EX-99.3 34 a2216533zex-99_3.htm EX-99.3

Exhibit 99.3

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

JUNE 30, 2013

on the

PROVED RESERVES

CERTAIN PETROLEUM INTERESTS

BRAZIL and COLOMBIA

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	9
VALUATION of RESERVES	12
SUMMARY and CONCLUSIONS	17

TABLE

Table 1 — Summary of Gross and Net Proved Reserves

Table 2 — Gross and Net Proved Reserves by Field, Brazil

Table 3 — Gross and Net Proved Reserves by Field, Colombia

Table 4 — Standardized Measure of Discounted Future Net Cash Flows relating to Proved Reserves

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

APPRAISAL REPORT

as of

JUNE 30, 2013

on the

PROVED RESERVES

CERTAIN PETROLEUM INTERESTS

BRAZIL and COLOMBIA

owned by

GEOPARK HOLDINGS LIMITED

FOREWORD

Scope of Investigation This report presents an appraisal, as of June 30, 2013, of the extent and value of the proved crude oil, condensate, and sales-gas reserves of certain petroleum interests in Brazil and Colombia in which GeoPark Holdings Limited (GeoPark) has represented that it owns an interest.

The properties included in this appraisal are the Manati field in Brazil (acquired in 2013) and two new 2013 discoveries in Colombia (the Tarotaro and Potrillo fields).

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 June 30, 2013. 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 advised that its

government royalty obligation in Brazil is paid in cash; therefore, net reserves in Brazil have not been reduced in consideration of this royalty obligation. GeoPark has also advised that its government royalty obligation in Colombia is paid in kind; therefore, net reserves in Colombia have been reduced in consideration of this royalty obligation.

GeoPark has represented that it owns a 10-percent working interest in the Manati field in Brazil. For the fields located in Colombia, GeoPark has represented that it owns a 75-percent working interest in the Potrillo field and a 45-percent working interest in the Tarotaro field.

This report presents values that were estimated for proved reserves using prices and costs provided by GeoPark. 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 us ed 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 June 30, 2013, on the appraised properties were used to prepare the estimates shown herein. Gross production through June 30, 2013, 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 20 degrees Celsius (°C) and a pressure base of 1 atmosphere for the Manati field in Brazil, and a temperature base of 60 °F and a pressure base of 14.7 pounds per square inch absolute (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 estimated GeoPark gross and net proved reserves for the properties evaluated in this report, as of June 30, 2013, 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

Brazil	710.0	71.0	277,940	27,794	530.0	53.0	202,730	20,273	1,240.0	124.0	480,670	48,067
Colombia	1,497.0	649.2	0	0	4,087.0	1,702.8	0	0	5,584.0	2,352.0	0	0

Total	2,207.0	720.2	277,940	27,794	4,617.0	1,755.8	202,730	20,273	6,824.0	2,476.0	480,670	48,067

Note: The estimates above for Colombia 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 Brazil by block and field. Table 3 presents the gross and net proved reserves for Colombia by block and field.

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 Manati field in Brazil the 12-month average adjusted product price was U.S.$107.50 per barrel for condensate based on a 12-month average Brent reference price of U.S.$108.21 per barrel. For the fields located in Colombia the 12-month average adjusted product price was U.S.$70.42 per barrel for crude oil based on a 12-month average Vasconia benchmark price of U.S.$103.18 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 Manati field in Brazil was U.S.$6.45 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.

Brazil

Fiscal Terms

The Government of Brazil’s Petroleum Law n° 9,478, the Petroleum Law of 1997, affords the Brazilian Government three elements of government take: 1) petroleum levies consisting of royalties, a special participation fee, and surface rentals; 2) direct taxes, which are levied through the financial transaction tax, the corporate income tax, and two social contribution taxes; and 3) indirect taxes, which are levies on equipment and services used by companies engaged in exploration and production activities. GeoPark has advised that the indirect tax levies for which it is responsible are included in the estimates of operating expenses and capital costs. Certain indirect levies are eligible for reimbursement from sales of refined products.

