Available for Distribution	147
Preemptive and Accretion Rights	148
Voting of the Underlying Class D Shares	149
Certain Provisions Relating to Acquisitions of Shares	150
Taxation	152
Argentine Tax Considerations	152
United States Federal Income Tax Considerations	154
Available Information	156
ITEM 11. Quantitative and Qualitative Disclosures about Market Risk	157
ITEM 12. Description of Securities Other than Equity Securities	158
PART II	159
ITEM 13. Defaults, Dividend Arrearages and Delinquencies	159
ITEM 14. Material Modifications to the Rights of Security Holders and Use of Proceeds	159
ITEM 15. Controls and Procedures	159
ITEM 16.	160

ITEM 16A. Audit Committee Financial Expert	160
ITEM 16B. Code of Ethics	160
ITEM 16C. Principal Accountant Fees and Services	160
ITEM 16D. Exemptions from the Listing Standards for Audit Committees	161
ITEM 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers	161
PART III	162
ITEM 17. Financial Statements	162
ITEM 18. Financial Statements	162
ITEM 19. Exhibits	162
SIGNATURES	163

iii

Conversion Table

1 ton = 1 metric ton= 1,000 kilograms = 2,204 pounds

1 barrel = 42 U.S. gallons

1 ton of oil = approximately 7.3 barrels (assuming a specific gravity of 34 degrees API (American Petroleum Institute))

1 barrel of oil equivalent = 5,615 cubic feet of gas = 1 barrel of oil, condensate or natural gas liquids

1 kilometer = 0.63 miles

1 million Btu = 252 termies

1 cubic meter of gas = 35.3147 cubic feet of gas

1 cubic meter of gas = 10 termies

1000 acres = approximately 4 square kilometers

References

YPF Sociedad Anónima is a stock corporation organized under the laws of the Republic of Argentina (“Argentina”). As used in this annual report, “YPF,” “the company,” “we,” “our” and “us” refer to YPF Sociedad Anónima and its controlled and jointly controlled companies or, if the context requires, its predecessor companies. “YPF Sociedad Anónima” refers to YPF Sociedad Anónima only. “Repsol YPF” refers to Repsol YPF, S.A. and its consolidated companies, including YPF, unless otherwise specified. We maintain our financial books and records and publish our financial statements in Argentine pesos. In this annual report, references to “pesos” or “Ps.” are to Argentine pesos, and references to “dollars,” “U.S. dollars” or “U.S.$” are to United States dollars.

Disclosure of Certain Information

In this annual report, references to “Audited Consolidated Financial Statements” are to YPF’s audited consolidated balance sheets as of December 31, 2007, 2006 and 2005, and YPF’s audited consolidated statements of income for the three years ended December 31, 2007, 2006 and 2005.

Unless otherwise indicated, the information contained in this annual report reflects:

·	for the subsidiaries that were consolidated using the global integration method at the date or for the periods indicated, 100% of the assets, liabilities and results of operations of such subsidiaries without excluding minority interests, and

for those subsidiaries whose results were consolidated using the proportional integration method, a pro rata amount of the assets, liabilities and results of operations for such subsidiaries at the date or for the periods indicated. For information regarding consolidation, see Note 1 to the Audited Consolidated Financial Statements.

The Audited Consolidated Financial Statements and other amounts derived from such Audited Consolidated Financial Statements, included in this annual report, reflect the effect of changes in the purchasing power of money by the application of the method for remeasurement in constant pesos. All the amounts were remeasured to constant pesos as of February 28, 2003. See Note 1 to the Audited Consolidated Financial Statements.

Forward-Looking Statements

This annual report, including any documents incorporated by reference, contains statements that we believe constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements may include statements regarding the intent, belief or current expectations of us and our management, including statements with respect to trends affecting our financial condition, financial ratios, results of operations, business, strategy, geographic concentration, production volume and reserves, as well as our plans with respect to capital expenditures, business strategy, geographic concentration, cost savings, investments and dividends payout policies. These statements are not a guarantee of future performance and are subject to material risks, uncertainties, changes and other factors which may be beyond our control or may be difficult to predict.

Accordingly, our future financial condition, prices, financial ratios, results of operations, business, strategy, geographic concentration, production volumes, reserves, capital expenditures, cost savings, investments and dividend policies could differ materially from those expressed or implied in any such forward-looking statements. Such factors include, but are not limited to, currency fluctuations, the price of petroleum products, the ability to realize cost reductions and operating efficiencies without unduly disrupting business operations, replacement of hydrocarbon reserves, environmental, regulatory and legal considerations and general economic and business conditions in Argentina, as well as those factors described in the filings made by YPF and its affiliates with the Securities and Exchange Commission, in particular, those described in “Item 3. Key Information—Risk Factors” below and “Item 5. Operating and Financial Review and Prospects.” YPF does not undertake to publicly update or revise these forward-looking statements even if experience or future changes make it clear that the projected results or condition expressed or implied therein will not be realized.

Oil and Gas Terms

Oil and gas reserves definitions used in this annual report are in accordance with the reserves definitions of Rule 4-10(a) (1)-(17) of Regulations S-X of the SEC.

The definitions of Reserves Estimate, Reserves Audit and Reserves Review as given below and used hereunder are not terms defined under U.S. Securities and Exchange Commission (“SEC”) Rules or Regulations and are terms used by YPF in this annual report as defined herein and consequently such definitions may be defined and used differently by other companies.

For the purpose of this annual report, any reserves estimate, or any independent reserves audit or any reserves review invoked hereunder, are in accordance with the oil and gas reserves definitions of Rule 4-10(a) (1)-(17) of Regulations S-X of the SEC.

The following terms have the meanings shown below unless the context indicates otherwise:

“acreage”: The total area, expressed in acres or km2, over which we have interests in exploration or production. Net acreage is our interest in the relevant exploration or production area.

“concession”: A grant of access for a defined area and time period that transfers certain entitlements to produce hydrocarbons from the host country to an enterprise. The company holding the concession generally has rights and responsibilities for exploration, development, production and sale of hydrocarbon. Typically, the concession is granted under a legislated fiscal system where the host country collects royalties on the estimated value at the wellhead of crude oil production and the natural gas volume commercialized and taxes or fees on profits earned.

“exploratory well”: A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

“hydrocarbons”: Crude oil and natural gas.

“natural gas liquids,” or “NGL”: The portions of gas from a reservoir that are liquefied at the surface in separators, field facilities, or gas processing plants. NGL from gas processing plants is also called liquefied petroleum gas, or “LPG.”

“oil and gas producing activities”:

(i)	Such activities include:

A.	The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations.

B.	The acquisition of property rights or properties for the purpose of further exploration and/or for the purpose of removing the oil or gas from existing reservoirs on those properties.

The construction, drilling and production activities necessary to retrieve oil and gas from their natural reservoirs, and the acquisition, construction, installation, and maintenance of field gathering and storage systems – including lifting the oil and gas to the surface and gathering, treating, field processing (as in the case of processing gas to extract liquid hydrocarbons) and field storage. For purposes of this section, the oil and gas production function shall normally be regarded as terminating at the outlet valve on the lease or field storage tank; if unusual physical or operational circumstances exist, it may be appropriate to regard the production function as terminating at the first point at which oil, gas or gas liquids are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal.

(ii)	Oil and gas producing activities do not include:

A.	The transporting, refining and marketing of oil and gas;

B.	Activities relating to the production of natural resources other than oil and gas;

C.	The production of geothermal steam or the extraction of hydrocarbons as a by-product of the production of geothermal steam or associated geothermal resources as defined in the Geothermal Steam Act of 1970; or

D.	The extraction of hydrocarbons from shale, tar sands or coal.

“proved oil and gas reserves”: Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

i)	Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

A.	that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

ii)

Reserves that can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

iii) Estimates of proved reserves do not include the following:

A.	oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

B.	crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

C.	crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

D.	crude oil, natural gas, and natural gas liquids, that may be recovered from oil sales, coal, gilsonite and other such sources.

“proved developed reserves”: Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

“proved undeveloped reserves”: Proved undeveloped oil and gas reserves are reserves 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved 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 tests in the area and in the same reservoir.

“recovery factor”: The recoverable amount of the original or residual estimated hydrocarbons in place in a reservoir, expressed as a percentage of total hydrocarbons in place.

“refining capacity”: The crude oil processing capacity of refineries, expressed as an average over a period of time for the quality of oil and under conditions for which the facility was designed. Such capacity could be improved through the application of updated operation and maintenance techniques, increased availability, equipment revamps, de-bottlenecking, and the use of higher qualities of crude oil than those for which the refinery was originally designed, among other improvements.

“reserves audit”: A reserves audit is the process of reviewing certain factual matters and assumptions on which an estimate of reserves and/or reserves information prepared by others has been based and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, (4) the classification of reserves appropriate to the relevant definitions used, and (5) the reasonableness of the estimated reserves quantities and/or the reserves information, and is, therefore, free of material misstatement. The term “reasonableness” cannot be defined with precision but reflects a quantity and/or value difference as contemplated under “Internal Control on Reserves and Reserves Audits.” Often a reserves audit includes a detailed review of certain critical assumptions and independent assessments with acceptance of other information less critical to the reserves estimation. Typically, a reserves audit letter should be of sufficient rigor to determine the appropriate reserves classification for all reserves in the property set evaluated and to clearly state the reserves classification system being utilized. In contrast to the term “audit” as used in a financial sense, a reserves audit is generally less rigorous than a reserves report.

The estimation of reserves and other reserves information is an imprecise science due to the many unknown geological and reservoir factors that can only be estimated through sampling techniques. Since reserves are therefore only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserves information is audited for the purpose of reviewing in sufficient detail the policies, procedures, methods and data used by us in estimating our reserves information so that the reserves auditors may express an opinion as to whether, in the aggregate, the reserves information furnished by us is reasonable within established and predetermined tolerances and has been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles and within the rules and regulations of the SEC.

In some cases, the auditing procedure may require independent estimates of reserves information for some or all properties. The desirability of such re-estimation will be determined by the reserves auditor exercising his or her professional judgment in arriving at an opinion as to the reasonableness of our reserves information. In those cases, an external reservoir engineer makes an independent comprehensive evaluation of reserves by interpreting and assessing all the pertinent data to generate such engineer’s own cash flow analysis and proved reserves estimate. The degree of assurance of such independent estimates cannot usually be provided with numeric precision.

The main product of these external engineering evaluations is a report that includes the engineer’s actual proved reserves estimates and economic evaluation. This report may also, at our request, include maps, logs, or other technical backup used by the external reservoir engineer, with an opinion letter that includes the reserves auditor’s findings, conformance or not with the applicable principles, definitions and procedures for estimating reserves. This opinion may also, at our request, include conclusions and recommendations. In the aforementioned case where the auditor performs an independent estimate of reserves information, we will call it an external reserves certification.

In all cases, in the opinion letter or report issued by the auditor, the reserves auditor states his or her professional standing and professional affiliation as a registered or certified professional from an appropriate governmental authority or professional organization.

A reserves auditor is a professional who has sufficient educational background, professional training and professional experience to enable him or her to exercise prudent professional judgment while in charge of the conduct of an audit of reserves information estimated by others. The determination of whether a reserves auditor is professionally qualified is made on an individual-by-individual basis with reference to the recognition and respect of his or her peers. A reserves auditor would normally be considered by us to be qualified if he or she (i) has a minimum of 10 years’ practical experience in petroleum engineering or petroleum production geology, with at least

five years of such experience in charge of the estimations and evaluation of reserves information; and (ii) either (A) has obtained, from a college or university of recognized stature, a bachelor’s or advanced degree in petroleum engineering, geology or other discipline of engineering or physical science, or (B) has received, and is maintaining in good standing, a registered or certified professional engineer’s license or a registered or certified professional geologist’s license, or the equivalent thereof, from an appropriate governmental authority or professional organization.

Our standard of independence for reserves auditors is that he or she must not have any financial interest in the properties under evaluation. This is in order that there is no incentive for his or her reports to be outcome-oriented because there is no direct economic benefit for him or her as a consequence of the results of his or her work. An independent reserves auditor’s compensation is based only on professional services carried out to deliver an unbiased analysis suitable for the public and financial communities. We also require that a statement of such independence is included in the auditor’s report.

The meaning of the terms “reserves audit,” “reserves report,” “external reserves certification” among others may not be comparable to other similar terms used by other companies in respect of proved reserves.

“reserves estimate”: The process whereby a qualified reserves estimator performs a comprehensive evaluation by interpreting and assessing all the pertinent data to generate such proved reserves estimates and cash flow analysis. The main product of this evaluation results in a report that includes: (i) the actual reserve estimate quantities, (ii) the future producing rates from such reserves, (iii) the future net revenues from such reserves, and (iv) the present value of such future net revenue. This report may also include maps, logs or other technical backup used by the estimator.

