Reserves Statement of Certain Fields,

Colombia

as of December 31, 2021

Prepared for

Ecopetrol S.A.

February 24, 2022

Exhibit 99.4

	GaffneyCline
	4425Westway Park Blvd
	Houston, TX 77041
	Tel: +1 713 850 9955 www.gaffneycline.com
	February 24, 2022

Fidel Delgado Doria

Gerente de Reservas

Ecopetrol S.A.

Calle 13 No. 36 -34

Bogotá, D.C.

Colombia

fidel.delgado@ecopetrol.com.com

Dear Fidel,

SEC Proved Reserves Statement

for Fifty Nine Fields in which Ecopetrol has an Interest, Colombia

as of December 31, 2021

Introduction

This Proved reserves statement has been prepared by Gaffney, Cline & Associates (GaffneyCline) and issued on February 24, 2022 at the request of Ecopetrol S.A. (Ecopetrol, or “the Client”), operator, participant operator, and interest participant in 59 fields in the Lower, Middle and Upper Magdalena Valley, Catatumbo, Piedemonte and Llanos Orientales Basins, Colombia.

This report is intended for use in conjunction with Ecopetrol’s December 31, 2021 filing obligations with the US Securities and Exchange Commission (SEC).

This report relates specifically and solely to the subject matter as defined in the scope of work in the Proposal for Services and is conditional upon the assumptions described herein. The report must be considered in its entirety and must only be used for the purpose for which it was intended.

GaffneyCline has prepared a reserves estimation, as of December 31, 2021, of the hydrocarbon liquids and natural gas reserves of fifty nine fields in which Ecopetrol has an interest in Colombia.

Ecopetrol S.A. www.gaff~eycline.com

Summary and Conclusions

On the basis of technical and other information made available to GaffneyCline concerning these property units, GaffneyCline hereby provides the reserves statement in the following Table 1.

Table 1: Statement of Hydrocarbon Reserves Volumes

Fifty-Nine Fields, Colombia

as of December 31, 2021

Reserves	Reserves Net to Ecopetrol’s Interest
	Oil/Cond. (MBbl)	NGL (MBbl)	Sales Gas (BCF)	Fuel Gas (BCF)
Developed	96,490	47,427	1,274	250
Producing
Non-Producing	10,711	9,907	288	24
Undeveloped	23,002	9,731	258	20
Total Proved	130,202	67,065	1,820	293

Notes:

1. Oil and condensate reserves net to Ecopetrol’s interest represent volumes after the deduction of royalties, under the concessions that govern the assets, based on Ecopetrol’s working interest.

2. Gas and NGL reserves net to Ecopetrol’s working interest include gas and NGL royalty volumes that are required to be paid in cash according to Resolutions 877 and 351 from Agencia Nacional de Hidrocarburos (ANH) and the corresponding clarification note from ANH #20146240188522.

3. Net sales gas reserves exclude volumes consumed in operations (fuel gas), which are reported separately.

4. Fuel gas represents working interest volumes consumed in operations.

5. The above Reserves include production:

a. Until the economic limit when contracts are solely operated by Ecopetrol.

b. Beyond the end of the current license period in concession contracts that include an expiry date which are assumed to revert to Ecopetrol as the sole license holder at the expiry of the contract and, based on information provided by Ecopetrol, normally include a 12% increase in the royalty rate at contract expiry.

6. Totals may not exactly equal the sum of the individual entries because of rounding.

Hydrocarbon liquid volumes represent crude oil and condensate, natural gasoline, and NGL estimated to be recovered during field separation and plant processing and are reported in thousands (103) of stock tank barrels (MBbl).  The volumes reported as gas represent expected

Ecopetrol S.A. February 24, 2022 Page 2 of 24

gas sales and are reported in billions (109) of standard cubic feet at standard conditions (BCF). Standard conditions are defined as 14.7 psia and 60°F. There is no oil consumed as fuel in operations, so it is not reported. The sales gas volumes have been reduced for fuel usage consumed in operations (CiO) and shrinkage because of processing. Royalties due on oil production payable to the State have been deducted from reported net interest volumes. Royalties due on NGL products, including sales gas, are not deducted; because they are paid in cash.

