YPF S.A. - 20-F annual report

The number of outstanding shares of each class of stock of YPF Sociedad Anónima as of December 31, 2010 was:

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.

In this annual report, references to “Audited Consolidated Financial Statements” are to YPF’s audited consolidated balance sheets as of December 31, 2010, 2009 and 2008, YPF’s audited consolidated statements of income for the years ended December 31, 2010, 2009 and 2008, YPF’s audited consolidated statements of cash flows for the years ended December 31, 2010, 2009 and 2008, YPF’s audited consolidated statements of changes in shareholders’ equity for the years ended December 31, 2010, 2009 and 2008, and the related notes and schedules thereto.

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 through February 28, 2003. See Note 1(a) to the Audited Consolidated Financial Statements.

Certain monetary amounts and other figures included in this annual report have been subject to rounding adjustments. Any discrepancies in any tables between the totals and the sums of the amounts are due to rounding.

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

Oil and gas reserves definitions used in this annual report are in accordance with Regulations S-X and S-K, as amended by the U.S. Securities and Exchange Commission’s (“SEC”) final rule, Modernization of Oil and Gas Reporting (Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08; December 31, 2008) and relevant guidance notes and letters issued by the SEC’s Staff.

The reported reserves contained in this annual report include only our proved reserves and do not include probable reserves, possible reserves or reserves from nontraditional or unconventional sources.

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

“acreage”: The total area, expressed in acres or km², over which YPF has interests in exploration or production. Net acreage is YPF’s interest in the relevant exploration or production area.

“concession contracts”: 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 the exploration, development, production and sale of hydrocarbon, and typically, an obligation to make payments at the signing of the concession and once production begins pursuant to applicable laws and regulations.

“crude oil”: Crude oil with respect to YPF’s production and reserves includes condensate and natural gas liquids (“NGL”).

“gas”: Natural gas.

“hydrocarbons”: Crude oil and natural gas.

“surface conditions”: Represents the pressure and temperature conditions at which volumes of oil, gas, condensate and natural gas liquids are measured for report purpose. It is also referred to as standard conditions. For YPF these conditions are 14.7 psi for pressure and 60 ºF for temperature. All volume units expressed in this report are at surface conditions.

Not applicable.

Not applicable.

The following tables present our selected financial and operating data. You should read this information in conjunction with our Audited Consolidated 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, 2010, 2009 and 2008 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 year ended December 31, 2007 is derived from our audited financial statements as of December 31, 2009, 2008 and 2007 (the “Restated Audited Consolidated Financial Statements”), included in our report on Form 6-K furnished to the SEC on March 14, 2011 (SEC Accession No. 0001208646-11-000114), which are not included in this annual report. The financial data as of December 31, 2009, 2008 and 2007 and for the years then ended included in this annual report reflects the effect of the restatement of our Argentine GAAP (as defined below) income tax expense, net income, earnings per ADS, accounts payable (when applicable), investments, other receivables, taxes payable and shareholders’ equity from the amounts originally presented to give retroactive effect to a change in Argentine GAAP introduced in 2010 requiring that a formerly off-balance sheet Ps.1,180 million as of December 31, 2009, deferred tax liability be recognized in our financial statements, which had the effect of increasing Argentine GAAP net income by Ps.203 million, Ps.261 million and Ps.290 million in 2009, 2008 and 2007, respectively, and decreasing shareholders’ equity by Ps 1,180 million, Ps.1,383 million and Ps.1,644 million at December 31, 2009, 2008 and 2007, respectively. Our net income and shareholders’ equity under U.S. GAAP were unaffected by this change in Argentine GAAP. For a discussion of this change, see Note 1(b) to our Audited Consolidated Financial Statements. The financial data as of and for the year ended December 31, 2006, is derived from our audited financial statements which are not included in this annual report. Amounts at and for the year ended December 31, 2006 were not required to be restated under Argentine GAAP and have not been restated. 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 12, 13 and 14 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, 2010, 2009 and 2008 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, 2010 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 31, 2010 of Ps.3.98 to U.S.$1.00, unless otherwise specified. The exchange rate quoted by Central Bank on April 8, 2011 was Ps.4.05 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 “—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, 2011 by Law 26,563, 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.

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.

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

YPF’s operations and earnings are subject to risks as a result of changes in competitive, economic, political, legal, regulatory, social, industrial, business and financial conditions. Investors should carefully consider these risks.

As a result of the recent global financial crisis and the continuing uncertain economic environment, certain risks may gain more prominence either individually or when taken together. Certain oil and gas prices and margins may be lower than in recent years due to reduced demand and certain other factors.

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. 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 real GDP increasing at an average cumulative rate of 8.5% between 2003 and 2008. As a result of the crisis in the global economy, Argentina’s GDP growth rate decelerated to 0.9% in 2009, but recovered in 2010 growing by approximately 9%, according to preliminary official data. No assurances can be given that the current rate of growth will continue in 2011 or subsequent years or that the economy will not contract. Continued high or increased rates of inflation in Argentina could increase our costs of operation, in particular labor costs, and may negatively impact our results of operations and financial condition.

The Argentine economy, including the financial and securities markets, is particularly sensitive to local political developments. Argentina’s national election for President and Vice President will take place in October 2011, and other relevant local and federal elections will also take place in 2011.

See “Item 5. Operating and Financial Review and Prospects—Factors Affecting Our Operations—Macroeconomic Conditions.” If economic conditions in Argentina were to deteriorate, it would likely have an adverse effect on our financial condition and results of operations.

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:

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 growth 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.

In recent years, due to regulatory, economic and government policy factors, our domestic gasoline, diesel and other fuel prices have frequently lagged substantially behind prevailing international and regional market prices for such products, and our ability to increase prices has been limited. 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 domestic prices of our products, 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 match the increases or decreases in hydrocarbon prices at the international or regional levels.

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 extensive restrictions on exports of natural gas from Argentina. 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—Delivery commitments—Natural gas supply contracts,” “Item 4. Information on the Company—

In addition, the effectiveness of certain of our natural gas export authorizations is subject to an analysis by the Argentine 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 Argentine Secretariat of Energy 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 Argentine 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 prevailing domestic 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.

Since 2002, new duties have been imposed on exports, and have been progressively increased over the years. Resolution 394/2007 of the Ministry of Economy and Production, published on November 16, 2007, amended the export duties on crude oil and other crude derivative products imposed in previous years. 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 by the Argentine government 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, 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. 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 Argentine 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.$233/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.

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.

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.

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.

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 for certain products 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.

Argentina’s oil and gas fields are mature and our reserves and production are likely to decline as reserves are depleted. Despite our efforts to replace our reserves, in the last two years our proved reserves declined by approximately 13.3%, and we replaced approximately 83.6% of our production with new proved reserves during 2010; average daily production in 2010, on a boe basis, declined by approximately 5.3% from 2009. 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 gas 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, some of which are beyond our control. Factors susceptible to our control include drilling, testing and production after the date of the estimates, which may require substantial revisions to reserves estimates; the quality of available geological, technical and economic data used by us and our interpretation thereof; the production performance of our reservoirs and our recovery rates, both of which depend in significant part on available technologies as well as our ability to implement such technologies and the relevant know-how; the selection of third parties with which we enter into business; and the accuracy of our estimates of initial hydrocarbons in place, which may prove to be incorrect or require substantial revisions. Factors mainly beyond our control include changes in prevailing oil and natural gas prices, which could have an effect on the quantities of our proved reserves (since the estimates of reserves are calculated under existing economic conditions when such estimates are made); changes in the prevailing tax rules, other government regulations and contractual conditions after the date estimates are made (which could make reserves no longer economically viable to exploit); and certain actions of third parties, including the operators of fields in which we have an interest.

As a result of the foregoing, 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 by leading to increased depreciation, depletion and amortization charges and/or impairment charges, which would reduce earnings and shareholders’ equity.

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, oil or natural gas spills or leaks, 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 to our operations and harm to our reputation. 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.

