EX-99.2 15 ec-20231231xex99d2.htm EX-99.2

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Exhibit 99.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

January 22, 2024

Board of Directors

Ecopetrol S.A.

Carrera 13 No. 36-24

Bogota, D.C.

Colombia

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2023, of the extent of the estimated net proved hydrocarbon reserves of certain properties in Colombia and the United States in which Ecopetrol S.A. has represented it holds an interest. These interests are held by Ecopetrol S.A. and through its wholly owned subsidiaries Ecopetrol America LLC, Ecopetrol Permian LLC, and Hocol S.A. (collectively, “ECOPETROL”).This evaluation was completed on January 22, 2024. ECOPETROL has represented that these properties account for 44.02 percent on a net equivalent barrel basis of ECOPETROL’s net proved reserves as of December 31, 2023. ECOPETROL has also represented that these properties account for 38.55 percent of ECOPETROL’s total proved developed net liquid hydrocarbon (oil, condensate, C5+, and LPG) reserves, 8.75 percent of its total proved developed net gas reserves, 61.52 percent of its total proved undeveloped net liquid reserves, and 41.86 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 United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S– K and is to be used for inclusion in certain SEC filings by ECOPETROL.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2023. Net reserves are defined as that portion of the gross reserves attributable to the interests held by ECOPETROL after deducting all interests held by others, including royalties paid in kind. ECOPETROL has advised that in September 2013, Resolución n° 877 was enacted by the government of Colombia, requiring that oil and condensate royalties be paid in kind and gas and C5+

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and LPG royalties be paid in cash. Based on this legislation, and at the request of ECOPETROL, royalties associated with gas and C5+ and LPG reserves for the properties in Colombia have been considered as a cash payment and are therefore included in the net gas and C5+ and LPG reserves estimated herein.

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

Information used in the preparation of this report was obtained from ECOPETROL. In the preparation of this report we have relied, without independent verification, upon information furnished by ECOPETROL with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves estimated in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us 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

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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

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engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report,determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

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(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.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by ECOPETROL, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The undeveloped reserves estimated herein were based on opportunities identified in the plan of development provided by ECOPETROL.

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

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and

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water saturation. When adequate data were available and when circumstances justified, material-balance methods were used to estimate OOIP and OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP and OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

For 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 as defined under the Definition of Reserves heading of this report or the expiration date of the fiscal agreement, whichever occurs first.

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

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

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

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

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Data provided by ECOPETROL from wells drilled through December 31, 2023, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through October, or November 2023. Estimated cumulative production, as of December 31, 2023, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. Oil is reported herein as oil and fuel oil. Fuel oil is defined as that portion of the oil consumed in field operations. Oil includes fuel oil. Pentanes and heavier fractions (C5+) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, are the result of low-temperature plant processing. Oil, condensate, C5+, and LPG reserves included in this report are expressed in millions of barrels (106bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as marketable gas, fuel gas, and sales gas. Marketable gas is defined as the total gas produced from the reservoir after reduction for shrinkage resulting from field separation; processing, including removal of the nonhydrocarbon gas to meet pipeline specifications; and flare and other losses but not from fuel usage. Fuel gas is defined as that portion of the gas consumed in field operations. 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 quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.73, 14.65, and 15.025 pounds per square inch absolute (psia) for the Gulf of Mexico, Texas, and New Mexico respectively. Gas quantities included in this report are expressed in millions of cubic feet (106ft3).

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

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At the request of ECOPETROL, marketable gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 5,700 cubic feet of gas per 1 barrel of oil equivalent.

Primary Economic Assumptions

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

Oil, Condensate, C5+, LPG, and Sales Gas Prices

ECOPETROL has represented that the oil and condensate prices were based on a reference 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.

ECOPETROL has represented that the C5+, LPG, and sales gas prices for the ECOPETROL properties in Colombia evaluated herein are defined by contractual agreements for gas sales based on specific market conditions. ECOPETROL supplied differentials by field to the Brent reference price of U.S.$82.80 per barrel. The volume-weighted average adjusted product prices attributable to the estimated proved reserves were U.S.$65.22 per barrel of oil and condensate, U.S.$84.21 per barrel of C5+, and U.S.$25.51 per barrel of LPG. The volume- weighted average adjusted product sales gas price attributable to the estimated proved sales gas reserves was U.S.$14.256 per thousand cubic feet of gas. Prices were held constant for the lives of the properties unless defined by contractual agreements.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses, provided by ECOPETROL and based on existing economic conditions, were held constant for the lives of the properties. Future capital expenditures were

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estimated using 2023 values, provided by ECOPETROL, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of the wells, and reclamation and restoration associated with the abandonment, were provided by ECOPETROL for all properties. Estimates of operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.

