Securities and Exchange Commission Letter

Thank you for your letter dated September 28, 2010 setting forth comments of the staff of the Division of Corporation Finance (the “Staff”) of the United States Securities and Exchange Commission (the “SEC” or “Commission”) on the annual report on Form 20-F for the year ended December 31, 2009 (the “2009 20-F”) of YPF Sociedad Anónima (“YPF”, also referred to in this letter as the “Company” and “we”).

To facilitate the Staff’s review, we have reproduced the captions and numbered comments from the Staff’s September 28, 2010 comment letter in bold text in our responses set forth in Annex I.

In providing these responses, and in response to the Staff’s request, we hereby acknowledge that:

We would like to express our appreciation for your time and cooperation in these matters, and we are available to discuss any of our responses with you at your convenience. In that connection, please do not hesitate to contact the undersigned in Buenos Aires at 54-11-5441-5531 or fax: 54-11-5441-2113; Diego De Vivo and Fernando Ros Redondo of Deloitte, our external auditors, at 54-11-4320-2700 (ext. 2221) and 34-915-14-50-00 (ext. 2631), or our counsel, Nicholas A. Kronfeld of Davis Polk & Wardwell LLP, at 212-450-4950 or fax: 212-450-3950.

Very truly yours,

/s/ Guillermo Reda

Guillermo Reda

Chief Financial Officer

The oil and gas industry is subject to particular economic and operation risks, page 11

Such disclosure should be set forth in the “Information on the Company” section of your annual report and in the “Risk Factors” section, as applicable. Please provide a sample of your proposed disclosure for our review. In responding to this comment, please consider all your products and services, not just those involved in offshore operations.

We confirm to the Staff that in future filings, starting with our annual report for the year ending December 31, 2010, we will include the disclosure to the effect of the below, revised and updated as necessary, in the “Risk Factors” and “Information on the Company” sections of our annual report, as applicable. We may, however, adjust the disclosure proposed below to conform to industry practice (as reflected by the disclosure of other companies in the industry in their annual reports), keeping in mind our obligations to disclose all material information with respect to such matters:

We may not have sufficient insurance to cover all the operating hazards that we are subject to

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 scope and coverage of the insurance policies and indemnification obligations discussed below are subject to change, and such policies are subject to cancellation in certain circumstances. In addition, the indemnification provisions of certain of our drilling, maintenance and other services contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations. We may also be subject to potential liabilities for which we are not insured or in excess of our insurance coverage, including liabilities discussed in “Item 3. Risk Factors—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.”

We insure our operations against risks inherent in the oil and gas industry, including loss of or damage to property and our equipment, control-of-well incidents, loss of production or profits incidents, removal of debris, sudden and accidental pollution, damage and clean up and third-party claims, including personal injury and loss of life, among other business risks. Our insurance policies are typically renewable annually and generally contain policy limits, exclusions and deductibles.

Our insurance policy covering our Argentine operations provides third party liability coverage up to U.S.$400 million per incident, with varying deductibles of between U.S.$0.1 million and U.S.$1 million, in each case depending on the type of incident. Certain types of incidents, such as intentional pollution and gradual and progressive pollution, are excluded from the policy’s coverage. The policy’s coverage extends to control-of-well incidents, defined as an unintended flow of drilling fluid, oil, gas or water from the well that cannot be contained by equipment on site, by increasing the weight of drilling fluid or by diverting the fluids safely into production. Our policy provides coverage for third-party liability claims relating to pollution from a control-of-well event ranging from U.S.$75 million for certain onshore losses and a maximum combined single limit of U.S.$250 million for offshore losses.

Our insurance policy also covers physical loss or damage in respect of but not limited to onshore and offshore property of any kind and description (whether upstream or downstream), up to U.S.$1,000 million per incident, with varying deductibles of between U.S.$1 million and U.S.$6.75 million, including loss of production or profits with deductibles of 60 days for downstream operations and 60 with a minimum deductible of U.S.$20 million for upstream operations.

Argentine regulations require us to purchase from specialized insurance companies (Aseguradoras de Riesgos de Trabajo – ART) insurance covering the risk of personal injury and loss of life of our employees. Our insurance policies cover medical expenses, lost wages and loss of life, in the amounts set forth in the applicable regulations. These regulatory requirements also apply to all of our contractors.