Gas reserves sales volumes are based on firm and existing gas contracts, or on the reasonable expectation of a contract or on the reasonable expectation that any such existing gas sales contracts will be renewed on similar terms in the future.

Ecopetrol has advised GaffneyCline that the Proved volumes included in this report represent 28% of Ecopetrol’s total Proved reserves on an oil-equivalent basis, 14% on oil basis and 67% on gas basis. The volume Proved Undeveloped included in this report represent 13% of Ecpetrol’s total Proved Undeveloped reserves on an oil equivalent basis, 6% on oil basis and 47% on gas basis. Considering the Proved Developed reserves, the volumes include in this report represent 36% on an oil-equivalent basis, 18% on oil basis and 72% on gas basis. GaffneyCline is not in a position to verify this statement as it was not requested to review Ecopetrol’s other oil and gas assets.

Descriptions of the fields are included in the technical reports, which have been issued separately.

Ecopetrol S.A. February 24, 2022 Page 3 of 24

Reserves Assessment

GaffneyCline’s estimate of reserves was based on data provided by Ecopetrol to GaffneyCline from September 2021 to December 2021. During this audit GaffneyCline used one or more of the following methods to assess the reserves: volumetric, performance or analogy, depending on the information available and the stage of development of the reservoir. Reserves volumes for existing wells were based on performance analysis (decline of production and behavior of appropriate fluid ratios). Reserves volumes for undrilled wells were based on established performance of analogous wells. Where appropriate, checks were made using estimates of hydrocarbons in place derived from a volumetric analysis. Production forecasts were first prepared to reasonable technical limits and then truncated by the economic limit.

GaffneyCline performed procedures necessary to enable it to render an opinion on the appropriateness of the methodologies employed, adequacy and quality of the data relied on, depth and thoroughness of the reserves estimation process, classification and categorization of reserves appropriate to the relevant definitions used, and reasonableness of the estimates.

The economic tests for the December 31, 2021 reserves volumes were based on prior twelve- month first-day-of-the-month average reference price for the Brent crude of US$ 69.24/Bbl, corrected for location and quality. Sales gas and plant product prices were advised by Ecopetrol according to existing contracts and/or regulations. No price escalation has been included, other than as provided for in existing contracts.

Future capital costs for operated and non-operated fields were provided by Ecopetrol.

Recent historical operating expense data were used as the basis for operating cost projections. Neither capital not operating costs were escalated for inflation. GaffneyCline has found that sufficient capital investments and operating expenses have been projected to produce the estimated volumes.

It is GaffneyCline’s opinion that the estimates of total remaining recoverable hydrocarbon liquid and gas volumes as of December 31, 2021 are, in the aggregate, reasonable and the reserves classification and categorization is appropriate and consistent with the definitions for reserves in Part 210 Rule 4-10(a) of Regulation S-X of the US Securities and Exchange Commission, which are provided in Appendix I.  A glossary of term is presented in Appendix III.

GaffneyCline is not aware of any potential changes in regulations applicable to these fields that could affect the ability of Ecopetrol to produce the estimated reserves.

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Basis of Opinion

This document reflects GaffneyCline’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client, the limited scope of engagement, and the time permitted to conduct the evaluation.

In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. GaffneyCline has not independently verified any information provided by, or at the direction of, the Client, and has accepted the accuracy and completeness of this data. GaffneyCline has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.

The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances,  scenarios and information that  could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.

There are numerous uncertainties inherent in estimating reserves, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas reserves assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas reserves prepared by other parties may differ, perhaps materially, from those contained within this report.

The accuracy of any reserves estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post- date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.

GaffneyCline has not undertaken a site visit and inspection because it was not included in the scope of work. As such, GaffneyCline is not in a position to comment on the operations or facilities in place, their appropriateness and condition, or whether they are  in compliance with the regulations pertaining to such operations. Further, GaffneyCline is not in a position to comment on any aspect of health, safety, or environment of such operation.

