FRANCESCO GATTEI

CHIEF FINANCIAL OFFICER

Direct Telephone (+39)-02-52031014

FRANCESCO ESPOSITO

HEAD OF ACCOUNTING AND FINANCIAL STATEMENTS

Direct Telephone (+39)- 02-52061632

Prot. CFO/185/2020/P

October 23, 2020

United States Securities and Exchange Commission

100 F Street N.E., Stop 7010

Washington, D.C. 20549

Attention: H. Roger Schwall

Assistant Director

Office of natural resources

Form 20-F for the Fiscal Year Ended December 31, 2019

Filed April 2, 2020

File No. 1-14090

Dear Mr. Schwall:

Thank you for your letter dated October 9, 2020 setting forth supplemental comments from the staff (the “Staff”) of the United States Securities and Exchange Commission on the annual report on Form 20-F of Eni S.p.A. (“Eni”) for the year ended December 31, 2019 (the “Form 20-F”). The information set forth below is submitted in response to your supplemental comments.

Business Overview

Exploration and Production

Oil and Gas Properties, Operations and Acreage, page 45

To the extent that there are known expirations or planned relinquishments of material amounts of acreage in the aggregate over the near term (3 – 5 years), disclosure of the gross and net acreage amounts by geographic area (individual country, groups of countries within a continent, or by continent) is required by Item 1208(b) of Regulation S-K. Please revise your disclosure accordingly or tell us why a revision is not needed.

Response

Please note that the reductions in our net acreage occurred in the course of 2019 related to planned divestitures of certain assets which were disclosed elsewhere in our 2019 filings or otherwise in furtherance of Eni’s announced portfolio management strategy intended to share exploration risk and monetize a portion of the exploration assets. With a view to providing the Staff with further insight regarding relinquishment of licenses or interest reductions of our properties in 2019, we report below the drivers of the main reductions in acreage:

i)       27,228 SqKm in Oman due to interest dilution in Block 52, a large exploration area, as part of the aforementioned strategy. Currently, we have no production in the Country;

ii)       7,938 SqKm in Indonesia due to interest dilution and area reduction in both exploration and development leases. The farmout which was part of our divestiture of a 20% interest in the East Sepinggan block to Neptune, is described on page 56 of our 2019 filing;

iii)       7,169 SqKm in Morocco for interest dilution in the large exploration lease Tarfaya, as part of the aforementioned strategy. Currently, we have no production in the Country;

iv)       5,244 SqKm in India, where we completed the exit from the country as anticipated in our filings several years ago;

v)       5,215 SqKm in China due to the relinquishment of exploration leases. China is not strategic to our operations (China production represents less than 1% of our total annual production);

vi)       4,580 SqKm in Vietnam due to the relinquishment of the exploration block 120. Eni still operates four other exploration leases in the Country. Currently, we have no production in the Country;

vii)        4,834 SqKm in Cyprus due to interest dilution in four exploration leases as part of the aforementioned strategy. Currently, we have no production in the Country;

viii)       3,931 SqKm in South Africa due to a partial area relinquishment in block ER236 following the entrance in the third exploration phase. Currently, we have no production in the Country;

ix)       3,182 SqKm in Portugal due to relinquishment and exit from the Country;

x)       1,985 SqKm in Ecuador due to the sale of the assets and exit from the Country as disclosed on page 57 of our 2019 filing.

Please also note that information about the main exploration acreage increases and acquisitions are disclosed on pages 30 to 32 of our 2019 filing, under the Heading “Significant business and portfolio developments”

We do not anticipate any significant change in our acreage due to lease expirations in the near term, because we generally have the right or ability to renew the leases that we are interested in exploiting. However, in response to the Staff’s comment, in future filings we will disclose forward looking information about expected acreage relinquishment or known expirations when material to the Company.

Supplemental Oil and Gas Information (Unaudited)

Oil and Natural Gas Reserves, page F-152

If your disclosure of total proved reserves also includes material amounts of natural gas to be consumed in operations as fuel in addition to the marketable or sales gas volumes, expand your total proved natural gas reserves disclosure to clarify the amounts. This comment applies to the comparable disclosure of natural gas reserves provided throughout your filing. Refer to FASB ASC 932-50-10.

Response

In response to the Staff’s comment, in future filings we will disclose volumes of proved reserves of natural gas to be consumed in operations, where we describe the reporting criteria for reserves. For illustration of this future disclosure, the corresponding paragraph of the 2019 Form 20-F on page F-153 would read as follows (additional disclosure highlighted):

“

Oil and gas reserves quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserves volumes associated with oil and gas deriving from such obligation represent 4%, 4% and 1.6% of total proved reserves as of December 31, 2019, 2018 and 2017, respectively, on an oil equivalent basis; (ii) volumes of natural gas used for own consumption with produced volumes amounting to 245, 235 and 191 BCF in 2019, 2018 and 2017, respectively. Volumes of proved reserves of natural gas to be consumed in operations amounted to approximately 2,330 BCF at 2019 year-end (2,470 BCF and 2,420 BCF respectively at 2018 and 2017 year-end) ; (iii) the quantities of hydrocarbons related to the Angola LNG plant.

