Exhibit 99.1


DeGolyer and MacNaughton
 5001 Spring Valley Road
 Suite 800 East
 Dallas, Texas 75244
  April 30, 2015
  GeoPark Limited
 Florida 851, Piso 1
 Buenos Aires, Argentina
  Ladies and Gentlemen:
  Pursuant to your request, we have conducted a reserves evaluation of the net proved oil, condensate, and gas reserves, as of December 31, 2014, of certain selected properties that GeoPark Limited (GeoPark) has represented that it owns. This evaluation was completed on March 9, 2015. The properties appraised consist of working interests located in Chile, Colombia, Brazil, and Peru. GeoPark has represented that these properties account for 100 percent on a net equivalent barrel basis of GeoPark’s net proved reserves as of December 31, 2014. 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. 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 GeoPark.
 
 Reserves estimates included herein are expressed as net reserves. 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 Geopark after deducting all interests owned by others and royalties paid in kind. GeoPark has advised that its interests include interests of minority shareholders not owned by GeoPark.
 
 Estimates of oil, condensate, 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
 
 
 2DeGolyer and MacNaughton
 
 uncertainties inherent in the application of judgmental factors in interpreting such information.
 
 Data used in this evaluation were obtained from reviews with GeoPark personnel, from GeoPark 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 GeoPark 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.
 
 When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. 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 OOIP or OGIP.
 
 Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or 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. When applicable, material balance and other engineering methods were used to estimate recovery factors. In such
 
 
 3DeGolyer and MacNaughton
 
 
 cases, 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 based on existing economic conditions.
 
 Proved developed producing reserves were estimated using performance-based methods, primarily decline-curve analysis of oil rate versus time of individual wells in combination with water-oil ratio trends. Proved developed nonproducing reserves were estimated based on analogy to similar workovers and recompletions.
 
 Reserves for future development wells were estimated by using type well data derived from historical behavior of nearby wells.
 
 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 quantities estimated herein are sales-gas volumes expressed at a temperature base of zero degrees Celsius (°C) and a pressure base of 1 kilogram per square centimeter (kg/cm2) for the fields in Chile, a temperature base of 60 °F and a pressure base of 14.7 pounds per square inch absolute (psia) for the fields in Colombia and Peru, and a temperature base of 20 °C and a pressure base of 1 atmosphere for the field in Brazil.
 
 The oil and condensate reserves estimated in this report are expressed in terms of 42 United States gallons per barrel. Oil and condensate reserves estimated herein are those to be recovered by conventional lease separation.
  Definition of Reserves
  Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used 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-
 
 
 4DeGolyer and MacNaughton
 
 
 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.
 
 (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
 
 
 5DeGolyer and MacNaughton
 
 
 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.
 
 6DeGolyer and MacNaughton
 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 economic assumptions were used for estimating existing and future prices and costs, expressed in United States dollars (U.S.$):
  Oil and Condensate Prices
  GeoPark 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 agreements. For the fields located in Chile, GeoPark supplied differentials by field to a Brent reference price of U.S.$101.19 per barrel. The volume-weighted average adjusted product price attributable to estimated proved reserves for the fields located in Chile was U.S.$87.63 per barrel for oil and condensate. For the fields located in Colombia, GeoPark supplied differentials by field to a Brent reference price of U.S.$101.19 per barrel. The volume-weighted average adjusted product price attributable to estimated proved reserves for the fields located in Colombia was U.S.$70.04 per barrel for oil. For the Manati field in Brazil, GeoPark supplied a differential to a Brent reference price of
 
 
 7DeGolyer and MacNaughton
 
 U.S.$101.19 per barrel. The average adjusted product price attributable to estimated proved reserves for the field located in Brazil was U.S.$87.23 per barrel for condensate. For the Situche field in Peru, GeoPark supplied a differential to a West Texas Intermediate reference price of U.S.$94.56 per barrel. The average adjusted product price attributable to estimated proved reserves for the field located in Peru was U.S.$102.56 per barrel of oil. These prices were held constant for the lives of the properties.
  Gas Prices
  GeoPark has represented that the gas prices are defined by contractual agreements based on specific market conditions. The volume-weighted average adjusted product price attributable to estimated proved reserves for the fields located in Chile was U.S.$6.31 per thousand cubic feet (Mcf). The volume-weighted average adjusted product price attributable to estimated proved reserves for the Manati field in Brazil was U.S.$7.32 per Mcf. These prices were held constant for the lives of the properties. There are no gas sales for fields in Colombia and Peru.
 
 
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   Operating Expenses and Capital Costs
  Operating expenses and capital costs, based on information provided by GeoPark, 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 proved oil and gas reserves.
 
 
 9DeGolyer and MacNaughton
   Our estimates of GeoPark’s 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 millions of barrels of oil equivalent (MMboe):
 
 Estimated by DeGolyer and MacNaughton

Net Proved Reserves

as of

December 31, 2014Oil and Condensate

(Mbbl)


Sales Gas

(MMcf)


Oil Equivalent

(MMboe)ChileProved Developed


1,463.7



9,352



3.0Proved Undeveloped


4,978.2



24,618



9.1Total Chile


6,441.9



33,970



12.1ColombiaProved Developed


7,594.8



0



7.6Proved Undeveloped


17,140.5



0



17.1Total Colombia


24,735.3



0



24.7BrazilProved Developed


69.0



20,863



3.6Proved Undeveloped


61.0



19,601



3.3Total Brazil


130.0



40,464



6.9PeruProved Developed


6,525.0



0



6.6Proved Undeveloped


12,243.8



0



12.2Total Peru


18,768.8



0



18.8Total Proved Developed


15,652.5



30,215



20.7Total Proved Undeveloped


34,423.5



44,219



41.8Total Proved


50,076.0



74,434



62.5
 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.
Net reserves include the interests of minority shareholders not owned by GeoPark.
 3.
For Chile, the net proved reserves attributable to minority interests owned by others include 1,329 Mbbl of oil and condensate and 6,973 MMcf of sales gas.
 4.
For Colombia, the net proved reserves attributable to minority interest, owned by others include 4,947 Mbbl of oil and condensate.
 5.
Totals may vary due to rounding.
  10DeGolyer and MacNaughton
 In our opinion, the information relating to estimated proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4 and 932-235-50-6 through 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 1203(a) 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.
 
 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.
 
 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 GeoPark. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of GeoPark. 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

Registered Engineering Firm F-716/s/ Thomas C. Pence[SEAL]
Thomas C. Pence, P.E.

Senior Vice President

DeGolyer and MacNaughton
  
  CERTIFICATE of QUALIFICATION
 
 
 I, Thomas C. Pence, 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 GeoPark dated March  9, 2015, and that I, as Senior Vice President, was responsible for the preparation of this letter report.
 
 2.
That I attended Texas A&M University, and that I graduated with a degree in Petroleum Engineering in the year 1982; 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 that I have in excess of 32 years of experience in the oil and gas reservoir studies and reserves evaluations.
 
  /s/ Thomas C. PenceThomas C. Pence, P.E.

Senior Vice President

DeGolyer and MacNaughton