As discussed under “—The oil and gas industry is subject to particular economic and operational risks” and “—We may incur significant costs and liabilities related to environmental, health and safety matters,” our exploration and production operations are subject to extensive economic, operational, regulatory and legal risks. We maintain insurance covering us against certain risks inherent in the oil and gas industry in line with industry practice, including loss of or damage to property and equipment, control-of well incidents, loss of production or income incidents, removal of debris, sudden and accidental seepage pollution, contamination and clean up and third-party liability claims, including personal injury and loss of life, among other business risks. However, our insurance coverage is subject to deductibles and limits that in certain cases may be materially exceeded by our liabilities. In addition, certain of our insurance policies contain exclusions that could leave us with limited coverage in certain events. See “Item 4. Information on the Company—Insurance”. In addition, we may not be able to maintain adequate insurance at rates or on terms that we consider reasonable or acceptable or be able to obtain insurance against certain risks that materialize in the future. If we experience an incident against which we are not insured, or the costs of which materially exceed our coverage, it could have a material adverse effect on our business, financial condition and results of operations.

The 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 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 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 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. Concessions representing approximately 48% of our proved reserves as of December 31, 2010 have been extended prior to the date of this annual report (see Note 10(c) to our Audited Consolidated Financial Statements). We cannot provide assurances that concessions that have not yet been renewed 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 operations.

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.

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. In addition, due to concern over the risk of climate change, a number of countries have adopted, or are considering the adoption of, new regulatory requirements to reduce greenhouse gas emissions, such as carbon taxes, increased efficiency standards, or the adoption of cap and trade regimes. If adopted in Argentina, these requirements could make our products more expensive as well as shift hydrocarbon demand toward relatively lower-carbon sources such as renewable energies.

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 accruals we have provided.

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.

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. Labor demands are commonplace in Argentina’s energy sector and unionized workers have blocked access to and damaged our plants in the recent past. Our operations were affected occasionally by labor strikes in recent years. See “Item 5. Operating and Financing Review and Prospects—Factors Affecting Our Operations—Macroeconomic Conditions.”

As of March 28, 2011 Repsol YPF controlled approximately 68.23% of our capital stock and voting rights and Petersen Energía S.A. (“Petersen Energía”) and Petersen Energía Inversora S.A. (“PEISA”, and together with Petersen Energía, the “Petersen Group”) controlled 15.46% 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 (in particular, Enrique Eskenazi, Sebastián Eskenazi, Ezequiel Eskenazi Storey and Matías Eskenazi Storey, shareholders of Petersen Energía, or to companies that are, directly or indirectly, wholly-controlled by any of them) an option to purchase an additional 10% 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 the Petersen Group’s interests may differ from those of our other shareholders.

Under our by-laws, 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 by-laws, 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.”

As of the date of this annual report, approximately 16.31% of our capital stock is held by non-affiliates (less than 0.5% of our capital stock was held by non-affiliates as of September 30, 2010). 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.

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.

Our corporate affairs are governed by our by-laws 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.

Repsol YPF owns Class D shares and ADSs representing a significant majority of our capital stock (which may be reduced by 10% if the Second Petersen Option described under “Item 7. Major Shareholders and Related Party Transactions—Option Agreements”). The Petersen Group owns ADSs representing up to approximately 15.46% of our capital stock (which may be increased up to approximately 25.46% if the Second Petersen Option is 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 (as defined in “Item 7. Major Shareholders and Related Party Transactions”). 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

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.

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 by-laws 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 BASE, 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.

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.

YPF is a limited liability company (sociedad anónima), incorporated under the laws of Argentina for an unlimited term. Our address is Macacha Güemes 515, C1106BKK Ciudad Autónoma de Buenos Aires, Argentina and our telephone number is (011-54-11) 5441-2000. Our legal name is YPF Sociedad Anónima and we conduct our business under the commercial name “YPF”.

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 LPG. Our downstream operations include the refining, marketing, transportation and distribution of oil and a wide range of petroleum products, petroleum derivatives, petrochemicals, LPG 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 2010, we had consolidated net sales of Ps.44,162 million (U.S.$11,096 million) and consolidated net income of Ps.5,790 million (U.S.$1,455 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 2008, when the Petersen Group purchased, in different stages, shares representing 15.46% of our capital stock. In addition, Repsol YPF granted certain affiliates of Petersen Energía an option to purchase up to an additional 10% of our outstanding capital stock. This option will expire on February 21, 2012. See “Item 7. Major Shareholders and Related Party Transactions.” Since September 2010, Repsol YPF has sold approximately 15.78% of our capital stock and granted an option to acquire from Repsol YPF additional shares representing 1.6% of our capital stock. As of March 28, 2011, Repsol YPF controlled approximately 68.23% of our capital stock and voting rights.

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.

For a description of our principal capital expenditures and divestitures, see “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources—Capital investments, expenditures and divestitures.”

Argentina is the largest producer of natural gas and the fourth largest producer of crude oil in Central and South America, based on 2009 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, until 2008, local prices for oil and natural gas products had remained significantly below those prevalent in neighboring countries and international commodity exchanges, heightening domestic demand for such products. In the case of natural gas, the price at which Bolivia exports natural gas to Argentina was approximately U.S.$7.33/mmBtu in December 2010, while our average sales price in Argentina during 2010 was approximately U.S.$1.96/mmBtu.

After declining during the economic crisis of 2001 and 2002, Argentina’s gross domestic product, or GDP, grew at an average annual real rate of approximately 8.5% from 2003 to 2008, although the growth rate decelerated to 0.9% in 2009 as a result of the global financial crisis, but recovered in 2010 growing by approximately 9%, according to preliminary official data. 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 approximately 6.7% and 4.7%, respectively, during the period 2003-2008 (and declined by 2.6% and 8.3%, respectively, in 2009), 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, diesel and gasoline, 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 gas (including NGL). In 2003, Argentina’s net exports of diesel amounted to approximately 1,349 mcm, while in 2010 its net imports of diesel amounted to approximately 1,466 mcm, according to information provided by the Argentine Secretariat of Energy. Significant investments in the energy sector are being carried out, and additional investments 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 have been in general substantially higher than the average 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 engaged in efforts to operate our refineries near their 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.

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

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.

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 granted certain affiliates of Petersen Energía options to purchase up to an additional 10.1% of our outstanding capital stock within four years. On May 20, 2008, PEISA exercised an option to purchase shares representing 0.1% of our capital stock. Additionally, PEISA launched a tender offer to purchase all of the shares of YPF that were not already owned by them at a price of U.S.$49.45 per share or ADS. Repsol YPF, pursuant to its first option agreement with Petersen Energía, had stated that it would not tender YPF shares to PEISA. A total of 1,816,879 shares (including Class D shares and ADSs), representing approximately 0.462% of our total shares outstanding, were tendered. Repsol YPF owns a majority of our capital stock and, subject to the shareholders’ agreement entered into between Repsol YPF and Petersen Energía, is able to determine substantially all issues decided by our shareholders. See “Item 7. Major Shareholders and Related Party Transactions.” Since September 2010, Repsol YPF has sold approximately 15.78% of our capital stock and granted an option to acquire from Repsol YPF additional shares representing 1.6% of our capital stock. As of March 28, 2011, Repsol YPF controlled approximately 68.23% of our capital stock and voting rights.

We conduct our business according to the following organization:

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 Chemicals 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 and certain construction activities, mainly related to the oil and gas industry, through our subsidiary A-Evangelista S.A. and its subsidiaries.

