Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

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

This file is intended to be a manifestation of certain data in the subject report and as such are subject to the same conditions thereof. The information and data contained in this 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

APPRAISAL REPORT

as of

DECEMBER 31, 2012

on the

PROVED RESERVES

CERTAIN PETROLEUM INTERESTS

owned by

GEOPARK HOLDINGS LIMITED

TABLE of CONTENTS

		Page

FOREWORD		1
Scope of Investigation		1
Authority		2
Source of Information		3
DEFINITION of RESERVES		4
ESTIMATION of RESERVES		10
VALUATION of RESERVES		14
SUMMARY and CONCLUSIONS		17

TABLE
Table	1 – Summary of Gross and Net Proved Reserves
Table	2 – Gross and Net Proved Reserves by Field, Chile
Table	3 – Gross and Net Proved Reserves by Field, Colombia
Table	4 – Reconciliation of Net Proved Oil and Condensate Reserves
Table	5 – Reconciliation of Net Proved Sales-Gas Reserves
Table	6 – Standardized Measure of Discounted Future Net Cash Flows and Changes Therein relating to Proved Reserves

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

APPRAISAL REPORT

as of

DECEMBER 31, 2012

on the

PROVED RESERVES

CERTAIN PETROLEUM INTERESTS

owned by

GEOPARK HOLDINGS LIMITED

FOREWORD

Scope of Investigation This report presents an appraisal, as of December 31, 2012, of the extent and value of the proved crude oil, condensate, and sales-gas reserves of certain petroleum interests in Argentina, Chile, and Colombia in which GeoPark Holdings Limited (GeoPark) has represented that it owns an interest. Oil and condensate reserves are reported in thousands of barrels and sales-gas reserves are reported in millions of cubic feet.

Estimates of proved reserves presented in this report have been prepared in compliance with the regulations promulgated by the United States Securities and Exchange Commission (SEC). These reserves definitions are discussed in detail in the Definition of Reserves section of this report.

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2012. Net reserves are defined as that portion of the gross reserves attributable to GeoPark’s working interest after deducting royalties paid in-kind.

GeoPark has represented that it owns a 100-percent working interest in the fields located in the Del Mosquito, Cerro Doña Juana, and Loma Cortaderal Blocks in Argentina and in the fields located in Chile

(Fell Block). For the fields located in Colombia, GeoPark has represented that during 2012 it acquired a 100-percent working interest in the La Cuerva Block, a 54.5-percent working interest in the Carupana field a 75-percent working interest in the Yamu field, a 10-percent working interest in the Llanos Block 32, and a 45-percent working interest in the Llanos Block 34 in Colombia.

This report presents values that were estimated for proved reserves using prices and costs as of the date the estimate was made. In this report, the prices and costs are held constant for the life of the properties. An explanation of the price and cost assumptions is included in the Valuation of Reserves section of this report.

Values shown in this report are expressed in terms of future net revenue and net present worth. Future net revenue is defined as the revenue attributable to the interests of GeoPark after deducting direct operating expenses, capital costs, taxes, and cash royalties. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Capital costs include such items as wells, pipelines, production facilities and compressors. Future income tax expenses were taken into account by determining the appropriate host country taxes to be paid. Net present worth is defined as the future net revenue derived from the proved reserves discounted at a specified arbitrary discount rate over the expected period of realization.

Estimates of oil, condensate, and sales-gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue 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.

Authority	This report was authorized by
	James F. Park, Chief Executive Officer,
	GeoPark.

Source of Information Information used in the preparation of this report 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, current costs of operation and development, current prices for production, agreements relating to 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.

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.

(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.

Probable reserves — Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.

Possible reserves — Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and

engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (iii) of the proved oil and gas definition, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

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.

The extent to which probable and possible reserves ultimately may be reclassified as proved reserves is dependent upon future

drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. No probable or possible reserves have been evaluated for this report.

ESTIMATION of RESERVES

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 original gas in place (OGIP). Structure maps and isopach maps were used 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 OOIP and OGIP.

For those fields where the volumetric method was applied, estimates of ultimate recovery were obtained by 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 reservoirs, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. In such cases, an analysis of reservoir performance, including production rates, reservoir pressures, and gas-oil ratio (GOR) 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.

