Eni S.p.A. has claimed confidential treatment of portions of this letter in accordance with 17 C.F.R. § 200.83
	Sede legale in Roma Piazzale Enrico Mattei, 1 00144 Roma Tel. centralino: +39 06598.21 www.eni.com

ALESSANDRO BERNINI
CHIEF FINANCIAL OFFICER
Direct Telephone (+39)-02-52041730
Fax (+39)-02-52041765
Prot. CFO/63/2011	September 20, 2011

United States Securities and Exchange Commission

100 F Street N.E., Stop 7010

Washington, D.C. 20549

	Attention: Mr. H. Roger Schwall
	Assistant Director
	Division of Corporation Finance
Re: Eni S.p.A.
Form 20-F for Fiscal Year Ended December 31, 2010
Filed April 7, 2011
Form 20-F/A for Fiscal Year Ended December 31, 2009
Filed April 7, 2011
File No. 1-14090

Dear Mr. Schwall:

Thank you for your letter dated August 19, 2011 setting forth comments of the Staff of the Commission relating to Eni’s annual report on Form 20-F for the year ended December 31, 2010 (the "2010 Form 20-F") and Form 20-F/A for the year ended December 31, 2009. The information set forth below is submitted in response to your comments. The numbered paragraphs and headings correspond to the numbered paragraphs and headings of your letter.

Capitale sociale Euro 4.005.358.876,00 i.v.
Registro Imprese di Roma, Codice fiscale 00484960588
Partita IVA 00905811006, R.E.A. Roma n. 756453
Sedi secondarie:
Via Emilia, 1 - Piazza Ezio Vanoni, 1
20097 San Donato Milanese (MI)

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Eni S.p.A. has claimed confidential treatment of portions
of this letter in accordance with 17 C.F.R. § 200.83

In accordance with the Staff’s policy with respect to requests for confidential treatment of responses to the Staff’s comment letters, we are submitting two separate letters to the Staff’s comments. Concurrent with the submission to you of this letter, confidential treatment of portions of this letter is being requested under the Commission’s rules in accordance with 17 C.F.R. § 200.83. Accordingly, a separate version of this response letter containing confidential information of the Company is being filed by hand and not via EDGAR. This letter being submitted via EDGAR does not contain confidential information of the Company and, therefore, is not submitted on a confidential basis.

Form 20-F for the Fiscal Year Ended December 31, 2010

Petroleum Engineering Comments

Risk Factors, page 5

Risks associated with the exploration and production of oil and natural gas, page 6

1. Please expand your disclosure here to present the consequences of loss of hydrocarbon containment during drilling, transportation and processing. Address offshore operations separately.

In response to the Staff comment, in our future filings we plan to expand our risk-factor disclosure as follows (changes are highlighted in bold):

"Risks associated with the exploration and production of oil and natural gas and other Group’s operations

The exploration and production of oil and natural gas requires high levels of capital expenditures and entails particular economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil and natural gas fields. In addition, the Group engages in processing, transportation, refining and petrochemical activities, storage and distribution of petroleum products, natural gas transportation, distribution and storage, and production of base chemical and specialty products, which involve a wide range of operational risks.
Eni’s results depend on its ability to identify and mitigate the risks and hazards inherent to operating in those industries. The Company seeks to minimize these operational risks by carefully designing and building its facilities, including wells, industrial complexes, plants and equipment, pipelines, storage sites and distribution networks, and conducting its operations in a safe

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Eni S.p.A. has claimed confidential treatment of portions
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and reliable manner. However, failure to manage these risks effectively could result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, and increase in cost, legal liability and/or damage or destruction of crude oil or natural gas wells as well as equipment and other property, all of which could lead to a disruption in operations. We also face risks once production is discontinued, because our activities require environmental site remediation.
In exploration and production, we encounter risks related to the physical characteristics of our oil or gas fields. These include the risks of eruptions of crude oil or of natural gas, discovery of hydrocarbon pockets with abnormal pressure, crumbling of well openings, leaks that can harm the environment and risks of fire or explosion.
Accidents at a single well can lead to loss of life, damage or destruction to property, environmental damage and consequently potential economic losses that could have a material and adverse effect on the business, results of operation and prospects of the Group.

