EXHIBIT 23.2
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
January 30, 2017
EOG Resources Inc.
1111 Bagby Street, Sky Lobby 2
Houston, Texas 77002
Ladies and Gentlemen:
Pursuant to your request, we have conducted a reserves audit of the net proved oil, condensate, natural gas liquids (NGL), and gas reserves, as of December 31, 2016, of certain properties in which EOG Resources Inc. (EOG) has represented that it owns an interest. This evaluation was completed on January 30, 2017. The properties evaluated consist of working and royalty interests located in the States of Montana, New Mexico, North Dakota, and Texas; China; and offshore from Trinidad. EOG has represented that these properties account for 83 percent on a net equivalent barrel basis of EOG’s net proved reserves as of December 31, 2016, 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 Securities and Exchange Commission (SEC) of the United States. We have reviewed information provided to us by EOG that it represents to be EOG’s estimates of the net reserves, as of December 31, 2016, for the same properties as those which we evaluated. This report was prepared in accordance with guidelines specified in Item 1202 (a) (8) of Regulation S‑K and is to be used for inclusion in certain SEC filings by EOG.
Reserves estimates included herein are expressed as net reserves as represented by EOG. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2016. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by EOG after deducting all interests owned by others.
Estimates of oil, condensate, NGL, and gas reserves 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 EOG personnel, from EOG 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 EOG 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.

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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.
Based on the current stage of field development, production performance, the development plans provided by EOG, and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.
When applicable, the volumetric method was used to estimate the original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volumes. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OGIP.
Estimates of ultimate recovery were obtained after applying recovery factors to OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. 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.
In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.
Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel use, flare, and shrinkage resulting from field separation and processing. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit and at the pressure base of the state or area in which the reserves are located. Gas quantities included herein are expressed in thousands of cubic feet (Mcf). Oil and condensate reserves estimated herein are those to be recovered by conventional lease separation. NGL reserves are those attributed to the lease according to processing agreements. Oil, condensate, and NGL reserves included herein are expressed in barrels (bbl) representing 42 United States gallons per barrel. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.
Definition of Reserves
Petroleum reserves estimated by EOG and by us included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by EOG 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:

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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.
(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 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.

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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) Definitions], or by other evidence using reliable technology establishing reasonable certainty.
Primary Economic Assumptions
The following assumptions were used for estimating future prices and costs:
Oil, Condensate, and NGL Prices
EOG has represented that the oil, condensate, and NGL 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 oil, condensate, and NGL prices were calculated for each property using differentials provided by EOG to the West Texas Intermediate reference price of $42.75 per barrel and held constant thereafter. The volume‑weighted average price over the lives of the properties was $40.87 per barrel of oil and condensate and $14.44 per barrel of NGL.
Gas Prices
EOG has represented that the 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 differentials provided by EOG to the Henry Hub reference price of $2.48 per million British thermal units ($/MMBtu) and held constant thereafter. British thermal unit factors provided by EOG were used to convert prices from $/MMBtu to dollars per thousand cubic feet ($/Mcf). The volume-weighted average price over the lives of the properties was $1.23 per thousand cubic feet.
Production and Ad Valorem Taxes
Production taxes were calculated using the tax rates for each state in which the reserves are located, including, where appropriate, abatements for enhanced recovery programs. Ad valorem taxes were estimated using rates provided by EOG.

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Operating Expenses, Capital Costs, and Abandonment Costs
Estimates of operating expenses, provided by EOG and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2016 values, provided by EOG, and were not adjusted for inflation. At the request of EOG, abandonment costs were not included in the preparation of this report. These costs have, however, been considered in determining the economic viability of the undeveloped reserves summarized herein.
EOG has represented that its estimated net proved reserves attributable to the reviewed properties were based on the definition of proved reserves of the SEC. EOG’s estimates of the net proved reserves attributable to these properties, which represent 83 percent of EOG’s total proved reserves on a net equivalent basis, are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

|  | Estimated by EOG Net Proved Reserves as of December 31, 2016
Properties Reviewed by DeGolyer and MacNaughton |  | Oil and Condensate (Mbbl) |  | NGL (MMcf) |  | Sales Gas (MMcf) |  | Oil Equivalent (Mboe)
Proved Developed |  | 438,188 |  | 144,006 |  | 1,110,800 |  | 767,328
Proved Undeveloped |  | 640,113 |  | 179,643 |  | 1,171,450 |  | 1,014,997
Total Proved |  | 1,078,301 |  | 323,650 |  | 2,282,251 |  | 1,782,326
Notes: 1. Gas is converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. 2. Numbers may not add due to rounding.

Our estimates of EOG’s net proved reserves attributable to the reviewed properties were based on the definition of proved reserves of the SEC and are summarized 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, 2016
Properties Reviewed by DeGolyer and MacNaughton |  | Oil and Condensate (Mbbl) |  | NGL (MMcf) |  | Sales Gas (MMcf) | Oil Equivalent (Mboe)
Proved Developed |  | 468,703 |  | 121,999 |  | 1,078,209 | 770,403
Proved Undeveloped |  | 692,749 |  | 183,891 |  | 1,195,328 | 1,075,862
Total Proved |  | 1,161,452 |  | 305,890 |  | 2,273,537 | 1,846,265
Note: Gas is converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

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In comparing the detailed net proved reserves estimates prepared by us and by EOG, we have found differences, both positive and negative, resulting in an aggregate difference of 3.6 percent when compared on the basis of net equivalent barrels. It is our opinion that there is no material difference between the net proved reserves estimates prepared by EOG and those prepared by us for those properties we reviewed.
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, 1202(a) (1), (2), (3), (4), (8), and 2013(a) of Regulation S-K of the Securities and Exchange Commission; provided, however, that the estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.
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.
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, 2016, estimated oil, condensate, NGL, and gas reserves.
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 EOG. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of EOG. 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/ GREGORY K. GRAVES
Gregory K. Graves, P.E.
Senior Vice President

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CERTIFICATE of QUALIFICATION
I, Gregory K. Graves, 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 EOG dated January 30, 2017, and that I, as Senior Vice President, was responsible for the preparation of this letter report.

2. | That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; 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 Society of Petroleum Evaluation Engineers; and that I have in excess of 32 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ GREGORY K. GRAVES
Gregory K. Graves, P.E.
Senior Vice President
DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION
I, Gregory K. Graves, 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 EOG dated February 1, 2016, and that I, as Senior Vice President, was responsible for the preparation of this letter report.

2. | That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; 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 Society of Petroleum Evaluation Engineers; and that I have in excess of 31 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ GREGORY K. GRAVES
Gregory K. Graves, P.E.
Senior Vice President
DeGolyer and MacNaughton