In our opinion, the information relating to estimated proved reserves of oil, condensate, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year and (ii) certain proved undeveloped reserves are scheduled for development more than 5 years after initial disclosure. The development plans provided by ECOPETROL for the properties evaluated herein include all development to be executed within 5 years of initial disclosure. In addition, the proved undeveloped reserves estimated for the Caño Sur Este field include locations with production start dates that extend beyond the 5-year initial disclosure period and are associated with the current water-handling capacities in these fields. ECOPETROL has represented that these wells are part of ongoing development projects and that all remaining development investments for these wells will be completed within 7 years from their initial disclosure. Based on these representations, reserves associated with these wells were classified as proved.

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.

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Summary of Conclusions

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DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate, C5+,, LPG, and gas reserves of certain properties in which ECOPETROL has represented it holds an interest.

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The estimated net proved reserves, as of December 31, 2023, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in millions of barrels (106bbl), millions of cubic feet (106ft3), and millions of barrels of oil equivalent (106boe):

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Estimated by DeGolyer and MacNaughton Net Proved Reserves

as of December 31, 2023

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​ |  | Oil and Condensate (106bbl) |  | Fuel Oil (106bbl) |  | C5+ (106bbl) |  | LPG (106bbl) |  | Marketable Gas (106ft3) |  | Fuel Gas (106ft3) |  | Sales Gas (106ft3) |  | Oil Equivalent (106boe) |
Colombia Proved Developed | ​ | 445.071 | ​ | 0.809 | ​ | 0.080 | ​ | 0.183 | ​ | 74,825.983 | ​ | 4,598.548 | ​ | 70,227.435 | ​ | 459.008 | ​
Proved Undeveloped | ​ | 148.617 | ​ | 2.644 | ​ | 0.002 | ​ | 0.006 | ​ | 24,884.690 | ​ | 1,029.387 | ​ | 23,855.303 | ​ | 155.626 | ​
Colombia Total Proved | ​ | 593.688 | ​ | 3.453 | ​ | 0.082 | ​ | 0.188 | ​ | 99,710.673 | ​ | 5,627.935 | ​ | 94,082.738 | ​ | 614.624 | ​
United States Proved Developed | ​ | 56.821 | ​ | 0.000 | ​ | 19.379 | ​ | 0.000 | ​ | 100,878.913 | ​ | 0.000 | ​ | 100,878.913 | ​ | 93.899 | ​
Proved Undeveloped | ​ | 75.403 | ​ | 0.000 | ​ | 24.044 | ​ | 0.000 | ​ | 116,835.362 | ​ | 0.000 | ​ | 116,835.362 | ​ | 119.944 | ​
United States Total Proved | ​ | 132.224 | ​ | 0.000 | ​ | 43.423 | ​ | 0.000 | ​ | 217,714.275 | ​ | 0.000 | ​ | 217,714.275 | ​ | 213.843 | ​
Total Proved | ​ | 725.912 | ​ | 3.453 | ​ | 43.505 | ​ | 0.188 | ​ | 317,424.948 | ​ | 5,627.935 | ​ | 311,797.013 | ​ | 828.467 | ​

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1. Totals may vary due to rounding.

2. Marketable gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 5,700 cubic feet of gas per 1 barrel of oil equivalent, as provided by ECOPETROL.

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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 reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2023, estimated reserves.

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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 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.

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​ |  | Submitted,
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​ | ​ | /s/ DeGOLYER and MacNAUGHTON
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​ | ​ | DeGOLYER and MacNAUGHTON
​ | ​ | Texas Registered Engineering Firm F-716

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​ | ​ | /s/ Peter R. Laudon, P.E., P.G.
​ | ​ | Peter R. Laudon, P.E., P.G.
​ | ​ | Vice President
​ | ​ | DeGolyer and MacNaughton

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CERTIFICATE of QUALIFICATION

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

| 1. | That I am a Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to ECOPETROL dated January 22, 2024, and that I, as Vice President, was responsible for the preparation of this report of third party.

| 1. | That I attended the University of Kansas, and that I graduated with a Bachelor of Science degree in Geology in the year 1988; that I attended the University of Missouri-Columbia and the Missouri University of Science and Technology, and that I graduated with a Master of Science degree in Geology and Geophysics in the year 1992; that I attended the Missouri University of Science and Technology, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1995; that I am a Licensed Professional Engineer and Licensed Professional Geologist in the State of Texas; that I am a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, the American Association of Professional Geologists, the Society of Independent Professional Earth Scientists, the Society of Professional Well Log Analysts; and that I have 29 years of petroleum industry experience and have been independently evaluating reserves and resources in excess of 20 years.

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​ |  | /s/ Peter R. Laudon, P.E., P.G.
​ | ​ | ​
​ | ​ | Peter R. Laudon, P.E., P.G.
​ | ​ | Vice President
​ | ​ | DeGolyer and MacNaughton

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