October 8, 2014

H. Roger Schwall

United States Securities and Exchange Commission

Division of Corporation Finance

Washington, D.C. 20549

Re: YPF Sociedad Anónima Form 20-F for the year ended December 31, 2013 File No. 001-12102

Dear Mr. Schwall:

Thank you for your letter dated September 24, 2014 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, 2013 (the “2013 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 24, 2014 comment letter in bold text in our responses set forth in Annex I.  Where we have agreed to provide additional disclosure or revisions to existing disclosure, we have provided in our responses, where appropriate, what the proposed additional disclosure or other revisions will look like in our future filings.

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

· YPF is responsible for the adequacy and accuracy of the disclosure in its filings with the Commission;

· Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

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

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 54-11-5441-5703 or fax: 54-11-5441-2113; or our counsel, Talbert Navia and Sey-Hyo Lee of Chadbourne & Parke LLP, at 212-408-5316 (fax: 646-710-5316) and 212-408-5122 (fax: 646-710-5122).

 Very truly yours,

/s/  Daniel Gonzalez

Daniel Gonzalez

Chief Financial Officer

Cc: Guillermo Cohen and Fernando Lattuca (Deloitte & Co. S.A.)

Annex I

Form 20-F for the Fiscal Year Ended December 31, 2013

Exploration and Production Overview, page 29

Main Properties, page 32

1. The disclosure relating to the material concentrations of your expiring undeveloped acreage appears to be limited to an analysis of such acreage only for 2014. If you have material amounts of acreage that will expire beyond this period, please expand your disclosure to present the expiration dates relating to such acreage to comply with the requirements in Item 1208(b) of Regulation S-K or advise us why additional disclosure is not required. In this regard, we note response 7 in your letter to staff dated October 29, 2010.

We acknowledge the Staff’s comment and advise the Staff that,as explained in our breakdown related to undeveloped acreage, a number of factors affect the expiration of the exploration permits for our undeveloped acreage. The granting of an exploration license depends fundamentally on the Company’s activities in each area and, consequently, the possibility that exploitable quantities of oil or gas could be discovered in such areas. In addition, in certain circumstances and considering the ongoing exploration activity for each area, the Company may apply to the relevant authorities for an extension of the expiration of the exploration permit for additional periods for the areas in question. The analysis is further complicated by the possibility of the expiration of the exploratory concessions over a longer period beyond one year from the date of the report, which is influenced by the activity that will be undertaken during that period and the potential results of this activity.

Notwithstanding the above, we confirm to the Staff that, in addition to what was indicated for 2014 in our 2013 20-F, we would be required to relinquish a maximum of approximately 9.2 thousand square kilometers of exploratory undeveloped acreage during 2015 and 2016 (approximately 11.8% of our 78 thousand square kilometers of net exploratory undeveloped acreage as of December 31, 2013).

In light of the above, we will expand the information provided in future filings substantially as follows. For the first year from the date of the most recently completed fiscal year covered by the annual report, we would disclose the expected expiration of undeveloped acreage consistent with the disclosure included in the 2013 Form 20-F. For the following two years thereafter, we would include the expiration information separately based on available information as of the date of the report, but with particular emphasis on the limitations of the information provided and indicating that such amounts represent the maximum acreage the Company could be required or could decide to relinquish:

“As of December 31, 2013, none of our exploratory undeveloped acreage was subject to exploration permits that will expire in 2014 in accordance with Law 17,319. However, as a result of the expiration in 2014 of the first, second or third exploration terms of certain of our exploration permits, we would 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). Additionally, and depending on the circumstances that could arise in each case (for instance, the state of exploratory activity in a certain area), we could request an extension of the expiration of the exploration permit, which would be subject to the approval of the respective governing authority. As a result, if no discoveries are made in 2014, we would be required to relinquish approximately 12 thousand square kilometers of exploratory undeveloped acreage (approximately 16% of our 78 thousand square kilometers of net exploratory undeveloped acreage as of December 31, 2013) during 2014.

Additionally, in accordance with information available as of the date of the report and considering the discussion above combined with the failure to make any discoveries or to engage in new activity on the part of the Company that could extend the expirations of the exploration permits, we could be required or could decide to relinquish a maximum of approximately 9.2 thousand square kilometers of exploratory undeveloped acreage (approximately 11.8% of our 78 thousand square kilometers of net exploratory undeveloped acreage as of December 31, 2013) during 2015 and 2016.

According to Law 17,319, we are entitled to decide, according to our best interest, which acreage related to each exploration permit to keep, within the required relinquishment percentage. Therefore, the areas to be relinquished consist usually of acreage where drilling has not been successful and that are considered non-core lease acreage.

Except as described above, we do not have any material undeveloped acreage related to our production concessions expiring in the near term.”

Internal Control on Reserves and Reserves Audit, page 38

2. Please expand your disclosure to explain why your third party reserves audits were performed as of September 30, 2013 rather than coinciding with the disclosure of your reserves in Form 20-F as of December 31, 2013. As part of your expanded disclosure, please clarify the following:

· why you believe reserves audits performed in advance of your fiscal year end represent an effective control over your reserves estimation effort,

· why you elected to have certain properties such as the Manantiales Behr, Restinga Alí, Río Mayo, Sarmiento, and Zona Central-Bella Vista Fields audited as of December 31, 2013, and

· the extent to which any subsequent events relating to well performance or the results of wells drilled resulted in a material change in the reserves not otherwise audited as of September 30, 2013 but subsequently disclosed as of December 31, 2013.

We take note of the Staff’s comment. As we indicated in the disclosure regarding internal control on reserves and reserves audits in the 2013 20-F, “All volumes  booked are submitted to a third party reserves audit on a periodic basis. The properties selected for a third party reserves audit in any given year are selected on the following basis:

 i. all properties on a three year cycle, and

ii. recently acquired properties not submitted to a third party reserves audit in the previous cycle and properties with respect to which there is new information which could materially affect prior reserves estimates.”

YPF has adopted the above-mentioned procedure by approving the corresponding internal policy (the “Policy”). The Policy establishes an annual close of reserves in the third quarter (that is, September 30 of each year) for an auditing process. As a result, we are able to have the information prepared by the time the Company must report to the markets. We only audit reserves in the fourth quarter in exceptional cases that could materially modify the Company’s reserve volumes. Examples of these cases include changes as a result of projects, changes in planned activities, well performance or ongoing negotiations.