This report has been prepared based on GaffneyCline’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, GaffneyCline is not in a position to attest to property title or rights, conditions of these rights (including environmental and abandonment obligations), or any necessary licenses and consents (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties).

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Definition of Reserves

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce, or a revenue interest in, the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. All categories of reserves volumes quoted herein have been derived within the context of an economic limit test (ELT) assessment (pre-tax and exclusive of accumulated depreciation amounts) prior to any net present value (NPV) analysis.

This report has been prepared based on GaffneyCline’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties.

GaffneyCline is not aware of any carbon pricing impost or GHG emissions related to regulations that are applicable to the evaluation of the assets that are the subject of this report. GaffneyCline has also not included the impact of any potential carbon pricing scheme or regulatory compliance costs for GHG emissions that may be implemented in the future.

Qualifications

In performing this study, GaffneyCline is not aware that any conflict of interest has existed. As an independent consultancy, GaffneyCline is providing impartial technical, commercial, and strategic advice within the energy sector. GaffneyCline’s remuneration was not in any way contingent on the contents of this report.

In the preparation of this document, GaffneyCline has maintained, and continues to maintain, a strict independent consultant-client relationship with Ecopetrol. Furthermore, the management and employees of GaffneyCline have no interest in any of the assets evaluated or related with the analysis performed as part of this report. The qualifications of the technical person primarily responsible for overseeing this estimate are provided in Appendix II.

Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work.

Ecopetrol S.A. February 24, 2022 Page 6 of 24

Notice

This report was prepared for public disclosure in its entirety by Ecopetrol in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. Ecopetrol will obtain GaffneyCline’s prior written approval for any other use of any results, statements or opinions expressed to Ecopetrol in this report that are attributed to GaffneyCline.

Yours sincerely,

Gaffney, Cline & Associates

Project Manager

Eduardo Sanchez, Principal Advisor

Reviewer

Rawdon J.H. Seager, Technical Director

Appendices

Appendix I	SEC Reserves Definitions
Appendix II	Technical Qualifications of Person Responsible for the Reserves Certification
Appendix III	Glossary

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Appendix I

SEC Reserves Definitions

Ecopetrol S.A.

February 24, 2022

U.S. SECURITIES AND EXCHANGE COMMISSION (SEC) MODERNIZATION OF OIL AND GAS REPORTING1

Oil and Gas Reserves Definitions and Reporting

(a)Definitions

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi- solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

¹    Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08] RIN 3235-AK00].

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(6) 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.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

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(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas- of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

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(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) 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%

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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 (a)(22)(iii) of this section, 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.

(18) 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

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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 (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities, they become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, arid fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) 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

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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.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there

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should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable.  Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration.

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Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) 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 paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties.  Properties with no proved reserves.

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February 24, 2022

Appendix II

Technical Qualifications of Person Responsible for the

Reserves Statement

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February 24, 2022

The reserves estimate of certain of Ecopetrol’s interests prepared by Gaffney, Cline & Associates (GaffneyCline), the results of which are presented in this report, was carried out by engineers and geoscientists under the direction of Mr. Eduardo Sanchez Josseaume.

Eduardo Sanchez J. is a Principal Advisor with GaffneyCline in Argentina and is responsible for preparing reserves audits, certifications and field evaluations. He was responsible for overseeing the preparation of the reserves estimate of certain Ecopetrol interests.

Mr. Sanchez has over 35 years of experience in the international oil and gas industry, with extensive experience in exploration, production and reservoir geosciences. He is qualified as a Reserves Auditor through having more than 30 years’ experience in petroleum geology with estimation and evaluation of Reserves Information. He holds a Master of Science degree in Geological Sciences from Universidad Nacional de Buenos Aires, Argentina, and a Postgrad in Business Administration from International Business School, Neuquén Argentina.

Mr. Sanchez is a member in good standing of the American Association of Petroleum Geologists (AAPG).