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

The proved reserves forecasts contained herein terminate at the economic limit, as defined in the Definition of Reserves section of this report, or at the end of the concession life, whichever occurs first.

Data available through December 31, 2012, on the appraised properties were used to prepare the estimates shown herein. Gross production through December 31, 2012, was deducted from gross ultimate recovery to arrive at estimates of gross reserves.

Gas quantities included herein are sales-gas quantities expressed at a temperature base of 59 degrees Fahrenheit (°F) and a pressure base of 14.696 pounds per square inch absolute (psia) for the fields in Argentina, 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, and a temperature base of 60 °F and a pressure base of 14.7 psia for the fields in Colombia. Sales gas is defined as the gas to be delivered to a pipeline inlet after deductions for separation, fuel usage and flare, the removal of condensate recovered from low temperature separation, and the removal of carbon dioxide, nitrogen, and water content as specified in the gas sales agreements.

The oil and condensate reserves estimated in this report are expressed in terms of 42 United States gallons per barrel. Crude oil reserves are to be recovered by conventional field operations.

All mature producing fields and reservoirs were evaluated using production-performance techniques.

Future oil and gas producing rates estimated for this report were based on production rates considering the most recent figures available or, in certain cases, were based on estimates provided by GeoPark. The rates used for future production are rates that are within the capacity of the well or reservoir to produce, based on available data.

The gas produced from the Fell Block (Chile) is being sold to a nearby methanol plant owned by Methanex Corporation

(Methanex). Methanex has stated that there will be a temporary shutdown of the plant, starting in March 2013, due to low inlet feed-gas volumes. Methanex expects to reopen the plant later in the year. The estimated reserves and gas deliverability schedule for the evaluation of Fell Block in this report are based on the following assumptions as represented by GeoPark:

1. GeoPark has represented that Methanex plans to redesign the plant during the 2013 shutdown to handle a minimum gas feed rate of 21 million cubic feet per day (MMcf/d), reduced from the current level of about 45 MMcf/d. This gas rate reduction would allow continuous plant operation with current levels of gas production.

2. GeoPark has provided documentation from Methanex stating that Methanex will take the current 2013 committed and contracted gas volume of 7 million cubic feet per day (MMcf/d) and that excess produced gas may be purchased by Empresa Nacional Del Petroleo (ENAP).

3. GeoPark has further represented that ENAP intends on taking at least 7 MMcf/d of GeoPark gas during any future plant shutdowns. This is primarily to maintain the oil fields production and oil sales to ENAP. In addition, GeoPark represents that ENAP plans to commit to a long-term agreement to purchase Fell Block gas for its expected future shortfalls (ranging from 5 to 10 MMcf/d during the summer up to 15 MMcf/d during peak winter months).

Based on the above GeoPark representations, the estimated Fell Block reserves and gas deliverability included in this report allows gas to be produced at full rates (30 to 70 MMcf/d) starting in 2014 (after reduction in 2013 due to the shutdown). When the gas rate declines below the redesigned minimum plant feed gas level, field production will be adjusted to an expected gas take as offered by ENAP for the remainder of the productive life. The lower future production levels cause a significant amount of future gas production to be uneconomic, thus reducing the estimated Fell Block gas reserves.

There are no reserves estimated for the Argentine fields at this time. This is due to the uneconomic status of current operations and proximity to the end of concession for these fields which does not allow for future capital investment of the fields.

The estimated GeoPark gross and net proved reserves for the properties evaluated in this report, as of December 31, 2012, are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	Proved Developed				Proved Undeveloped				Total Proved
	Oil and Condensate (Mbbl)		Sales Gas (MMcf)		Oil and Condensate (Mbbl)		Sales Gas (MMcf)		Oil and Condensate (Mbbl)		Sales Gas (MMcf)
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net

Argentina	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Chile	2,104.8	2,104.8	12,768	12,768	3,153.3	3,153.3	16,813	16,813	5,258.1	5,258.1	29,581	29,581
Colombia	3,513.0	2,008.6	0	0	9,560.0	4,618.4	0	0	13,073.0	6,627.0	0	0

Total	5,617.8	4,113.4	12,768	12,768	12,713.3	7,771.7	16,813	16,813	18,331.1	11,885.1	29,581	29,581

Note: The estimates above include the 20-percent minority share not owned by GeoPark.

