Exhibit 99.3



DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244



February 27, 2014



Board of Directors

Ecopetrol S.A.

Calle 35 No. 7-21 Piso 1

Bogota, D.C. Colombia



Ladies and Gentlemen:



Pursuant to your request,
we have audited the net proved hydrocarbon reserves, as of December 31, 2013, of certain selected properties in Colombia and Peru
in which Ecopetrol S.A. has represented are owned by Ecopetrol S.A., its wholly owned subsidiary Hocol Petroleum Limited, and through
its ownership interest in Savia Peru S.A. (collectively, “ECOPETROL”). This evaluation was completed on February 27,
2014. ECOPETROL has represented that these properties account for 20 percent on a net equivalent barrel basis of ECOPETROL’s
net proved reserves as of December 31, 2013. ECOPETROL has also represented that these properties account for 27 percent of ECOPETROL’s
total proved developed net liquid hydrocarbon (oil, condensate, and natural gas liquids (NGL)) reserves, 1 percent of its total
proved developed net gas reserves, 28 percent of its total proved undeveloped net liquid hydrocarbon reserves, and 15 percent
of its total proved undeveloped net gas reserves. The net proved reserves estimates have been prepared in accordance with the reserves
definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the
United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to
be used for inclusion in certain SEC filings by ECOPETROL.



Reserves included herein
are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties
after December 31, 2013. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by
ECOPETROL after deducting all interests owned by others, including royalties paid in kind.











Estimates of oil, condensate,
NGL, and natural gas reserves should be regarded only as estimates that may change as further production history and additional
information become available. Not only are such reserves estimates based on that information which is currently available, but
such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.



Data used in this audit
were obtained from reviews with ECOPETROL personnel, ECOPETROL files, from records on file with the appropriate regulatory agencies,
and from public sources. In the preparation of this report we have relied, without independent verification, upon such information
furnished by ECOPETROL with respect to property interests, production from such properties, current costs of operation and development,
current prices for production, agreements relating to current and future operations and sale of production, and various other information
and data that were accepted as represented. We believe the data used in this audit are appropriate for the purposes of this report.



Methodology and Procedures



Estimates of reserves
were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance
with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers
entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February
19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar
reservoirs, stage of development, quality and completeness of basic data, and production history.



When applicable, the
volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach
maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data
were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data
were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.





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Estimates of ultimate
recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the
type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production
histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. In such cases,
an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the
estimation of reserves.



For depletion-type
reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics,
reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of
production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production
licenses as appropriate.



Gas quantities estimated
herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point
of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves
are expressed at a temperature base of 60 degrees Fahrenheit and a pressure base of 14.7 pounds per square inch absolute.
Condensate reserves estimated herein are those to be recovered by conventional field separation.



In this report NGL
are defined to be liquefied petroleum gas (LPG) and C5+. LPG is defined to be propane and butane.



The proved reserves
for the properties included herein were estimated by the performance method, the volumetric method, or a combination of performance
and volumetric methods. The following table summarizes the approximate percentage of net reserves estimated by each of these methods.



|Percent Net Proved Reserves Estimated by Method
|-----------------------------------------------
|                                               
|Method                                         
|                                               
|Volumetric                                     
|Performance                                    
|Combination                                    





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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.





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(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.





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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.





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Primary Economic Assumptions



The following economic
assumptions were used for estimating existing and future prices and costs:



Oil, Condensate, and
NGL Prices



ECOPETROL has represented that
the oil, condensate, and NGL 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. The volume-weighted average adjusted
product prices attributable to estimated proved reserves for the properties in Colombia evaluated herein were U.S.$89.78 per barrel
for crude oil and condensate and U.S.$83.16 per barrel for NGL, based on a 12-month average Brent reference price of U.S.$108.32
per barrel. ECOPETROL supplied differentials by field to the Brent reference price, and the prices were held constant thereafter.
ECOPETROL has also represented that the volume-weighted average adjusted product prices attributable to estimated proved reserves
for the properties in Peru evaluated herein were U.S.$105.68 per barrel for crude oil and condensate and U.S.$60.08 per barrel
for NGL based on the 12-month average Ardjuna and Minas crude reference prices, and the prices were held constant thereafter.



Natural Gas Prices



ECOPETROL has represented that
the natural gas prices for the properties in Colombia evaluated herein are defined by contractual agreements based on specific
market conditions. The volume-weighted average adjusted product price attributable to estimated proved reserves was U.S.$4.37 per
thousand cubic feet, and the prices were held constant thereafter. ECOPETROL has also represented that the natural gas prices for
the properties in Peru evaluated herein are defined by contractual agreements based on specific market conditions, and the average
adjusted product price was U.S.$0.92 per thousand cubic feet, and the prices were held constant thereafter.





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Operating Expenses
and Capital Costs



Operating expenses and capital
costs, based on information provided by ECOPETROL, were used in estimating future costs required to operate the properties. In
certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated changes in operating
conditions. These costs were not escalated for inflation.



While the oil and gas
industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover
its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31,
2013, estimated proved oil and gas reserves. The reserves estimated in this report can be produced under current regulatory guidelines.



Our estimates of ECOPETROL’s
net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves of the SEC and are
as follows, expressed in millions of barrels (MMbbl), millions of cubic feet (MMcf), and millions of barrels of oil equivalent
(MMboe):



|                           |  | Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2013 |        
|-------------------------- |  | --------------------------------------------------------------------------------- | -------
|                           |  | Oil, Condensate, 
and NGL (MMbbl)                                                 |        
|                           |  |                                                                                   |        
|South America              |  |                                                                                   |        
|Proved Developed           |  |                                                                                   | 247.696
|Proved Undeveloped         |  |                                                                                   | 141.266
|                           |  |                                                                                   |        
|South America Total Proved |  |                                                                                   | 388.962



| | Note: | Gas
is converted to oil equivalent using a factor of 5,615 cubic feet of gas per 1 barrel of oil equivalent.
| | ----- | ------------------------------------------------------------------------------------------------------------





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In our opinion, the
information relating to estimated proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has
been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards
Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures
(January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules
302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 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.



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DeGolyer and MacNaughton



To the extent
the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as
engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance
therewith or sufficient therefor.



DeGolyer and MacNaughton
is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world
since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in ECOPETROL. Our fees were
not contingent on the results of our evaluation. This letter report has been prepared at the request of ECOPETROL. DeGolyer and
MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this
report.





| | Submitted,                             
| | ---------------------------------------
| |                                        
| | /s/ DeGolyer and MacNaughton           
| |                                        
| | DeGOLYER and MacNAUGHTON               
| | Texas Registered Engineering Firm F-716
| |                                        
| | /s/ R. M. Shuck, P.E.                  
| | R. M. Shuck, P.E.                      
| | Senior Vice President                  
| | DeGolyer and MacNaughton               



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CERTIFICATE of QUALIFICATION



I, R. M. Shuck, Petroleum
Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:



| | 1. | That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter
report addressed to ECOPETROL dated February 27, 2014, and that I, as Senior Vice President, was responsible for the preparation
of this report.
| | -- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 2. | That I attended the University of Houston, and that I graduated with a Bachelor of Science degree
in Chemical Engineering in the year 1977; that I am a Registered Professional Engineer in the State of Texas; that I am a member
of the Society of Petroleum Engineers; and that I have in excess of 36 years of experience in oil and gas reservoir studies and
evaluations.
| | -- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





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