For the reasons discussed above, we believe our process based on auditing reserves in advance of the end of our fiscal year represents an effective control over our reserves estimation because there are no material changes in reserves that could fall outside the scope of a reserves audit. As a result, we avoid reaching partial conclusions regarding reserve volumes expressed as of December 31 of each year. With respect to 2013, there were no changes in reserves associated with well performance or drilling activity following the close of the audit as of September 30. It is a common practice at YPF to inform the reserves auditor of any changes after such date in order to be added to the information comprising the audit.

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The extension of the terms of the concessions of the Manantiales Behr, Restinga Alí, Río Mayo, Sarmiento, and Zona Central-Bella Vista blocks in the Chubut province were an exceptional event due to the volumes of the reserves involved. The agreement was executed on December 26, 2013, and the details of the agreement were included on pages 84 and F-72 of the 2013 20-F. The blocks were submitted for external audit within a larger group of other blocks. All documentation was provided to our reserves auditors for evaluation, as stated in its report, which is attached to the 2013 20-F as Exhibit 99.2, on pages 2, 8 and 10. We also incorporated changes in reserve volumes during the fourth quarter of 2013 as a result of this extension.

Oil and Gas Production, Production Prices and Production Costs, page 40

3. Please expand the disclosure of your production to present the total annual quantities, by final product sold, for each of the periods presented to comply with the requirements in Item 1204(a) of Regulation S-K.

We acknowledge the Staff’s comment and advise the Staff that in future filings we will include tables with total annual quantities, by final product sold, in addition to the tables reporting production on a daily basis. In our 2013 20-F, we included tables on a daily basis to eliminate the effects of non-comparable years where the number of days is 366 instead of 365.

The following information presents production on an annual basis in accordance with Item 1204(a) of Regulation S-K for the years ended December 2013, 2012 and 2011. As we mentioned in “Disclosure of Certain Information” in our 2013 20-F, certain figures included in the following tables have been subject to rounding adjustments; consequently, any discrepancies in any tables between the totals and the sums of the amounts are due to rounding. We will include substantially similar tables in our future filings:

Oil and Condensate Production (1)	2013	2012	2011
		MMbbls
Consolidated Entities
South America
Argentina	84	82	81
North America
United States	*	1	1
Total Consolidated Entities	84	83	82
Equity-Accounted Entities
South America
Argentina	-	_	-
North America
United States	-	-	-
Total Equity-Accounted Entities	-	-	-
Total Oil Production (2)	84	83	82

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NGL Production (1)	2013	2012	2011
		MMbbls
Consolidated Entities
South America

Argentina	18	17	18
North America
United States	-	-	-
Total Consolidated Entities	18	17	18
Equity-Accounted Entities
South America
Argentina	*	*	*
North America
United States	-	-	-
Total Equity-Accounted Entities	*	*	*
Total NGL Production (3)	18	17	18
Natural Gas Production (1)	2013	2012	2011
		Bcf
Consolidated Entities
South America
Argentina	372	366	383
North America
United States	1	1	1
Total Consolidated Entities	373	367	384
Equity-Accounted Entities
South America
Argentina	5	10	14
North America
United States	-	-	-
Total Equity-Accounted Entities	5	10	14
Total Natural Gas Production(4)(5)	378	377	398

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Oil Equivalent Production (1)(6)	2013	2012	2011
		MMBoe
Consolidated Entities
Oil and Condensate	84	83	82
Natural Gas Liquids	18	17	18
Natural Gas	66	65	68
Equity-Accounted Entities
Oil and Condensate	-	-	-
Natural Gas Liquids	*	*	*
Natural Gas	1	2	3
Total Oil Equivalent Production	169	167	171

* Not material (less than 1).

(1)   Loma La Lata Central and Loma La Lata Norte (southern and northern parts of Loma La Lata Field) in Argentina contain approximately 18% of our total proved reserves expressed on an oil equivalent barrel basis. Oil and condensate production in these fields was approximately 5, 5, and 5 mmbbl for the years ended December 31, 2013, 2012 and 2011, respectively. Natural gas liquids production in these fields was approximately 9, 10 and 10 mmbbl for the years ended December 31, 2013, 2012 and 2011, respectively. Natural gas production in the Loma La Lata field was 110, 159 and 182 bcf for the years ended December 31, 2013, 2012 and 2011, respectively.

(2)   Oil and condensate production for the years 2013, 2012 and 2011 includes an estimated approximately 12, 11 and 10 mmbbl, respectively, of crude oil and condensate in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax. Equity-accounted entities’ production of crude oil and condensate in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, is not material.

(3)   Natural gas liquids production for the years 2013, 2012 and 2011 includes an estimated approximately 3, 2 and 2 mmbbl, respectively, of natural gas liquids in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax. Equity-accounted entities’ production of natural gas in respect of royalty payment which are a financial obligation, or are substantially equivalent to a production or similar tax, is not material.

(4)   Natural gas production for the years 2013, 2012 and 2011 includes an estimated approximately 47, 48 and 48 bcf, respectively, of natural gas in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax. Equity-accounted entities’ production of natural gas in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, is not material.

(5)   Does not include volumes consumed or flared in operation, and inventory changes, if any (whereas sale volumes shown in the reserves table included in “Supplemental Information on Oil and Gas Exploration and Production Activities—Oil and Gas Reserves” include such amounts).

(6)   Volumes of natural gas have been converted to an oil equivalent basis at 5.615 mcf per barrel.

4. We note you present your natural gas liquids (“NGLs”) combined with crude oil and condensate as a single aggregated figure for purposes of disclosing information related to your production quantities and average sales price. This combined disclosure appears to be inconsistent with your separate disclosure elsewhere of the net quantities of your NGL reserves. Furthermore, Items 1204(a) and 1204(b)(1) of Regulation S-K require the disclosure of the production and the average sales price by final product sold or produced, of oil, gas, and other products such as NGLs. To comply with Item 1204 of Regulation S-K, please revise your disclosure to provide the annual production and the average sales price by individual product type for each of the periods presented.

We take note of the Staff’s comment and advise the Staff that in future filings we will include information regarding NGL, such as annual production and average sale price, in addition to the information we have been including in our 20-F documents.