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February 24, 2022

Appendix III

Glossary

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February 24, 2022

%	Percentage	BTU	British Thermal Units
1H05	First half (6 months) of 2005 (example)	bwpd	Barrels water per day
2Q06	Second quarter (3 months) of 2006 (example)	CBM	Coal Bed Methane
2D	Two dimensional	CiO	Consumed in Operations
3D	Three dimensional	CO2	Carbon Dioxide
4D	Four dimensional	CAPEX	Capital Expenditure
1P	Proved Reserves	CCGT	Combined Cycle Gas Turbine
2P	Proved plus Probable Reserves	cm	centimetres
3P	Proved plus Probable plus Possible Reserves	CMM	Coal Mine Methane
ABEX	Abandonment Expenditure	CNG	Compressed Natural Gas
ACQ	Annual Contract Quantity	Cp	Centipoise (a measure of viscosity)
oAPI	Degrees API (American Petroleum Institute)	CSG	Coal Seam Gas
AAPG	American Association of Petroleum Geologists	CT	Corporation Tax
AVO	Amplitude versus Offset	D1BM	Design 1 Build Many
A$	Australian Dollars	DCQ	Daily Contract Quantity
B	Billion (109)	Deg C	Degrees Celsius
Bbl	Barrels	Deg F	Degrees Fahrenheit
/Bbl	per barrel	DHI	Direct Hydrocarbon Indicator
BBbl	Billion Barrels	DLIS	Digital Log Interchange Standard
BHA	Bottom Hole Assembly	DST	Drill Stem Test
BHC	Bottom Hole Compensated	DWT	Dead-weight ton
Bscf or Bcf	Billion standard cubic feet	E&A	Exploration & Appraisal
Bscfd or Bcfd	Billion standard cubic feet per day	E&P	Exploration and Production
Bm3	Billion cubic metres	EBIT	Earnings before Interest and Tax
bcpd	Barrels of condensate per day	EBITDA	Earnings before interest, tax, depreciation and amortisation
BHP	Bottom Hole Pressure	ECS	Elemental Capture Spectroscopy
blpd	Barrels of liquid per day	EI	Entitlement Interest
bpd	Barrels per day	EIA	Environmental Impact Assessment
boe	Barrels of oil equivalent @ xxx mcf/Bbl	ELT	Economic Limit Test
boepd	Barrels of oil equivalent per day @ xxx mcf/Bbl	EMV	Expected Monetary Value
BOP	Blow Out Preventer	EOR	Enhanced Oil Recovery
bopd	Barrels oil per day	EUR	Estimated Ultimate Recovery
bwpd	Barrels of water per day	FDP	Field Development Plan
BS&W	Bottom sediment and water	FEED	Front End Engineering and Design
		FPSO	Floating Production Storage and Offloading
		FSO	Floating Storage and Offloading