We have adopted a position in agreements entered into with contractors that provide drilling services, well services or other services to our exploration and production operations (“E&P Services Agreements”), whereby contractors are generally responsible for indemnifying us to varying degrees for certain damages caused by their personnel and property above the drilling surface. Similarly, we are generally responsible under our drilling contracts to indemnify our contractors for any damages caused by our personnel and property above the drilling surface.

We typically assume responsibility for indemnifying our contractors for any loss or liability resulting from damages caused below the surface provided that such damages below the surface have not been caused by the negligence of the contractor in which case the contractor shall be liable up to a limited amount agreed by the parties in the E&P Services Agreements.

E&P Services Agreements usually establish that contractors are responsible for pollution or contamination including clean-up costs and third party damages caused above the surface by the spill of substances under their control, provided that the damage has been caused by the negligence or willful misconduct of the contractor. In the event of pollution or contamination produced below the surface, contractors shall also typically be liable for damages caused due to the contractor’s negligence or willful misconduct. However, in this last case the damages are also usually limited to an amount agreed upon by the parties in the E&P Services Agreement.

We are also partners in several joint ventures and projects that are not operated by us. Contractual provisions, as well as our obligations arising from each agreement, can vary. In certain cases, insurance coverage is provided by the insurance policy entered into by the operator, while in others, our risks are covered by our insurance policy covering our Argentine operations. In addition, in certain cases we may contract insurance covering specific incidents or damages which are not provided for in the operator’s insurance policy. We also retain the risk for liability not indemnified by the field or rig operator in excess of our insurance coverage.

With respect to downstream servicing contracts, contractors are usually responsible for damages to their own personnel and caused by them to third parties and they typically indemnify us for damages to equipment. A mutual hold-harmless provision for indirect damages such as those resulting from loss of use or loss of profits is normally included.

Our operations in the Gulf of Mexico currently include only our 15% working interest, through our subsidiary Maxus U.S. Exploration Company, in the Neptune field, which is operated by BHP Billiton. Our Gulf of Mexico operations are insured under a policy similar to that described above for our Argentine properties, with certain differences that are addressed below.

Our Gulf of Mexico operations insurance policy provides coverage of up to U.S.$250 million, depending on the type of incident, and is subject to varying deductibles. This policy covers property damage, loss of production and third party liability, subject to certain customary exclusions. The policy covers certain control-of-well incidents and also covers first and third party clean-up and defense costs, care, custody and control incidents, and windstorm incidents. The policy also contains certain exclusions, including in connection with control-of-well incidents.

Our Gulf of Mexico operations insurance policy covers, up to a limit of U.S.$10 million, third party liability arising from personal injury and loss of life and extends to our employees, contractors and unaffiliated third party individuals. Our insurance policy also covers physical damage to or loss of property, subject to deductibles ranging between U.S.$750 thousand and U.S.$1.25 million, depending on the type of property involved, and loss of production with a deductible of 60 days of production (90 days in the case of windstorms).

Certain contractors are responsible for indemnifying the consortium for damages caused by their personnel and property, while the consortium/operator is responsible for indemnifying such contractors for damages caused by its personnel and property. The operator/consortium is also responsible for indemnifying contractors for certain losses and liabilities resulting from pollution or contamination.

During 2008 and 2009, we operated the Aurora offshore field, a shallow water project consisting of four exploratory wells located in the Golfo San Jorge in Argentinean waters, but these projects have now been definitively terminated. We also have a working interest in block E2, located in the Austral basin, in Argentinean waters, and which is operated by ENAP Sipetrol. All drilling projects that we operate or in which we have working interests have in place an Emergency Response Plan (“ERP”), including response plans for oil spills. The offshore fields operated by us as well as those in which we have a working interest have in place a Health, Safety, Environmental and Community (“HSEC”) management plan to control all risks associated with the project.