Eni’s activities in the Refining & Marketing and Petrochemicals sectors also entail additional health, safety and environmental risks related to the overall life cycle of the products manufactured, as well as raw materials used in the manufacturing process, such as catalysts, additives and monomer feedstock. These risks can arise from the intrinsic characteristics of the products involved (flammability, toxicity, or long-term environmental impacts such as greenhouse gas emissions), their use, emissions and discharges resulting from their manufacturing process, and from recycling or disposing of materials and wastes at the end of their useful life.

In the transportation area, the type of risk depends not only on the hazardous nature of the products transported, but also on the transportation methods used (mainly pipelines, maritime, river-maritime, rail, road, gas distribution networks), the volumes involved, and the sensitivity of the regions through which the transport passes (quality of infrastructure, population density, environmental considerations). All modes of transportation of hydrocarbons are particularly susceptible to a loss of containment of hydrocarbons and other hazardous materials, and, given the high volumes involved, could present a significant risk to people and the environment.

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Eni S.p.A. has claimed confidential treatment of portions
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Eni has implemented and maintains a system of policies, procedures and compliance mechanisms to manage safety, health, environmental, reliability and efficiency risks; to verify compliance with applicable laws and policies; and to respond to and learn from unexpected incidents. Nonetheless, in certain situations where Eni is not the operator, the Company may have limited influence and control over third parties, which may limit its ability to manage and control such risks. Eni maintains insurance coverage that include coverage for physical damage to our assets, third party liability, workers’ compensation, pollution and other damage to the environment and other coverage. Our insurance is subject to caps, exclusion and limitation, and there is no assurance that such coverage will adequately protect us against liabilities from all potential consequences and damages. In light of the accident at the Macondo well in the Gulf of Mexico, we may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher retentions. Also, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.

The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production interests, the imposition of specific drilling and other work obligations, income taxes and taxes on production, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production.

Our oil and natural gas operations are particularly exposed to health, safety, security and environmental risks.

We have material operations relating to the exploration and production of hydrocarbons located offshore. In 2010 approximately 60% of our total oil and gas production for the year derived from offshore fields, mainly in Egypt, Libya, Norway, Angola, Italy, Gulf of Mexico and UK. Offshore operations in the oil and gas industry are inherently riskier than onshore activities. As recent events in the Gulf of Mexico have shown, the potential impacts of offshore accidents and spills to health, safety, security and the environment can be catastrophic due to the objective difficulties in handling hydrocarbons containment and other factors. Also offshore operations are subject to marine perils, including severe storms and other adverse weather conditions and vessel collisions, as well as interruptions or termination by governmental authorities based on safety, environmental and other considerations. Failure to manage these risks could result in

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Eni S.p.A. has claimed confidential treatment of portions
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injury or loss of life, damage to property, environmental damage, and could result in regulatory action, legal liability, loss of revenues and damage to our reputation and could have a material adverse effect on our operations or financial condition."

In addition, please note that our 2010 Form 20-F included separate risk disclosure relating to the regulatory risk and associated costs relating in particular to deep water drilling following the Macondo accident, which we plan to repeat or update as appropriate in future filings. See "The oil and gas industry may face increased regulation both in the USA and elsewhere that could increase the cost of regulatory compliance and may require changes to our drilling operations and exploration and development plans and may lead to higher royalties and taxes" on page 7 of the 2010 20-F.

Information on Company, page 22
Significant Business and Portfolio Developments, page 24

2. We note the reference to the Zubair field here and page 50. Please:

• Tell us the figures for Zubair proved reserves and proved undeveloped reserves that you have booked;
• Illustrate the computation of your projected annual production entitlement and proved reserves for year-end 2010 as governed by the technical service contract;
• Explain your claim to reserves in light of the provisions of your technical service contract, i.e. profit oil at $2/barrel; and

Address whether you have the option for payment in kind for cost recovery and profit payment.

Eni’s proved reserves booked at the end of 2010 for the Zubair field represented less than [***] of our total proved reserves, with the vast majority of that amount classified proved undeveloped.

In our letters dated October 29, 2010 and February 11, 2011 in response to the Staff comments on our 2009 Form 20-F, we briefly illustrated the contractual terms and the basis for our claim to proved reserves as of the end of 2009.
Under the Zubair Technical Service Contract, Eni and its partners are required to increase the field’s production from an initial level of approximately 0.2 million barrel of oil per day to 1.2 million over a period of six years and maintain such level for a period of seven years thereafter.

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Eni S.p.A. has claimed confidential treatment of portions
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Development of the field includes a Rehabilitation Plan, aimed at improving the initial production level and knowledge of the reservoir, and a Redevelopment Plan designed to attain the scheduled targets.