Royalties

The federal royalty rate in Brazil varies by field between 5 and 10 percent. GeoPark has advised that the royalty obligation for the Manati field is 7.5-percent.

Oil royalty is assessed on the market value of the oil (and condensate), which is defined as the greater of the sales price or the market valuation as determined by the National Petroleum Agency (ANP). Gas royalty is levied on the market value of the gas production less gas injected.

Special Participation Fee

The special participation fee (SPF) is a tax assessed at the field level on a sliding scale basis that varies depending on the location of the field (onshore or offshore), water depth, level of production, and number of

years on production. The tax basis for the SPF is similar to the tax basis for corporation tax (CIT) with some exceptions. Drilling costs are depreciated using a units-of-production basis for SPF, but expensed for CIT. An annual provision for abandonment costs is also deductible for SPF, but expensed in the year incurred for CIT. In years in which the SPF is paid there is an additional 1-percent research and development fee assessed.

Surface Rental Fees

Rental fees are payable to the ANP and vary by field, depending on stage of activity (exploration or development), geological characteristics, and location of sedimentary basin. GeoPark provided the contracted area for the Manati field and the associated stage of activity and corresponding rental rate in Brazilian reais (R$) per square kilometer.

Corporate Income Tax

Corporation tax in Brazil is assessed on a consolidated entity basis at a statutory rate of 34 percent. This rate consists of the base tax rate of 15 percent, surtax of 10 percent, and a social contribution component of 9 percent. For purposes of this evaluation, corporation tax was applied on an individual field basis without considering the effects of consolidation on GeoPark’s combined corporate tax liability. GeoPark has represented that it is eligible for tax benefits that reduce the corporate tax rate to 15.25 percent through 2017. This benefit is included in the calculations herein. The tax calculations also include a U.S.$140 million tax basis provided by GeoPark.

Social Contribution Taxes

Two social contribution taxes are levied on the market value of oil and gas sales. The Contribution for the Worker’s Social Integration Program (PIS) is assessed at a rate of 1.65 percent and the Contribution for Social Security Funding (COFINS) is levied at a 7.6-percent rate. GeoPark has represented that these taxes have been netted out of the product prices that were provided.

Earn-Out Payment

GeoPark has advised that the sellers of the Manati field have rights to additional income from the field. GeoPark is responsible for payments to the sellers up to 40 percent of annual cash flow that exceeds U.S.$25 million. The earn-out payments are capped at a cumulative U.S.$20 million.

Exchange Rate

An exchange rate of R$2.04 per U.S.$1.00 has been provided by GeoPark and used to convert the respective currencies.

Colombia

Fiscal Terms

Terms of the contracts for the Potrillo and Tarotaro fields afford GeoPark the right to develop and receive its share of production in excess of a sliding-scale government royalty (8 percent of the first 5,000 barrels of oil per day (BOPD) up to 20 percent for 125,000 BOPD). The contracts also require GeoPark to pay a subsurface rights fee of 12 cents for every net barrel produced of oil. For the Tarotaro field there is a special participation royalty of 1 percent of production net of royalty. Both fields are subject to an additional profits tax (APT) payable at 30 percent for production volumes in excess of 5 million barrels per field structure. This tax is assessable for revenues in excess of a base price that varies with oil gravity.

Corporate Income Tax

As advised by GeoPark, Colombian income taxes are paid at a statutory rate of 33 percent.

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 June 30, 2013, 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.$)	Net Present Worth at 10 Percent (M U.S.$)

Brazil	92,291	78,092	181,157	137,190
Colombia	21,533	19,780	84,413	71,939

Total	113,824	97,872	265,570	209,129

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

Standardized measure of discounted future net cash flows (SMV) relating to proved reserves, as of June 30, 2013, are shown in Table 4. 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, 932-235-50-6 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, 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; 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.