The HSEC management plans in place at facilities operated by us include ERPs for an oil spill or leak, and these ERPs are regularly assessed for adequacy in light of available information and technical developments. We review our HSEC management plans for our drilling projects on a regular basis to ensure that appropriate measures are in place for every phase of the project. We are currently in the planning stage for a deep water project named Malvinas, located in blocks CAA40/CAA46 and situated in Argentinean waters. Our HSEC management plan for this project includes an ERP for an oil spill. The overall clean up and recovery would be managed by an Argentine company contracted by us and authorized by the relevant government authority in the event of a Level I spill (a small spill close to the offshore operation that generally requires only on site resources) or Level II spill (a larger spill that generally requires resources and assistance from other oil industry operators), and would be supported by the companies which are parties to the “Inter-company agreement,” which was entered into by several oil companies and pursuant to which they have committed to cooperate in case of oil spills or environmental damage in Argentinean waters. We will supply every vessel involved in this project with sufficient weather-appropriate equipment to control a Level I or Level II spill, including oceanic containment boom, skimmers, temporal and storage tanks, transfer pumps, polypropylene absorbent booms and dispersants, among other equipment. In case of a Level III spill (a very large spill with serious consequences that generally requires substantial additional resources and assistance), we have contracted a leading international oil services company to provide the relevant equipment and experienced personnel in a timely manner, and to manage the overall response.

With respect to the Neptune field, under the Joint Operating Agreement, the operator of the field is required to maintain an HSEC management plan based on health and safety rules agreed upon between the operator and the non-operators. As a non-operator, we are entitled to review the operator’s safety and environmental management systems for compliance with the HSEC management plan, but we do not have direct control over the measures taken by the field operator to remedy any particular spill or leak. The operator of the field is required to notify all non-operators, including us, in writing of any spill greater than 50 barrels, among other incidents. The HSEC management plan in respect of the Neptune field is administered by a leading oil field services contractor contracted by the operator and includes a plan of action in the event of a spill or leak.

Our production activities in the Gulf of Mexico are not material to our strategic plans, business or results of operations. The Neptune field, in which we have a 15% working interest, is our only producing asset in the Gulf of Mexico. Our share of production from the Neptune field accounted for 0.48% of our net revenues in 2009, while our working interest in the field represented 1.12% of our total consolidated assets as of December 31, 2009.

The moratorium on Gulf of Mexico activities did not impact existing production levels in the Neptune field. Additionally, the impact of the drilling moratorium on our exploration activities and strategic plans has been minimal because we do not currently have interests in any drilling activities in the Gulf of Mexico outside of the Neptune field and no exploration wells were planned in our 2010 budget.

We confirm to the Staff that if our activities in the Gulf of Mexico become material to our strategic plans, business or results of operations in the future, we will supplement our disclosure as necessary in future filings.

We take note of the Staff’s comment. We confirm that we do not have off-balance sheet arrangements other than those described in “—Liquidity and Capital Resources—Guarantees provided”, and that such off-balance sheet arrangements have not had and are not reasonably likely to have a material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources, as contemplated in Item 5.E of Form 20-F and Item 303(a)(4) of Regulation S-K. Further, we have certain additional commitments relating to product purchases and investments in connection with our exploration activities that, under Argentine generally accepted accounting principles, are not included in our financial statements. These product purchase obligations and investment commitments are set forth in our table of contractual obligations and the footnotes to that table under the caption “—Liquidity and Capital Resources—Contractual obligations”.

We confirm to the Staff that in future filings we will, to the extent accurate, provide disclosure to the effect of the following in “Item 5—Operating and Financial Review and Prospects—Off-Balance Sheet Arrangements”:

“We do not have any material off-balance sheet arrangements. Our only off-balance sheet arrangements are those described in “—Liquidity and Capital Resources—Guarantees.””

“GCA reserves the right to approve, in advance, the use and context of the use of any results, statement or opinion expressed in this report. Such approval shall include, but not be confined to, statement or references in documents of a public or semi-public nature such as loan agreements, prospectuses, reserves statements, press releases etc. This report has been prepared for RY and should not be used for purposes other than those for which it is intended”.

Please obtain and file a revised reserves statement which retains no language that could suggest either a limited audience or a limit on potential investor reliance.

We acknowledge the Staff’s comment and have raised this matter with GCA, who have agreed that, in connection with our future filings, they will remove the language that suggests a limited audience or a limit on potential investor reliance and will instead use the following language in respect of the third party use of their report:

“This report has been prepared at the request of RY regarding assets held by YPF in Argentina and is for inclusion in RY’s and YPF’s respective filings with the U.S. Securities and Exchange Commission.”