Substantially all of our operations, properties and customers are located in Argentina. However, we carry out exploration activities in the United States and Guyana, and hold an interest in a producing field in the United States and in two exploratory areas in Uruguay (see “—Exploration and Production—Principal properties—International properties”). Additionally, since 2010 we market

The following table sets forth net sales and operating income for each of our lines of business for the years ended December 31, 2010, 2009 and 2008:

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

The following table sets forth information with regard to YPF’s developed and undeveloped acreage by geographic area as of December 31, 2010:

As of December 31, 2010 approximately 0.2% of our exploratory undeveloped acreage corresponded to exploration permits which will expire in 2011 and which are not subject to renewal in accordance with Law 17,319, since they are in the last year of their extension term. In addition, as a result of the expiration in 2011 of the first, second or third exploration terms of certain of our exploration permits, we will be required to relinquish a fixed portion of the acreage related to each such expiring permit, as set forth in Law 17,319, as long as exploitable quantities of oil or gas are not discovered in such areas (in which case we may seek to obtain a declaration of their commercial viability from the relevant authorities, and the related areas would then be subject to exploitation concessions). Provided no such discoveries are made in 2011, we will be required to relinquish approximately 5.8 thousand square kilometers of exploratory undeveloped acreage (approximately 11.8% of our 48.9 thousand square kilometers of net exploratory undeveloped acreage as of December 31, 2010) during 2011. We are entitled to decide, according to our best interest, which portions of each of the exploration permits to keep, within the required relinquishment percentage. Therefore, the areas to be relinquished consist usually of acreage were drilling has not been successful and that are considered non-core lease acreage.

We do not have any material undeveloped acreage related to our production concessions expiring in the near term.

Argentina is the largest gas and fourth largest oil producing nation in Central and South America according to the 2009 edition of BP Statistical Review of World Energy, published in June 2010 (the “BP Statistical Report”). 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. As of the date of this annual report, a total of 24 sedimentary basins have

The following table shows our gross and net interests in productive oil and gas wells in Argentina by basin, as of December 31, 2010:

The table below provides certain information with respect to our net working interests in our principal oil and gas fields in Argentina at December 31, 2010, all of which are mature:

Approximately 87% of our proved crude oil reserves in Argentina are concentrated in the Neuquina (53%) and Golfo San Jorge (34%) basins, and approximately 94% of our proved gas reserves in Argentina are concentrated in the Neuquina (71%), Noroeste (16%) and Austral (7%) basins.

As of December 31, 2010, YPF held 117 production concessions and exploration permits in Argentina. YPF directly operates 83 of them, including 61 production concessions and 22 exploration permits.

As of December 31, 2010, YPF held 26 exploration permits in Argentina, 21 of which are onshore exploration permits and five of which are offshore exploration permits. YPF has 100% ownership of three onshore permits, and its participating interests in the rest vary between 50% and 90%. YPF’s interests in the offshore permits vary between 30% and 35%.

As of December 31, 2010, YPF had 91 production concessions in Argentina. YPF has a 100% ownership interest in 54 production concessions, and its participating interests in the remaining 37 production concessions vary between 12.2% and 98%.

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 also contributed to production declines and capital project delays. During the year 2010, a series of labor and community conflicts resulted in lost production of approximately 3.2 mmboe in areas we operate.

We participate in 23 exploration and 25 production joint ventures and contractual arrangements (18 of them not operated by YPF) in Argentina. Our interests in these joint ventures and contractual arrangements range from 12.2% to 98%, 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 main 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.

As of December 31, 2010, we had mineral rights in 55 blocks in the United States, comprised of 50 exploratory blocks, with a net surface area of 670 square kilometers and five development blocks, with a net surface area of 17 square kilometers. Our U.S. subsidiaries’ net proved reserves in these properties in the United States as of December 31, 2010 were 1 mmboe. Our U.S. subsidiaries’ net hydrocarbon production in these properties in the United States for 2010 was 0.6 mmboe.

The Neptune Field is located approximately 120 miles from the Louisiana coast within the deepwater region of the Central Gulf of Mexico. The unitized field area comprises Atwater Valley Blocks 573, 574, 575, 617 and 618. Our indirect subsidiary, Maxus U.S. Exploration Company, has a

In 2009, YPF Holdings Inc. (“YPF Holdings”) participated in the drilling of the Northwood exploration prospect in the Gulf of Mexico with a net interest of 3.5%. YPF Holdings’ total net investment was U.S.$11.5 million. No reserves were found.

In addition, YPF Holdings has entered into various operating agreements and capital commitments associated with the exploration and development of its oil and gas properties. Such contractual, financial and/or performance commitments are not material, except for commitments related to the Neptune Project located in the vicinity of the Atwater Valley Area, Blocks 573, 574, 575, 617 and 618. Total commitments remaining as of December 31, 2010 for the Neptune Project are minimum pipeline transportation payment obligations of U.S.$12.1 million.

As of December 31, 2010, YPF held, through YPF Guyana Ltd., a wholly-owned subsidiary of YPF International, S.A., a 30% working interest in a petroleum prospecting license (the “Petroleum Prospecting License”) as part of a petroleum agreement (the “Petroleum Agreement”) in connection with the Georgetown block, offshore Guyana. The surface exploratory area attributable to YPF Guyana Ltd.’s working interest is 2,520 square kilometers, which represents approximately 622.7 thousand undeveloped acres. The Guyana government renewed the Petroleum Prospecting License on November 25, 2009 for three years. In accordance with the Petroleum Agreement, the beginning of a new renewal period implied the relinquishment of 930 square kilometers (according to YPF Guyana Ltd.’s 30% working interest) of the original Georgetown exploration block area, as well as the drilling of an exploratory well that must commence before May 25, 2011.

The main exploration activities performed during 2010 were related to the definition and location of the Jaguar-1 exploration well. The 3D seismic data was re-processed to estimate geo-pressures and to define the best seabed location for the drilling rig. In addition, the geological petroleum system was re-assessed to account for any potential hazard related to overpressures, particularly, near the reservoir target.

As of December 31, 2010, the Georgetown block consortium had agreed on the location and the drilling of the Jaguar-1 well, with a total depth of 21,450 ft. The Georgetown block consortium agreed to contract a jackup drilling rig (Atwood Beacon, from Atwood Oceanics), and upgrade it for a high pressure/high temperature well. As of such date, the engineering well design had been completed and the long lead items (well head, special tubular material, etc.) had already been ordered. The total estimated cost of the exploratory well is approximately U.S.$110 million (approximately U.S.$33.2 million, considering YPF Guyana Ltd.’s working interest). The well was originally planned to be spud in April 2011. However, as a result of weather conditions, activity was postponed and the well is currently planned to be spud in August 2011 and the entire operation is expected to take approximately 180 days to complete, including hydrocarbon appraisal, plug and abandonment.

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

Finally, as of December 31, 2010, we held a 40% working interest in Área 3, operated by us, and a 40% working interest in Área 4, operated by Petrobras Uruguay, both of which are exploratory areas located in the Punta del Este basin (Uruguay).

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to

Information on net proved reserves as of December 31, 2010 and 2009 was calculated in accordance with the SEC rules and FASB’s ASC 932, as amended. Accordingly, crude oil prices used to determine reserves were calculated at the beginning of each month, for crude oils of different quality produced by the company, considering the realized prices for crude oils of such quality in the domestic market until 2011 (taking into account the effects of export taxes according to Law 26,217 which are enforceable until such year) and, for the following years, we considered the unweighted average price of the first-day-of-the-month price for each month within the twelve-month period ended December 31, 2010 and 2009, respectively, which refers to the WTI prices adjusted by each different quality produced by the company. Additionally, since there are no benchmark market natural gas prices available in Argentina, the company used average realized gas prices during the relevant year to determine its gas reserves. Information on net proved reserves as of December 31, 2008 was calculated using year-end prices and costs, respectively.

Net reserves are defined as that portion of the gross reserves attributable to the interest of YPF after deducting interests owned by third parties. In determining net reserves, we exclude from our reported reserves royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and is able to make lifting and sales arrangements independently. By contrast, to the extent that royalty payments required to be made to a third party, whether payable in cash or in kind, are a financial obligation, or are substantially equivalent to a production or severance tax, the related reserves are not excluded from our reported reserves despite the fact that such payments are referred to as “royalties” under local rules. We follow the same methodology in reporting our production amounts.

Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on concessions and leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of crude oil and natural gas liquids.

YPF’s estimated proved reserves as of December 31, 2010 are based on estimates generated through the integration of available and appropriate data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results. Data used in these integrated assessments include information obtained directly from the subsurface via wellbore, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also include subsurface information obtained through indirect measurements, including high quality 2-D and 3-D seismic data, calibrated with available well control. Where applicable, surface geological information was also utilized. The tools used to interpret and integrate all these data included both proprietary and commercial software for reservoir modeling, simulation and data analysis. In some circumstances, where appropriate analog reservoir models are available, reservoir parameters from these analog models were used to increase the reliability of our reserves estimates.

For further information on the estimation process of our proved reserves, see “—Internal controls on reserves and reserves audits.”

The following table sets forth our estimated net proved developed and undeveloped reserves of crude oil and natural gas at December 31, 2010.

YPF had estimated net proved undeveloped reserves of 231 mmboe at December 31, 2010, which represented approximately 24% of the 982 mmboe total reported proved reserves as of such date. This compares to estimated net proved undeveloped reserves of 211 mmboe at December 31, 2009 (approximately 21% of the 1,013 mmboe total reported proved reserves as of such date).

The 10% increase in net proved undeveloped reserves in 2010 is mainly attributable to the addition of new proved undeveloped reserves related to new development studies (30 mmboe), improved recovery projects in Argentina (30 mmboe) and extensions of existing developments (6 mmboe), which exceeded reductions of our proved undeveloped reserves in 2010, which primarily relate to the transfer from proved undeveloped to proved developed reserves resulting from our development activity and revisions to previous estimates. The largest transfers were associated with the drilling of new wells (16 mmboe) and the production response of certain improved recovery projects (4 mmboe).

YPF’s total expenditure to advance the development of reserves was approximately U.S.$1,222 million during 2010, of which U.S.$340 million was allocated to projects related to proved undeveloped reserves.

As at December 31, 2010, we did not have material amounts of proved undeveloped reserves in individual fields or countries that have remained undeveloped for five years or more after being disclosed as proved undeveloped reserves.

All of our oil and gas reserves held in consolidated companies have been estimated by our petroleum engineers. In order to meet the high standard of “reasonable certainty,” reserves estimates are stated taking into consideration additional guidance as to reservoir economic producibility requirements, acceptable proved area extensions, drive mechanisms and improved recovery methods, marketability under existing economic and operating conditions and project maturity.

Where applicable, the volumetric method is used to determine the original quantities of petroleum in place. Estimates are made by using various types of logs, core analysis and other available data. Formation tops, gross thickness, and representative values for net pay thickness,

Estimates of ultimate recovery are obtained by applying recovery factors to the original quantities of petroleum in place. These factors are based on the drive mechanisms inherent in the reservoir, analysis of the fluid and rock properties, the structural position of the reservoir and its production history. In some instances, comparisons are made with similar production reservoirs in the areas where more complete data is available.

Where adequate data is available and where circumstances are justified, material-balance and other engineering methods are used to estimate ultimate recovery. In these instances, reservoir performance parameters such as cumulative production, production rate, reservoir pressure, gas oil ratio behavior and water production are considered in estimating ultimate recovery.

In certain cases where the above methods could not be used, proved reserves are estimated by analogy to similar reservoirs where more complete data are available.

To control the quality of reserves booking, a process has been established that is integrated into the internal control system of YPF. This process to manage reserves booking is centrally controlled and has the following components:

For those areas submitted to third party reserves audit, YPF’s proved reserves figures have to be within 7% of the third party reserves audit figures for YPF to declare that the volumes have been ratified by a third party reserves audit. In the event that the difference is greater than the tolerance, YPF will reestimate its proved reserves to achieve this tolerance level or should disclose the third party figures.

In 2010, DeGolyer & MacNaughton audited areas operated by YPF in the Golfo San Jorge and Neuquina basins in Argentina and Gaffney, Cline & Associates Inc audited non-operated areas in the Gulf of Mexico and Oklahoma basins in the United States. All these third party audits were performed, as of September 30, 2010 on fields which, in our estimates as of such date, contained proved reserves of 462 mmboe in the aggregate, and cumulatively covered approximately 47% of our proved reserves in Argentina as of that date. The 2010 third party reserves audits covered approximately 138 mmboe of our proved undeveloped reserves, which represented approximately 59% of our aggregate proved undeveloped reserves as of September 30, 2010. A copy of the related reserves audit reports are filed as Exhibits to this annual report.

We are required, in accordance with Resolution S.E. No. 324/06 of the Argentine Secretariat of Energy, to file annually and by March 31 of every year details of our estimates of our oil and gas reserves and resources with the Argentine Secretariat of Energy, as defined in that resolution and certified by an external auditor. The aforementioned certification and external audit only have the meaning established by Resolution S.E. No. 324/06, and are not to be interpreted as a certification or external audit of oil and gas reserves under SEC rules. We last filed such a report for the year ended December 31, 2010 and the estimates of our proved oil and gas reserves filed with the Argentine Secretariat of Energy are materially higher than the estimates of our proved oil and gas reserves contained in this annual report mainly because: (i) information filed with the Argentine Secretariat of Energy includes all properties of which we are operators, irrespective of the level of our ownership interests in such properties; (ii) information filed with the Argentine Secretariat of Energy includes other categories of reserves and resources different to proved reserves that are not included in this

The following table shows our oil (including crude oil, condensate and natural gas liquids) and gas production on an as sold and daily basis for the years indicated. In determining net production, we exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in such production and is able to make lifting and sales arrangements independently. By contrast, to the extent that royalty payments required to be made to a third party, whether payable in cash or in kind, are a financial obligation, or are substantially equivalent to a production or severance tax, they are not excluded from our net production amounts despite the fact that such payments are referred to as “royalties” under local rules. This is the case for our production in Argentina, where royalty expense is accounted for as a production cost.

The composition of the crude oil produced by us in Argentina varies by geographic area. Almost all crude oil produced by us in Argentina has very low or no sulfur content. We sell substantially all the crude oil we produce in Argentina to our Refining and Marketing business segment. Most of the natural gas produced by us is of pipeline quality. All of our gas fields produce commercial quantities of condensate, and substantially all of our oil fields produce associated gas.

The following table sets forth the average production costs and average sales price by geographic area for 2010, 2009 and 2008:

The following table shows the number of wells drilled by us or consortiums in which we had a working interest in Argentina during the periods indicated.

Our project portfolio, updated in May 2010, included more than 1,400 projects to develop proved, probable and possible reserves, in addition to exploration and development resources, all focused mainly on crude oil and the measuring of unconventional resources in the Neuquina basin. The financial viability of these investments and reserves recovery efforts, however, will generally depend on the prevailing economic and regulatory conditions in Argentina, as well as the market prices of hydrocarbon products.

We are fully dedicated to identifying new opportunities in both infill potential and improved sweep efficiency in our mature fields. These efforts are guided by subsurface modeling conducted by in-house multidisciplinary teams. Furthermore a strong emphasis is being placed in surveillance activities to improve water injection utilization. Tertiary recovery is being pursued with polymer injection in the Golfo San Jorge basin.

During the past three years our main exploratory activities in Argentina have had the following principal focuses:

YPF has also a 30% working interest in the block E-3 located in the Colorado basin (where Petrobras Argentina, the operator, holds a 35% working interest, and ENARSA 35%) and a 40% working interest in the Block Área 4 located in the Punta del Este basin (where Petrobras Uruguay, the operator, holds a 40% working interest, and GALP 20%).

Onshore: YPF continued its near-field exploration activity in its concession blocks, explored for deep gas in the Noroeste and Neuquina basins and embarked on six new exploratory fronts in during 2010:

In December 2009, YPF invited the provincial governments to take part in “Plan Exploratorio Argentina.” The objective of such program is to complete a national survey of all potential exploration opportunities, especially in non-traditional basins. At the date of this annual report, twelve provinces have signed agreements with YPF.