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For information related to annual production please see the response to Comment No. 3. In addition, the following discloses the average sales price by individual product type for each of the periods presented in our 2013 20-F, where NGL data were added to the information originally reported:

Production costs and sales price	Total	Argentina	United States
	(Ps./boe)
Year ended December 31, 2013
Lifting costs	88.02	88.02	88.52
Local taxes and similar payments(1)	5.55	5.58	—
Transportation and other costs	19.89	19.88	21.96
Average production costs	113.46	113.48	110.48
Average oil sales price	393.62	392.77	541.74
Average natural gas liquid sales price	114.05	112.90	252.27
Average natural gas sales price	72.39	72.37	108.12
Year ended December 31, 2012
Lifting costs	66.22	65.89	65.09
Local taxes and similar payments(1)	3.24	3.26	—
Transportation and other costs	19.50	19.51	17.54

Average production costs	88.97	88.66	82.63
Average oil sales price	288.71	317.11	466.75
Average natural gas liquid sales price	110.29	108.12	379.60
Average natural gas sales price	54.78	60.33	92.12
Year ended December 31, 2011
Lifting costs	48.24	48.24	48.93
Local taxes and similar payments(1)	2.03	2.04	—
Transportation and other costs	15.25	15.23	18.07
Average production costs	65.52	65.51	67
Average oil sales price	245.86	244.69	412.19
Average natural gas liquid sales price	104.12	102.96	314.54
Average natural gas sales price	55.24	55.21	111.74

(1) 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 Ps.32.77 per boe, Ps.25.10 per boe and Ps.19.50 per boe per boe for the years ended December 31, 2013, 2012 and 2011, respectively.

5. Also expand the footnote disclosure relating to Loma La Lata Central and Loma La Lata Norte to provide the annual production amounts for other products sold such as NGLs relating to these fields to comply with Item 1204(a) of Regulation S-K or advise us why additional disclosure is not required.

We acknowledge the Staff’s comment and advise the Staff that in future filings we will include information regarding NGL in a geographic area and country containing 15% or more of our proved reserves.

Regarding NGL production for Loma La Lata Central and Loma La Lata Norte for the periods ended December 31, 2013, 2012 and 2011, please see footnote (1) included in the response to Comment No. 3.

Notes to the Consolidated Financial Statements

Supplemental Information on Oil and Gas Producing Activities (Unaudited), page F-82

Changes in YPF’s Estimated Net Proved Reserves, page F-83

6. We note you provide footnote disclosure of the net quantities of your NGL reserves which we estimate represent 12.1%, 11.8% and 12.7% of your worldwide total crude oil, condensate and natural gas liquids reserves for the years ending December 31, 2013, 2012 and 2011, respectively. However, you do not provide the disclosure of the changes in such reserves. Please expand your disclosure to provide

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the changes in the net quantities of your natural gas liquids reserves for each of the periods presented pursuant to FASB ASC paragraph 932-235-50-5.

We take note of the Staff’s comment and advise the Staff that in future filings we will include additional information regarding changes in the net quantities of our natural gas liquids reserves for each of the periods presented. As disclosed in our 2013 20-F, our proved NGL reserves represent approximately 7% of our total consolidated reserves as of December 31, 2013.

Below, we include information which corresponds to the periods ended December 2013, 2012 and 2011 related to changes in the net quantities of our NGL reserves for each period. In addition, we disclose oil production without considering NGL, as it will be disclosed in a separate table in accordance with the Staff’s comments and the requirements of Item 1204(a) of Regulation S-K. We note that information corresponding to changes in proved reserves expressed on a boe basis does not change compared with those amounts reported in our 2013 20-F.  As we mentioned in “Disclosure of Certain Information” in our 2013 20-F, certain figures included in the following tables have been subject to rounding adjustments; consequently any discrepancies in any tables between the totals and the sums of the amounts are due to rounding. We will include substantially similar tables in our future filings:

	2013			2012			2011
Crude Oil and Condensate	Worldwide	Argentina	Other Foreign	Worldwide	Argentina	Other Foreign	Worldwide	Argentina	Other Foreign
Consolidated Entities	(Millions of barrels)
At January 1,	521	520	1	511	510	1	455	454	1
Developed	397	397	*	379	378	1	344	343	1
Undeveloped	124	123	*	133	133	-	112	112	-
Revisions of previous estimates (1)	83	83	*	69	68	1	77	76	1
Extensions and discoveries	26	26	-	17	17	-	41	41	-
Improved recovery	11	11	-	6	6	-	19	19	-
Purchase of minerals in place	1	1	-	-	-	-	-	-	-
Sale of minerals in place	-5	-5	-	-	-	-	-	-	-
Production for the year (2)	-84	-84	*	-83	-82	-1	-82	-81	-1
At December 31 (3),	552	551	1	521	520	1	511	510	1
Developed	422	421	1	397	397	*	379	378	1
Undeveloped	130	130	-	124	123	*	133	133	-
Equity-Accounted Entities
At January 1,	*	*	-	*	*	-	*	*	-
Developed	*	*	-	*	*	-	*	*	-
Undeveloped	-	-	-	-	-	-	-	-	-
			-	-	-	-	-	-	-
Revisions of previous estimates (1)	-	-	-	-	-	-	-	-	-
Extensions and discoveries	-	-	-	-	-	-	-	-	-
Improved recovery	-	-	-	-	-	-	-	-	-
Purchase of minerals in place	-	-	-	-	-	-	-	-	-
Sale of minerals in place	*	*	-	-	-	-	-	-	-
Production for the year (2)	*	*	-	-	-	-	-	-	-
At December 31 (3),	-	-	-	*	*	-	*	*	-
Developed	-	-	-	*	*	-	*	*	-
Undeveloped	-	-	-	-	-	-	-	-	-

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	2013			2012			2011
Crude Oil and Condensate	Worldwide	Argentina	Other Foreign	Worldwide	Argentina	Other Foreign	Worldwide	Argentina	Other Foreign
Consolidated and	(Millions of barrels)
Equity-Accounted Entities
At January 1,
Developed	397	397	*	379	378	1	344	343	1
Undeveloped	124	123	*	132	132	-	112	112	-
Total	521	520	1	511	510	1	456	455	1

At December 31,
Developed	422	421	1	397	397	*	379	378	1
Undeveloped	130	130	-	124	123	*	132	132	-
Total	552	551	1	521	520	1	511	510	1

* Not material (less than 1)

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

(2)     Oil and condensate production for the years 2013, 2012 and 2011 includes an estimated approximately 12, 11 and 10 mmbbl, respectively, of crude oil and condensate in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax. Equity-accounted entities’ production of crude oil and condensate in respect of royalty payments that are a financial obligation or are substantially equivalent to a production or similar tax is not material.