“reserves review”: The process whereby a qualified reserves professional reviewer conducts a high-level assessment of reserves information to determine if it is plausible. The steps consist primarily of:

inquiry;

analytical procedures;

analysis;

review of historical reserves performance; and

discussions with reserves management staff.

“plausible” means the reserves data appearing to be worthy of belief based on the information obtained by a reserves estimator or by an independent qualified reserves auditor in carrying out the aforementioned steps. It may result in a statement like “Nothing came to my attention that would indicate the reserves information has not been prepared and presented in accordance with the applicable principles and definitions.”

Our standard for an “Independent Qualified Reserves Auditor” is that an Independent Qualified Reserves Auditor is a professional who has sufficient educational background, professional training and professional experience to enable him or her to exercise prudent professional judgment while in charge of the conduct of an audit of reserves information estimated by others. The determination of whether a Reserves Auditor is professionally qualified is made on an individual-by-individual basis with reference to the recognition and respect of his or her peers. A Reserves Auditor would normally be considered by us to be qualified if he or she (i) has a minimum of 10 years’ practical experience in petroleum engineering or petroleum production geology, with at least 5 years of such experience in charge of the estimations and evaluation of reserves information; and (ii) either (A) has obtained, from a college or university of recognized stature, a bachelor’s or advanced degree in petroleum engineering, geology or other discipline of engineering or physical science, or (B) has received, and is maintaining in good standing, a registered or certified professional engineer’s license or a registered or certified professional geologist’s license, or the equivalent thereof, from an appropriate governmental authority or professional organization.

Our standard of independence for Consulting Reserves Auditors is that he or she must not have any financial interest in the properties under evaluation. This is in order that there is no incentive for his or her reports to be outcome-oriented because there is no direct economic benefit for him or her as a consequence of the results of his or her work. The Independent Qualified Reserves Auditor’s compensation is based only on professional services

carried out to deliver an unbiased analysis suitable for the public and financial communities. We also require that a statement of such independence be included in the auditor’s report.

Reviews do not require examination of the detailed documentation that supports the reserves information, unless this information does not appear to be plausible. A reserves review, due to the limited nature of the investigation involved, does not provide the level of assurance provided by a reserves estimate or a reserves audit. Though reserves reviews can be done for specific applications, they are not a substitute for an audit or an estimate.

Abbreviations:

“bbl”

Barrels

“Bcf”

Billion cubic feet ≡ 109 cubic feet

“Bcm”

Billion cubic meters ≡ 109 cubic meters

“boe”

Barrels of oil equivalent

“boe/d”

Barrels of oil equivalent per day

“Condensate”

Mixture of hydrocarbons that exist in the gaseous phase at original temperature and pressure of the reservoir, but when produced condense into liquid phase at temperature and pressure associated with surface production equipment

“Gas”

Natural gas

“GWh”

Gigawatt hours

“HP”

Horse Power

“km”

Kilometers

“km2”

Square kilometers

“m”

Thousand

“m3”

Cubic meter

“mbbl/d”

Thousand barrels per day

“mboe/d”

Thousand barrels of oil equivalent per day

“mcf”

Thousand cubic feet

“mcm”

Thousand cubic meters

“mm”

Million

“mmbbl”

Million barrels

“mmboe”

Million barrels of oil equivalent

“mmboe/d”

Million barrels of oil equivalent per day

“mmBtu”

Million British thermal units

“mmcf”

Million cubic feet

“mmcf/d”

Million cubic feet per day

“mmcm”

Million cubic meters

“mmcm/d”

Million cubic meters per day

“mtn”

Thousand tons

“MW”

Megawatts

“Oil”

Crude oil, condensate and natural gas liquids

“WTI”

West Texas Intermediate

“USA”

United States

Oil and gas reserves definitions used in this annual report are in accordance with the reserves definitions of Rule 4-10(a) (1)-(17) of Regulation S-X of the SEC.

The definitions of reserves estimate, reserves audit and reserves review as given below and used hereunder are not terms defined under SEC Rules or Regulations and are terms used by us in this annual report as defined herein and consequently such terms may be defined and used differently by other companies.

PART I

ITEM 1. Identity of Directors, Senior Managers and Advisers

Not applicable.

ITEM 2. Offer Statistics and Expected Timetable

Not applicable.

ITEM 3. Key Information

Selected Financial Data

The following tables present our selected financial and operating data. You should read this information in conjunction with our Audited Financial Statements and related notes, and the information under “Item 5. Operating and Financial Review and Prospects” included elsewhere in this annual report.

The financial data as of December 31, 2007, 2006 and 2005 and for the years then ended is derived from our Audited Consolidated Financial Statements, which are included in this annual report. The financial data as of and for the years ended December 31, 2004 and 2003 is derived from our audited financial statements, which are neither included nor incorporated by reference in this annual report. Our audited financial statements have been prepared in accordance with generally accepted accounting principles in Argentina, which we refer to as Argentine GAAP and which differ in certain significant respects from generally accepted accounting principles in the United States, which we refer to as U.S. GAAP. Notes 13, 14 and 15 to our Audited Consolidated Financial Statements provide a description of the significant differences between Argentine GAAP and U.S. GAAP, as they relate to us, and a reconciliation to U.S. GAAP of net income and shareholders’ equity as of December 31, 2007, 2006 and 2005 and for the years then ended.

In this annual report, except as otherwise specified, references to “$,” “U.S.$” and “dollars” are to U.S. dollars, and references to “Ps.” and “pesos” are to Argentine pesos. Solely for the convenience of the reader, peso amounts as of and for the year ended December 31, 2007 have been translated into U.S. dollars at the exchange rate quoted by the Argentine Central Bank (Banco Central de la República Argentina or Central Bank) on December 28, 2007 of Ps.3.15 to U.S.$1.00 (the last quoted rate in December 2007), unless otherwise specified. The exchange rate quoted by Central Bank on April 10, 2008 was Ps. 3.16 to U.S.$1.00. The U.S. dollar equivalent information should not be construed to imply that the peso amounts represent, or could have been or could be converted into U.S. dollars at such rates or any other rate. See “Item 3. Key Information—Exchange Rates.”

Certain figures included in this annual report have been subject to rounding adjustments. Accordingly, figures shown as totals may not sum due to rounding.

	As of and for Year Ended December 31,
	2007			2007			2006			2005(1)			2004(1)			2003(2)
	(in millions of
	U.S.$, except for per share and per ADS data)			(in millions of pesos, except for per share and per ADS data)
Consolidated Income Statement Data:
Argentine GAAP(3)
Net sales(4)(5)		9,239			29,104			25,635			22,901			19,931			17,514
Gross profit		3,208			10,104			9,814			11,643			10,719			9,758
Administrative expenses		(256	)		(805	)		(674	)		(552	)		(463	)		(378	)
Selling expenses		(673	)		(2,120	)		(1,797	)		(1,652	)		(1,403	)		(1,148	)
Exploration expenses		(166	)		(522	)		(460	)		(280	)		(382	)		(277	)
Operating income		2,113			6,657			6,883			9,161			8,471			7,955
Income on long-term investments		11			34			183			39			154			150
Other expenses, net		(139	)		(439	)		(204	)		(545	)		(981	)		(152	)
Interest expense		(93	)		(292	)		(213	)		(459	)		(221	)		(252	)
Other financial income (expenses) and holding gains (losses), net		257			810			667			561			359			202
Income from sale of long-term investments		2			5			11			15			—			—
Reversal (impairment) of other current assets		22			69			(69	)		—			—			—
Income before income tax		2,173			6,844			7,258			8,772			7,782			7,903
Income tax		(876	)		(2,758	)		(2,801	)		(3,410	)		(3,017	)		(3,290	)
Net income from continuing operations		1,297			4,086			4,457			5,362			4,765			4,613
Income on discontinued operations		—						—			—			3			15
Income from sale of discontinued operations		—						—			—			139			—
Net income		1,297			4,086			4,457			5,362			4,907			4,628
Earnings per share and per ADS(6)		3.30			10.39			11.33			13.63			12.48			11.77
Dividends per share and per ADS(6) (in pesos)	n.a.				6.00			6.00			12.40			13.50			7.60
Dividends per share and per ADS(6)(7) (in U.S. dollars)	n.a.				1.93			1.97			4.25			4.70			2.62
U.S. GAAP
Operating income		1,643			5,176			5,626			8,065			6,550			7,567
Net income		1,056			3,325			3,667			5,142			4,186			4,435
Earnings per share and per ADS(6) (in pesos)	n.a.				8.45			9.32			13.07			10.64			11.28
Consolidated Balance Sheet Data:
Argentine GAAP(3)
Cash		62			196			118			122			492			355
Working capital		1,296			4,081			4,905			2,903			3,549			4,001
Total assets		12,096			38,102			35,394			32,224			30,922			32,944
Total debt(8)		316			994			1,425			1,453			1,930			2,998
Shareholders’ equity(9)		8,273			26,060			24,345			22,249			21,769			22,534
U.S. GAAP
Total assets		12,935			40,746			37,046			34,748			32,540			34,125
Shareholders’ equity		9,228			29,067			26,241			24,254			23,506			24,334
Other Consolidated Financial Data:
Argentine GAAP
Fixed assets depreciation		1,314			4,139			3,718			2,707			2,470			2,307
Cash used in fixed asset acquisitions		1,957			6,163			5,002			3,722			2,867			2,418

____________

(1)	Consolidated income and balance sheet data for the years ended December 31, 2005 and 2004 set forth above include the retroactive effect from the application of new accounting rules in Argentina effective since January 1, 2006.

(2)	Consolidated income and balance sheet data for the year ended December 31, 2003 set forth above do not include the retroactive effect from the application of new accounting rules in Argentina, which was not material.

(3)

The financial statements reflect the effect of changes in the purchasing power of money by the application of the method for remeasurement in constant Argentine pesos set forth in Technical Resolution No. 6 of the Argentine Federation of Professional Councils in Economic Sciences (“F.A.C.P.C.E.”) and taking into consideration General Resolution No. 441 of the National Securities Commission (“CNV”), which established the discontinuation of the remeasurement of financial statements in constant Argentine pesos as from March 1, 2003. See Note 1 to the Audited Consolidated Financial Statements.

(4)

Includes Ps.1,350 million for the year ended December 31, 2007, Ps.1,451 million for the year ended December 31, 2006, Ps.1,216 million for the year ended December 31, 2005, Ps.1,122 million for the year ended December 31, 2004 and Ps.760 million for the year ended December 31, 2003 corresponding to the proportional consolidation of the net sales of investees in which we hold joint control with third parties. See Note 13(b) to the Audited Consolidated Financial Statements.

(5)

Net sales are net to us after payment of a fuel transfer tax, turnover tax and, from 2002, customs duties on hydrocarbon exports. Royalties with respect to our production are accounted for as a cost of production and are not deducted in determining net sales. See Note 2(g) to the Audited Consolidated Financial Statements.

(6)	Information has been calculated based on outstanding capital stock of 393,312,793 shares. Each ADS represents one Class D share. There were no differences between basic and diluted earnings per share and ADS for any of the years disclosed.

(7)	Amounts expressed in U.S. dollars are based on the exchange rate as of the date of payment. For periods in which more than one dividend payment was made, the amounts expressed in U.S. dollars are based on exchange rates at the date of each payment.

(8)	Total debt under Argentine GAAP includes nominal amounts of long-term debt of Ps.523 million as of December 31, 2007, Ps.510 million as of December 31, 2006, Ps.1,107 million as of December 31, 2005, Ps.1,684 million as of December 31, 2004 and Ps.2,085 million as of December 31, 2003.

(9)	Our subscribed capital as of December 31, 2007 is represented by 393,312,793 shares of common stock and divided into four classes of shares, with a par value of Ps.10 and one vote per share. These shares are fully subscribed, paid-in and authorized for stock exchange listing.

Exchange Rates

From April 1, 1991 until the end of 2001, the Convertibility Law (Law No. 23,928) established a fixed exchange rate under which the Central Bank was obligated to sell U.S. dollars at one peso per U.S. dollar. On January 6, 2002, the Argentine Congress enacted the Public Emergency Law (Law No. 25,561, the Public Emergency and Foreign Exchange System Reform Law), formally putting an end to the Convertibility Law regime and abandoning over 10 years of U.S. dollar-peso parity. The Public Emergency Law, which has been extended until December 31, 2008, grants the executive branch of the Argentine government the power to set the exchange rate between the peso and foreign currencies and to issue regulations related to the foreign exchange market. Following a brief period during which the Argentine government established a temporary dual exchange rate system pursuant to the Public Emergency Law, the peso has been allowed to float freely against other currencies since February 2002 although the government has the power to intervene by buying and selling foreign currency for its own account, a practice in which it engages on a regular basis.