We acknowledge the Staff’s comment and confirm to the Staff that in future filings we will revise the risk factor in question to read substantially as follows:

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, leading to increased depreciation, depletion and amortization charges and/or impairment charges, which would reduce earnings and shareholders’ equity.

We take note of the Staff’s comment. In addition, we confirm that we have no material undeveloped acreage corresponding to production concessions or exploration permits expiring in the near term.

“[b] Disclose, as of a reasonably current date or as of the end of the fiscal year, the amount of undeveloped acreage, both leases and concessions, if any, expressed in both gross and net acres by geographic area, together with an indication of acreage concentrations, and, if material, the minimum remaining terms of leases and concessions.”

None of our material production concessions, individually or in the aggregate, expire prior to 2017, as disclosed on page 12 of our 2009 20-F, under the caption “—Risk Factors—Argentine oil and gas production concessions and exploration permits are subject to certain conditions and may not be renewed” (“…The expiration of part of our and other Argentine oil companies’ concessions occurs in 2017… Concessions representing approximately 50% of our proved reserves as of December 31, 2009 have been extended prior to the date of this annual report…”).

A substantial majority of our exploration permits are currently under their first basic exploration term, and are regulated by the regime explained in “Item 4. Information on the Company—Regulatory Framework and Relationship with the Argentine Government—Exploration and Production,” starting on page 58 of our 2009 20-F.

In the near term (2010-2012), a total of 207 thousand gross undeveloped acres (158 thousand net undeveloped acres) are scheduled for expiration. This includes scheduled expirations of exploration permits which are under their last extension term, and therefore not subject to renewal, amounting to approximately 99 thousand gross undeveloped acres (50 thousand net undeveloped acres).

We confirm to the Staff that in future filings we will disclose, if material, undeveloped acreage in respect of our production concessions and exploration permits expiring in the near term or, to the extent accurate, specifically disclose that we do not have any material undeveloped acreage related to our leases or concessions expiring in the near term.

We advise the Staff that the 2009 third party reserves audit covered approximately 39 mmboe of our proved undeveloped reserves, which represent 17.34% of our aggregate proved undeveloped reserves as of September 30, 2009 (the effective date of the third party audit report). We confirm to the Staff that we will include this information in our future filings.

The qualifications of YPF’s Reserves Control Director and the Quality Reserves Coordinator are set forth on pages 30 and 31 of the 2009 Form 20-F, under the caption “—Internal controls in reserves and reserves audits.” The qualifications of the person overseeing the reserves audits performed by third party engineers are included in the report set forth in Appendix I of Exhibit 99.1 to our 2009 20-F. YPF acknowledges the Staff’s comment and confirms that in future filings it will include the qualifications of the person(s) overseeing the audits in its discussion of audits performed by third parties.

The average per unit production cost on page 33 of our 2009 20-F was calculated according to Item 1204(b)(2) of Regulation S-K, which requires issuers to disclose, for each of the last three fiscal years, by geographical area, “the average production cost, not including ad valorem and severance taxes, per unit of production”. The production costs on page F-61 of our 2009 20-F were calculated in accordance with FASB ASC 932-360-25-15, which does not require the exclusion of ad valorem and severance taxes.

The following are our calculations of our 2009 unit production costs included on page 33 of our 2009 20-F (amounts have been rounded):

If we were to use cost of production figures that included ad valorem and severance taxes to calculate our unit production cost, such cost would have been approximately 45.40 pesos/boe, as noted by the Staff.

Additionally, we confirm to the Staff that in future filings we will include a footnote to the table presenting our average per unit production cost similar to the following, to facilitate a better understanding of our calculation methodology for unit production cost:

“(*) Does not include ad valorem and severance taxes, including the effect of royalty payments which are a financial obligation or are substantially equivalent to such taxes, in an amount of approximately Pesos xxx per boe.”

We acknowledge the Staff’s comment and advise the Staff that all natural gas volumes set forth under the caption “Supplemental Information on Oil and Gas Producing Activities (Unaudited)” are presented net of flared or vented gas. The footnote should have applied to the table header, rather than to the “production for the year” row.