“

We are also planning to disclose such volumes of reserves of natural gas to be consumed in operations in other sections of our filing where proved reserves of hydrocarbons are discussed (e.g. in Item 4 on pages 35 and 37 of the 2019 filing) including the break-down of proved developed vs. proved undeveloped.

The illustration of your proposed expanded disclosure, for the year ended December 31, 2019, identifies the major factors impacting each category of change without explaining the entire volume. Expand your disclosure further to identify and quantify the remaining factors, or group of factors, so the entire volume of each category is fully reconciled. Refer to FASB ASC 932-235-50-5.

Response

In response to the Staff’s comment, in future filings we will provide further break-downs of the changes in the Company’s proved reserves by disclosing the specific volumes attributable to each factor that resulted in changes in the total net quantities of our proved reserves, so the entire volume of each category is fully reconciled.

For illustration of this future disclosure, the corresponding paragraphs of the 2019 Form 20-F would read as follows (additional disclosure with respect to our prior response highlighted):

“

Pages No. 38-39 of Eni’s Annual Report on Form-20-F for the year 2019

“Eni’s proved reserves as of December 31, 2019 totaled 7,268 mmBOE (liquids 3,601 mmBBL; natural gas 19,832 BCF). Eni’s proved reserves reported an increase of 115 mmBOE, or 1.6%, from December 31, 2018 due to progress made in the year in exploring for and developing new reserves and property acquisitions net of property sales.

……

Eni’s subsidiaries added 548 mmBOE of proved oil and gas reserves in 2019 net of sales and purchase of minerals-in-place. This comprised 236 mmBBL of liquids and 1,525 BCF of natural gas. The breakdown of additions to proved reserves is the following:

The increase of 34 mmBBL in oil reserves was driven for 21 mmBBL by the final investment decisions relating to the Assa North field in Nigeria and the Agogo field in the operated Block 15/06 offshore Angola. The remaining extensions and discoveries related to certain fields in USA (9 mmBBL in total, relating to Nikaitchuq and Pegasus-2 fields) and 4 mmBBL in North Africa and Middle East Region driven by incremental near-field discoveries.

The 358 BCF additions to gas reserves were driven for 274 BCF by the final investment decisions made for the projects of Udr-Ghasha in the offshore United Arab Emirates. 78 BCF related to the final investment decision relating the Assa North field in Nigeria and the remaining 6 BCF in USA and UK.

Upward revisions of 747 BCF at gas reserves were reported in Sub-Saharan Africa and were mainly driven by the final investment decision for the expansion of the Bonny liquefaction plant, owned by Nigeria LNG (Eni’s interest 10,4%). Upward revisions of 467 BCF were reported in Egypt due to progress in development activities at the Zohr and other minor projects. Upward revisions of 267 BCF were reported in North Africa and were mainly driven by progress in the development at Berkine North fields in Algeria (227 BCF), while the remaining volumes related to the progress of activities in Libya and other fields in Algeria. In Kazakhstan we recorded upward revisions of 79 BCF due to better field performance. In the Rest of Asia the upward revisions related to Pakistan (23 BCF relating to over nine fields), United Arab Emirates (13 BCF in three fields), Indonesia at the Jangkrik field (15 BCF) and Iraq at the Zubair Field (15 BCF) mainly driven by progress in development activities. Other revisions for 11 BCF were recorded in UK and US.

Downward revisions of 310 BCF were reported in Italy due to the removal of uneconomical reserves reflecting lower commodity prices. Other downward revisions of 108 BCF were reported in Australia and Oceania, Turkmenistan (down 70 BCF) and in Mexico (down 30 BCF) due to the removal of uneconomical reserves reflecting lower commodity prices.

Upward revisions of proved reserves of crude oil were reported in Kazakhstan for 79 mmBBL and were due to progress in developing the Kashagan and Karachaganak projects. Upward revisions of 37 mmBBL were reported in North Africa mainly due to the development of the Berkine North fields in Algeria and other contributions from Libya. Upward revisions of 46 mmBBL were reported in Sub-Saharan Africa and were driven by progress in development activities in Congo and Angola, and Nigeria, while 45 mmBBL of upward revisions in the rest of Asia were due to the progress of development in the Umm Shaiff and other projects in UAE (25 mmBLS) and to entitlement effects in Iraq, Turkmenistan and Timor Leste. Upward revisions also include 6 mmBBL in Italy and Rest of Europe and 4 mmBBL in the USA. Downward revisions (total 24 mmBBL) are related to Mexico Area 1 (20 mmBBL) due to the removal of uneconomic volumes and for 4 mmBBL in Australia;

Eni’s share of equity-accounted entities

Eni’s share of equity-accounted entities added 246 mmBOE of proved oil and gas reserves in 2019 net of sale and purchase minerals-in-place. The breakdown of total additions to proved reserves is the following: (i) revisions of previous estimates were additions of 42 mmBBL of proved reserves of crude oil mainly in the Rest of Europe (up by 45 mmBBL) driven by development activities at the Balder X field in Norway. Downward revisions of crude oil reserves for 5 mmBBL were recorded in America due to the removal of uneconomical reserves in Venezuela.

Upward revisions to proved reserves of natural gas were 91 BCF and were explained 76 BCF by the Rest of Europe due to Balder X field in Norway (76 BCF), while 13 BCF were added in Sub-Saharan Africa at the ALNG project in Angola and the remaining 2 BCF in projects in Tunisia and Venezuela due to better field performance;

(ii) extensions and discoveries added 6 mmBBL of proved reserves of crude oil in the rest of Europe and were mainly driven by the production start-up of the Trestakk field in Norway;

(iii) purchase of minerals in place were 109 mmBBL of proved reserves of crude oil and 405 BCF of proved reserves of natural gas and were localized in the rest of Europe and explained by the acquisition of ExxonMobil producing and development assets in Norway by our 70%-participated joint venture Vår Energi;

(iv) sales of minerals-in-place were 6 mmBBL and related to minor assets divested by the Vår Energi JV in the Rest of Europe.

………………………………………………………………………………………………………………”

The illustration of your proposed future disclosure, for the year ended December 31, 2019, identifies the major factors impacting each category of change without explaining the entire volume. Expand your disclosure further to identify and quantify the remaining factors, or group of factors, so the entire volume of each category is fully reconciled. Refer to Item 1203(b) of Regulation S-K.

Response

In response to the Staff’s comment, in future filings we will provide further break-downs of the changes in the Company’s proved reserves by disclosing the specific volumes attributable to each factor that resulted in changes in the total net quantities of our proved reserves, so the entire volume of each category is fully reconciled.

For illustration of this future disclosure, the corresponding paragraphs of the 2019 Form 20-F would read as follows (additional disclosure with respect to our prior response highlighted):

“

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2019 totaled 2,114 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,113 mmBBL, mainly concentrated in Africa and Asia.

Proved undeveloped reserves of natural gas amounted to 5,415 BCF, mainly located in Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to 905 mmBBL of liquids and 5,041 BCF of natural gas. The table below provide a summary of changes in total proved undeveloped reserves for 2019.

In 2019, total proved undeveloped reserves decreased by 195 mmBOE mainly due to progress made in maturing PUDs to proved developed (655 mmBOE).

Additions to PUDs for the year included:

The increase of 34 mmBBL in oil reserves were driven for 21 mmBBL by the final investment decisions relating to the Assa North field in Nigeria and the Agogo field in the operated Block 15/06 offshore Angola and for 7 mmBBL in USA (Nikaitchuq and Pegasus-2) and 6 mmBBL in Norway (Trestakk and Goliat).

The 358 BCF additions to gas reserves were driven for 274 BCF by the final investment decisions made for the projects of Udr-Ghasha in the offshore United Arab Emirates; 78 BCF related to final investment decisions at the Assa North field in Nigeria and the remaining 6 BCF in USA and UK;

Additions of crude oil pud reserves amounted to 157 mmBBL and related to the following countries: 37 mmBBL were reported in Norway due to progress at the BalderX filed, 30 mmBBL in Kazakhstan, 28 mmBBL in United Arab Emirates and 21 mmBBL in Nigeria, 13 in Congo and 10 mmBBL in Algeria driven by progress in development activities. The remaining part (18 mmBBL) is related to projects in other seven countries. Downward revisions amounting to 37 mmBBL related to Mexico (19 mmBBL) and Venezuela (6 mmBBL) due to removal of uneconomic volumes, while downward revisions were reported in Libya for 9 mmBBL and Angola for 3 mmBBL due to reservoir underperformance.

Upward revisions of 804 BCF were reported in Sud-Saharan Africa and were mainly driven by the final investment decision made for an expansion project at the Bonny liquefaction plant in Nigeria and in Egypt for 397 BCF due to the development activity of the Zohr project. These additions were partly offset by downward revisions of 120 BCF that were reported in Libya due to reservoir underporfmance and the remaining 23 BCF in seven countries.

During 2019, Eni matured 655 mmBOE of proved undeveloped reserves to proved developed reserves due to progress in development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves related to the following fields/projects:

Egypt 370 mmBOE (Zohr, Nidoco and others minor fields),

Kazakhstan 100 mmBOE (mainly in Kashagan),

Congo 49 mmBOE (Litchendjili and Nene),

Nigeria 36 mmBOE (mainly Ngl Eleme),

Mexico 17 mmBoe (Area 1),

Angola 16 mmBOE,

Norway 14 mmBOE,

United Arab Emirates 14 mmBOE,

Libya 12 mmBOE

The remaining 27 mmBOE related to start ups in 7 countries.

***

We are available to discuss the forgoing with you at your convenience. If you have any questions relating to this letter, please feel free to call the undersigned at +39-02-520-31014 and at +39-02-52061632.

Very truly yours,