The following table sets forth the annual high, low, average and period-end exchange rates for U.S. dollars for the periods indicated, expressed in nominal pesos per U.S. dollar, based on rates quoted by the Central Bank. The Federal Reserve Bank of New York does not report a noon buying rate for Argentine pesos.

	Low		High		Average			Period End
	(pesos per U.S. dollar)
Year ended December 31,
2003		2.76		3.35		2.94	(1)		2.93
2004		2.80		3.06		2.94	(1)		2.98

	Low		High		Average			Period End
	(pesos per U.S. dollar)
2005		2.86		3.04		2.90	(1)		3.03
2006		3.03		3.10		3.07	(1)		3.06
2007		3.05		3.18		3.12	(1)		3.15

Month
October 2007		3.15		3.18		3.16			3.15
November 2007		3.12		3.15		3.14			3.15
December 2007		3.13		3.15		3.14			3.15
January 2008		3.13		3.16		3.14			3.16
February 2008		3.15		3.17		3.16			3.16
March 2008		3.14		3.17		3.16			3.17
April 2008(2)		3.16		3.17		3.16			3.16

____________

Source: Central Bank

(1)	Represents the average of the exchange rates on the last day of each month during the period.

(2)	Through April 10, 2008.

No representation is made that peso amounts have been, could have been or could be converted into U.S. dollars at the foregoing rates on any of the dates indicated.

Exchange Controls

Prior to December 1989, the Argentine foreign exchange market was subject to exchange controls. From December 1989 until April 1991, Argentina had a freely floating exchange rate for all foreign currency transactions, and the transfer of dividend payments in foreign currency abroad and the repatriation of capital were permitted without prior approval of the Central Bank. From April 1, 1991, when the Convertibility Law became effective, until December 21, 2001, when the Central Bank closed the foreign exchange market, the Argentine currency was freely convertible into U.S. dollars.

On December 3, 2001, the Argentine government imposed a number of monetary and currency exchange control measures through Decree 1570/01, which included restrictions on the free disposition of funds deposited with banks and tight restrictions on transferring funds abroad (including the transfer of funds to pay dividends) without the Central Bank’s prior authorization subject to specific exceptions for transfers related to foreign trade. Since January 2003, the Central Bank has gradually eased these restrictions and expanded the list of transfers of funds abroad that do not require its prior authorization (including the transfer of funds to pay dividends). In June 2003, the Argentine government set restrictions on capital flows into Argentina, which mainly consisted of a prohibition against the transfer abroad of any funds until 180 days after their entry into the country. In June 2005, the government established further restrictions on capital flows into Argentina, including increasing the period that certain incoming funds must remain in Argentina to 365 calendar days and requiring that 30% of incoming funds be deposited with a bank in Argentina in a non-assignable, non-interest-bearing account for 365 calendar days. Under the exchange regulations currently in force, restrictions exist in respect of the repatriation of funds or investments by non-Argentine residents. For instance, subject only to limited exceptions, the repatriation by non-Argentine residents of funds received as a result of the sale of the Class D shares in the secondary market is subject to a limit of U.S.$500,000 per person per calendar month. In order to repatriate such funds abroad, non-Argentine residents also are required to demonstrate that the funds used to make the investment in the Class D shares were transferred to Argentina at least 365 days before the proposed repatriation. The transfer abroad of dividend payments is currently authorized by applicable regulations to the extent that such dividend payments are made in connection with audited financial statements and are approved by a shareholders’ meeting.

Risk Factors

Risks Relating to Argentina

Argentina’s economy may not continue to grow at current rates or may contract in the future

The Argentine economy has experienced significant volatility in recent decades, including numerous periods of low or negative growth and high and variable levels of inflation and devaluation. Since the most recent crisis of 2001 and 2002, the Argentine economy has grown at a rapid pace during recent years, with GDP increasing on a real basis by 8.7% in 2003, 9.0% in 2004, 9.2% in 2005, 8.5% in 2006 and 8.7%, based on preliminary data, in 2007. However, no assurances can be given that current rates of growth will continue. The Argentine economy remains susceptible to, among other things, a decline in commodity prices, limited international financing and investment in infrastructure and an increase in inflation. Sustained inflation in Argentina could increase our costs of operation, in particular labor costs, and without a corresponding increase in the price of our products, may negatively impact our results of operations and financial condition. Substantially all of our operations, properties and customers are located in Argentina, and, as a result, our business is to a large extent dependent upon economic conditions prevailing in Argentina. If economic conditions in Argentina were to deteriorate, it would likely have an adverse effect on our financial condition and results of operations.

Political and regulatory developments in Argentina may affect our domestic operations

The Argentine government exercises significant influence over the economy. In particular, the oil and gas industry is subject to extensive government regulation and control. As a result, our business is to a large extent dependent upon regulatory and political conditions prevailing in Argentina and our results of operations may be materially and adversely affected by regulatory and political changes in Argentina. We currently face risks and challenges relating to government regulation and control of the energy sector, including those set forth below and elsewhere in these risk factors:

·	limitations on our ability to pass increases in international prices of crude oil and other hydrocarbon fuels and exchange rate fluctuations through to domestic prices, or to increase local prices of natural gas (in particular for residential customers), gasoline and diesel;

·	higher taxes on exports of hydrocarbons;

·	restrictions on hydrocarbon export volumes driven mainly by the requirement to satisfy domestic demand;

·	in connection with the Argentine government’s policy to provide absolute priority to domestic demand, regulatory orders to supply natural gas and other hydrocarbon products to the domestic retail market in excess of previously contracted amounts;

·	the import of certain hydrocarbon fuels at international market prices to satisfy domestic demand at significantly lower domestic prices;

·	regulatory developments leading to the imposition of stricter supply requirements, fines or other actions by governmental authorities in response to fuel shortages at service stations;

·	the implementation or imposition of stricter quality requirements for petroleum products in Argentina; and

·	higher taxes on domestic fuel sales not compensated by price increases.

The Argentine government has made certain changes in regulations and policies governing the energy sector to give absolute priority to domestic supply at low, stable prices in order to sustain economic recovery. As a result of the above-mentioned changes, for example, on days during which a gas shortage occurs, exports of natural gas (which are also affected by other government curtailment orders) and the provision of gas supplies to industries, electricity generation plants and service stations selling compressed natural gas are interrupted for priority to be given to residential consumers at lower prices. We cannot assure you that changes in applicable laws and regulations, or adverse judicial or administrative interpretations of such laws and regulations, will not adversely affect our results of operations. See “Item 4. Information on the Company—Regulatory Framework and Relationship with the Argentine Government.” Similarly, we cannot assure you that future government policies aimed at sustaining economic recovery or in response to domestic needs will not adversely affect the oil and gas industry.

In January 2007, Law No. 26,197 was enacted, which, in accordance with Article 124 of the National Constitution, provided that Argentine provinces shall be the owners of the hydrocarbon reservoirs located within their territories. Pursuant to the law, the Argentine Congress is charged with enacting laws and regulations aimed at developing mineral resources within Argentina, while the provincial governments are responsible for enforcing these laws and administering hydrocarbon fields that fall within the territories of their respective provinces. Certain provincial governments, however, have construed the provisions of Law No. 26,197 and Article 124 to empower the provinces to enact their own regulations concerning exploration and production of oil and gas within their territories. There can be no assurance that regulations or taxes (including royalties) enacted or administered by the provinces will not conflict with federal law, and such taxes or regulations may adversely affect our operations and financial condition.

Limitations on local pricing in Argentina may adversely affect our results of operations

In recent years, due to regulatory, economic and government policy factors, our domestic gasoline, diesel and other fuel prices have lagged substantially behind prevailing international and regional market prices for such products, and our ability to increase prices has been limited. For example, in January 2008, diesel import prices were approximately U.S.$700/cubic meter, while the average domestic sales prices were approximately U.S.$350/cubic meter before government subsidies. Likewise, the prices at which we sell natural gas in Argentina (particularly to the residential sector) are subject to government regulations and currently are substantially below regional market prices for natural gas. For additional information on domestic pricing for our products, see “Item 5. Operating and Financial Review and Prospects” and “Item 4. Information on the Company—Regulatory Framework and Relationship with the Argentine Government—Market Regulation.” We cannot assure you that we will be able to increase the prices of our products sufficiently in the future, and limitations on our ability to do so would continue to adversely affect our financial condition and results of operations. Similarly, we cannot assure you that hydrocarbon prices in Argentina will reach prevailing international or regional levels.

We are subject to direct and indirect export restrictions, which have affected our results of operations and caused us to declare force majeure under certain of our export contracts

The Argentine Hydrocarbons Law (Law No. 17,319) allows for hydrocarbon exports as long as they are not required for the domestic market and are sold at reasonable prices. In the case of natural gas, Law 24,076 and related regulations require that the needs of the domestic market be taken into account when authorizing long term natural gas exports.

During the last several years, the Argentine authorities have adopted a number of measures that have resulted in the substantial restriction of exports of natural gas from Argentina, and the Argentine government’s current policy is not to allow any exports of natural gas other than to the residential sector in certain other countries.

Due to the foregoing, we have been obliged to sell a part of our natural gas production previously destined for the export market in the local Argentine market and have not been able to meet our contractual gas export commitments in whole or, in some cases, in part, leading to disputes with our export clients and forcing us to declare force majeure under our export sales agreements. We believe that the measures mentioned above constitute force majeure events that relieve us from any contingent liability for the failure to comply with our contractual obligations, although no assurance can be given that this position will prevail. See “Item 4. Information on the Company—Exploration and Production—The Argentine natural gas market” and “Item 8. Financial Information—Legal Proceedings.”

In addition, the effectiveness after certain specific dates of certain of our natural gas export authorizations is subject to an analysis by the Secretariat of Energy of natural gas reserves in the Noroeste basin. The result of such analysis is uncertain and may have an adverse impact upon our performance of the export gas sales agreements related to such export authorizations should the Secretariat determine that reserves are inadequate. See “Item 8. Financial Information—Legal Proceedings—Argentina.”

Crude oil exports, as well as the export of most of our hydrocarbon products, currently require prior authorization from the Secretariat of Energy (pursuant to the regime established under Resolution S.E. No. 1679/04 as amended and supplemented by other regulation). Oil companies seeking to export crude oil or LPG must first demonstrate that the local demand for such product is satisfied or that an offer to sell the product to local purchasers has been made and rejected. Oil refineries seeking to export diesel fuel must also first demonstrate that the local demand of diesel is duly satisfied. Because domestic diesel production does not currently satisfy Argentine domestic consumption needs, we have been prevented since 2005 from selling diesel production in the export market, and thereby obliged to sell in the local market at significantly lower prices.

We are unable to predict how long these export restrictions will be in place, or whether any further measures will be adopted that adversely affect our ability to export gas, crude oil and diesel fuel or other products and, accordingly, our results of operations.

The imposition of new export duties and other taxes could adversely affect our results

In recent years, new duties have been imposed on exports. In March 2002, oil and gas companies were levied with a five-year, 20% tax on proceeds from the export of crude oil and a five-year, 5% tax on proceeds from the export of oil products. These duties on exports were increased on May 11, 2004 to the following taxation rates: 25% on exports of crude oil, 20% on exports of butane, methane and LPG, and 5% on exports of gasoline and diesel. On May 26, 2004, a 20% duty on natural gas and natural gas liquids exports was imposed. On August 4, 2004, the Ministry of Economy and Production issued a resolution establishing a progressive scheme of export duties for crude oil, with rates ranging from 25% to 45%, depending on the quotation of the WTI reference price at the time of export and thereby modifying the fixed 25% tax rate established in May of that year.

Resolution 394/2007 of the Ministry of Economy and Production, published on November 16, 2007, amends the export duties on crude oil and other crude derivative products. The new regime provides that when the WTI international price exceeds the reference price, which is fixed at U.S.$60.9/barrel, the producer shall be allowed to collect at U.S.$42/barrel, with the remainder being withheld by the Argentine government as an export tax. If the WTI international price is under the reference price but over U.S.$45/barrel, a 45% withholding rate will apply. If such price is under U.S.$45/barrel, the applicable export tax is to be determined within a term of 90 business days. The withholding rate determined as indicated above also currently applies to diesel, gasoline and other crude derivative products. In addition, the calculation procedure described above also applies to other petroleum products and lubricants based upon different withholding rates, reference prices and prices allowed to producers. See “Item 4. Information on the Company—Regulatory Framework and Relationship with the Argentine Government—Market Regulation.”

