Exhibit 15.a (iv)

DeGolyer and MacNaughton

5001 Spring Valley Road
Suite 800 East

Dallas, Texas 75244

February 16, 2026

Mr. Alessandro Tiani
Head of Reserves
Eni S.p.A.

Via Emilia 1

20097 San Donato Milanese
Italia

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2025, of the extent of the estimated net proved oil, condensate, liquefied petroleum gas (LPG), and gas reserves of certain properties in which Eni S.p.A. (Eni) has represented it holds an interest through its 50.00-percent corporate ownership of Azule Energy S.p.A. This evaluation was completed on February 16, 2026. The properties evaluated herein consist of working interests located offshore Angola (Table 1). Eni has represented that these properties account for 3.0-percent on a net equivalent barrel basis of Eni’s net proved reserves as of December 31, 2025, and that Eni’s 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). It is our opinion that the procedures and methodologies employed by Eni for the preparation of its proved reserves estimates as of December 31, 2025, comply with the current requirements of the SEC. We have reviewed information provided to us by Eni that it represents to be Eni’s estimates of the net reserves, as of December 31, 2025, for the same properties as those which we have independently evaluated. 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 Eni.

Reserves estimated herein are expressed as net reserves as represented by Eni. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2025. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Eni after deducting all interests held by others.

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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 provided by or on behalf of Eni. In the preparation of this report we have relied, without independent verification, upon information furnished by or on behalf of Eni 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.

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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 established production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

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(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.

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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# 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.” 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 plan provided by or on behalf of Eni, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

The proved undeveloped reserves estimates were based on opportunities identified in the plan of development provided by or on behalf of Eni.

Eni has represented that it has confirmed through its corporate ownership that the operator is committed to the development plan provided by or on behalf of Eni and that the operator has the financial capability to execute the development plans, 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 water saturation.

When applicable, 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, other engineering methods were used to estimate recovery factors based on 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 to the expiration of the production agreement, whichever occurred first. In the estimation of reserves, the current production license limits (including known extensions, as described herein) for each license were applied.

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.

In certain fields, reservoir simulation studies performed by Eni were reviewed. The available data related to future field development were also examined.

Data provided by or on behalf of Eni from wells drilled through December 31, 2025, 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 July 2025 or August 2025. Estimated cumulative production, as of December 31, 2025, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 5 months.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. LPG reserves estimated herein consist primarily of propane and butane fractions and are the result of low-temperature plant processing. Oil, condensate, and LPG reserves included in this report are expressed in millions of barrels (10 6 bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil, condensate, and LPG reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as marketable gas and fuel 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. Gas reserves estimated herein are reported as marketable gas reserves; therefore, fuel gas is included as reserves. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (◦F) and at a pressure base of 14.696 pounds per square inch absolute (psia). Gas quantities included in this report are expressed in billions of cubic feet (10 9 ft 3).

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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 consist of associated and nonassociated gas.

# Primary Economic Assumptions

This report has been prepared using initial prices, expenses, and costs provided by or on behalf of Eni 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, LPG, and Gas Prices

Oil, condensate, LPG, and gas prices were furnished by or on behalf of Eni for each contract area and were held constant for the remaining producing lives of the fields. The prices were based on a reference price, calculated as the unweighted arithmetic 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. The Brent marker price for the period was U.S.$69.29 per barrel. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were U.S.$68.13 per barrel of oil, U.S.$50.70 per barrel of condensate, and U.S.$29.32 per barrel of LPG. Eni has represented that the gas prices are defined by contractual agreements. The volume-weighted average gas price attributable to the estimated proved reserves over the lives of the properties was U.S.$3.40 per thousand cubic feet of sales gas.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses were based on information provided by or on behalf of Eni and based on existing economic conditions. In certain cases, future expenses, either higher or lower than current expenses, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Future capital expenditures were estimated using current capital cost forecasts provided by Eni and were not adjusted for inflation. Certain capital cost forecasts include contractual spending as and when agreed.

Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were estimated using information provided by Eni and were not adjusted for inflation. In the case of undeveloped reserves, incremental abandonment costs were considered in the estimates.

Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.

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Fiscal Terms and Host Country Taxes

Eni has defined certain contract areas, which are groups of fields within an area governed by a specific agreement with the government of Angola. Host country taxes, where applicable, are taxes paid to the government of Angola. The economic models used in this report were constructed based upon the fiscal terms applicable to these contract areas. Projections of estimated production, operating expenses, and capital costs were summed for each field within each of the contract areas. These summed projections were used as input into the economic model.