Table 1 presents a summary of the gross and net proved reserves. Table 2 presents the gross and net proved reserves for Chile by block and field. Table 3 presents the gross and net proved reserves for Colombia by block and field. Reconciliations of net proved oil and condensate reserves and sales-gas reserves, as of December 31, 2012, are shown in Tables 4 and 5, respectively.

VALUATION of RESERVES

This report has been prepared using price and cost assumptions specified by GeoPark. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB).

Revenue values in this report have been estimated for certain properties in accordance with the terms of the relevant concession agreement. Discussion of the relevant economic parameters follows:

Oil and Condensate Prices

GeoPark has represented that the oil and condensate prices were based on a 12-month average price, calculated as the unweighted 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 the 12-month average adjusted product price was U.S.$85.42 per barrel for crude oil based on a 12-month average West Texas Intermediate benchmark price of U.S.$94.84 per barrel. For the fields located in Colombia the 12-month average adjusted product price was U.S.$74.18 per barrel for crude oil based on a 12-month average Vasconia benchmark price of U.S.$106.34 per barrel. GeoPark supplied differentials by field to the benchmark product prices, and the prices were held constant thereafter.

Natural Gas Prices

GeoPark has represented that the natural gas prices are defined by contractual agreements based on specific market conditions. GeoPark has further represented that the average product price for the fields located in Chile was U.S.$4.04 per thousand cubic feet (Mcf), and the prices were held constant for the lives of the properties.

Operating Expenses and Capital Costs

Estimates of operating expenses and capital costs were based on data provided by GeoPark. Estimates of future costs may vary from estimates provided by GeoPark in order to conform to specific reserves cases. Future operating expense and capital cost estimates were not adjusted for the effects of inflation.

Abandonment Costs

Abandonment costs were estimated based on data provided by GeoPark.

Colombian and Chilean Income Taxes

As advised by GeoPark, Colombian income taxes are paid at a statutory rate of 33 percent. For the Fell Block, normally GeoPark would be subject to a 35-percent Chilean corporate income tax rate. However, Geopark has stated that it receives a reduced tax rate due to a special clause in the Fell Block Licence Operating Contract (CEOP) between GeoPark and the Government of Chile. Therefore, at the request of GeoPark, a 15-percent corporate tax rate for the Fell Block has been used for this evaluation. These liabilities have been considered in this evaluation.

Exchange Rate

Future net revenue has been estimated using U.S. dollars. No conversion to or from other currencies has been made.

The estimated future net revenue and net present worth of the future net revenue at a discount rate of 10 percent for the proved developed and total proved reserves by country, as of December 31, 2012, are presented below in thousands of U.S. dollars (M U.S.$):

	Proved Developed		Total Proved
	Future Net Revenue (M U.S.$)	Net Present Worth at 10 Percent (M U.S.$)	Future Net Revenue (M U.S.$)	Net Present Worth at 10 Percent (M U.S.$)

Argentina	0	0	0	0
Chile	124,466	113,413	239,804	202,449
Colombia	38,199	34,795	165,059	133,645

Total	162,665	148,208	404,863	336,094

Note: The estimates above include the 20-percent minority share not owned by GeoPark.

Standardized measure of discounted future net cash flows (SMV) and changes therein relating to proved reserves, as of December 31, 2012, are shown in Table 6. The SMV is the net present worth discounted at 10 percent.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from 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 through 932-235-50-9, 932-235-50-30, and 932-235-50-31 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) and 1203(a) of Regulation S–K of the Securities and Exchange Commission.

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.

SUMMARY and CONCLUSIONS

The estimated proved developed, proved undeveloped, and total proved oil, condensate, and sales-gas reserves, as of December 31, 2012, of certain fields attributable to the interests of GeoPark and located in Argentina, Chile, and Colombia are summarized as follows, expressed in millions of cubic feet (MMcf) or thousands of barrels (Mbbl):

	Net Reserves
	Oil and Condensate (Mbbl)	Sales Gas (MMcf)

Proved Developed	4,113.4	12,768
Proved Undeveloped	7,771.7	16,813

Total Proved	11,885.1	29,581

Note: The estimates above include the 20-percent minority share not owned by GeoPark.