With respect to natural gas products, in July 2006, the Ministry of Economy and Production issued Resolution 534/06, which increased to 45% the export duty on natural gas. This resolution also required the Customs General Administration to apply the natural gas price set by the Framework Agreement between Argentina and Bolivia (the “Framework Agreement”), which was approximately U.S.$6/mmBtu in December 2007, as the valuation basis for calculating export duties on natural gas sales, irrespective of the actual price of such sales. In 2006, exports from the Tierra del Fuego province, which were previously exempted from taxes, were made subject to export duties at the prevailing rates. Moreover, in May 2007 the Ministry of Economy and Production increased to 25% the export duty on exports of butane, propane and LPG.

Resolution No. 127/2008 of the Ministry of Economy and Production increased export duties applicable to natural gas exports from 45% to 100%, mandating a valuation basis for the calculation of the duty as the highest price established in any contract of any Argentine importer for the import of gas, abandoning the previously applicable reference price set by the Framework Agreement between Argentina and Bolivia mentioned above. Resolution No. 127/2008 provides with respect to LPG products (including butane, propane and blends thereof) that if the international price of the relevant LPG product, as notified daily by the Secretariat of Energy, is under the reference price established for such product in the Resolution (U.S.$338/m3 for propane, U.S.$393/m3 for butane and U.S.$363/m3 for blends of the two), the applicable export duty for such product will be 45%. If the international price exceeds the reference price, the producer shall be allowed to collect the maximum amount established by the Resolution for the relevant product (U.S.$223/m3 for propane, U.S.$271/m3 for butane and U.S.$250/m3 for blends of the two), with the remainder being withheld by the Argentine government as an export tax.

As a result of the aforementioned export tax increases, we may be and, in certain cases, have already been forced to seek the renegotiation of our export contracts, despite, in most cases, the prior authorization of such contracts by the Argentine government. We cannot provide assurances that we will be able to renegotiate such contracts on terms acceptable to us.

The imposition of these export taxes has adversely affected our results of operations. We cannot assure you that these taxes will not continue or be increased in the future or that other new taxes will not be imposed.

We may be exposed to fluctuations in foreign exchange rates

Our results of operations are exposed to currency fluctuation and any devaluation of the peso against the U.S. dollar and other hard currencies may adversely affect our business and results of operations. The value of the peso has fluctuated significantly in the past and may do so in the future. We are unable to predict whether, and to what extent, the value of the peso may further depreciate or appreciate against the U.S. dollar and how any such fluctuations would affect our business.

We may be subject to exchange and capital controls

In 2001 and 2002, as a result of the economic crisis, Argentina imposed exchange controls and transfer restrictions substantially limiting the ability of companies to retain foreign currency or make payments abroad. Under current Argentine law, exporters are required to convert proceeds from export operations into domestic currency, subject to certain exceptions applicable to the oil and gas industry that permit us to retain abroad 70% of export proceeds. See “Item 4. Information on the Company—Regulatory Framework and Relationship with the Argentine Government—Repatriation of Foreign Currency.” There can be no assurances regarding future modifications to exchange and capital controls. The imposition of stricter exchange and capital controls could adversely affect our financial condition or results of operations and our ability to meet our foreign currency obligations and execute our financing plans.

Our access to international capital markets is influenced by the perception of risk in Argentina and other emerging economies, which may affect our ability to finance our operations and the trading values of our securities.

International investors consider Argentina to be an emerging market. Economic and market conditions in other emerging market countries, especially those in Latin America, influence the market for securities issued by Argentine companies. Volatility in securities markets in Latin America and in other emerging market countries may have a negative impact on the trading value of our securities and on our ability and the terms on which we are able to access international capital markets.

Risks Relating to the Argentine Oil and Gas Business and Our Business

Oil and gas prices could affect our level of capital expenditures

The prices that we are able to obtain for our hydrocarbon products affect the viability of investments in new exploration, development and refining, and as a result the timing and amount of our projected capital expenditures for such purposes. We budget capital expenditures related to exploration, development, refining and distribution activities by taking into account, among other things, market prices for our hydrocarbon products. In the event that current domestic prices prevail or decrease, our ability to improve our hydrocarbon recovery rates, find new reserves and carry out certain of our other capital expenditure plans is likely to be adversely affected, which in turn would have an adverse effect on our results of operations.

Our reserves and production are likely to decline

Argentina’s oil and gas fields are mature and our reserves and production are declining as reserves are depleted. In the last two years our proved reserves declined by approximately 20%, and we replaced 51% of our production with new proved reserves during 2007; average daily production in 2007 declined by approximately 4.1% from 2006. We are engaged in efforts to mitigate these declines by adding reserves through technological enhancements aimed at improving our recovery factors as well as through deepwater offshore exploration and development of tight gas. These efforts are subject to material risks and may prove unsuccessful due to risks inherent to the oil and gas industry.

Our oil and natural gas reserves are estimates, in accordance with the guidelines established by the U.S. Securities and Exchange Commission (SEC)

Our oil and gas proved reserves are estimated in accordance with the guidelines established by the SEC. Proved reserves are estimated using geological and engineering data to determine with reasonable certainty whether the crude oil or natural gas in known reservoirs is recoverable under existing economic and operating conditions.

The accuracy of proved reserve estimates depends on a number of factors, assumptions and variables, among which the most important are:

·	the results of drilling, testing and production after the date of the estimates, which may require substantial revisions;

·	the quality of available geological, technical and economic data and the interpretation and judgment of such data;

·	the production performance of our reservoirs;

·	developments such as acquisitions and dispositions, new discoveries and extensions of existing fields and the application of improved recovery techniques;

changes in oil and natural gas prices, which could have an effect on the size of our proved reserves because the estimates of reserves are based on prices and costs at the date when such estimates are made, and a decline in the price of oil or gas could make reserves no longer economically viable to exploit and therefore not classifiable as proved; and

·	whether the prevailing tax rules, other government regulations and contractual conditions will remain the same as on the date estimates are made (as changes in tax rules and other government regulations could make reserves no longer economically viable to exploit).

Many of the factors, assumptions and variables involved in estimating proved reserves are beyond our control and are subject to change over time. See “Item 4. Information on the Company—Exploration and Production—Reserves.” Consequently, measures of reserves are not precise and are subject to revision. Any downward revision in our estimated quantities of proved reserves could adversely impact our financial results, leading to increased depreciation, depletion and amortization charges and/or impairment charges, which would reduce earnings and shareholders’ equity.

The oil and gas industry is subject to particular economic and operational risks

Oil and gas exploration and production activities are subject to particular economic and industry-specific operational risks, some of which are beyond our control, such as production, equipment and transportation risks, and natural hazards and other uncertainties, including those relating to the physical characteristics of onshore and offshore oil or natural gas fields. Our operations may be curtailed, delayed or cancelled due to bad weather conditions, mechanical difficulties, shortages or delays in the delivery of equipment, compliance with governmental requirements, fire, explosions, blow-outs, pipe failure, abnormally pressured formations, and environmental hazards, such as oil spills, gas leaks, ruptures or discharges of toxic gases. If these risks materialize, we may suffer substantial operational losses and disruptions. Drilling may be unprofitable, not only with respect to dry wells, but also with respect to wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs are taken into account.

Argentine oil and gas production concessions and exploration permits are subject to certain conditions and may not be renewed

The Federal Hydrocarbons Law provides for oil and gas concessions to remain in effect for 25 years as from the date of their award, and further provides for the concession term to be extended for up to 10 additional years, subject to terms and conditions approved by the grantor at the time of the extension. The expiration of a substantial part of

our and other Argentine oil companies’ concessions occurs in 2017. The authority to extend the terms of current and new permits, concessions and contracts has been vested in the governments of the provinces in which the relevant area is located (and the federal government in respect of offshore areas beyond 12 nautical miles). In order to be eligible for the extension, any concessionaire and permit holder must have complied with its obligations under the Federal Hydrocarbons Law and the terms of the particular concession or permit, including evidence of payment of taxes and royalties, the supply of the necessary technology, equipment and labor force and compliance with various environmental, investment and development obligations. Under the Federal Hydrocarbons Law, non-compliance with these obligations and standards may also result in the imposition of fines and in the case of material breaches, following the expiration of applicable cure periods, the revocation of the concession or permit. We cannot provide assurances that our concessions will be extended or that additional investment, royalty payment or other requirements will not be imposed on us in order to obtain extensions. The termination of, or failure to obtain the extension of, a concession or permit could have a material adverse effect on our business and results of our operations.

Our acquisition of exploratory acreage and crude oil and natural gas reserves is subject to heavy competition

We face intense competition in bidding for crude oil and natural gas production areas, which are typically auctioned by governmental authorities, especially those areas with the most attractive crude oil and natural gas reserves. Some provinces of Argentina, including La Pampa, Neuquén and Chubut, have created provincial government-owned companies to develop activities in the oil and gas industry. Energía Argentina S.A. (ENARSA), the Argentine state-owned energy company, has also entered the market, particularly in the context of offshore exploration. As a result, the conditions under which we are able to access new exploratory or productive areas could be adversely affected.

We may incur significant costs and liabilities related to environmental, health and safety matters

Our operations, like those of other companies in the oil and gas industry, are subject to a wide range of environmental, health and safety laws and regulations in the countries in which we operate. These laws and regulations have a substantial impact on our operations and those of our subsidiaries, and could result in material adverse effects on our financial position and results of operation. A number of events related to environmental, health and safety matters, including changes in applicable laws and regulations, adverse judicial or administrative interpretations of such laws and regulations, changes in enforcement policy, the occurrence of new litigation or development of pending litigation, and the development of information concerning these matters, could result in new or increased liabilities, capital expenditures, reserves, losses and other impacts that could have a material adverse effect on our financial condition and results of operations. See “Item 8. Financial Information―Legal Proceedings,” “Item 4. Information on the Company—Regulatory Framework and Relationship with the Argentine Government—Argentine Environmental Regulations” and “Item 4. Information on the Company—Regulatory Framework and Relationship with the Argentine Government—U.S. Environmental Regulations.” Environmental, health and safety regulation and jurisprudence in Argentina is developing at a rapid pace and no assurance can be provided that such developments will not increase our cost of doing business and liabilities.

The cessation of natural gas deliveries from Bolivia may have a material adverse effect on our long-term natural gas supply commitments

We rely on imports of natural gas from Bolivia pursuant to the Framework Agreement between the Bolivian and Argentine governments. See “Item 4. Information on the Company―Exploration and Production—the Argentine natural gas market.” The current delivery capacity from Bolivia is 7.7mmcm/d, and the delivery of volumes exceeding 7.7mmcm/d is subject to the construction of the North East Pipeline, which has not yet commenced. Bolivian natural gas imports pursuant to the Framework Agreement are performed under a gas supply agreement between YPFB (the Bolivian state-owned oil and gas company) and ENARSA, which establishes a guaranteed delivery volume of 4.6mmcm/d. The price charged by Bolivia pursuant to this agreement was approximately U.S.$6/mmBtu in December 2007 (approximately U.S.$6.98/mmBtu in March 2008). We have entered into a gas supply contract with ENARSA to buy a portion of such gas (with a guaranteed volume of 2.6mmcm/d) through December 31, 2009 at a price of approximately U.S.$1.8/mmBtu. The difference between our

contractual price and cost of the natural gas purchased pursuant to the Framework Agreement is currently absorbed by ENARSA and financed by the Argentine government with the collection of export duties on natural gas.

Any suspension of natural gas deliveries from Bolivia under these contracts, or an increase in the subsidized price of gas currently charged by ENARSA, could have a material adverse effect on our financial condition and results of operations, including our inability to provide gas to certain clients, since we plan to fulfill our supply contracts of natural gas in part through import volumes from Bolivia.

We are party to a number of legal proceedings

As described under “Item 8. Financial Information—Legal Proceedings,” we are party to a number of labor, commercial, civil, tax, criminal, environmental and administrative proceedings that, either alone or in combination with other proceedings, could, if resolved in whole or in part adversely to us, result in the imposition of material costs, fines, judgments or other losses. While we believe that we have provisioned such risks appropriately based on the opinions and advice of our external legal advisors and in accordance with applicable accounting rules, certain loss contingencies, particularly those relating to environmental matters, are subject to change as new information develops and it is possible that losses resulting from such risks, if proceedings are decided in whole or in part adversely to us, could significantly exceed any reserves we have established.

Our business depends to a significant extent on our production and refining facilities and logistics network

Our oil and natural gas field facilities, refineries and logistics network are our principal production facilities and distribution network on which a significant portion of our revenues depends. Although we insure our properties on terms we consider prudent and have adopted and maintain safety measures, any significant damage to, accident or other production stoppage at our facilities or network could materially and adversely affect our production capabilities, financial condition and results of operations.