(3)     Proved oil and condensate reserves of consolidated entities as of December 31, 2013, 2012 and 2011 include an estimated approximately 82, 75 and 66 mmbbl, respectively, of crude oil and condensate in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax. Oil reserves of equity-accounted entities in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax, is not material.

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	2013			2012			2011
Natural Gas Liquids	Worldwide	Argentina	Other Foreign	Worldwide	Argentina	Other Foreign	Worldwide	Argentina	Other Foreign
Consolidated entities	(Millions of barrels)
At January 1,	69	69	-	73	73	-	76	76	-
Developed	56	56	-	58	58	-	60	60	-
Undeveloped	13	13	-	14	14	-	15	15	-
Revisions of previous estimates (1)	22	22	-	13	13	-	14	14	-
Extensions and discoveries	3	3	-	1	1	-	2	2	-
Improved recovery	*	*	-	-	-	-	-	-	-
Purchase of minerals in place(4)	1	1	-	-	-	-	-	-	-
Sale of minerals in place	-2	-2	-	-	-	-	-	-	-
Production for the year (2)	-18	-18	-	-17	-17	-	-18	-18	-
At December 31 (3),	76	76	-	69	69	-	73	73	-
Developed	55	55	-	56	56	-	58	58	-
Undeveloped	21	21	-	13	13	-	14	14	-
Equity-Accounted entities
At January 1,	1	1	-	1	1	-	1	1	-
Developed	1	1	-	1	1	-	1	1	-
Undeveloped	-	-	-	-	-	-	-	-	-
		-	-			-			-
Revisions of previous estimates (1)	-	-	-	-	-	-	-	-	-
Extensions and discoveries	-	-	-	-	-	-	-	-	-
Improved recovery	-	-	-	-	-	-	-	-	-
Purchase of minerals in place	-	-	-	-	-	-	-	-	-
Sale of minerals in place (4)	-1	-1	-	-	-	-	-	-	-
Production for the year (2)	*	*	-	-	-	-	-	-	-

At December 31 (3),	-	-	-	1	1	-	1	1	-
Developed	-	-	-	1	1	-	1	1	-
Undeveloped	-	-	-	-	-	-	-	-	-

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	2013			2012			2011
Natural Gas Liquids	Worldwide	Argentina	Other Foreign	Worldwide	Argentina	Other Foreign	Worldwide	Argentina	Other Foreign
Consolidated and	(Millions of barrels)
Equity-Accounted Entities
At January 1,
Developed	57	57	-	59	59	-	61	61	-
Undeveloped	13	13	-	14	14	-	15	15	-
Total	70	70	-	74	74	-	76	76	-
At December 31,
Developed	55	55	-	57	57	-	59	59	-
Undeveloped	21	21	-	13	13	-	14	14	-
Total	76	76	-	70	70	-	74	74	-

* Not material (less than 1)

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

(2)  Natural gas liquids production for the years 2013, 2012 and 2011 includes an estimated approximately 3, 2 and 2 mmbbl, respectively, in respect of royalty payments which are a financial obligation, or are substantially equivalent to a production or similar tax. Equity-accounted entities’ production of natural gas liquids in respect of royalty payments that are a financial obligation or are substantially equivalent to a production or similar tax is not material.

(3)  Proved natural gas liquids reserves of consolidated entities as of December 31, 2013, 2012 and 2011 include an estimated approximately 11, 10 and 10 mmbbl, respectively, of natural gas liquids in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax. Proved natural gas liquids reserves of equity-accounted entities in respect of royalty payments that are a financial obligation, or are substantially equivalent to a production or similar tax are not material.

(4)     Approximately 1 mmbbl was transferred to consolidated entities in 2013 as a result of an increase in YPF Energía Eléctrica’s working interest in the Ramos Field. These rights were previously owned by Pluspetrol Energy and previously included under equity-accounted entities.

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7. There appears to be a significant difference between the net quantities of your natural gas production including the volumes consumed or flared in operation disclosed on pages F-84 and F-85 and our estimates of the corresponding annual net quantities of your natural gas production disclosed as sales volumes on page 41. For example, you disclose total annual production on a worldwide basis for your consolidated entities and your equity-accounted entities of 442, 442 and 453 Bcf of gas for the years ending December 31, 2013, 2012 and 2011, respectively. We estimate the corresponding annual sales volumes to be 377, 376 and 398 Bcf or a difference of 17%, 18% and 14%, respectively.

Please expand the disclosure on page F-85 to clarify that your natural gas production figures include volumes consumed or flared in operation. Also clarify the extent and reason that such volumes have been adjusted to account for inventory changes. In this regard, we note response 10 in your letter to the staff dated October 29, 2010.

We acknowledge the Staff’s comment and advise the Staff that in future filings, in addition to footnote 5 included in the table of Oil and Gas Production, Production Prices and Production Costs on pages 40-41 of the 2013 20-F where we disclose the following:

“Does not include volumes consumed or flared in operation (whereas sale volumes shown in the reserves table included in ‘Supplemental Information on Oil and Gas Exploration and Production Activities—Oil and Gas Reserves’ include such amounts).”

we will include in the “Supplemental Information on Oil and Gas Exploration and Production Activities—Oil and Gas Reserves—Changes in YPF’s Estimated Net Proved Reserves” a footnote substantially similar to the following footnote:

“Includes volumes consumed or flared in operation for the periods ended December 31, 2013, 2012 and 2011, respectively.”

In addition, the reference to inventory changes was included in our 2013 20-F solely for the purpose of showing that the disclosed values of natural gas production are based on an “as sold basis” (including natural gas consumed, flared or inventory changes, if any).  In future filings, we will include the reference to inventory changes in the footnote only to the extent that there were material inventory changes included in the disclosure of natural gas on an “as sold basis.” Furthermore, we confirm that for the years ended December 31, 2013, 2012 and 2011, there were no inventory changes that were considered (or that should be considered) related to natural gas production disclosed on an “as sold basis.”

