Exhibit 99.1(d)

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

This is a digital representation of a DeGolyer and MacNaughton report.

Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

January 14, 2015

Maxus Energy Corporation

10333 Richmond Avenue

Suite 1050

Houston, Texas 77042

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 December 31, 2014, of certain properties that 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), has represented that it owns. This evaluation was completed on January 14, 2015. 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 December 31, 2014, 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 December 31, 2014, for the same properties as those which we evaluated.

Reserves estimates 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 December 31, 2014. 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.

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Estimates of oil, condensate, NGL, and natural gas should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Maxus personnel, from 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, water-cut, 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.

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In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for wich more complete data were available.

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 or area in which the interest is located. Condensate reserves estimated herein are those to be recovered by conventional lease separation. NGL reserves are those attributed to the leasehold interests according to processing agreements.

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.

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

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

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

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

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

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

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(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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

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application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

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 supplied differentials by field to a West Texas Intermediate reference price of $90.14 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to estimated proved reserves was $88.36 per barrel of oil and condensate.

Natural Gas Liquids Price

Maxus supplied differentials by field to a reference price of $49.58 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to estimated proved reserves was $42.02 per barrel of NGL.

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. The gas prices were calculated for each property using

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differentials to the Henry Hub reference price of $4.29 per million British thermal units (MMbtu) furnished by Maxus and held constant thereafter. The volume-weighted average price attributable to estimated proved reserves was $4.326 per thousand cubic feet of gas.

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 December 31, 2014, estimated oil and gas reserves.

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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 December 31, 2014
Properties reviewed by DeGolyer and MacNaughton	Oil and Condensate (Mbbl)		Natural Gas Liquids (Mbbl)		Sales Gas (MMcf)		Oil Equivalent (Mboe)
Crescendo
Proved Developed		250		0		4,184		971
Proved Undeveloped		0		0		0		0
Total Proved Crescendo		250		0		4,184		971
Neptune
Proved Developed		1,032		36		527		1,162
Proved Undeveloped		0		0		0		0
Total Proved Neptune		1,032		36		527		1,162
Total Proved		1,282		36		4,711		2,133

Notes:

1. Gas is converted to oil equivalent using an energy equivalent factor of 5,800 cubic feet of gas per 1 barrel of oil equivalent in Crescendo.

2. Gas is converted to oil equivalent using an energy equivalent factor of 5,615 cubic feet of gas per 1 barrel of oil equivalent in Neptune.

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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 December 31, 2014
	Oil and Condensate (Mbbl)		Natural Gas Liquids (Mbbl)		Sales Gas (MMcf)		Oil Equivalent (Mboe)
Crescendo
Proved Developed		252		0		4,215		979
Proved Undeveloped		0		0		0		0
Total Proved Crescendo		252		0		4,215		979
Neptune
Proved Developed		1,106		38		599		1,251
Proved Undeveloped		0		0		0		0
Total Proved Neptune		1,106		38		599		1,251
Total Proved		1,358		38		4,814		2,230

Notes:

1. Gas is converted to oil equivalent using an energy equivalent factor of 5,800 cubic feet of gas per 1 barrel of oil equivalent in Crescendo.

2. Gas is converted to oil equivalent using an energy equivalent factor of 5,615 cubic feet of gas per 1 barrel of oil equivalent in Neptune.

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 Securities and Exchange Commission; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

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

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 4.5 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 January 14, 2015, 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 40 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