We could be subject to organized labor action

Although we consider our current relations with our workforce to be good, we have experienced organized work disruptions and stoppages in the past and we cannot assure you that we will not experience them in the future, which could adversely affect our business and revenues.

Risks Relating to Our Class D Shares and ADSs

Repsol YPF controls a significant majority of our shares and voting rights

Following the Petersen Transaction, as defined in “Item 7. Major Shareholders and Related Party Transactions,” Repsol YPF controls approximately 84% of our capital stock and voting rights and Petersen Energía S.A. (“Petersen Energía”) controls approximately 15% of our shares and voting rights, in each case subject to the shareholders’ agreement described below. In addition, Repsol YPF has granted certain affiliates of Petersen Energía options to purchase an additional 10.1% of our capital stock held by Repsol YPF. A number of YPF corporate matters are subject to the voting and other procedures set forth in a shareholders’ agreement entered into between Repsol YPF, certain affiliates of Repsol YPF and Petersen Energía. Repsol YPF will be able to determine substantially all other matters requiring approval by a majority of our shareholders, including the election of a majority of our directors. Subject to the terms of the shareholders’ agreement, Repsol YPF will also direct our operations and may be able to cause or prevent a change in our control. See “Item 7. Major Shareholders and Related Party Transactions―Shareholders’ Agreement.” Repsol YPF’s and Petersen Energía’s interests may differ from those of our other shareholders.

Certain strategic transactions require the approval of the holder of our Class A shares or may entail a cash tender offer for all of our outstanding capital stock

Under our bylaws, the approval of the holder of our Class A shares is required to undertake certain strategic transactions, including a merger, an acquisition that results in the purchaser holding 15% or more of our capital stock or an acquisition that results in the purchaser holding a majority of our capital stock. The interests of our Class A shareholder, the Argentine government, may differ from those of our other shareholders, and, as result, we may not be able to undertake certain transactions on terms that are advantageous to our other shareholders or at all.

In addition, under our bylaws, an acquisition that results in the purchaser holding 15% or more of our capital stock would require such purchaser to make a public cash tender offer for all of our outstanding shares and convertible securities, which could discourage certain investors from acquiring significant stakes in our capital stock. See “Item 10. Additional Information—Certain Provisions Relating to Acquisitions of Shares.”

Active markets may not develop for our Class D shares or the ADSs

As of the date of this annual report, less than 1% of our capital stock is held by non-affiliates. As a result, the public markets for our Class D shares and ADSs have had limited trading volume. Although the ADSs will continue to be listed on the NYSE and the underlying Class D shares will continue to be listed on the BASE, we cannot assure you that more active and liquid markets will develop or of the price at which the Class D shares or the ADSs may be sold.

Restrictions on the movement of capital out of Argentina may impair your ability to receive dividends and distributions on, and the proceeds of any sale of, the Class D shares underlying the ADSs

Argentine law currently permits the government to impose temporary restrictions on capital movements in circumstances where a serious imbalance develops in Argentina’s balance of payments or where there are reasons to foresee such an imbalance. Although the transfer of funds abroad in order to pay dividends currently does not require Central Bank approval, restrictions on the movement of capital to and from Argentina such as those that previously existed during the recent economic crisis could, if reinstated, impair or prevent the conversion of dividends,

distributions, or the proceeds from any sale of Class D shares, as the case may be, from pesos into U.S. dollars and the remittance of the U.S. dollars abroad. We cannot assure you that the Argentine government will not take such measures in the future.

Under the terms of our deposit agreement with the depositary for the ADSs, the depositary will convert any cash dividend or other cash distribution we pay on the shares underlying the ADSs into U.S. dollars, if it can do so on a reasonable basis and can transfer the U.S. dollars to the United States. If this conversion is not possible for any reason, including restrictions of the type described in the preceding paragraph, the deposit agreement allows the depositary to distribute the foreign currency only to those ADR holders to whom it is possible to do so. If the exchange rate fluctuates significantly during a time when the depositary cannot convert the foreign currency, you may lose some or all of the value of the dividend distribution.

Under Argentine law, shareholder rights may be different from other jurisdictions

Our corporate affairs are governed by our bylaws and by Argentine corporate law, which differ from the legal principles that would apply if we were incorporated in a jurisdiction in the United States or in other jurisdictions outside Argentina. In addition, rules governing the Argentine securities markets are different and may be subject to different enforcement in Argentina than in other jurisdictions.

Actual or anticipated sales of a substantial number of Class D shares could decrease the market prices of our Class D shares and the ADSs

Repsol YPF owns Class D shares and ADSs representing a significant majority of our capital stock (which may be reduced by approximately 10% if the Petersen Options described under “Item 7. Major Shareholders and Related Party Transaction—Option Agreements” are exercised). Petersen Energía owns ADSs representing up to approximately 15% of our capital stock (which may be increased up to approximately 25% if the Petersen Options described under “Item 7. Major Shareholders and Related Party Transaction—Option Agreements” are exercised). In addition, as described in greater detail under “Item 7. Major Shareholders and Related Party Transactions—Registration Rights and Related Agreements,” we have filed and undertaken to maintain an effective shelf registration statement for the benefit of the lenders under the senior secured term loan facility provided to Petersen Energía to enable it to enter into the Petersen Transaction. The lenders under the senior secured term loan facility, upon the acceleration of such facility following the occurrence and continuation of an event of default under such facility, will be able to freely sell up to approximately 15% of our outstanding capital stock (which may be increased to approximately 25% if the Petersen Options are exercised) under the shelf registration statement. Sales of a substantial number of Class D shares or ADSs after the consummation of this offering by Repsol YPF, Petersen Energía, such lenders or any other significant shareholder, or the anticipation of such sales, could decrease the trading price of our Class D shares and the ADSs. See “Item 7. Major Shareholders and Related Party Transactions.”

You may be unable to exercise preemptive, accretion or other rights with respect to the Class D shares underlying your ADSs

You may not be able to exercise the preemptive or accretion rights relating to the shares underlying your ADSs (see “Item 10. Additional Information—Preemptive and Accretion Rights”) unless a registration statement under the U.S. Securities Act of 1933 (the “Securities Act”) is effective with respect to those rights or an exemption from the registration requirements of the Securities Act is available. We are not obligated to file a registration statement with respect to the shares relating to these preemptive rights, and we cannot assure you that we will file any such registration statement. Unless we file a registration statement or an exemption from registration is available, you may receive only the net proceeds from the sale of your preemptive rights by the depositary or, if the preemptive rights cannot be sold, they will be allowed to lapse. As a result, U.S. holders of Class D shares or ADSs may suffer dilution of their interest in our company upon future capital increases.

In addition, under the Argentine Corporations Law, foreign companies that own shares in an Argentine corporation are required to register with the Superintendency of Corporations (Inspección General de Justicia, or “IGJ”) in order to exercise certain shareholder rights, including voting rights. If you own our Class D shares directly (rather than in the form of ADSs) and you are a non-Argentine company and you fail to register with IGJ, your ability to exercise your rights as a holder of our Class D shares may be limited.

You may be unable to exercise voting rights with respect to the Class D shares underlying your ADSs at our shareholders’ meetings

The depositary will be treated by us for all purposes as the shareholder with respect to the shares underlying your ADSs. As a holder of ADRs representing the ADSs being held by the depositary in your name, you will not have direct shareholder rights and may exercise voting rights with respect to the Class D shares represented by the ADSs only in accordance with the deposit agreement relating to the ADSs. There are no provisions under Argentine law or under our bylaws that limit the exercise by ADS holders of their voting rights through the depositary with respect to the underlying Class D shares. However, there are practical limitations on the ability of ADS holders to exercise their voting rights due to the additional procedural steps involved in communicating with these holders. For example, holders of our shares will receive notice of shareholders’ meetings through publication of a notice in an official gazette in Argentina, an Argentine newspaper of general circulation and the bulletin of the Buenos Aires Stock Exchange, and will be able to exercise their voting rights by either attending the meeting in person or voting by proxy. ADS holders, by comparison, will not receive notice directly from us. Instead, in accordance with the deposit agreement, we will provide the notice to the depositary. If we ask it to do so, the depositary will mail to holders of ADSs the notice of the meeting and a statement as to the manner in which instructions may be given by holders. To exercise their voting rights, ADS holders must then instruct the depositary as to voting the Class D shares represented by their ADSs. Due to these procedural steps involving the depositary, the process for exercising voting rights may take longer for ADS holders than for holders of Class D shares, and Class D shares represented by ADSs may not be voted as you desire. Class D shares represented by ADSs for which the depositary fails to receive timely voting instructions may, if requested by us, be voted as we instruct at the corresponding meeting.

Shareholders outside of Argentina may face additional investment risk from currency exchange rate fluctuations in connection with their holding of our Class D shares or the ADSs

We are an Argentine company and any future payments of dividends on our Class D shares will be denominated in pesos. The peso has historically fluctuated significantly against many major world currencies, including the U.S. dollar. A depreciation of the peso would likely adversely affect the U.S. dollar or other currency equivalent of any dividends paid on our Class D shares and could result in a decline in the value of our Class D shares and the ADSs as measured in U.S. dollars.

ITEM 4. Information on the Company

History and Development of YPF

Overview

We are Argentina’s leading energy company, operating a fully integrated oil and gas chain with leading market positions across the domestic upstream and downstream segments. Our upstream operations consist of the exploration, development and production of crude oil, natural gas and liquefied petroleum gas. Our downstream operations include the refining, marketing, transportation and distribution of oil and a wide range of petroleum products, petroleum derivatives, petrochemicals, liquid petroleum gas and bio-fuels. Additionally, we are active in the gas separation and natural gas distribution sectors both directly and through our investments in several affiliated companies. In 2007, we had consolidated net sales of Ps.29,104 million (U.S.$9,239 million) and consolidated net income of Ps.4,086 million (U.S.$1,297 million).

Most of our predecessors were state-owned companies with operations dating back to the 1920s. In November 1992, the Argentine government enacted the Privatization Law (Law No. 24,145), which established the procedures for our privatization. In accordance with the Privatization Law, in July 1993, we completed a worldwide offering of 160 million Class D shares that had previously been owned by the Argentine government. As a result of that offering and other transactions, the Argentine government’s ownership interest in our capital stock was reduced from 100% to approximately 20% by the end of 1993.

Since 1999, we have been controlled by Repsol YPF, an integrated oil and gas company headquartered in Spain with global operations. Repsol YPF owned approximately 99% of our capital stock from 2000 until February 21, 2008, when Petersen Energía, S.A. purchased 58,603,606 of our ADSs, representing 14.9% of our capital stock, from Repsol YPF for U.S.$2,235 million. In addition, Repsol YPF also granted certain affiliates of Petersen Energía options to purchase up to an additional 10.1% of our outstanding capital stock within four years. See “Item 7. Major Shareholders and Related Party Transactions.” We believe that Petersen Energía’s participation in our capital stock and management will strengthen our Argentine ties and expertise.

Upstream Operations

We operate more than 70 oil and gas fields in Argentina, accounting for approximately 42% of the country’s total production of crude oil, excluding natural gas liquids, and approximately 42% of its total natural gas production, including natural gas liquids, in 2007, according to the Argentine Secretariat of Energy.

·	We had proved reserves, as estimated as of December 31, 2007, of approximately 623 mmbbl of oil and 3,708 bcf of gas, representing aggregate reserves of 1,283 mmboe.

·	In 2007, we produced 120 mmbbl of oil (329 mbbl/d) and 635 bcf of gas (1,740 mmcf/d).

Downstream Operations

We are Argentina’s leading refiner with operations conducted at three wholly owned refineries with combined annual refining capacity of approximately 116 mmbbl (319.5 mbbl/d). We also have a 50% interest in Refinor, a jointly controlled entity operated by Petrobras Energía S.A., which has a refining capacity of 26.1 mbbl/d.

·	Our retail distribution network for automotive petroleum products as of December 31, 2007 consisted of 1,692 YPF-branded service stations, which we believe represented approximately 31.1% of all service stations in Argentina.

·	We are a leading petrochemical producer in Argentina and in the Southern Cone of Latin America, with operations conducted through our Ensenada plant. In addition, Profertil, a company that we jointly control, is a leading producer of urea in the Southern Cone.

The following chart illustrates our organizational structure, including our principal subsidiaries, as of the date of this annual report.

The map below illustrates the location of our productive basins, refineries, storage facilities and crude oil and multi-product pipeline networks.

The Argentine Market

Argentina is the second largest producer of natural gas and the fourth largest producer of crude oil in Latin America based on 2006 production, according to the BP Statistical Review.