8. Also expand your disclosure on pages F-85, F-86 and elsewhere on page 41 to provide the net quantities of your natural gas reserves and the oil equivalent amounts of such reserves attributable to your estimates of the volumes consumed or flared in operation for each of the periods disclosed. Refer to the disclosure requirements in FASB ASC paragraph 932-235-50-10.

We take note of the Staff’s comment and advise the Staff that in future filings, we will include in the “Supplemental Information on Oil and Gas Exploration and Production Activities—Oil and Gas Reserves—Changes in YPF’s Estimated Net Proved Reserves” a footnote substantially similar to the following footnote:

“Includes estimated volumes to be consumed or flared in operation for an amount of 376,293 and 275 Bcf of natural gas for the periods ended December 31, 2013, 2012 and 2011, respectively.”

9. Please expand your disclosure to provide a narrative explanation for the significant changes in net reserves relating to each line item entry other than production for the periods ending December 31, 2012 and 2011. Refer to the disclosure requirements in FASB ASC paragraph 932-235-50-5.

We take note of the Staff’s comment and confirm to the Staff that in future filings we will include the narrative explanation for the significant changes in net reserves relating to each line item entry other than

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production for the two preceding periods, which were previously included in previous filings, in addition to the narrative explanation corresponding to the period for the fiscal year that is subject to report substantially as follows:

Changes in our estimated proved reserves during 2013

a) Revisions of previous estimates

During 2013, the Company’s proved reserves were revised upwards by 106 million barrels (“mmbbl”) of crude oil, condensate, and natural gas liquids, and 564 billion cubic feet (“bcf”) of natural gas.

The main revisions to proved reserves have been due to the following:

-­   The term of concession contracts was extended for several operated and non-operated fields located in Chubut Province. Because of this, approximately 43 mmbbl of oil proved reserves and 15 bcf of proved gas reserves were added in the Manantiales Behr, El Trebol, Escalante, Zona Central—Bella Vista, Cañadón Perdido, El Tordillo, La Tapera and Sarmiento fields.

-­   In the Magallanes field, approximately 36 million barrels of oil equivalent ("mmboe")  (9 mmbbl of oil and 150 bcf of gas) of proved developed reserves were added as a result of better than expected production and revised expected production until the expiration of the concession contract.

-­   A total of 8 mmbbl of liquids and 84 bcf of gas proved developed reserves were added in Loma La Lata Central, in the southern part of Loma La Lata field, mainly because of new projects, revision of existing projects, and a higher than forecasted production performance.

-­   In the Golfo San Jorge Basin, Los Perales and Seco León fields, 12 mmboe of proved developed reserves (10.6 mmbbl of oil and 8.2 bcf of gas) were added because of an improved production performance.

-­   A total of 9 mmbbl of liquids and 122 bcf of gas proved reserves were added in the El Porton, Chihuido de la Salina, Chihuido de la Salina Sur and Filo Morado fields in relation with production response, workovers activity and project revision in accordance with updated field response.

-­   In the Rincón del Mangrullo field approximately 6 mmbbl of liquids proved reserves, and 74 bcf of mainly proved undeveloped gas reserves were added because of additional drilling activity planned for 2014.

-­   The Chihuido de la Sierra Negra field added approximately 7 mmbbl of oil and 3 bcf of gas proved developed reserves due to better than expected production performance.

-­   Production rates did not behave as expected in the Aguada Pichana, Puesto Hernández, Aguada Toledo - Sierra Barrosa and Barrancas fields. Proved developed reserves were reduced 8.8 mmboe based on this new information.

-­   New wells drilled during 2013 in several operated areas did not perform as expected. Because of this, proved reserves were reduced in 6 mmbbl of liquids and 4 bcf of gas mainly in the Barranca Baya, Loma La Lata Norte, Loma Campana, Cerro Fortunoso, and Vizcacheras fields.

b) Extensions and discoveries

Wells drilled in unproved reserve areas added approximately 61 mmboe of proved reserves (179 bcf of natural gas and 29 mmbbl of oil).

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-­   A total of approximately 27.5 mmboe of proved reserves were added as a result of wells drilled and scheduled to be drilled during 2014 in the Aguada Toledo - Sierra Barrosa Field. The main contributions came from the Lajas Tight Gas formation (15.9 mmboe), and the Lotena formation (7.9 mmboe).

­ -  Unconventional proved developed oil reserves for a total of 10.6 mmboe were added as a consequence of 57 new wells drilled in unproved reserves and resources areas of the Loma La Lata Norte, Loma La Lata fields in the Vaca Muerta Formation.

­ -  In the Loma Campana Field, unconventional proved developed oil reserves for a total of 4.0 mmboe were added related to 22 new wells drilled in unproved reserves and resources areas.

-­   In the Golfo San Jorge Basin, extensions drilled in the Seco León Field (25 new wells) allowed the addition of approximately 2.8 mmboe of mainly oil proved reserves.

-­   Also in the Golfo San Jorge Basin, 37 new extension wells drilled in the Barranca Baya Field added 2.6 mmboe of mainly oil reserves.

c) Improved recovery

A total of approximately 11.5 mmboe of proved oil reserves have been added due to positive production response, new production and injection wells, and from workovers, performed as part of the improved recovery projects, including:

-­   In the Neuquina Basin, Aguada Toledo - Sierra Barrosa field approximately 6.3 mmboe of oil reserves were added as a result of new scheduled Secondary Recovery projects, extension projects, and new wells drilled in the area.

­ -  In the San Jorge Basin, Manantiales Behr and El Trebol Fields 3.4 mmboe of Secondary Recovery Reserves were added as a result of recovery factor improvements based on new drilling and project optimization.

-­   In the Neuquina Basin in Cerro Fortunoso Field, proved undeveloped reserves were reduced by approximately 3.7 mmboe because of observed changes in the behaviour of a secondary recovery pilot project.

d) Sales and acquisitions

-­   The acquisition of a 23% working interest in the Aguarague and San Antonio Sur Fields of the Noroeste Basin resulted in the addition of approximately 8.9 mmboe of proved reserves. YPF’s working interest in this field is currently 53%.