In our opinion, the information relating to estimated proved reserves of oil, condensate, LPG, 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, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the SEC; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

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

# Summary of Conclusions

DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate, LPG, and marketable gas reserves of certain properties located offshore Norway in which Eni has represented it holds an interest through its 50-percent corporate ownership of Azule Energy S.p.A. Eni has represented that its estimated net proved reserves attributable to the evaluated properties were based on the definitions of proved reserves of the SEC.

Eni has represented that its estimated net proved reserves, as of December 31, 2025, attributable to its ownership in Azule Energy S.p.A., which represent 3.0 percent of Eni’s net reserves, are summarized as follows, expressed in millions of barrels (10 6 bbl) and billions of cubic feet (10 9 ft 3):

| Estimated by Eni
| Net Proved Reserves
| as of December 31, 2025
| Oil, Condensate, | Marketable
| and LPG | Gas
| (10 6 bbl) | (10 9 ft 3)
Total Proved | 160 | 228

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In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by Eni, the aggregate difference has been found to be less than 5 percent. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by Eni on the properties evaluated and referred to above do not differ materially from those estimated by DeGolyer and MacNaughton.

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, 2025, estimated reserves.

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 Eni. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Eni. 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/ Peter Laudon
| Peter Laudon, P.E., P.G.
| Vice President
| DeGolyer and MacNaughton

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DEGOLYER AND MACNAUGHTON

# CERTIFICATE of QUALIFICATION

I, Peter Laudon, 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 an Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Eni dated February 16, 2026, and that I, as Vice President, was responsible for the preparation of this report of third party.

2. That I attended the University of Kansas, and that I graduated with a Bachelor of Science degree in Geology in the year 1988, and that I attended the University of Missouri at Rolla, and that I graduated with both a Master of Science degree in Geology in the year 1992 and a Bachelor of Science degree in Petroleum Engineering in the year 1995; that I am a Licensed Professional Geologist and that I am a Licensed Professional Engineer in the State of Texas; that I am a member of the American Association of Petroleum Geologists, the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, the Society of Professional Well Log Analysts, and the American Association of Petroleum Geologists; and that I have in excess of 32 years of experience in oil and gas reservoir studies and evaluations.

| /s/ Peter Laudon
| Regnald A. Boles, P.E.
| Executive Vice President
| DeGolyer and MacNaughton

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TABLE 1

Block Area Field |  | Block Area Field |  | Block Area Field |  | Block Area Field
Block 0 |  | Block 14K |  | Block 17 |  | Block 31/21
Area A&B |  | Lianzi |  | Clov |  | 31/21
Banzala Bomboco Cabinda A LPG |  | Lianzi Block 15 |  | Cravo Lirio O11W |  | Ceres Cordelia Dione
Cabinda B LPG |  | Kizomba A |  | OVM |  | Hebe
Kokongo |  | Chocalho |  | Dalia |  | Leda
Kungulo Limba Limba SW Lomba |  | Clochas Hungo Marimba Kizomba B |  | Dalia Manganes Tulipa Girassol |  | Miranda Oberon Portia Tebe
Mafumeira Malongo North Malongo West |  | Bavuca Bavuca South Dikanza |  | Girassol – Jasmin Rosa Paz Flor |  | Terra Titania Urano
Nemba North N'dola Nsano Nsinga Numbi |  | Kakocha Kissanje Likembe Mavacola Mondo |  | Acacia Perpetua - Hortensia Zinia Block 18 |  |
Sanha |  | Mondo |  | Greater Plutonio |  |
Takula Vuko Wamba |  | Mondo South Saxi-Batuque |  | Cesio Cobalto Cromio |  |
Lifua |  | Batuque |  | Galio |  |
Lifua South N'dola |  | Saxi |  | Paladio Platina |  |
South N'dola |  | Block 15/06 |  | Plutonio |  |
|  | East Hub |  |  |  |
Block 1&2 - NGC |  | Afoxe |  | Block 31 |  |
1&2 NGC |  | Agidigbo |  | PAJ |  |
Maboqueiro |  | Cabaca North |  | Astraea |  |
Quiluma Block 14 |  | Cabaca SE Cuica Kalimba |  | Juno Palas PSVM |  |
BBLT |  | Lumpembe |  | Marte |  |
Belize Belize North Benguela |  | UM 45 UM 8 West Hub |  | Plutao Saturno Venus |  |
Benguela North Lobito |  | Agogo Mpungi |  |  |  |
Tomboco |  | Mpungi North |  |  |  |
TL |  | Ndungu |  |  |  |
Landana Landana North Tombua |  | Ochigufu Sangos Vandumbu |  |  |  |

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