Estimates of the net present worth derived from the proved developed and total proved reserves of GeoPark’s net petroleum interests, as of December 31, 2012, discounted at a rate of 10 percent and expressed in thousands of U.S. dollars (M U.S.$), are presented in the following table:

		Net Present Worth at 10 Percent (M U.S.$)

Proved Developed		148,208
Total Proved		336,094

Note: The estimates above include the 20-percent minority share not owned by GeoPark.

	Submitted,

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

SIGNED: June 28, 2013

	/s/ Thomas C. Pence, P.E.
	Thomas C. Pence, P.E.
	Senior Vice President
	DeGolyer and MacNaughton
[SEAL]

	TABLE 1
	SUMMARY of GROSS and NET PROVED RESERVES
	as of
	DECEMBER 31, 2012
	for
	CERTAIN FIELDS
	in
	ARGENTINA, CHILE, and COLOMBIA
	with interests owned by
	GEOPARK HOLDINGS LIMITED

Proved Developed

Proved Undeveloped

Total Proved

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Oil and

Sales

Oil and

Sales

Oil and

Sales

Condensate

Gas

Condensate

Gas

Condensate

Gas

Country

(Mbbl)

(MMcf)

(Mbbl)

(MMcf)

(Mbbl)

(MMcf)

Argentina

0.0

Chile

2,104.8

12,768

3,153.3

16,813

5,258.1

29,581

Colombia

3,513.0

2,008.6

9,560.0

4,618.4

13,073.0

6,627.0

Total

5,617.8

4,113.4

12,768

12,713.3

7,771.7

16,813

18,331.1

11,885.1

29,581

Note: The estimates above include the 20-percent minority share not owned by GeoPark.

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

TABLE 2

GROSS and NET PROVED RESERVES by FIELD

as of

DECEMBER 31, 2012

for

CERTAIN FIELDS

CHILE

with interests owned by

GEOPARK HOLDINGS LIMITED

	Proved Developed				Proved Undeveloped				Total Proved
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	Oil and	Oil and	Sales	Sales	Oil and	Oil and	Sales	Sales	Oil and	Oil and	Sales	Sales
Block	Condensate	Condensate	Gas	Gas	Condensate	Condensate	Gas	Gas	Condensate	Condensate	Gas	Gas
Field	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)

Fell
Alakaluf	80.1	80.1	630	630	268.7	268.7	1,136	1,136	348.8	348.8	1,766	1,766
Aonikenk	0.3	0.3	19	19	18.9	18.9	601	601	19.2	19.2	620	620
Aonikenk - Sur	5.3	5.3	104	104	9.4	9.4	203	203	14.7	14.7	307	307
Bump Hill	55.3	55.3	0	0	93.9	93.9	0	0	149.2	149.2	0	0
Cerro Iturbe	4.0	4.0	1,094	1,094	4.2	4.2	691	691	8.2	8.2	1,785	1,785
Cerro Sutlej	1.0	1.0	242	242	0.0	0.0	0	0	1.0	1.0	242	242
Copihue	36.2	36.2	260	260	141.3	141.3	41	41	177.5	177.5	301	301
Dicky	1.1	1.1	612	612	15.4	15.4	1,987	1,987	16.5	16.5	2,599	2,599
Dicky Oeste	0.0	0.0	38	38	7.4	7.4	1,126	1,126	7.4	7.4	1,164	1,164
Estancia Zunilda	0.3	0.3	31	31	0.0	0.0	0	0	0.3	0.3	31	31
Faro	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Guanaco	245.9	245.9	129	129	567.7	567.7	194	194	813.6	813.6	323	323
Kimiri Aike	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Kimiri Aike Norte	0.0	0.0	0	0	45.7	45.7	563	563	45.7	45.7	563	563
Kiuaku	0.1	0.1	16	16	0.0	0.0	0	0	0.1	0.1	16	16
Konawentru	1,187.1	1,187.1	304	304	836.9	836.9	160	160	2,024.0	2,024.0	464	464
Maku	1.9	1.9	180	180	0.0	0.0	0	0	1.9	1.9	180	180
Manekenk	5.5	5.5	131	131	15.9	15.9	1,092	1,092	21.4	21.4	1,223	1,223
Martin	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Mogote	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Molino	0.0	0.0	37	37	0.6	0.6	1,268	1,268	0.6	0.6	1,305	1,305
Monte Aymond	25.0	25.0	2,438	2,438	254.7	254.7	1,488	1,488	279.7	279.7	3,926	3,926
Monte Aymond Tertiary	0.0	0.0	1,558	1,558	0.0	0.0	0	0	0.0	0.0	1,558	1,558
Monte Aymond Oeste	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Munición Oeste	0.0	0.0	0	0	93.5	93.5	51	51	93.5	93.5	51	51
Murtilla - Dorado Norte	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Nika	3.4	3.4	426	426	0.0	0.0	0	0	3.4	3.4	426	426
Nika Oeste	2.1	2.1	98	98	0.0	0.0	0	0	2.1	2.1	98	98
Nika Sur	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Ovejero	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Pampa	0.0	0.0	0	0	27.4	27.4	2,080	2,080	27.4	27.4	2,080	2,080
Pampa Larga	7.5	7.5	3,550	3,550	275.1	275.1	701	701	282.6	282.6	4,251	4,251
Puesto Ranger	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Punta Delgada Norte	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Punta Delgada Oeste	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
San Miguel	0.3	0.3	43	43	13.0	13.0	1,816	1,816	13.3	13.3	1,859	1,859
Santiago Norte	5.4	5.4	580	580	20.9	20.9	1,402	1,402	26.3	26.3	1,982	1,982
Santiago Norte Area	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Sauce	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Selknam	0.0	0.0	0	0	67.0	67.0	89	89	67.0	67.0	89	89
Tetera	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Williche	7.1	7.1	0	0	0.0	0.0	0	0	7.1	7.1	0	0
Yagan	234.5	234.5	138	138	0.0	0.0	0	0	234.5	234.5	138	138
Yagan Norte	195.4	195.4	110	110	375.7	375.7	124	124	571.1	571.1	234	234