-­   The execution of a contract for a Joint Venture Project for the development and operation of the Loma Campana and Loma La Lata Norte (North of Loma La Lata) fields resulted in an 8.8 mmboe reduction in proved reserves of Vaca Muerta and Quintuco formations. As part of this agreement, YPF’s working interest in these fields changed from 100% to 50%.

-­   Approximately 6.5 mmboe were transferred to Consolidated Entities as a result of YPF Energía Eléctrica’s working interest in the Ramos Field. These rights were previously owned by Pluspetrol Energy and are thus disclosed under Equity-accounted Entities reserves.

Changes in our estimated proved reserves during 2012

a) Revisions of previous estimates:

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During 2012, the Company’s proved reserves were revised upwards by 82 million barrels (“mmbbl”) of crude oil, condensate and natural gas liquids and 220 billion cubic feet (“bcf”) of natural gas,

The main revisions to proved reserves have been due to the following:

­-   Negotiation of the extension of exploitation concessions in the provinces of Santa Cruz, Salta and Tierra del Fuego (See Note 11.b to the financial statements in the annual report on Form 20-F for the year ended December 31, 2012) resulted in 79 mmbbl of crude oil and 231 bcf of Gas were additions to proved reserves during 2012.

-­   Crude oil production performed better than expected during 2012, resulting in approximately 27 mmbbl additions to proved developed reserves. The main additions to crude oil reserves were from: Aguada Pichana, Chihuido de la Sierra Negra, Puesto Hernández, Seco León, Los Perales and Lomas del Cuy fields.

­-   In Vizcacheras, Tierra del Fuego and Barrancas areas a total of approximately 7 mmbbl of oil were discounted from proved developed reserves due to poor production results.

­-   A total of approximately 121 bcf were added as proved developed natural gas reserves as a result of better than expected production performance. This increase was mainly based on additions from Aguada Pichana, Loma La Lata, Ramos, Aguada Toledo – Sierra Barrosa and Paso Bardas Norte fields.

­ -  A reduction of 25 million of barrels of oil equivalent (“mmboe”) of unconventional Vaca Muerta reservoir as a result of incorporating new information according to the behavior of the project, while it continues to execute the pilot project.

­ -  Due to revision of development projects studies, approximately 12 mmboe of proved undeveloped reserves were discounted, mainly in Lotena Formation, Loma La Lata Field.

­ -  Approximately 6 mmboe of proved reserves were added mainly in Cañadón Yatel, Volcan Auca Mahuida and Las Manadas Fields as a consequence of the addition of new development projects studies to our plan.

-­   An addition of approximately 3 mmboe of proved reserves were achieved as a result of successful workover activities performed in some areas, mainly in the Chihuido La Salina Sur, Volcan Auca Mahuida and Los Perales fields.

­-   Results of some of our development wells were below expectations in certain areas, resulting in a downward revision of approximately 4 mmboe of proved reserves, mainly in Loma La Lata, Seco Leon, Manantiales Behr and Barranca Baya Fields.

 b) Improved recovery

A total of approximately 7 mmbbl of proved oil reserves have been added due to positive production response, new production and injection wells, and from workovers, performed as part of the improved recovery projects mainly in Aguada Toledo - Sierra Barrosa, CNQ 7A and Chihuido de la Sierra Negra Fields.

c) Extensions and discoveries

Wells drilled in unproved reserve areas added approximately 24 mmboe of proved reserves (31 bcf of natural gas and 18 mmbbl of oil).

­ - In Vizcacheras field approximately 7 mmboe of proved reserves were added as a result of drilled wells and development projects associated to exploratory well ViO.x-2.

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­ -  In Loma La Lata field 24 new wells drilled in unproved reserves area contributed approximately with 2.5 mmbbl of crude oil, condensate and natural gas liquids and 4.4 bcf of gas of proved reserves mainly from Vaca Muerta and Quintuco formations.

­ -  In Aguada Pichana field similar activity carried out drilling 10 new wells in an unproved reserves area accounted for approximately 7 bcf of proved reserves additions related to extensions and discoveries.

­-   As a result of the drilling activity in unproved reserve areas approximately 5 mmboe proved oil reserves were added in the Manantiales Behr (approximately 1.4 mmboe), Aguada Toledo - Sierra Barrosa (approximately 2 mmboe), Lindero Atravesado (approximately 1 mmboe), Barranca Baya (approximately 1.2 mmboe) and Cañadón Yatel (approximately 1.1 mmboe).

Changes in our estimated proved reserves during 2011

a) Revisions of previous estimates:

During 2011, the Company’s proved reserves were revised upwards by 91 million barrels (“mmbbl”) of crude oil and 166 billion cubic feet (“bcf”) of natural gas,

The main revisions to proved reserves have been due to the following:

– A net volume of 51.8 mmboe of proved reserves was added (50.8 mmbbls of liquids and 6.2 bcf of gas) as a result of a ten year extension of exploitation concessions contracts in Mendoza Province.

This revision involves the following reserve areas: El Portón, Barrancas, Cerro Fortunoso, El Manzano, La Brea, Llancanelo, Llancanelo “R”, Puntilla de Huincan, Río Tunuyán, Valle del Río Grande, Vizcacheras, Cañadón Amarillo, Altiplanicie del Payún, Chihuido de la Sierra Negra and La Ventana.

– Production performance was better than expected in some oil and gas fields, mainly in San Roque, Chihuido Sierra Negra, Tierra del Fuego, El Portón, Chihuido La Salina Sur, Chihuido La Salina, CNQ 7A and Los Perales. According to these results a 61.1 mmboe upward revision was made in proved reserves (36.7 mmbbls of liquid and 136.7 bcf of gas).

– In Loma La Lata field approximately 38 bcf of gas and 2.2 mbbls of liquids were added as proved undeveloped reserves as a result of a revision of developlment project studies, due to better than expected results in new wells to Sierras Blancas formation.

– Due to revision of development projects, approximately 7.2 mmboe of proved undeveloped reserves were added. Upward revisions were made mainly in Volcán Auca Mahuida, CNQ 7A, Barranca Baya, Pico Truncado fields, and downward in Señal Picada field.