In response to the economic crisis of 2001 and 2002, the Argentine government, pursuant to the Public Emergency Law (Law No. 25,561), established export taxes on certain hydrocarbon products. In subsequent years, in order to satisfy growing domestic demand and abate inflationary pressures, this policy was supplemented by constraints on domestic prices, temporary export restrictions and subsidies on imports of natural gas and diesel. As a result, local prices for oil and natural gas products have remained significantly below those prevalent in neighboring countries and international commodity exchanges, heightening domestic demand for such products. For example, in January 2008, diesel import prices were approximately U.S.$700/cubic meter, while the average domestic sales prices were approximately U.S.$350/cubic meter before government subsidies. In addition, the price at which Bolivia exports natural gas to Argentina was approximately U.S.$6/mmBtu in December 2007 (U.S.$6.98/mmBtu in March 2008), while our average sales price for such gas in Argentina was approximately U.S.$2.29/mmBtu.

Argentina’s gross domestic product, or GDP, has grown at an average annual real rate of approximately 9% from 2003 to 2006, after declines during the economic crisis of 2001 and 2002. Driven by this economic expansion and low domestic prices, energy demand has increased significantly during the same period, outpacing energy supply (which in the case of oil declined). For example, Argentine natural gas and diesel consumption grew at average annual rates of 6.5% and 6.9%, respectively, during this period, according to the BP Statistical Review and the Argentine Secretariat of Energy. As a result of this increasing demand and actions taken by the Argentine regulatory authorities to support domestic supply, exported volumes of hydrocarbon products, especially natural gas and diesel, declined steadily over this period. At the same time, Argentina has increased hydrocarbon imports, becoming a net importer of certain products, such as diesel, and increased imports of natural gas. In 2003, Argentina’s net exports of diesel amounted to approximately 1,349 thousand cubic meters, while in 2007 its net imports of diesel amounted to approximately 800 thousand cubic meters, according to the Argentine Secretariat of Energy. Significant investments in the energy sector are expected to be required in order to support continued economic growth, as the industry is currently operating near capacity.

Demand for diesel in Argentina exceeds domestic production. In addition, the import prices of refined products substantially exceed the domestic sales prices of such products, rendering the import and resale of such products uneconomic. As a result, service stations experience temporary shortages and are required to suspend or curtail diesel sales. While we are operating our refineries at or above capacity, during peak demand periods we are forced to prorate supplies among our service stations according to historical sales levels.

As the largest integrated oil and gas company in Argentina, we believe that we are well positioned to benefit from potential reform in the energy sector, although we cannot assure that reforms will be implemented or, if implemented, that they will be advantageous to our business. We also believe that, as a result of limitations on the prices of our products, our margins should be less sensitive to declines, if any, in international prices of oil and gas.

History of YPF

Beginning in the 1920s and until 1990, both the upstream and downstream segments of the Argentine oil and gas industry were effectively monopolies of the Argentine government. During this period, we and our predecessors were owned by the state, which controlled the exploration and production of oil and natural gas, as well as the refining of crude oil and marketing of refined petroleum products. In August 1989, Argentina enacted laws aimed at the deregulation of the economy and the privatization of Argentina’s state-owned companies, including us. Following the enactment of these laws, a series of presidential decrees were promulgated, which required, among other things, us to sell majority interests in our production rights to certain major producing areas and to undertake an internal management and operational restructuring program.

In November 1992, Law No. 24,145 (referred to as the Privatization Law), which established the procedures by which we were to be privatized, was enacted. In accordance with the Privatization Law, in July 1993, we completed a worldwide offering of 160 million Class D shares that had previously been owned by the Argentine government. As a result of that offering and other transactions, the Argentine government’s ownership percentage in our capital stock was reduced from 100% to approximately 20% by the end of 1993.

In January 1999, Repsol YPF acquired 52,914,700 Class A shares in block (14.99% of our shares) which were converted to Class D shares. Additionally, on April 30, 1999, Repsol YPF announced a tender offer to purchase all outstanding Class A, B, C and D shares (the “Offer”). Pursuant to the Offer, in June 1999, Repsol YPF acquired an additional 82.47% of our outstanding capital stock. Repsol YPF acquired additional stakes in us from minority shareholders and other transactions in 1999 and 2000. As of December 31, 2007, Repsol YPF controlled 99.04% of our share capital.

Between 2004 and 2005 we made non-strategic asset divestitures totaling U.S.$239.5 million.

On February 21, 2008, Petersen Energía purchased 58,603,606 of our ADSs, representing 14.9% of our capital stock, from Repsol YPF for U.S.$2,235 million. In addition, Repsol YPF also granted certain affiliates of Petersen Energía options to purchase up to an additional 10.1% of our outstanding capital stock within four years. Repsol YPF will retain a majority of our capital stock and, subject to the shareholders’ agreement entered into between Repsol YPF and Petersen Energía, will be able to determine substantially all issues decided by our shareholders. See “Item 7. Major Shareholders and Related Party Transactions.”

Business Segments

We organize our business along the following segments:

·	Exploration and Production;

·	Refining and Marketing; and

Chemical.

The Exploration and Production segment’s sales to third parties in Argentina and abroad include sales of natural gas and services fees (primarily for the transportation, storage and treatment of hydrocarbons and products). In addition, crude oil produced by us in Argentina, or received from third parties in Argentina pursuant to service contracts, is transferred from Exploration and Production to Refining and Marketing at transfer prices established by us, which generally seek to approximate Argentine market prices.

The Refining and Marketing segment purchases crude oil from the Exploration and Production segment and from third parties. Refining and Marketing activities include crude oil refining and transportation, as well as the marketing and transportation of refined fuels, lubricants, LPG, compressed natural gas and other refined petroleum products in the domestic wholesale and retail markets and the export markets.

The Chemical segment sells petrochemical products both in the domestic and export markets.

Additionally, we record certain assets, liabilities and costs under the Corporate and Other segment, including corporate administration costs and assets, certain building construction activities and environmental remediation activities related to YPF Holdings’ discontinued operations.

The following table sets forth net sales and operating income for each of our lines of business for the years ended December 31, 2007, 2006 and 2005:

	For the Year Ended December 31,
	2007			2006			2005
	(in millions of pesos)
Net Sales(1)
Exploration and Production(2)(3)
To unrelated parties		3,288			3,076			2,910
To related parties		724			774			626
Intersegment sales and fees(3)		14,056			14,033			11,659
Total Exploration and Production		18,068			17,883			15,195
Refining and Marketing(4)
To unrelated parties		20,375			17,651			15,791
To related parties		2,045			1,624			1,425
Intersegment sales and fees		1,858			1,526			962
Total Refining and Marketing		24,278			20,801			18,178
Chemical
To unrelated parties		2,563			2,401			2,062
Intersegment sales and fees		892			647			207
Total Chemical		3,455			3,048			2,269
Corporate and Other
To unrelated parties		109			109			87
Intersegment sales and fees		440			282			243
Total Corporate and Others		549			391			330
Less intersegment sales and fees		(17,246	)		(16,488	)		(13,071	)
Total net sales(5)		29,104			25,635			22,901
Operating Income (Loss)
Exploration and Production		5,679			6,564			7,140
Refining and Marketing		1,234			258			1,900
Chemical		500			572			542
Corporate and Other		(620	)		(540	)		(451	)
Consolidation adjustments		(136	)		29			30
Total operating income		6,657			6,883			9,161

____________

(1)

Net sales are net to us after payment of a fuel transfer tax, turnover tax and customs duties on exports. Royalties with respect to our production are accounted for as a cost of production and are not deducted in determining net sales. See Note 2 (g) to the Audited Consolidated Financial Statements.

(2)	Includes exploration and production operations in Argentina and the United States.

(3)	Intersegment sales of crude oil to Refining and Marketing are recorded at transfer prices established by us, which generally seek to approximate Argentine market prices.

(4)	Includes LPG activities.

(5)	Total net sales include export sales of Ps.8,400 million, Ps.8,649 million, and Ps.8,644 million for the years ended December 31, 2007, 2006 and 2005, respectively. The export sales were mainly to the United States, Brazil and Chile.

Exploration and Production

Principal properties

Argentine properties

Our production is concentrated in Argentina and our domestic operations are subject to numerous risks. See “Item 3. Key Information—Risk Factors.”

Argentina is the fourth largest hydrocarbon producing nation in Latin America and the fourth largest in terms of reserves, after Mexico, Venezuela and Brazil. Oil has historically accounted for the majority of the country’s hydrocarbon production and consumption, although the relative share of natural gas has increased rapidly in recent years. According to the Secretariat of Energy, 19 sedimentary basins have been identified in the country. Five of these are combined onshore/offshore and three are entirely offshore. Total onshore acreage is composed of approximately 334 million acres, and total offshore acreage includes 99 million acres on the South Atlantic shelf within the 200-meter depth line. A substantial portion of the 432 million acres in sedimentary basins has yet to be evaluated by exploratory drilling. Commercial production is concentrated in five basins: Neuquina, Cuyana and Golfo San Jorge in central Argentina, Austral in southern Argentina (which includes onshore and offshore fields), and the Noroeste basin in northern Argentina. The Neuquina and Golfo San Jorge basins are the most significant basins for our activities in Argentina. As of December 31, 2007, we had an interest in 18.6 million net acres onshore and offshore (within the 200-meter depth line), of which 6.4 million net acres were under production concessions and 12.2 million net acres were under exploration permits.

The following table shows our gross and net interests in productive oil and gas wells and exploration permits and production concessions in Argentina by basin, as of December 31, 2007.

	Wells								Acreage
	Oil				Gas				Production Concessions(1)				Exploration Permits(1)
	Gross(2)		Net(2)		Gross(2)		Net(2)		Gross(2)		Net(2)		Gross(2)		Net(2)
Onshore									(thousands of acres)
Neuquina		3,288		2,811		575		418		4,008		3,114		1,478		1,246
Golfo San Jorge		6,805		5,975		51		50		2,472		2,347		4,927		2,464
Cuyana		805		627		—		—		427		375		2,157		1,861
Noroeste		29		8		47		15		1,329		372		—		—
Austral		120		37		54		16		602		181		—		—
Offshore		5		2		—		—		115		63		18,920		6,625

____________

(1)

Production concessions are granted after commercially exploitable quantities of oil or gas are discovered, are based upon the estimated field size as determined by geological and geophysical techniques and are subject to adjustment based upon new information concerning the reservoir. Accordingly, not all acreage covered by production concessions is, in fact, producing. Acreage held under exploration permits is unproved and non-producing.

(2)	“Gross” wells and acreage include all wells and acreage in which we have an interest. “Net” wells and acreage equals gross wells and acreage after deducting third party interests.

The table below provides certain information with respect to our principal oil and gas fields in Argentina at December 31, 2007, all of which are mature:

				Production 2007				Reserves as December 31, 2007							Development stage of the area
Areas (1)	Interest			Oil (mbbl)		Gas (mmcf)		Oil (Mbbl)		Gas (mmcf)		BOE (mboe)		Basin/Location
Barrancas		100	%		2,218		75		16,377		574		16,479	Cuyana	Mature Field
Cerro Fortunoso		100	%		1,871		—		9,287		0		9,287	Neuquina	Mature Field
La Ventana		(2	)		1,988		269		13,983		1,896		14,321	Cuyana	Mature Field
Vizcacheras		100	%		3,594		351		25,748		2,117		26,125	Cuyana	Mature Field
El Portón-Chihuido La Salina		100	%		12,661		58,660		58,416		351,645		121,042	Neuquina	Mature Field
Chihuido Sierra Negra		100	%		10,783		1,903		45,817		7,548		47,161	Neuquina	Mature Field
Paso Bardas Norte		100	%		302		13,367		329		45,086		8,359	Neuquina	Mature Field
Señal Picada		100	%		2,156		150		18,323		1,135		18,525	Neuquina	Mature Field
Aguada Toledo – Sierra Barrosa		100	%		813		52,909		7,690		177,190		39,247	Neuquina	Mature Field
Loma la Lata		100	%		17,066		271,057		92,411		1,840,126		420,127	Neuquina	Mature Field
El Trébol		100	%		2,132		318		11,285		1,075		11,477	Golfo San Jorge	Mature Field
Manantiales Behr		100	%		5,885		3,998		23,428		9,843		25,182	Golfo San Jorge	Mature Field
Seco León		100	%		3,502		3,812		19,953		16,069		22,815	Golfo San Jorge	Mature Field
Barranca Baya		100	%		4,157		853		20,757		3,767		21,428	Golfo San Jorge	Mature Field
Lomas del Cuy		100	%		3,344		2,079		13,415		6,946		14,652	Golfo San Jorge	Mature Field
Los Perales		100	%		7,962		22,149		34,680		46,150		42,899	Golfo San Jorge	Mature Field

___________

(1)	Exploitation areas.