Total	2,104.8	2,104.8	12,768	12,768	3,153.3	3,153.3	16,813	16,813	5,258.1	5,258.1	29,581	29,581

Note: The estimates above include the 20-percent minority share not owned by GeoPark.

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

TABLE 3

GROSS and NET PROVED RESERVES by FIELD

as of

DECEMBER 31, 2012

for

CERTAIN FIELDS

COLOMBIA

with interests owned by

GEOPARK HOLDINGS LIMITED

	Proved Developed				Proved Undeveloped				Total Proved
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	Oil and	Oil and	Sales	Sales	Oil and	Oil and	Sales	Sales	Oil and	Oil and	Sales	Sales
Block	Condensate	Condensate	Gas	Gas	Condensate	Condensate	Gas	Gas	Condensate	Condensate	Gas	Gas
Field	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)

La Cuerva	1,149.0	1,057.0	0	0	1,277.0	1,176.0	0	0	2,426.0	2,233.0	0	0

Yamu
Carupana	546.0	273.7	0	0	0.0	0.0	0	0	546.0	273.7	0	0
Yamu	56.0	38.6	0	0	169.0	116.6	0	0	225.0	155.2	0	0
Total Yamu Block	602.0	312.3	0	0	169.0	116.6	0	0	771.0	428.9	0	0

Llanos Block 32
Maniceno	260.0	23.7	0	0	0.0	0.0	0	0	260.0	23.7	0	0
Samaria	0.0	0.0	0	0	0.0	0.0	0	0	0.0	0.0	0	0
Total Llanos Block 32	260.0	23.7	0	0	0.0	0.0	0	0	260.0	23.7	0	0

Llanos Block 34
Max	225.0	92.2	0	0	2,570.0	1,053.5	0	0	2,795.0	1,145.7	0	0
Tua	1,277.0	523.4	0	0	5,544.0	2,272.3	0	0	6,821.0	2,795.7	0	0
Total Llanos Block 34	1,502.0	615.6	0	0	8,114.0	3,325.8	0	0	9,616.0	3,941.4	0	0

Grand Total	3,513.0	2,008.6	0	0	9,560.0	4,618.4	0	0	13,073.0	6,627.0	0	0

Note: The estimates above include the 20-percent minority share not owned by GeoPark.