– The results of some of our development wells were below expectations in certain areas, resulting in a downward revision of approximately 4.7 mmboe of proved reserves, mainly in Manantiales Behr, Acambuco, Cañadón Amarillo, Barranca Baya and Señal Picada.

b) Improved recovery

– In Golfo San Jorge basin, completion of technical/economic feasibility studies for new projects, and for extension of current improved recovery projects, resulted in an addition of 8.1 mmbbls of proved undeveloped reserves, mainly in Seco León, Los Perales and Barranca Baya areas.

– In Cerro Fortunoso, in Neuquina Basin, 6.7 mmbbls of proved undeveloped reserves were added due to a new development study for expansion of an existing Improved Recovery project in a Block located to the north east of the area.

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– In CNQ7A an addition of 1.3 mmbbls of proved reserves was made due to development results and positive production response of improved recovery projects.

c) Extensions and discoveries

– Extensions and Discoveries made a significant contribution during 2011, adding a total of 62 mmboe of proved reserves (43.1 mmbbls of liquids and 103.8 bcf of gas).

– In Loma La Lata field, successful results in drilling and producing hydrocarbons from Non Conventional Shale Oil reservoirs allowed an addition of 4.8 mmboe of Proved Developed and 28.6 mmboe of Proved Undeveloped Reserves (net proved 23.3 mmbbls of oil and 56.4 bcf of gas). The scheduled development project includes drilling of 112 new wells in Proved Undeveloped locations and 271 wells in unproved reserves areas.  

– As a result of the drilling activity at approximately 190 wells in unproved reserve areas, 13.5 mmboe of proved oil reserves were added mainly in Manantiales Behr (4.3 mmboe), Aguada Pichana (3.2 mmboe), Vizcacheras (2.6 mmboe), Barranca Baya (1.8 mmboe), and Cerro Fortunoso (1.5 mmboe).

Standardized Measure of Discounted Future Net Cash Flows, page F-89

10. Please expand your disclosure to clarify your assumptions for the revenue and costs used in the calculation of your standardized measure of future net cash flows attributable to the volumes consumed or flared in operation. Refer to FASB ASC paragraph 932-235-50-36.

We advise the Staff that both revenue and costs used in the calculation of our standardized measure of future net cash flows do not include amounts related to the volumes consumed or flared in operation. Consequently, “future cash inflows” and “future production costs” are disclosed net of the amount of gas estimated to be consumed or flared and do not affect the “Standardized measure of discounted future net cash flows.”

Additionally, we confirm to the Staff that in future filings we will include a footnote to the table (specifically for “Future cash inflows” and “Future production costs”) to facilitate a better understanding of our calculation methodology for volumes consumed or flared in operation:

“(*) Does not include amounts corresponding to volumes consumed or flared in operation”

11. We note the probable reserves presented in the reserves report were prepared in accordance with the Petroleum Resources Management System (PRMS) approved by the Society of Petroleum Engineers, et al. We also note information relating to probable reserves is not disclosed in your filing on Form 20-F. The staff believes the information presented in the reserve report pursuant to Item 1202(a)(8)(ix) of Regulation S-K should correlate with the disclosure in your annual filing on Form 20-F. Therefore, please obtain and file a revised reserve report that presents probable reserves prepared to comply with the definitions contained in Rule 4-10(a) of Regulation S-X. Additionally, revise your filing on Form 20-F to disclose this information in a manner that is consistent with the guidance in Instruction 2 to paragraph (a)(2) of Item 1202 and the disclosure requirements for probable reserves under Item 1202(a)(2) of Regulation S-K. Alternatively, obtain and file a revised reserve report which does not include the information relating to probable reserves.

We acknowledge the comments from the Staff regarding the reserves audit report issued by DeGolyer and MacNaughton regarding certain properties owned by Maxus Energy Corporation (“Maxus”) that represent the equivalent of 1.17 mmboe as of December 31, 2013, or approximately 0.1% of our consolidated proved reserves at that date.

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As mentioned in the disclosure regarding internal controls on reserves and reserves audits in our 2013 20-F, our policy is based on externally auditing 100% of our reserves every three years. This is why the Maxus reserves were included in the 2013 audit process, without regard to their materiality within our consolidated total reserves.

We received the attached report from our auditors regarding this issue, in accordance with the Staff’s comments. The report eliminates any reference to probable reserves, which is in line with the information provided in the 2013 20-F and consistent with the Staff’s comments.

In future filings, we will include reserves audit reports containing information exclusively reported in the 20-F. With respect to proved reserves, we will exclude any reference to probable reserves, which is consistent with the approach taken by the Company. These changes are in line with the guidelines indicated by the Staff as well as the requirements specified in the following Comment No. 12, all of which were included in the attached report.

12. The reserves report does not include certain disclosures required by Items 1202(a)(7) and 1202(a)(8) of Regulation S-K. Please obtain and file a revised reserves report to include the following information in order to satisfy your filing obligations.

· The qualifications of the technical person primarily responsible for overseeing the preparation of the reserves estimates presented in the reserves report (Item 1202(a)(7)).

· The purpose for which the report was prepared (e.g. for inclusion as an exhibit in a filing made with the U.S. Securities and Exchange Commission (SEC) (Item 1202(a)(8)(i)).

· For whom the report was prepared (e.g. the relationship between the ownership interests of Maxus Energy Corporation as disclosed in the report and those relating to YPF Sociedad Anónima) (Item 1202(a)(8)(i)).

· The percentage of the Company’s total proved reserves (e.g. for properties located in the United States) covered by the report (1202(a)(8)(iv)).

· A brief summary of the third party’s conclusions with respect to the reserves estimates (e.g. in the case of an audit, the degree of agreement between the Company’s and third party engineer’s reserve figures) (Item 1202(a)(8)(ix)).

We respectfully direct the Staff to the reserves audit report, as discussed in our response to Comment No. 11, above.