During 2010, YPF completed fourteen exploratory wells in Argentina, thirteen of them in the Neuquina basin and one in Noroeste basin. Six out of the fourteen wells were discoveries.

During 2010, in the Loma La Lata Field, facilities we continued the improvement and optimization of our oil and gas production facilities (by interconnecting our primary separation units with the low pressure gas pipe line). With respect to the Sixth Stage low pressure compression project at the Loma La Lata natural gas field, gas production and wellhead pressure were above our initial forecast so new reservoir and facilities simulations were made during this year in order to continue the optimization of compression and surface facilities in 2011. Additionally, we successfully continued with the Sierras Blancas formation infill drilling (in gas development wells), and began the Quintuco formation evaluation with appraisal drilling (with oil development wells), to be continued through 2011.

In the El Medanito oilfield (100% owned by YPF) after an aggressive delineation drilling campaign and a second generation waterflooding pilot during 2010, the drilling activity planned for 2011 includes the beginning of a massive re-development in the whole area, and the continuation of new facilities construction started last year. Moreover a new waterflooding pilot in the southwest region of the field is planned for this year in order to promote, if successful, the incorporation of proved reserves from secondary recovery following the incorporation of primary reserves in 2010. In 2012, we plan to continue with the massive drilling project in south area and some activities to assess the remaining potential in the north.

In 2010, we promoted the Llancanelo development project in the province of Mendoza, with the drilling of two vertical and two horizontal wells. Currently, the project is at a stage of production testing to continue the activity during 2011. This project will require a total investment of U.S.$55 million for the next triennium. We further maintained the development of the Barrancas and Loma de la Mina fields with the drilling of 19 and 11 wells respectively. Additionally, the Integral Development of the Cerro Fortunoso field began with the drilling of 5 wells in the so called North Plunge and 10 additional wells in the main area. Five wells were also drilled at the Vizcacheras field which allowed the expansion of the productive area. With respect to the Cañadón Amarillo project, we drilled 10 wells, (9 of which are horizontal), at the main structural area, as scheduled in the field development plan.

The Manantiales Behr Integral Development project includes the El Alba, La Carolina, Grimbeek and Sur Manantiales projects. Currently, the area has 700 oil production wells and 12 gas production wells. In 2010, we drilled 162 wells across various projects, which represented a total estimated investment of U.S.$180 million for this period. The overall objective of this new project is to achieve the comprehensive development of new areas, to facilitate the construction of new wells, the implementation of new enhanced oil recovery projects and to provide developmental support with the relevant surface facilities. We have identified our greatest development potential at our Grimbeek, El Alba and La Carolina projects, our pilot polymer injection project at Grimbeek II, our surfactant injection project at Sur Manantiales Behr and further potential infill drilling opportunities that we have detected in some areas. The development group is formed of 18 experts and includes geologists, geophysicists, engineers, petrophysicists, technicians and a team leader.

At Santa Cruz in 2010, we implemented 10 integral development projects across 4 development areas (Las Heras, El Guadal, Los Perales and Cañadón Seco), comprising a total portfolio of 82 projects. The principal integral projects include Cerro Grande, Maurek, Seco León and Los Perales. 161 wells have been drilled in connection with these projects, which, inclusive of associated facilities costs, represent a total estimated investment of U.S.$296 million. The main objective of these integral projects is the comprehensive development of such areas through the construction of new wells, implementation of new enhanced oil recovery projects and to provide development support with the appropriate surface facilities. We will maintain these projects through 2011.

In block CNQ7A, operated by Petro Andina Resources Argentina S.A. (PAR) in which we have a 50% working interest, the delineation of the El Corcobo Norte, Jagüel Casa de Piedra, Cerro Huanul Sur and Puesto Pinto Reservoirs was completed in 2009 and development of these reservoirs has begun. In 2009, a water injection pilot project in Cerro Huanul Sur was completed with better results than expected.

During 2010, exploratory wells Lo-x-1 and Lo-x-2 were drilled. Lo-x-2 was tested and is currently under evaluation. Lo-x-1 is currently close to completion.

On September 8, 2010, there was a fire at the platform site AM-2, Magallanes field, operated by Sipetrol and located offshore off the Strait of Magellan. There was no environmental damage or serious injuries. As a consequence of the incident, the field was out of production until December 2010, when conditions returned to normal operation in the damaged platform. Production is expected to be completely normalized through the first half of 2011. The deferred production is 900 m3/d of oil and 2.1 MMm3/d of gas (gross value).

In the Tierra del Fuego area, operated by Apache Corp, where YPF holds a 30% working interest, some brownfield exploration activity was performed. The 3D seismic interpretation supplied

For information regarding our exploration and development activities in the United States, Guyana and Uruguay, see “—Principal properties—International properties”.

The following table shows the number of wells in the process of being drilled as of December 31, 2010.

We are committed to providing fixed and determinable quantities of crude oil and natural gas in the near future under a variety of contractual arrangements.

With respect to crude oil, we sell substantially all of our Argentine production to our Refining and Marketing business segment to satisfy our refining requirements. As of December 31, 2010, we were contractually committed to deliver 74 mbbl of crude oil in the future, generally under short term delivery contracts. According to our estimates as of December 31, 2010, crude oil commitments could be met with our own production.

As of December 31, 2010, we were contractually committed to deliver 47,549 mmcm of natural gas in the future, of which approximately 20,819 mmcm will have to be delivered in the period from 2011 through 2013. According to our estimates as of December 31, 2010, our contractual delivery commitments for the next three years could be met with our own production and, if necessary, with purchases from third parties.

However, since 2004 the Argentine government has established regulations for both the export and internal natural gas markets which have affected Argentine producers’ ability to export natural gas. Consequently, since 2004 we have been forced in many instances to partially or fully suspend natural gas export deliveries that are contemplated by our contracts with export customers. Provisions totaling Ps.411 million, Ps.139 million and Ps.61 million have been recorded in 2010, 2009 and 2008, respectively, in connection with our contractual commitments in the natural gas export market.

Among the regulations adopted by the Argentine government, on June 14, 2007, the Argentine Secretariat of Energy passed Resolution No. 599/07, according to which we were compelled to enter into an agreement with the Argentine government regarding the supply of natural gas to the domestic market during the period 2007 through 2011 (the “Agreement 2007-2011”). It must be noted that YPF has not entered into any contractual commitment to supply natural gas to the domestic market. The purpose of the Agreement 2007-2011 is to guarantee the supply of natural gas to the domestic market at the demand levels registered in 2006, plus the growth in demand by residential and small commercial customers. See “—Regulatory Framework and Relationship with the Argentine Government—Market Regulation” and “Risk Factors—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.” According to our estimates as of December 31, 2010, supply

We have appealed the validity of the aforementioned regulations and have invoked the occurrence of a force majeure event (government action) under our export natural gas purchase and sales agreements, although certain counterparties to such agreements have rejected our position. See “Item 8. Financial Information—Legal Proceedings—Argentina—Accrued, probable contingencies—Alleged defaults under natural gas supply contracts”, “Item 8. Financial Information—Legal Proceedings—Argentina—Non-accrued, possible contingencies—Claims related to the gas market and others” and “Item 8. Financial Information—Legal Proceedings—Argentina—Non-accrued, remote contingencies—Arbitration with AES Uruguaiana Empreendimentos S.A. (AESU), Companhia de Gás do Estado do Río Grande do Sul (Sulgás) and Transportadora de Gas del Mercosur S.A. (TGM).”

The Argentine government has established regulations for both the export and internal natural gas markets which have affected Argentine producers’ ability to export natural gas under their contracts. YPF’S principal supply contracts are briefly described below.

We are currently committed to supply a daily quantity of 125 mmcf/d to the Methanex plant in Cabo Negro, Punta Arenas, in Chile (under four agreements which expire between 2017 and 2025). Pursuant to instructions from the Argentine government, deliveries were interrupted from 2007.