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

TABLE 4

RECONCILIATION of NET PROVED OIL and CONDENSATE RESERVES

as of

DECEMBER 31, 2012

for

CERTAIN PROPERTIES

CHILE and COLOMBIA

with interests owned by

GEOPARK HOLDINGS LIMITED

	Total Proved
	Chile		Colombia		Total
	(Mbbl)		(Mbbl)		(Mbbl)
Proved Developed and Undeveloped Reserves as of December 31, 2011	5,254.1		0.0		5,254.1

Revisions	(1,250.8	)	0.0		(1,250.8	)
Improved Recovery	0.0		0.0		0.0
Purchases or (Sales) of minerals in place	0.0		7,522.8		7,522.8
Extensions and discoveries	2,670.0		0.0		2,670.0
Annual production	(1,415.2	)	(895.8	)	(2,311.0	)

Proved Developed and Undeveloped Reserves as of December 31, 2012	5,258.1		6,627.0		11,885.1

Proved Developed Reserves
December 31, 2011	2,133.2		0.0		2,133.2
December 31, 2012	2,104.8		2,008.6		4,113.4

Notes:

1. The Colombian properties were acquired during 2012.

2. The estimates above include the 20-percent minority share not owned by GeoPark.

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

TABLE 5

RECONCILIATION of NET PROVED SALES-GAS RESERVES

as of

DECEMBER 31, 2012

for

CERTAIN PROPERTIES

CHILE and COLOMBIA

with interests owned by

GEOPARK HOLDINGS LIMITED

	Total Proved
	Chile		Colombia	Total
	(MMcf)		(MMcf)	(MMcf)
Proved Developed and Undeveloped Reserves as of December 31, 2011	57,157		0	57,157

Revisions	(21,860	)	0	(21,860	)
Improved Recovery	0		0	0
Purchases or (Sales) of minerals in place	0		0	0
Extensions and discoveries	2,256		0	2,256
Annual production	(7,972	)	0	(7,972	)

Proved Developed and Undeveloped Reserves as of December 31, 2012	29,581		0	29,581

Proved Developed Reserves
December 31, 2011	24,476		0	24,476
December 31, 2012	12,768		0	12,768

Notes:

1. The Colombian properties were acquired during 2012.

2. The estimates above include the 20-percent minority share not owned by GeoPark.

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

TABLE 6

STANDARDIZED MEASURE of DISCOUNTED FUTURE NET CASH FLOWS and

CHANGES THEREIN relating to PROVED RESERVES

as of

DECEMBER 31, 2012

for

CERTAIN PROPERTIES

CHILE and COLOMBIA

with interests owned by

GEOPARK HOLDINGS LIMITED

	Total Proved
	Chile		Colombia		Total
	(M U.S.$)		(M U.S.$)		(M U.S.$)
Future cash inflows	568,647		491,578		1,060,225
Future production costs	135,525		181,780		317,305
Future development costs	149,100		45,966		195,066
Future income tax expenses	44,218		98,773		142,991
Future net cash flows	239,804		165,059		404,863
10% annual discount for estimated timing of cash flows	(37,355	)	(31,414	)	(68,769	)

Standardized measure of discounted future net cash flows	202,449		133,645		336,094

The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2012 (All values are in M U.S.$):

Standardized Measure December 31, 2011	285,603		0		285,603

Sales and transfers of oil and gas produced, net of production costs	(110,331	)	(10,015	)	(120,346	)
Net changes in prices and production costs	45,100		0		45,100
Extensions, discoveries and improved recovery	108,768				108,768
Development costs incurred during the period	57,055		0		57,055
Revisions of previous quantity estimates	(174,757	)	0		(174,757	)
Change in estimated development costs	(73,255	)	0		(73,255	)
Purchase or (Sales) of Minerals in Place	0		143,660		143,660
Accretion of discount	36,215		0		36,215
Net change in income taxes	23,250		0		23,250
Other	4,801		0		4,801

Standardized Measure December 31, 2012	202,449		133,645		336,094

Discounted future net cash flows at 10 percent before corporate income tax expenses	239,460		207,879		447,339

Notes:

1. “Other” includes factors such as exchange rate variations and estimation errors (2012 actual vs. estimated forecasts).

2. The Colombian properties were acquired during 2012.

3. The estimates above include the 20-percent minority share not owned by GeoPark.

4. Future income tax expenses includes Windfall Profits Tax paid in Colombia.

5. At GeoPark’s request, the discounted future net cash flows at 10 percent before corporate income tax expenses has been presented in the table above.

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.