SUMMARY and CONCLUSIONS

The estimated proved developed, proved undeveloped, and total proved oil, condensate, and sales-gas reserves, as of June 30, 2013, of certain fields attributable to the interests of GeoPark and located in Brazil and Colombia are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

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

Proved Developed	720.2	27,794
Proved Undeveloped	1,755.8	20,273

Total Proved	2,476.0	48,067

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

Estimates of the net present worth derived from the proved developed and total proved reserves of GeoPark’s net petroleum interests, as of June 30, 2013, 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		97,872
Total Proved		209,129

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

	Submitted,

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

SIGNED: August 14, 2013

		/s/ R. M. Shuck, P.E.
		R. M. Shuck, P.E.
	[SEAL]	Senior Vice President
		DeGolyer and MacNaughton

Aug. 14, 2013

TABLE 1

SUMMARY of GROSS and NET PROVED RESERVES

as of

JUNE 30, 2013

for

CERTAIN FIELDS

BRAZIL 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)

Brazil

710.0

71.0

277,940

27,794

530.0

53.0

202,730

20,273

1,240.0

124.0

480,670

48,067

Colombia

1,497.0

649.2

4,087.0

1,702.8

5,584.0

2,352.0

Total

2,207.0

720.2

277,940

27,794

4,617.0

1,755.8

202,730

20,273

6,824.0

2,476.0

480,670

48,067

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

Aug. 14, 2013

TABLE 2

GROSS and NET PROVED RESERVES by FIELD

as of

JUNE 30, 2013

for

CERTAIN FIELDS

BRAZIL

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

Block

Condensate

Gas

Condensate

Gas

Condensate

Gas

Field

(Mbbl)

(MMcf)

(Mbbl)

(MMcf)

(Mbbl)

(MMcf)

BCAM-40

Manati

710.0

71.0

277,940

27,794

530.0

53.0

202,730

20,273

1,240.0

124.0

480,670

48,067

Aug. 14, 2013

TABLE 3

GROSS and NET PROVED RESERVES by FIELD

as of

JUNE 30, 2013

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

Sales

Oil and

Sales

Oil and

Sales

Block

Condensate

Gas

Condensate

Gas

Condensate

Gas

Field

(Mbbl)

(MMcf)

(Mbbl)

(MMcf)

(Mbbl)

(MMcf)

Yamu

Potrillo

127.0

87.7

100.0

69.0

227.0

156.7

Llanos Block 34

Tarotaro

1,370.0

561.5

3,987.0

1,633.8

5,357.0

2,195.3

Total

1,497.0

649.2

4,087.0

1,702.8

5,584.0

2,352.0

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

Aug. 14, 2013

TABLE 4

STANDARDIZED MEASURE of DISCOUNTED FUTURE NET CASH FLOWS

relating to

PROVED RESERVES

as of

JUNE 30, 2013

for

CERTAIN PROPERTIES

BRAZIL and COLOMBIA

with interests owned by

GEOPARK HOLDINGS LIMITED

	Total Proved
	Brazil		Colombia		Total
	(M U.S.$)		(M U.S.$)		(M U.S.$)
Future cash inflows	323,363		165,619		488,982
Future production costs	130,628		25,249		155,877
Future development costs	6,331		12,615		18,946
Future income tax expenses	5,247		43,342		48,589
Future net cash flows	181,157		84,413		265,570
10% annual discount for estimated timing of cash flows	(43,967	)	(12,474	)	(56,441	)

Standardized measure of discounted future net cash flows	137,190		71,939		209,129

Discounted future net cash flows at 10 percent before corporate income tax expenses	141,903		109,365		251,268

Notes:

1. GeoPark’s interest in the Manati field in Brazil was acquired on May 14, 2013.

2. GeoPark’s Colombia interests represent new discoveries in 2013.

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

4. 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.