(2)	69.6% for crude oil and 60% for natural gas liquids and natural gas.

Approximately 84% of our proved crude oil reserves in Argentina are concentrated in the Neuquina (50%) and Golfo San Jorge (34%) basins, and 96% of our proved gas reserves in Argentina are concentrated in the Neuquina (79%), Noroeste (13%) and Austral (4%) basins.

As of December 31, 2007, YPF held 109 production concessions and exploration permits in Argentina. YPF directly operates 73 of them, including 61 production concessions and 12 exploration permits.

As of December 31, 2007, we held 18 exploration permits in Argentina, 11 of which are onshore exploration permits and seven of which are offshore exploration permits. We have has 100% ownership of five onshore permits and one offshore permit, and our participating interests in the rest vary between 27% and 90%. Our interests in the offshore permits vary between 30% and 50%.

As of December 31, 2007, we had 91 production concessions. we have a 100% ownership interest in 54 production concessions, and our participating interests in the remaining 37 production concessions vary between 12% and 70%.

Joint ventures and contractual arrangements in Argentina

We participate in 18 exploration and production joint ventures in Argentina. Our interests in these joint ventures range from 12% to 70%, and our obligations to share exploration and development costs vary under these agreements. In addition, under the terms of some of these joint ventures, we have agreed to indemnify our joint venture partners in the event that our rights with respect to such areas are restricted or affected in such a way that the purpose of the joint venture cannot be achieved. For a list of the exploration and production joint ventures in which we participate, see Note 6 to the Audited Consolidated Financial Statements. We are also a party to a number of other contractual arrangements that arose through the renegotiation of service contracts and risk contracts and their conversion into production concessions and exploration permits, respectively.

International properties – United States

Our foreign operations, through YPF Holdings, are subject to certain environmental claims. See “—Environmental Matters—YPF Holdings—operations in the United States.”

As of December 31, 2007, we had mineral rights in 56 blocks in the United States, comprised of 51 exploratory blocks, with a net surface area of 863 square kilometers and five development blocks, with a net surface area of 17 square kilometers.

Our U.S. subsidiaries’ net petroleum production in the United States for 2007 was 100 mboe, while in 2006 the net production for the year was 105 mboe.

Our U.S. subsidiaries net proved reserves in the United States as of December 31, 2007 were 6,935 mboe.

Our U.S. subsidiaries have entered into various operating agreements and capital commitments associated with the exploration and development of their oil and gas properties. Such contractual, financial and/or performance commitments are not material, except those commitments related to the development of the Neptune Field.

The Neptune Field is located in deep water in the Central Gulf of Mexico, approximately 120 miles from the Louisiana coast. The field is comprised of Atwater Blocks 573, 574, 575, 617 and 618. The Sigsbee Escarpment is the dominant sub-sea feature of the field, with water depths ranging from 4,200 ft. to 6,500 ft. The host facility is located above the escarpment in 4,250 ft. of water, in Green Canyon Block 613. BHP Billiton is the operator of the Neptune Field. The joint venture participants are BHP Billiton (35%), Marathon Oil Corp. (30%), Woodside Petroleum Ltd (20%), and our indirect subsidiary Maxus (US) Exploration (15%).

The Neptune reserves will be produced using a standalone tension leg platform (TLP). The facility will have the design capacity to produce up to 60,000 bpd and 50 mmcf/day. Sub-sea development wells will be tied back to the TLP. The oil and gas will be exported via new lateral pipelines into the existing Caesar and Cleopatra trunk lines. The new lateral pipelines will be installed, owned and operated by Enbridge Offshore LLC.

On March 16, 2008, we were notified that a structural anomaly had been identified on at least one of the pontoons on the Neptune Platform. As a result, commencement of operations has been delayed while the facility is inspected, the structural anomaly is evaluated, and any necessary corrective actions are implemented. As of the date of this annual report, no information as to the timing or potential cost of these actions was available, nor did we know when such information may become available.

Exploration and Development Activities

The following table shows the number of wells drilled by us in Argentina, or in which we participated, and the results obtained, for the periods indicated.

	For the Year Ended December 31,
	2007		2006		2005
Gross wells drilled(1)
Exploratory
Oil		4		1		6
Gas		2		1		1
Dry		17		17		7
Total		23		19		14
Development
Oil		622		703		632
Gas		75		42		34
Dry		14		12		18
Total		711		757		684
Net wells drilled(1)
Exploratory
Oil		4		1		5
Gas		1		1		–
Dry		12		13		5
Total		17		15		10
Development
Oil		488		580		485
Gas		51		15		17
Dry		13		10		16
Total		552		605		518

___________

(1)	“Gross” wells means all wells in which we have an interest. “Net” wells means gross wells after deducting interests of others.

Our principal exploration activities in 2007 focused mainly on underexplored areas within currently producing onshore regions. In 2007, we also completed all of our planned seismic acquisition and site surveys in shallow and deep water basins in Argentine offshore areas in which we plan to commence our drilling operations in 2008.

Three-dimensional seismic testing is being extensively used in several basins to increase exploratory success, improve the quality of exploratory prospects, optimize positioning of the wells and decrease development risk. In 2006, 2,960 km2 of three-dimensional seismic testing were recorded and evaluated, including 2,523 km2 of onshore seismic testing (1,593 km2 exploratory and 930 km2 for development) and 437 km2 of offshore seismic testing in the offshore Colorado Marina basin (as part of an 1,974 square kilometers survey completed in February 2007). In 2007, a total of 2,611 km2 of three-dimensional seismic testing were recorded in the Austral basin and the offshore Colorado Marina basin.

During 2007, 23 exploratory wells (operated and non-operated areas) were drilled: 18 in the Neuquina basin, 4 in the Golfo San Jorge basin and one in the Austral basin. Successful wells included the Borde Sur del Payún (oil), Borde Sur del Payún Shallow (oil ), Los Cavados Este (oil), Rincon Amarillo x-5 (gas) (located in the Neuquina

basin), Estancia Baltaza (oil) (located in the Golfo San Jorge basin) and Arroyo Gamma Sureste (gas) located in Austral basin.

With respect to production initiatives, we continued to improve our facilities and focus our efforts to improve operating efficiencies at our key oil and gas properties. For example, our U.S.$30 million Low Pressure Compression Project at the Loma La Lata natural gas field became fully operational in August 2007. In addition, a new natural gas processing and compression plant with a total capacity of 21 mmcf/d was completed at the Loma La Lata field during the first half of 2007, at a total cost of U.S.$13 million. This plant fed from 10 high CO2-content wells and has been operating since June 30, 2007, processing 10.6 mmcf/d. We expect that the new plant will help YPF to keep the Huincul Methanol plant in service for at least three years.

Our key ongoing production asset capital improvement projects include the Ramos Low Pressure Project in the northwest of Argentina, which is expected to increase compression capacity at that site from 23,680 HP to 38,500 HP (this project is expected to be completed during the first quarter of 2008 at a total cost of approximately U.S.$22 million) and a water injection project at Rincón de los Sauces in the Neuquina basin, in the Chihuido de la Sierra Negra field, to mitigate the natural production decline attributable to the maturity of that field (this project is expected to be completed in 2009 at a total cost of approximately U.S.$133 million). In the year ended December 31, 2007, we also repaired 30 wells, drilled eleven new wells to replace collapsed wells and commenced the revamping of the water treatment plant in Chihuido de la Sierra Negra (we invested U.S.$21.8 million in these projects in 2007). We also continued our work on the Water Alternating GAS (WAG) project in Chihuido de la Sierra Negra in 2007, where a pilot project is expected to be completed in the first half of 2008. Due to the development of new fields, 55 new wells were drilled in Desfiladero Bayo, Bayo Este and Cañadón Amarillo during the year 2007.

In the block CNQ 7A, operated by Petroandina Resources, in which we have a 50% interest, the delineation of the El Corcobo Norte, Jagüel Casa de Piedra, Cerro Huanunl Sur and Puesto Pinto Reservoirs has been completed and the development of those reservoirs has begun. The El Corcobo Norte and Jagüel Casa de Piedra water injection projects also have begun, and a steam injection project in Puesto Pinto has started.

We are also working on a pipeline installation from Corcobo Norte to Puesto Hernandez, which will facilitate the transport of crude to our refinery in Lujan de Cuyo, replacing the current truck transport to the Medanito Plant.

In UNAS (the minor South Business Unit in the Golfo San Jorge basin), 434 injection wells were closed due to the application of new state and provincial regulations, which established tighter anular space control parameters. As a result, the water injection volume was reduced by 91 mbbls/d during 2007, resulting in a reduction in production of an estimated 4 mbbls/d net of oil. Both the Las Heras and Chubut Cañadón Seco economic units have started a remediation campaign, performing overhauls on 71 wells and drilling five replacement wells. The total capital expenditure for these jobs was U.S.$15 million.

Our production declines in recent periods are attributable mainly to the continuing maturity of our fields, although work stoppages and pipeline issues have on occasion contributed to production and capital project delays. During 2007, in the UNAS and UNAO (the West Business Unit in the Neuquina and Cuyana basin), a series of labor and community conflicts halted the production of approximately 1.32 million of barrels of oil equivalent. In December 2006, due to some problems that affected the main pipeline of Magallanes UTE located in the Tierra del Fuego province, oil and gas production was stopped. At the beginning of 2007, our joint venture partner began to replace 18.6 km of pipeline (17 km offshore and 1.6 km onshore), which connects the A3 platform and the battery. In addition, 3.7 km of pipeline that links the AM2 and AM3 platforms will be replaced. These works were long-delayed by unfavorable weather conditions, and are expected to be completed in the first half of 2008. The total contribution by YPF for this project is estimated to be U.S.$20.9 million.

As of March 31, 2008, we had 35 gross and 25 net wells in the process of drilling.

We are engaged in efforts, through the PLADA program, to mitigate the decline in our reserves and production by adding reserves through technological enhancements aimed at improving our recovery factors, including through better reserve delineation, secondary and tertiary recovery, and infill drilling. PLADA was implemented, beginning in 2007, under the Front End Loading (“FEL”) methodology, and visualization stage studies have so far been conducted on 41 areas of reserves.

Reserves

In each concession, we or the consortium of which we are a part are entitled to the reserves that can be produced over the license period, which may be the life of the field.

The following table sets forth our estimated proved reserves and proved developed reserves of crude oil and natural gas at December 31, 2005, 2006, and 2007, which are subject to the explanations and qualifications that follow.

	Crude Oil(1)			Gas			Combined(2)
	(millions of barrels)			(Bcf)			(boe in millions)

Proved Developed and Undeveloped Reserves

Reserves as of December 31, 2005		777			4,683			1,611
Revisions of previous estimates(3)		9			(63	)		(2	)
Extensions, discoveries and improved recovery		20			46			29
Production for the year		(126	)		(651	)		(242	)
Reserves as of December 31, 2006		680			4,015			1,396
Revisions of previous estimates(3)		46			319			100
Extensions, discoveries and improved recovery		17			9			19
Production for the period		(120	)		(635	)		(232	)
Reserves as of December 31, 2007		623			3,708			1,283

Proved Developed Reserves
As of December 31, 2005		604			3,201			1,174
As of December 31, 2006		521			2,571			979
As of December 31, 2007		460			2,441			895

_____________

(1)	Includes crude oil, condensate and natural gas liquids.

(2)	Volumes of gas in the table above and elsewhere in this annual report have been converted to boe at 5.615 mcf per barrel.

(3)	Revisions in estimates of reserves are performed at least once a year. Revision of oil and gas proved reserves are considered prospectively in the calculation of depreciation.

Net crude oil and gas proved reserves as of December 31, 2007 were 1,283 million boe (49% oil, and 51% gas), a 8% decrease compared to net crude oil and gas proved reserves of 1,396 million boe reported as of December 31, 2006.

Changes in our estimated net proved reserves

— Changes in our estimated net proved reserves during 2006

1. Revisions of previous estimates

During 2006, the proved reserves were revised downwards by 2.5 million boe (a decrease of 63.0 billion cubic feet of gas and an increase of 8.7 million barrels of oil).

Revision of previous estimates of proved reserves in UNAO assets not operated by us resulted in the removal of 53.5 billion cubic feet of proved reserves of gas and 1.5 million barrels of proved reserves of oil. Revisions were immaterial for the assets not operated by us in UNAS areas. Revision on the minor UNAO areas resulted in the removal of 5.4 billion cubic feet of proved gas reserves and the inclusion of 2.7 million barrels of

proved reserves of oil. The reserves of all the productive areas were externally audited by GCA (Gaffney, Cline & Associates) and D&M (DeGolyer & MacNaughton) over a period of two years (2005-2006).