We keep records of all gas volumes that are sold, flared or vented for operational and reservoir monitoring purposes. Consequently, we confirm to the Staff that flared and vented gas, if it were included in our production and reserves volumes, would have represented immaterial amounts of our total reported gas produced in 2009 and our gas reserves as of December 31, 2009. We also confirm to the Staff that in future filings we will include flared and vented gas in our reserves and production volumes.

We take note of the Staff’s comment and acknowledge that the language in question on page F-65 of our 2009 20-F is incorrect.

We confirm to the Staff that our 2009 proved reserves and the future cash inflows of our 2009 standardized measure were both calculated using the methodology set forth by Rule 4-10(a)(22)(v) of Regulation S-X and FASB ASC 932-235-50-31, respectively.

YPF is subject to extensive regulations relating to the oil and gas industry in Argentina which include specific natural gas market regulations as well as hydrocarbon export taxes that apply until 2011 according to Law 26,217, all of which affect the realized prices of oil and other products in the domestic market (as further explained in “Item 4. Information on the Company—Regulatory Framework and Relationship with the Argentine Government”). Such regulations affect the way in which market prices are set between market participants. As a result, crude oil prices used to determine reserves are set at the beginning of every month until 2011, for crude oils of different quality produced by us, considering the realized prices for crude oils of such quality in the domestic market, taking into account the effects of Law 26,217, 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, 2009, which refers to the WTI prices adjusted by each different quality produced by us. Additionally, a significant portion of the Argentine gas market is regulated. Natural gas prices for the residential and power generation segments, as well as natural gas for vehicles, are regulated by the government. Natural gas prices for industrial consumers are negotiated by market participants on a private basis. As a result, there are no benchmark market natural gas prices available in Argentina and, consequently, we used average realized gas prices during the year to determine our gas reserves.

Further to the explanation above, we disclose in the table below the prices used to determine our 2009 proved reserves and the future cash inflows of our 2009 standardized measure:

We also confirm to the Staff that in future filings we will amend the introductory paragraph under “Supplemental Information on Oil and Gas Producing Activities (Unaudited)—Standardized measure of discounted future net cash flows” to the following:

“The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a discount factor. Future cash inflows represent the revenues that would be received from production of year-end proved reserve quantities assuming the future production would be sold at the price used for reserves estimate as of December 31, 20xx (the “average price”). Consequently, crude oil prices used to determine reserves are set at the beginning of every month, for crude oils of different quality produced by us, 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 No. 26,217 which are enforceable until such year, and the unweighted average price of the first-day-of-the-month price for each month within the twelve-month period ended December 31, 20xx, which refers to the WTI prices adjusted by each different quality produced by us, for the following years. Additionally, and considering that there are no benchmark market natural gas prices available in Argentina, we used average realized gas prices during the year to determine our gas reserves.”

We acknowledge the Staff’s comment and have raised this matter with GCA, which has confirmed to us that they audited and accepted the methodology and prices used by us in estimating our reserves, as discussed in our response to question no. 11, for purposes of their audit, with necessary adjustments to take account of the date of their report. GCA has further advised us that, in connection with any report included in our future filings, they will include the applicable benchmark oil prices that were the starting point for the determination of the adjusted oil prices used to estimate our proved reserves.


Total oil production (millions of barrels) (a)	111
Total gas production (billion cubic feet) (a)	472

Total boe production (millions of boe)	195


Production costs (millions of Pesos) (b)	8,856
Minus (c):
Ad valorem and severance taxes (millions of Pesos) (d)	(2,514	)

“Adjusted” production costs (millions of Pesos)	6,342


A - “Adjusted” production costs (millions of Pesos)	6,342
B - Production (millions of boe) (c)	195
Unit production cost (A / B)	32.55


	Price reference (in US$/bbl)	Price used in calculations (in US$/bbl)
		Years 2010 and 2011	Years following 2011
Crude oil	WTI: 61.08	Range (*) between 41.52 and 46.11	Range (*) between 53.98 and 60.08
Natural gas	N/A	Range(**) between 0.80 and 2.01


Re:		YPF Sociedad Anónima Form 20-F for the year ended December 31, 2009 File No. 001-12102