We have a 17-year contract (entered into in 1999 and subsequently modified) to supply 53 mmcf/d of natural gas to the Termoandes power plant located in Salta, Argentina. The natural gas comes from the Noroeste basin. This power plant provides power to a high voltage line running from Salta to Región II in Chile. We have recently renegotiated the terms of the contract, including the possibility of terminating it in 2013.

We currently have several supply contracts with Chilean electricity producers (through the Gas Andes pipeline linking Mendoza, Argentina to Santiago, Chile, which has a transportation capacity of 353 mmcf/d (designed capacity with compression plants)); including:

We also have a 21-year contract (entered into in 1999) to deliver 93 mmcf/d of natural gas to a Chilean distribution company (Innergy) that distributes natural gas to residential and industrial clients through a natural gas pipeline (with a capacity of 318 mmcf/d) connecting Loma La Lata (Neuquén, Argentina) with Chile.

Finally, in Chile we also have natural gas supply contracts with certain thermal power plants in northern Chile (Edelnor, Electroandina, Nopel and Endesa) utilizing two natural gas pipelines (with a carrying capacity of 300 mmcf/d each) connecting Salta, Argentina, to Northern Chile (Región II). The contracts with Edelnor and Electroandina have been recently modified, becoming interruptible supply contracts.

In Brazil, we had entered into a 20-year supply contract (signed in 2000) to provide 99 mmcf/d of natural gas to the thermal power plant of AES Uruguaiana Empreendimentos S.A. (AESU) through a pipeline linking Aldea Brasilera, Argentina, to Uruguayana, Brazil (with a capacity of 560 mmcf/d). See “Item 8. Financial Information—Legal Proceedings—Argentina—Accrued, probable

Because of certain restrictions imposed by the Argentine government (see “—The Argentine natural gas market,” below), we could not meet our export commitments and were forced to declare force majeure under our natural gas export sales agreements, although certain counterparties have rejected our position (see “Item 8. Financial Information—Legal Proceedings”). As a result of actions taken by the Argentine authorities, through measures described in greater detail under “Item 4. Information on the Company-Regulatory Framework and Relationship with the Argentine Government—Market Regulation—Natural gas”, we have been forced to reduce the export volumes authorized to be provided under the relevant agreements and permits as shown in the chart below:

We estimate (based on preliminary reports of amounts delivered by transport companies) that natural gas consumption in Argentina totaled approximately 1,555 bcf in 2010. We estimate that the number of users connected to distribution systems throughout Argentina amounted to approximately 7.6 million as of December 31, 2010. The domestic natural gas market has grown significantly over recent years, driven by the forces of economic growth and domestic price constraints; we believe that the natural gas market will continue to grow, though not at the same rate as it has recently done.

In 2010, we sold approximately 36% of our natural gas to local residential distribution companies, 10% to NGV (Natural Gas Vehicle), approximately 52% to industrial users (including Mega and Profertil) and power plants, and approximately 2% in exports to foreign markets (principally Chile). Sales are affected by increased consumption by residential consumers during winter months (June-August). During 2010, approximately 80% of our natural gas sales were produced in the Neuquina basin. In 2010, our domestic natural gas sales volumes were 10% less than those in 2009, primarily as a result of the decrease in our purchases from Bolivia (in particular, during those months of 2010 in which a new purchase contract was been negotiated with resulted in a decrease of our sales of natural gas purchased from Bolivia).

The Argentine government has taken a number of steps aimed at satisfying domestic natural gas demand, including pricing regulations, export controls and higher export taxes and domestic market injection requirements. These restrictions were imposed on all Argentine exporting producers, affecting natural gas exports from every producing basin. See “—Delivery commitments—Natural gas supply contracts”. Exporting producers, such as us, have no choice but to comply with the Argentine government’s directions to curtail exports in order to supply gas to the domestic market, whether such directions are issued pursuant to resolutions or otherwise. The above-mentioned Resolutions provide penalties for non-compliance. Rule SSC No. 27/2004 issued by the Undersecretary of Fuels (“Rule 27”), for example, punishes the violation of any order issued thereunder by suspending or revoking the production concession. Resolutions No. 659 and No. 752 also provide that producers not complying with injection orders will have their concessions and export permits suspended or

The Argentine government began suspending natural gas export permits pursuant to Rule 27 in April 2004, and in June 2004 the Argentine government began issuing injection orders to us under Resolution No. 659. Thereafter, the volumes of natural gas required to be provided to the domestic market under the different mechanisms described above have continued to increase substantially. The regulations pursuant to which the Argentine government has restricted natural gas export volumes in most cases do not have an express expiration date. Likewise, we have not received any documentation indicating that the Argentine government will suspend or withdraw these actions. Accordingly, we are unable to predict how long these measures will be in place, or whether such measures or any further measures adopted will affect additional volumes of natural gas.

See “—Regulatory Framework and Relationship with the Argentine Government” for additional information on these and other related regulations.

Most of our proved natural gas reserves in Argentina are situated in the Neuquina basin (approximately 72% as of December 31, 2010), which is strategically located in relation to the principal market of Buenos Aires and is supported by sufficient pipeline capacity during most of the year. Accordingly, we believe that natural gas from this region has a competitive advantage compared to natural gas from other regions. The capacity of the natural gas pipelines in Argentina has proven in the past to be inadequate at times to meet peak-day winter demand, and there is no meaningful storage capacity in Argentina. Since privatization, local pipeline companies have added capacity, improving their ability to satisfy peak-day winter demand but no assurances can be given that this additional capacity will be sufficient to meet demand.

In order to bridge the gap between supply and demand, especially with respect to peak-day winter demand, the Argentine government has entered into gas import agreements. The Framework Agreement between the Bolivian and the Argentine governments (executed on June 29, 2006) provides for natural gas imports from Bolivia to Argentina to be managed by ENARSA. In May 2010, we accepted the offer made by ENARSA for the sale to us of a minimum amount of 2.5 mmcm/d of natural gas obtained by ENARSA from the Republic of Bolivia through May 1, 2011.

YPF provides regasification services to ENARSA. YPF has executed a Charter Party Agreement to provide and operate a regasification vessel, which is moored at the Bahía Blanca Port facilities. Using the vessel for the conversion of liquefied natural gas (LNG) into its gaseous state (which allows for the supply of up to 8 additional mmcm/d of natural gas), a volume of approximately 1,801 mmcm of natural gas has been injected into the pipeline linking to the national network, most of which was supplied during the peak demand period, i.e., winter. The contractual regasification period was extended, since 2009, to the rest of the year at the request of ENARSA. In accordance with the Extension Agreement, the 2010 regasification season began on May 1 and ended on October 30. During October, the contract that YPF signed with Excelerate Energy SRL, Excelerate Energy LP and ENARSA was extended, with the objective of continuing to give services of regasification from November 1, 2010 until April 30, 2011. The current success of the Bahía Blanca project in addition to the continued growth of the domestic demand encourages YPF and ENARSA to further analyze new alternatives to consolidate the position of LNG in the Argentina energy matrix. Both companies have agreed to constitute a joint venture (in which each company will hold a 50% working interest) to operate in Paraná de las Palmas river, near Escobar, in the Province of Buenos Aires, a new regasification project similar to the one operating in Bahía Blanca. Start up is expected by May 2011.

Decree No. 180/2004 created two trust funds to help finance an expansion of the North Pipeline operated by Transportadora Gas del Norte S.A. (TGN), whose capacity increased by 1.8 mmcm/d (63.6 mmcf/d) in 2005, and an expansion of the San Martín Pipeline operated by Transportadora Gas del Sur S.A. (TGS), whose capacity increased by 2.9 mmcm/d (102.4 mmcf/d) in 2005. Both expansions are currently operating. In 2008, there was an additional expansion of approximately 67 mmcf/d in the pipelines operated by TGS, and additional works were completed in 2009.

