Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

March 21, 2025

GeoPark Limited

Calle 94 N° 11-30, 8th floor

Bogotá, Colombia

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2024, of the extent of the estimated net proved oil, condensate, and gas reserves of certain properties in Argentina, Brazil, Colombia, and Ecuador in which GeoPark Limited (GeoPark) has represented it holds an interest. This evaluation was completed on March 21, 2025. 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, 2024. 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 United States Securities and Exchange Commission (SEC). 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 remaining to be produced from these properties after December 31, 2024. Net reserves are defined as that portion of the gross reserves attributable to the interests held by GeoPark after deducting all interests held by others, including royalties paid in kind.

Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such 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.

Information used in this evaluation was obtained from GeoPark. In the preparation of this report we have relied, without independent verification, upon such information furnished by GeoPark with respect to the property interests being evaluated, 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 was not considered necessary for the purposes of this report.

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

DeGolyer and MacNaughton

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 the reserves definitions of Rules 4–10(a)(1)–(32) of Regulation S–X of the SEC and 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 (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. 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 plan provided by GeoPark, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The undeveloped reserves estimates were based on opportunities identified in the plan of development provided by GeoPark.

GeoPark has represented that its senior management is committed to the development plan provided by GeoPark and that GeoPark has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

The volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, 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 methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP and 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 based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.

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 certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

For cases where history-matched dynamic models were available and applicable, model results were used to estimate recovery factors and reserves production forecasts.

The reserves estimates contained herein were limited to the economic limit, as defined under the Definition of Reserves heading of this report, or to the end of the concession, whichever occurs first.

DeGolyer and MacNaughton

Data provided by GeoPark from wells drilled through December 31, 2024, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through September 2024. Estimated cumulative production, as of December 31, 2024, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 3 months.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. Oil reserves include fuel oil. Fuel oil is defined as that portion of the oil consumed in field operations. Oil and condensate reserves included in this report are expressed in thousands of barrels (10³bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as marketable gas, fuel gas, and sales gas. Marketable gas is defined as the total gas produced from the reservoir after reduction for shrinkage resulting from field separation; processing, including removal of nonhydrocarbon gas to meet pipeline specifications; and flare and other losses but not from fuel usage. Fuel gas is defined as that portion of the gas consumed in field operations and is estimated as reserves. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as marketable gas and sales gas. Gas quantities are expressed at a temperature base of 15.5 degrees Celsius (°C) and at a pressure base of 1 kilogram per cubic centimeter (kg/cm³). Gas quantities included in this report are expressed in millions of cubic feet (10⁶ft³).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities reported herein are both nonassociated gas and associated gas.

At the request of GeoPark, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by GeoPark in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

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. GeoPark supplied differentials to a Brent reference price of U.S.$78.58 per barrel and the prices were held constant thereafter. For the fields located in Argentina, the volume-weighted average adjusted product price attributable to the estimated proved reserves was U.S.$65.12 per barrel of oil. For the Manati field located in Brazil, the volume-weighted average adjusted product price attributable to the estimated proved reserves was U.S.$68.50 per barrel of condensate. For the fields located in Colombia, the volume-weighted average adjusted product price attributable to the estimated proved reserves was U.S.$64.40 per barrel of oil. For the fields located in Ecuador, the volume-weighted average adjusted product price attributable to the estimated proved reserves was U.S.$68.50 per barrel of oil.

In Argentina, GeoPark has represented that 80 percent of the oil is to be exported and 20 percent is to be sold on the domestic market. Brent prices were used as the export market price and a price of U.S.$68.00 per barrel was used for the domestic market price. Prices were not escalated for inflation.

DeGolyer and MacNaughton

Gas Prices

GeoPark has represented that the gas prices are defined by contractual agreements and their expected extensions, which are based on specific market conditions. The volume-weighted average adjusted product price attributable to the estimated proved reserves for the fields located in Argentina was U.S.$2.20 per thousand cubic feet (10³ft³) of gas. The volume-weighted average adjusted product price attributable to the estimated proved reserves for the Manati field located in Brazil was U.S.$8.15 per 10³ft³ of gas. The volume-weighted average adjusted product price attributable to the estimated proved reserves for the fields located in Colombia was U.S.$7.86 per 10³ft³ of gas.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses and capital costs, provided by GeoPark and based on existing economic conditions, were held constant for the lives of the properties. This information included historical costs as well as operating expense and capital cost estimates for future development. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by GeoPark for each field or block and were included in the year following cessation of production, except in Brazil, where abandonment costs are allocated annually into an abandonment fund. Abandonment costs were not escalated.

Operating expenses, capital costs, and abandonment costs were considered in determining the economic viability of the undeveloped reserves estimated herein.

In Argentina, GeoPark holds a 45-percent working interest in the evaluated properties. Additionally, GeoPark carries the portion of the capital expenditures of a minority interest holder in exchange for an additional share of production. This carry is reflected herein as an increase in GeoPark’s working interest from 45 to 49 percent during the carry period. These blocks in the Vaca Muerta play were acquired in 2024 and became effective in July 2024. As of the date of this report, this acquisition is undergoing customary regulatory approvals from the respective provincial government.

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, 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 FASB 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 SEC; 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

Summary of Conclusions

DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate, and gas reserves of certain properties in which GeoPark has represented it holds an interest. The estimated net proved reserves, as of December 31, 2024, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (10³bbl), millions of cubic feet (10⁶ft³), and thousands of barrels of oil equivalent (10³boe):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2024
	Oil and Condensate (10³bbl)	Sales Gas (10⁶ft³)	Oil Equivalent (10³boe)

Argentina
Proved Developed	5,708	1,736	5,997
Proved Undeveloped	30,397	9,721	32,017

Total Proved	36,105	11,457	38,015

Brazil
Proved Developed	15	6,116	1,034
Proved Undeveloped	0	0	0

Total Proved	15	6,116	1,034

Colombia
Proved Developed	49,959	884	50,106
Proved Undeveloped	6,396	0	6,396

Total Proved	56,355	884	56,502

Ecuador
Proved Developed	515	0	515
Proved Undeveloped	367	0	367

Total Proved	882	0	882

Grand Total
Proved Developed	56,197	8,736	57,653
Proved Undeveloped	37,160	9,721	38,780

Total Proved	93,357	18,457	96,433

Notes:

1. Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

2. Oil reserves include fuel oil quantities associated with the Platanillo field in Colombia. Fuel oil quantities were estimated to be 33 10³bbl of the proved developed reserves and 33 10³bbl of the total proved reserves.


	Submitted,



	/s/ DeGolyer and MacNaughton
	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716


	/s/ German H. Moss
	German H. Moss, P.E.
[SEAL]	Vice President
	DeGolyer and MacNaughton


	/s/ German H. Moss
	German H. Moss, P.E.
[SEAL]	Vice President
	DeGolyer and MacNaughton