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FWL	Free Water Level	LKH	Lowest Known Hydrocarbons
ft	Foot/feet	LKO	Lowest Known Oil
Fx	Foreign Exchange Rate	LNG	Liquefied Natural Gas
g	gram	LoF	Life of Field
g/cc	grams per cubic centimetre	LPG	Liquefied Petroleum Gas
gal	gallon	LTI	Lost Time Injury
gal/d	gallons per day	LWD	Logging while drilling
G&A	General and Administrative costs	m	Metres
GBP	Pounds Sterling	M	Thousand
GCoS	Geological Chance of Success	m3	Cubic metres
GDT	Gas Down to	Mcf or Mscf	Thousand standard cubic feet
GIIP	Gas Initially In Place	MCM	Management Committee Meeting
GJ	Gigajoules (one billion Joules)	MMcf or MMscf	Million standard cubic feet
GOC	Gas Oil Contact	m3/d	Cubic metres per day
GOR	Gas Oil Ratio	mD	Measure of Permeability in millidarcies
GRV	Gross Rock Volumes	MD	Measured Depth
GTL	Gas to Liquids	MDT	Modular Dynamic Tester
GWC	Gas water contact	Mean	Arithmetic average of a set of numbers
HDT	Hydrocarbons Down to	Median	Middle value in a set of values
HSE	Health, Safety and Environment	MFT	Multi Formation Tester
HSFO	High Sulphur Fuel Oil	mg/l	milligrams per litre
HUT	Hydrocarbons up to	MJ	Megajoules (One Million Joules)
H2S	Hydrogen Sulphide	Mm3	Thousand Cubic metres
IOR	Improved Oil Recovery	Mm3/d	Thousand Cubic metres per day
IPP	Independent Power Producer	MM	Million
IRR	Internal Rate of Return	MMm3	Million Cubic metres
J	Joule (Metric measurement of energy) I kilojoule = 0.9478 BTU)	MMm3/d	Million Cubic metres per day
k	Permeability	MMBbl	Millions of barrels
KB	Kelly Bushing	MMBTU	Millions of British Thermal Units
KJ	Kilojoules (one Thousand Joules)	Mode	Value that exists most frequently in a set of values = most likely
kl	Kilolitres	Mscfd	Thousand standard cubic feet per day
km	Kilometres	MMscfd	Million standard cubic feet per day
km2	Square kilometres	MW	Megawatt
kPa	Thousands of Pascals (measurement of pressure)	MWD	Measuring While Drilling
KW	Kilowatt	MWh	Megawatt hour
KWh	Kilowatt hour	mya	Million years ago
LAS	Log ASCII Standard	NGL	Natural Gas Liquids
LKG	Lowest Known Gas	N2	Nitrogen

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NTG	Net/Gross Ratio	SPE	Society of Petroleum Engineers
NPV	Net Present Value	SPEE	Society of Petroleum Evaluation
OBM	Oil Based Mud	SPS	Subsea Production System
OCM	Operating Committee Meeting	SS	Subsea
ODT	Oil-Down-To	stb	Stock tank barrel
OGIP	Original Gas in Place	STOIIP	Stock tank oil initially in place
OIIP	Oil Initially In Place	Swi	irreducible water saturation
OOIP	Original Oil in Place	sw	Water Saturation
OPEX	Operating Expenditure	T	Tonnes
OWC	Oil Water Contact	TD	Total Depth
p.a.	Per annum	Te	Tonnes equivalent
Pa	Pascals (metric measurement of pressure)	THP	Tubing Head Pressure
P&A	Plugged and Abandoned	TJ	Terajoules (1012 Joules)
PDP	Proved Developed Producing	Tscf or Tcf	Trillion standard cubic feet
Phie	effective porosity	TCM	Technical Committee Meeting
PI	Productivity Index	TOC	Total Organic Carbon
PIIP	Petroleum Initially In Place	TOP	Take or Pay
PJ	Petajoules (1015 Joules)	Tpd	Tonnes per day
PSDM	Post Stack Depth Migration	TVD	True Vertical Depth
psi	Pounds per square inch	TVDss	True Vertical Depth Subsea
psia	Pounds per square inch absolute	UFR	Umbilical Flow Lines and Risers
psig	Pounds per square inch gauge	USGS	United States Geological Survey
PUD	Proved Undeveloped	US$	United States dollar
PVT	Pressure, Volume and Temperature	VLCC	Very Large Crude Carrier
P10	10% Probability	Vsh	shale volume
P50	50% Probability	VSP	Vertical Seismic Profiling
P90	90% Probability	WC	Water Cut
RF	Recovery factor	WI	Working Interest
RFT	Repeat Formation Tester	WPC	World Petroleum Council
RT	Rotary Table	WTI	West Texas Intermediate
R/P	Reserve to Production	wt%	Weight percent
Rw	Resistivity of water
SCAL	Special core analysis
cf or scf	Standard Cubic Feet
cfd or scfd	Standard Cubic Feet per day
scf/ton	Standard cubic foot per ton
SL	Straight line (for depreciation)
so	Oil Saturation
SPM	Single Point Mooring

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February 24, 2022