Natural gas is delivered by us through our own gathering systems to the trunk lines from each of the major basins. The capacity of the natural gas transportation pipelines in Argentina is mainly used by distribution companies. A major portion of the available capacity of the transportation pipelines is booked by firm customers, mainly during the winter, leaving capacity available for interruptible customers to varying extents throughout the rest of the year.

We have utilized natural underground structures located close to consuming markets as underground natural gas storage facilities, with the objective of storing natural gas during periods of low demand and selling the natural gas stored during periods of high demand. Our principal gas storage facility, “Diadema,” is located in the Patagonia region, near Comodoro Rivadavia City. The injection of natural gas into the reservoir started in January 2001.

We participated in the development of Mega to increase its ability to separate liquid petroleum products from natural gas. Mega allowed YPF, through the fractionation of gas liquids, to increase production at the Loma La Lata gas field by approximately 5.0 mmcm/d in 2001.

We own 38% of Mega, while Petrobras and Dow Chemical have stakes of 34% and 28%, respectively.

Mega operates:

Mega commenced operations at the beginning of 2001. Mega’s maximum annual production capacity is 1.35 million tons of natural gasoline, LPG and ethane. YPF is Mega’s main supplier of natural gas. The production of the fractionation plant is used mainly in the petrochemical operations of Petroquímica Bahía Blanca (“PBB”) and is also exported by tanker to Petrobras’ facilities in Brazil.

We participate in three power stations with an aggregate installed capacity of 1,622 megawatts (“MW”):

In 2010, these plants collectively generated approximately 8,960 GWh in the aggregate.

Additionally, we own assets that are part of Filo Morado, which has an installed capacity of 63 MW. However the relevant facilities have not been in operation since November 2008.

We also own and operate power plants supplied with natural gas produced by us, which produce power for use by us in other business units:

We currently hold through our subsidiary YPF Inversora Energética S.A. (“YPF Inversora Energética”) a 45.33% stake in Gas Argentino S.A. (“GASA”), which in turn holds a 70% stake in Metrogas S.A. (“Metrogas”), which is a natural gas distributor in southern Buenos Aires and one of the main distributors in Argentina. During 2010, Metrogas distributed approximately 19.6 mmcm of natural gas per day to 2 million customers in comparison with approximately 20.5 mmcm of natural gas per day distributed to 2 million customers in 2009.

GASA’s debt issues. The economic crisis that affected the country at the end of 2001 and beginning of 2002 caused a severe deterioration of the financial and operational situation of GASA. Thus the decision was made on March 25, 2002 to suspend payment of principal and interest on its entire financial debt. From then on, Metrogas’ management has focused on an efficient and rational use of its cash flow in order to be able to comply with all of the legal requirements agreed with the Argentine government with respect to its services. After negotiating a restructuring of the outstanding debt with its creditors, GASA reached and executed on December 7, 2005 an agreement (the Master Restructuring Agreement, or “MRA”) with its creditors, by which they would exchange debt for equity in GASA and/or Metrogas. The MRA was presented to the Argentine National Antitrust Protection Board (Comisión Nacional de Defensa de la Competencia or “CNDC”) and ENARGAS, and was subject to their approval as a condition precedent to the closing of the MRA. The MRA included a creditors’ option to terminate the agreement if the closing of the debt restructuring had not occurred by December 7, 2006. The MRA obtained ENARGAS’ approval but the CNDC’s approval was pending. On May 15, 2008, certain holders of the bonds communicated to YPF Inversora Energética that they were terminating the MRA. After the termination of the MRA, three different entities claiming to be holders of GASA bonds commenced four different judicial proceedings against GASA aiming to collect a total of U.S.$46 million, including interest and fees, and one of them, Coolbrand LLC, started a separate proceeding (“Coolbrand c/Gasa s/acción subrogatoria”). On May 11, 2009, GASA was notified of a bankruptcy petition brought by Continental Energy Investment LLC, and on May 19, 2009, GASA filed a voluntary reorganization petition (“concurso preventivo”), which was approved on June 8, 2009. The period to verify credits ended on October 7, 2009. On February 10, 2010, the judge declared all the credits verified but for one presented by one of GASA’s advisors. GASA now has an exclusivity period to negotiate with the verified creditors. On March 12, 2010, GASA filed motions for review (“incidentes de revisión”) of credits verified by Coolbrand LLC, Amanda Venture, Latam Energy and Continental Energy. The filing of these motions does not suspend the voluntary reorganization petition.

On August 9, 2010 the judge decided, taking into consideration Metrogas S.A.’s voluntary reorganization petition, to modify and extend the date to present GASA’s proposal to the creditors to March 9, 2012. The Court of Appeals has confirmed such decision.

Metrogas’ debt issues. In 2006, Metrogas reached an agreement with its main creditors in order to restructure its financial debt and align its future financial commitments to the expected generation of funds. The main objective of the restructuring process was to modify certain terms and conditions included in its outstanding loans and negotiable agreements by adjusting interest rates and the amortization period so as to align them with the expected cash flow required for repayment of the indebtedness. Accordingly, on April 20, 2006, Metrogas entered into an out-of-court preventive agreement with creditors representing approximately 95% of its unsecured indebtedness, which became effective in May 2006. In October 2008, Metrogas executed an interim agreement (Acuerdo Transitorio) with the Unit for the Renegotiation and Analysis of Public Service Contracts (Unidad de Renegociación y Análisis de Contratos de Servicios Públicos, or “UNIREN”), including a limited tariff increase that is intended to fund certain projects that Metrogas is required to undertake. The government approved this agreement and it has been published in the Official Gazette on April 14, 2009 but it has not been implemented since the new tariff chart has not yet been issued. The negotiation of the general tariff of Metrogas (Acta Acuerdo de Renegociación Contractual Integral) with the UNIREN remains pending.

Metrogas’ financial condition continued to deteriorate in 2009. On June 17, 2010, the board of directors of Metrogas, following the advice of Metrogas’ external legal advisors and considering Metrogas’ inability to fulfill certain payment obligations, decided that Metrogas should file a voluntary reorganization petition (“concurso preventivo”), which was filed on such date.

On the same date, Metrogas was notified of the Resolution No. I-1260 dictated by ENARGAS, which determined the judicial intervention of the company for a 120 days term. Antonio Gómez was named Interventor of Metrogas. The resolution justifies the intervention decision on the filling of a voluntary reorganization petition by Metrogas, and states that the intervention shall control administration and disposition acts of Metrogas which can in any manner affect the regular gas distribution. Moreover, it orders the execution of due diligence and the determination of the value of all Metrogas assets. Metrogas appealed such resolution and asked for a preliminary order to cease the effects of the intervention. The request for a preliminary order was rejected on September 8, 2010.

On July 15, 2010, the judge approved the commencement of Metrogas’s voluntary reorganization proceedings. The period to provide evidence on claimed credits ended on November 10, 2010 and Metrogas may recognize categories of creditors through April 20, 2011. The judge also established March 9, 2012 as the date to formally present Metrogas’s proposal to creditors.

The period to verify credits as well as the period to file any responses has ended, and the official receiver has presented its report regarding the admission of the verified credits. The judge shall make a decision regarding the acceptance or rejection of the creditors suggested by the official receiver in his report in April 2011.

On October 18, 2010, Metrogas was notified of the Resolution No. I-1431 dictated by ENARGAS, which extended the judicial intervention of the company for 120 additional days and ratified Mr. Antonio Gómez as its interventor (“interventor”). Moreover, on February 14, 2011, Resolution No. 1612 of ENARGAS extended the intervention for 120 additional days.

As of both December 31, 2010 and December 31, 2009, YPF had an allowance for the total value of its investment in YPF Inversora Energética.

During 2010, our Refining and Marketing activities included crude oil refining and transportation, and 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 certain export markets.