Main changes to proved reserves have been due to:

·	In the Noroeste basin, 9.2 billion cubic feet of gas were removed fundamentally due to the low production behavior of the Campo Durán (Tupambi) deposit in the Aguaragüe area.

·	In the Cuyana basin, except for the inclusion of 0.7 million barrels of oil due to the upgrading of recovery systems at the Estructura Cruz de Piedra deposit, all the other areas showed low production behavior and gave rise to an overall removal of 4.6 million barrels of oil.

·	In the Neuquina basin, the primary upward revisions were made in the Aguada Toledo-Sierra Barrosa area, where 52.9 billion cubic feet of gas reserves were added due to the implementation of low compression, the repair of a well and the adjustment update of the material balance.

In the Paso Bardas Norte area, 3.7 billion cubic feet of gas reserves were added due to the adjustment of the Materials Balance in the Huitrín La Tosca deposit and in the Piedras Negras area, and 3.1 billion cubic feet of gas were reclassified as proved following the signing of a gas contract for electric power generation.

The primary downward revisions in this basin occurred in the Puesto Cortadera, Rincón del Mangrullo and Loma La Lata-Lotena deposits. Overall, 56.1 billion cubic feet of proved gas reserves were removed due to the adverse effect of some wells and the corresponding adjustment of estimates. In the Filo Morado area within the Faja Plegada, a downward revision of 23 billion cubic feet of gas and 1.6 million barrels of oil was made due to production behavior.

In Southern Argentina, the positive results of development drilling (primarily in the areas of Manantiales Behr, Zona Cental-Bella Vista Este, Escalante, El Trébol, Las Heras and Lomas del Cuy) in locations adjacent to the production areas, classified as not proved due to their geological uncertainty and to the fields’ improved production response, resulted in the inclusion of 5.5 million barrels of oil and 4.2 billion cubic feet of gas into proved reserves.

2. Improved recovery

Additions of net proved reserves for improvements in the recovery were largely due to: the successful completion of technical/economic feasibility studies for the expansion of existing projects at UNAS, which will be implemented within the next three years; the improvement of response from ongoing projects in UNAS; and the response from physical activity performed at UNAO that have added 8.7 million barrels of oil.

3. Extensions and discoveries

In the Neuquina basin, in the Malargüe area, 1.9 million barrels were added as proved oil reserves due to the outlining activity performed at the Loma de La Mina and Loma Alta areas.

In the Rincón de los Sauces area, the outlining projects of Desfiladero Bayo Este and the Pata Mora fields, and the discoveries in the area of the CNQ 7A exploration permit, resulted in the addition of 1.9 million barrels of proved oil reserves.

Proved gas reserves have been added in the Loma La Lata area as the result of offset wells in the areas Aguada Toledo-Sierra Barrosa, Lindero Atravesado, Rincón del Mangrullo and Aguada Pichana for a total of 33.8 billion cubic feet of gas.

In the Golfo San Jorge basin, offset wells in the vicinity of proved areas (principally at Manantiales Behr, Barranca Baya, Seco León, Lomas del Cuy and Cañadon Yatel) added 6.0 million barrels of proved oil reserves.

An anticlinical structure of Tertiary sandstone which contains dry gas was discovered at the Cerro Piedra field. The production started at the end of 2006 with one well, and the field will be fully developed after working-over three other wells. Estimated proved reserves were 8.1 billion of cubic feet of gas (1.4 million boe).

— Changes in our estimated net proved reserves during 2007

1. Revisions of previous estimates

During 2007, the proved reserves were revised upwards by 100 million boe (an increase of 319 billion cubic feet of gas and 46 million barrels of oil).

Main changes to proved reserves have been due to:

In the Noroeste basin, in the Acambuco area, 74.7 billion cubic feet of natural gas and 1.5 million barrels of oil, condensate and natural gas liquids were added to proved reserves by the production performance of well Mac-1001-bis in Macueta reservoir, which in turn provided a basis for considering the two neighboring wells, Mac.x-1002 and Mac.e-1003, as proved undeveloped reserves. The reserves of San Pedrito reservoir were revised downwards as a result of a more extensive material-balance study performed by YPF and 28.4 billion cubic feet of gas and 0.1 million barrels of condensate were removed from proved reserves.

·	In the Aguaragüe area, 23.7 billion cubic feet of gas were added to proved reserves in Santa Rosa–Icla reservoir. The increase was mainly in proved undeveloped reserves and is related to volumetric studies conducted in areas where new drilling activity is to be performed in 2009 and 2010.

In the Loma La Lata-Sierras Blancas reservoir, the revision of the development plan for the southeastern and northeastern parts of the field, in conjunction with a general improvement in production performance, resulted in the addition of 168.8 billion cubic feet of gas and 9.1 million barrels of associated liquids to proved reserves.

In the San Roque area, in accordance with a new evaluation of the fields, 54.0 billion cubic feet of gas and 3.0 million barrels of associated liquids in Aguada San Roque reservoir, as well as 50.0 billion cubic feet of gas and 3.2 million barrels of associated liquids in Loma las Yeguas reservoir, were added to proved reserves. The addition was mostly to proved undeveloped reserves and in both cases was related to the planned installation of compression facilities scheduled for mid 2008.

In the CNQ7A area, proved reserves were increased by 6.7 million barrels of oil because of the general revaluation of reserves performed in conformity with the development plans for the four reservoirs. These plans, which include the drilling and workover of more than 350 wells, are being implemented by the operator.

In Golfo San Jorge basin fields, the positive results of development drilling (primarily in the areas of Manantiales Behr, Cañadón Vasco and Cañadón Perdido) in locations adjacent to the production areas, previously classified as non-proved due to their geological uncertainty, and to the fields’ improved production response, resulted in the inclusion of 2.3 million barrels of oil in proved reserves.

The production performance in some of the south areas has been adversely affected by the closing of injection wells due to corrosion problems which has caused a downward deviation in current production estimates. Secondary production decreased for that reason in some areas, but primary production increased in others, mainly in Barranca Baya, Escalante and Tierra del Fuego areas, with these effects practically offsetting one another. The temporary closing of injector wells resulted in the recategorization of certain proved developed production oil reserves into proved developed non-productive and proved undeveloped oil reserves. The downward revisions resulted in a reduction of 1.2 million barrels of oil in proved reserves.

·	Those reserves that were booked since 2003, without a development program for the next two years, were taken out, resulting in the removal of 4.0 million barrels from proved oil reserves, mainly in Los Perales, Barranca Baya and Manantiales Behr fields.

·	The anti-clinical structure of Tertiary sandstone discovered in 2006 in the Cerro Piedra field in the Southern region has been in production throughout 2007. The new pressure analysis shows that dry gas reserves increased by 4.2 billion cubic feet.

·	The delay in various development plans resulted in the removal of 1.6 million barrels of proved oil reserves because production would be beyond the concession expiration date.

·	In Austral basin, in CAM 2 A Sur area, the well Poseidón-112 was flooded and thus closed down, resulting in a net proved reserve decrease of 0.6 million boe.

In Neptune (USA), the delineation and development activity carried out has produced new information about the geological and petrophysical parameters which differs, in some cases, from previous estimates, leading to a negative revision of 574 mboe of proved reserves, comprised of negative revisions of 0.7 billion cubic feet of gas and 452 mbbl of oil. The revised figures are in line with the estimate of GCA.

2. Improved recovery

In the Cuyana basin, in the Barrancas area 0.3 million barrels of oil were added to proved reserves as a result of the successful drilling of wells B-499 and B-501 as part of the secondary recovery project for the Cabras/Brecha Verde reservoir.

In the Neuquina basin, in the Desfiladero Bayo area, 2.2 million barrels of oil were added to proved reserves due to the drilling of 14 new wells as part of the Centro Infill Project in the Agrio + Troncoso and Rayoso reservoirs.

In the Chihuido de la Sierra Negra area, 1.3 million barrels of oil were added to proved reserves due to the commencement of drilling during 2007 and the establishment of drilling plans for 2008 for the Lomita-Rayoso reservoir.

In the CNQ7A area, definition for a secondary recovery project in the Jaguel Casa de Piedra reservoir as part of the overall development plan established for the field resulted in the addition of 1.0 million barrels of oil to proved reserves based on the successful results of a pilot injection project started in November 2005.

In the Señal Picada area, 0.7 million barrels of oil were added to proved reserves because of the expansion of the secondary recovery project to the eastern part of the SP-Quintuco reservoir.

In the Golfo San Jorge oil fields, 1.8 million barrels of oil were added to net proved reserves as a result of improvements in recovery through water injection projects.

3. Extensions and discoveries

In the Cuyana basin, in the area La Ventana Central, 0.2 million barrels of oil were added to proved reserves as a result of the extension of well RV-35 in the Rio Viejas reservoir.

In the Neuquina basin, the most important upward revision was in the Aguada Toledo-Sierra Barrosa area, where 3.4 billion cubic feet of gas were added to proved reserves in the Cupén Mahuida Precuyano reservoir as a result of the appraisal of well CuM.a-13.

In the Loma Alta Sur area, 1.4 million barrels of oil and 1.1 billion cubic feet of gas were added to proved reserves as a result of the appraisal of wells LA.a-16 and LA.a-17.

In the Desfiladero Bayo area, 0.3 million barrels of oil were added to proved reserves in the reservoir Agrio + Troncoso as a result of the appraisal of well DB.a-185 and 0.5 million barrels of oil in the Desfiladero Bayo Este reservoir as a result of the appraisal of well DBE.a-90.

In the Cañadón Amarillo area, 0.5 million barrels of oil were added to proved reserves in the reservoir Barda Negra + Tordillo as a result of the appraisal of well Cam.x-1002.

In the Señal Picada area, 0.3 million barrels of oil were added to proved reserves in the reservoir SP-Quintuco as a result of the appraisal of well SP.a-299 together with the definition of a development plan for the eastern part of the field.

In the Golfo San Jorge basin, offset wells in the vicinity of proved areas (principally at Manantiales Behr, Barranca Baya and Cañadon Yatel) added 4.2 million of barrels of proved oil reserves.

In the Manantiales Behr area, 1.6 million barrels of oil were added to proved reserves in the Grimbeek field as a result of several appraisals of wells in the Grimbeek north zone.

A new small anticlinal structure of Tertiary sandstone which contains dry gas was discovered at the Cerro Piedra field in the south last year. Estimated proved reserves were 0.6 billion cubic feet of gas and the field was connected to existing facilities and is currently in production.

— Additional Information—Restatement of Previously Reported Reserves as of December 31, 2004

On January 26, 2006, we announced that we would reduce our prior proved reserve estimates by 509 million boe (55% gas), including 493 million boe corresponding to our proved developed and undeveloped reserves and 16 million boe corresponding to proved developed and undeveloped reserves of affiliated companies. The Audit and Control Committee of our parent company, Repsol YPF, undertook an independent review of the facts and circumstances of the reduction in proved reserves. The Audit and Control Committee presented the final conclusions to the Board of Directors of Repsol YPF at its meeting of June 15, 2006. According to the independent review, the process for determining reserves with respect to our fields in Argentina was flawed from 2003 to 2004, and our personnel at times failed to apply properly SEC criteria for reporting proved reserves.

The independent review reported that this was principally due to:

·	lack of proper understanding of and training on the requirements of the SEC for booking proved reserves;

·	undue optimism regarding the technical performance of the fields and focus on replacement ratio;

·	absence of a meaningful deliberative process for determining proved reserves and resolving disputes; and

unwillingness to accept personal responsibility for reporting internally adverse facts regarding reserves and a corresponding tendency to view such issues as falling within another person’s or department’s jurisdiction. Over time, problems emerged and grew in the absence of delineation of responsibilities for booking proved reserves and in the absence of clear directives pre-2005.

This notwithstanding, no evidence was found that any personnel involved in the reporting of proved reserves were motivated by personal gain.

The tables below reflect the reconciliation of proved reserves as restated with proved reserves as originally reported for the year 2004:

	Oil
	Proved developed and undeveloped reserves			Proved developed reserves
	(Millions of barrels)
As originally reported as of December 31		1,114			908
Effect of the adjustment As of beginning of year		(67	)		(63	)
Movement during the year		17			18
Total		(50	)		(45	)
As restated as of December 31		1,064			863

	Gas
	Proved developed and undeveloped reserves			Proved developed reserves
	(Billions of cubic feet)
As originally reported as of December 31		6,820			5,041
Effect of the adjustment As of beginning of year		(1,531	)		(1,383	)
Movement during the year		387			387
Total		(1,144	)		(996	)
As restated as of December 31		5,676			4,045