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DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

October 6, 2014

Maxus Energy Corporation

1330 Lake Robbins Drive

Suite 300

The Woodlands, Texas 77380

Ladies and Gentlemen:

Pursuant to your request, we have conducted a reserves audit of the net proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of October 1, 2013, of certain properties owned by Maxus Energy Corporation (Maxus), an indirect wholly owned subsidiary of YPF S.A. (YPF) for the purposes of YPF’s disclosure of reserves pursuant to the requirements of Item 1202 of Regulation S–K and inclusion of this report as an exhibit to YPF’s filings with the United States Securities and Exchange Commission (SEC). This evaluation was completed on August 30, 2013. The properties appraised consist of working and overriding royalty interests located in Oklahoma and Texas (Crescendo) and offshore Gulf of Mexico (Neptune). Maxus has represented that these properties account for 100 percent on a net equivalent barrel basis of Maxus’ net proved reserves of assets they can account for as of October 1, 2013, and that the net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules  4–10(a) (1)–(32) of Regulation S–X of the SEC of the United States. We have reviewed information provided to us by Maxus that it represents to be Maxus’ estimates of the net reserves, as of October 1, 2013, for the same properties as those which we evaluated.

Reserves included herein are expressed as net reserves as represented by Maxus. Gross reserves are defined as the total estimated petroleum to be produced from these properties after September 30, 2013. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Maxus after deducting all interests owned by others.

Estimates of oil, condensate, NGL, and natural gas should be regarded only as estimates that may change as further production history and additional

DeGolyer and MacNaughton

information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Maxus personnel, Maxus’ files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Maxus with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

DeGolyer and MacNaughton

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as that portion of the total gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base of the state in which the interest is located. Condensate reserves estimated herein are those to be recovered by conventional lease separation.

Definition of Reserves

Petroleum reserves estimated by Maxus and by us included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by Maxus and by us in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

DeGolyer and MacNaughton

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

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)   Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered

DeGolyer and MacNaughton

 by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a)

DeGolyer and MacNaughton

 Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Primary Economic Assumptions

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

Oil and Condensate Prices

Maxus has represented that the oil and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Maxus requested that this report be delivered at the end of August 2013, approximately 30 days before the “as of” date of this report. In doing so, the September 1, 2013, posted product price, the final product price used to determine the average product price for the 12-month period preceding the “as of” date of the evaluation, was not available. At Maxus’ request the final product price used to calculate the average product price for the 12-month period preceding the “as of” date of this report was the product price posted on August 16, 2013. Maxus supplied differentials by field to a West Texas Intermediate reference price of $95.10 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to estimated proved reserves was $92.96 per barrel of oil and condensate.

Natural Gas Liquids Price

Maxus supplied differentials by field to a reference price of $60.48 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to estimated proved reserves was $52.92 per barrel.

DeGolyer and MacNaughton

Natural Gas Prices

Maxus has represented that the natural gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Maxus requested that this report be delivered at the end of August 2013, approximately 30 days before the “as of” date of this report. In doing so, the September 1, 2013, posted gas price, the final gas price used to determine the average gas price for the 12-month period preceding the “as of” date of the evaluation, was not available. At Maxus’ request the final gas price used to calculate the average gas price for the 12-month period preceding the “as of” date of this report was the gas price posted on August 16, 2013. The gas prices were calculated for each property using differentials to the Henry Hub reference price of $3.58 per million British thermal units (MMbtu) furnished by Maxus and held constant thereafter. The volume-weighted average price attributable to estimated proved reserves was $3.601 per thousand cubic feet.

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Maxus, were used in estimating future costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the October 1, 2013, estimated oil and gas reserves. The reserves estimated in this report can be produced under current regulatory guidelines.

DeGolyer and MacNaughton

Maxus has represented that its estimated net proved reserves attributable to the reviewed properties are based on the definition of proved reserves of the SEC. Maxus represents that its estimates of the net proved reserves attributable to these properties which represent 100 percent of Maxus’ reserves on a net equivalent basis are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by Maxus Net Proved Reserves as of October 1, 2013
	Oil and Condensate (Mbbl)	Natural Gas Liquids (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Properties reviewed by DeGolyer and MacNaughton
Crescendo
Proved Developed	18	0	2,383	442
Proved Undeveloped	0	0	0	0
Total Proved Crescendo	18	0	2,383	442
Neptune
Proved Developed	778	23	359	865
Proved Undeveloped	0	0	0	0
Total Proved Neptune	778	23	359	865
Total Proved	796	23	2,742	1,307
Note: Gas is converted to oil equivalent using a factor of 5,615 cubic feet of gas  per 1 barrel of oil equivalent.

DeGolyer and MacNaughton

Our estimates of Maxus’ net proved reserves attributable to the reviewed properties are based on the definition of proved reserves of the SEC and are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of October 1, 2013
	Oil and Condensate (Mbbl)	Natural Gas Liquids (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Crescendo
Proved Developed	16	0	2,514	464
Proved Undeveloped	0	0	0	0
Total Proved Crescendo	16	0	2,514	464
Neptune
Proved Developed	737	25	383	830
Proved Undeveloped	0	0	0	0
Total Proved Neptune	737	25	383	830
Total Proved	753	25	2,897	1,294
Note: Gas is converted to oil equivalent using a factor of 5,615 cubic feet of gas  per 1 barrel of oil equivalent.

In our opinion, the information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8)(i), (ii), and (v)–(x) of Regulation S–K of the SEC; provided, however, that (i) estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year and (ii) the as-of date of this report does not coincide with Maxus’ fiscal year.

DeGolyer and MacNaughton

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

This report was completed on August 30, 2013; therefore, events that may have occurred after the preparation of this report but before the “as-of” date of October 1, 2013, that might have affected the reserves, prices, and costs used in the estimates presented herein were not taken into account.

In comparing the detailed net proved reserves estimates prepared by us and by Maxus, we have found differences, both positive and negative, resulting in an aggregate difference of 1.0 percent when compared on the basis of net equivalent barrels. It is our opinion that the net proved reserves estimates prepared by Maxus on the properties reviewed by us and referred to above, when compared on the basis of net equivalent barrels, in aggregate, do not differ materially from those prepared by us.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Maxus. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Maxus. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/  Paul J. Szatkowski, P.E

Paul J. Szatkowski, P.E

Senior Vice President

 DeGolyer and MacNaughton

.

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

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

1.   That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Maxus dated October 6, 2014 and that I, as Senior Vice President, was responsible for the preparation of this report.

2.   That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 39 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Paul J. Szatkowski, P.E

Paul J. Szatkowski, P.E

Senior Vice President

DeGolyer and MacNaughton