The Refining and Marketing segment is organized into the following divisions:

We market a wide range of refined petroleum products throughout Argentina through an extensive network of sales personnel, YPF-owned and independent distributors, and a broad retail distribution system. In addition, we export refined products, mainly from the port at La Plata. The refined petroleum products marketed by us include gasoline, diesel, jet fuel, kerosene, heavy fuel oil and other crude oil products, such as motor oils, industrial lubricants, LPG and asphalts.

We wholly own and operate three refineries in Argentina:

Our three wholly-owned refineries have an aggregate refining capacity of approximately 319,500 barrels per calendar day. The refineries are strategically located along our crude oil pipeline and product pipeline distribution systems. In 2010, our crude oil production, substantially all of which was destined to our refineries, represented approximately 81% of the total crude oil processed by our refineries. Through our stake in Refinor, we also own a 50% interest in a 26,100 barrel-per-calendar-day refinery located in the province of Salta, known as Campo Durán.

The following table sets forth the throughputs and production yields for our three wholly-owned refineries for each of the three years ended December 31, 2010, 2009 and 2008:

During 2010, overall volumes of crude oil/feedstock processed decreased by 1.8% compared with 2009 (our refinery capacity utilization was 93.2%, compared to 94.9% in 2009) due mainly to overhauls at our refineries, as well as the lower availability in the market of some specific crude oil (Medanito) used by our refineries as well as for lubricants production in our La Plata refinery. Additionally, union conflicts with fishing workers affected the operations of Puerto Rosales, resulting in limited crude oil availability from the Golfo San Jorge basin. In 2009, overall volumes of crude oil/feedstock processed decreased by 5.5% compared with 2008 due mainly to scheduled maintenance overhauls at our La Plata refinery, as well as our production optimization efforts in response to market conditions and the decrease in sales volumes in foreign markets (which decreased 37% compared with 2008).

The La Plata refinery is the largest refinery in Argentina, with a nominal capacity of 189,000 barrels of crude oil per calendar day. The refinery includes three distillation units, two vacuum distillation units, two catalytic cracking units, two coking units, a coker naphtha hydrotreater unit, a platforming unit, a gasoline hydrotreater, a diesel fuel hydrofinishing unit, an isomerization unit, an FCC (fluid cracking catalysts) naphtha splitter and desulfuration unit, and a lubricants complex. The refinery is located at the port in the city of La Plata, in the province of Buenos Aires, approximately 60 kilometers from the City of Buenos Aires. During 2010, the refinery processed approximately 175 thousand barrels of crude oil per calendar day. The capacity utilization rate at the La Plata refinery for 2010 was 92.7%. As mentioned above, capacity utilization was affected by maintenance overhauls, lack of Medanito oil and union conflicts with fishing workers affecting availability of crude oil from the Golfo San Jorge basin. In 2009, the refinery processed approximately 172 thousand barrels of crude oil per calendar day. The capacity utilization rate at the La Plata refinery for 2009 was 91.2%. The crude oil processed at the La Plata refinery comes mainly from our own production in the Neuquina and Golfo San Jorge basins. Crude oil supplies for the La Plata refinery are transported

In October 2009, we commenced developing a detailed engineering project for a new Gasoil Hydrotreater Unit (HTG “B”), seeking to comply with Resolution 478/09, which requires companies to produce diesel fuel with a maximum level of sulfur of 500 parts per million, to be sold in large cities. The construction of the reactor and columns has commenced, and the compressor, feed pumps, vacuum system, ejectors, and additional equipment have been bought. The civil work in the refinery began in September 2010. Start up is expected by the first half of 2012.

The construction of a new coker unit in La Plata Refinery has been approved to increase the coking capacity by 30% and to replace an old unit. This will allow higher utilization rates of refinery. The development of detailed engineering began in June 2010. Start up is expected by 2014.

The Luján de Cuyo refinery has a nominal capacity of 105,500 barrels per calendar day, the third largest capacity among Argentine refineries. The refinery includes two distillation units, a vacuum distillation unit, two coking units, one catalytic cracking unit, a platforming unit, a Methyl TerButil Eter (“MTBE”) unit, an isomerization unit, an alkylation unit, a naphtha splitter, and hydrocracking and hydrotreating units. During 2010, the refinery processed approximately 101 thousand barrels of crude oil per calendar day. During 2010 the capacity utilization rate was 6.3% lower than in 2009, reaching a rate of 95.6%. The maintenance overhaul performed at the FCC caused a reduction in the processing of crude for more than 30 days. The utilization rate was also affected by the lack of Medanito crude oil mentioned above. In 2009, the refinery processed approximately 107 thousand barrels of crude oil per calendar day. Because of its location in the western province of Mendoza and its proximity to significant distribution terminals owned by us, the Luján de Cuyo refinery has become the primary facility responsible for providing the central provinces of Argentina with petroleum products for domestic consumption. The Luján de Cuyo refinery receives crude supplies from the Neuquina and Cuyana basins by pipeline directly into the facility. Approximately 87.0% of the crude oil processed at the Luján de Cuyo refinery in 2010 (and 83.1% of the crude oil processed in this refinery in 2009) was produced by us. Most of the crude oil purchased from third parties comes from oil fields in Neuquén or in Mendoza.

In November 2010, we started up a new furnace in Topping III (in the Luján de Cuyo refinery) replacing the three furnaces previously in operation. Provided other upgrades are made in certain installations, this will allow us to increase the nominal capacity of the unit by 2,500 barrels per calendar day. In order to comply with government regulations on sulfur specifications for fuels, which will become effective in the middle of 2012, the Luján de Cuyo refinery is developing two projects: a naphtha Hydrotreater Unit (HTN II) and a gasoil Hydrotreater Unit (HDS III). The developing basic engineering stage with respect to the first project has been completed, while the second consists in buying a used unit located in the Philippines.

The Plaza Huincul refinery, located near the town of Plaza Huincul in the province of Neuquén, has an installed capacity of 25,000 barrels per calendar day. During 2010, the refinery processed approximately 22 thousand barrels of crude oil per calendar day. In this period, the capacity utilization rate was 7.1% lower than in 2009, reaching a rate of 86.5%. This decrease was mainly due to the maintenance overhaul of the distillation unit in January 2010. In 2009, the refinery processed approximately 23 thousand barrels of crude oil per calendar day. The only products currently produced commercially at the refinery are gasoline, diesel fuel and jet fuel, which are sold primarily in nearby areas and in the southern regions of Argentina. Heavier products, to the extent production exceeds local demand, are blended with crude oil and transported by pipeline from the refinery to La Plata refinery for further processing. The Plaza Huincul refinery receives its crude supplies from the Neuquina basin by pipeline. Crude oil processed at the Plaza Huincul refinery is mostly produced by us. In 2010, 23.7% of the refinery’s crude supplies were purchased from third parties, while in 2009, such purchases reached 26.4% of the refinery’s crude supplies.

At the end of 2009, we completed the construction of tanks and facilities for the reception and blending of biodiesel in order to facilitate compliance in the future with new specifications for diesel fuel as established pursuant to Law 26,093. See “—Domestic Marketing Division.” At the end of March 2010, the facility started to blend biodiesel in gasoil at 5% by volume.

During 1997 and 1998, each of our refineries were certified under ISO (International Organization for Standardization) 9001 (quality performance) and ISO 14001 (environmental performance). The Luján de Cuyo and Plaza Huincul refineries were also certified under OHSAS 18001 (security performance) in 1999 and 2009, respectively. Between 2007 and 2010, our refineries were recertified under ISO 9001:2000, ISO 14001:2004 and OHSAS 18001:2007.

We have available for our use a network of five major pipelines, two of which are wholly-owned by us. The crude oil transportation network includes nearly 2,700 kilometers of crude oil pipelines with approximately 640,000 barrels of aggregate daily transportation capacity of refined products. We have total crude oil tankage of approximately 7 mmbbl and maintain terminal facilities at five Argentine ports.

Information with respect to YPF’s interests in its network of crude oil pipelines is set forth in the table below: