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eni.com

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

 Re: Eni SpA

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

 1. We have read your response to prior comment 1 and note the disclosure shown on page 46 of your
filing indicates material changes in acreage occurred during 2019,
e.g. 27,600 square kilometers related to the relinquishment of licenses and 55,500 square kilometers relating to partial relinquishments
or interest reductions. We also note your net quantities of undeveloped acreage as of December 31, 2019 declined by 49,548 square
kilometers or approximately 13.1% from December 31, 2018.

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;

    2

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

 2. We have read your response to prior comment 2 and note your proposal to enhance the narrative
and tabular disclosures of your annual production to identify the volumes of natural gas consumed in operations.

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.

    3

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.

 3. We have read your response to prior comment 3 and note your proposal to expand your disclosure
to provide additional narrative and further break-downs of the changes in the Company’s total proved reserves by identifying
the specific volumes attributable to each factor that resulted in the changes.

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.

    4

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:

 (i) extensions and discoveries were up by 101 mmBOE of which 34 mmBBL of crude oil and 358 BCF of
natural gas.

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.

 (ii) revisions of previous estimates were up by 459 mmBOE of which 203 mmBBL of crude oil and 1,227
BCF of natural gas.

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.

    5

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;

 (iii) purchases of mineral-in-place added 29 mmBBL of crude oil proved reserves in America and
related to an investment in the Oooguruk production field in Alaska. The same transaction explained the purchase of 7 BCF of
natural gas.

 (iv) sales of minerals-in-place were 29 mmBBL in America and related to the disposal of our entire
interest in an asset in Ecuador. Sales of proved reserves of gas were 67 BCF of which the largest amount of 48 BCF was in Asia
and related to the farm-out of a 20% interest in the Merakes discovery in Indonesia. In addition, sales of minerals-in-place include
approximately 18 BCF of proved reserves of gas as part of a long-term supply agreement to a state-owned national oil company, whereby
the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause, as discussed above.

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;

    6

(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.

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

 4. We have read your response to prior comment 3 and note your proposal to expand your disclosure
to provide additional narrative and further break-downs of the changes in the Company’s proved undeveloped reserves by identifying
the specific volumes attributable to each factor that resulted in the changes.

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,
t