The Contractor is entitled to a Service Fee which includes the recovery of Petroleum Costs and a Remuneration Fee. Under the contract, the Contractor has the option to receive payment of the Service Fee either in kind or in cash. Eni has elected the former option. Accordingly, the Service Fee is payable in oil.

The above described contractual terms establish an oil entitlement mechanism and associated risk profile similar to those applicable in Production Sharing Contracts since the Contractor can only earn service fees to the extent incremental production reaches certain levels. In addition the contract does not establish a fixed level of oil price for the purpose of calculating production entitlements. Accordingly, higher oil prices will reduce Eni's cost oil and profit oil entitlement, and lower oil prices will increase such entitlement.

The Rehabilitation Plan was approved in June 2010. In the fourth quarter of 2010 actual production from the field exceeded the contractual baseline by more than 10% triggering Eni’s contractual right to book its equity production in relation to its share of cost recovery and remuneration.

Proved reserve entitlements have been calculated as follows. First, Eni calculated projected production at the field based on available technical data. Second, the amount of Service Fee was calculated based on costs and projected production. Third, the dollar amount of Service Fee calculated as above was divided by the relevant market price determined in accordance with applicable SEC regulation.

3. Tell us whether you claim proved reserves under service contracts elsewhere (e.g. the Villano field on page 25). If so, please tell us the proved figures for each field and the justification for your claims to proved reserves.

Proved reserves related to properties regulated under service contracts other than Zubair mainly relate to Villano field in Ecuador, Agbara and Okono-Okpoho fields in Nigeria and Iranian fields, which cumulatively represented less than [***] of our total proved reserves as of end of 2010.
The various service contracts applicable to those fields differ in several aspects, but in all cases the risk profile, as well as the entitlement to oil production, is similar to that applicable in Production Sharing Contracts, because the costs incurred by Eni

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Eni S.p.A. has claimed confidential treatment of portions
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to develop and operate those fields are reimbursable to the extent that there exists amounts of marketable hydrocarbons production. For these reasons Eni deems it appropriate to book reserves in respect of such contracts.

In relation to the Villano field, under the terms of the service contract, the contractor is entitled to receive a service fee based on a capped remuneration tariff per barrel. The level of cost recovery and profitability therefore is subject to variation in market prices and field production performance.

The two Nigerian contracts are defined as Service Contracts, but the contractual terms actually contemplate a mechanism of cost recovery and profit oil that is the same as in PSAs.

For the description of the Iran Service contract please refer to our letter dated February 11, 2011 in response to the Staff comments about our 2009 Form 20-F.

Summary of Proved Oil and Gas Reserves, page 29

4. Item 1201(d) of Regulation S-K defines "geographic area" as a country, a group of countries within a continent or a continent. Item 1202(a)(2) requires tabular disclosure of reserves by each geographic area that contains 15% or more of a registrant’s proved reserves. Please explain to us why you do not provide such disclosure for North Africa, which accounts for 33% of your consolidated subsidiary proved reserves.

We acknowledge the Staff’s comment. We engage in exploration and production of oil and natural gas in Egypt, Libya, Algeria and Tunisia which we group as a single geographic area denominated North Africa for reserve disclosure purposes. Instruction 4 to paragraph (a) (2) of item 1202 states that "A registrant need not provide disclosure of the reserves in a country containing 15% of more of the registrant’s proved reserves if that country’s government prohibits disclosure of reserves in that country." We believe that providing a further break-down of geographic areas within North Africa would result in a breach of instructions that Eni received from the state-owned company of one such country prohibiting disclosure of reserves in that country.

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Eni S.p.A. has claimed confidential treatment of portions
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5. Revise your table to include your equity accounted reserves by geographic area. See Question 154.02 of Compliance and Disclosure Interpretations (October 26, 2009), available at http://www.sec.gov/divisions/corpfin/guidance/oilandgas-interp.htm.

Eni proved reserves related to equity-accounted entities represented approximately 8% of total proved reserves as of the end of 2010. On page 3 of the 2010 Form 20-F, we disclose that our share of reserves held by equity-accounted entities mainly relates to our joint-venture operations conducted in Russia since 2007. In addition, we disclosed in the 2010 20-F that we booked for the first time certain amounts of oil reserves in connection to the Junin 5 joint project in Venezuela. Other residual amounts relate to joint venture operations in Africa, America and Asia.
A large part of our proved reserves booked in connection with joint operations are undeveloped as our initiatives are progressing towards production. Accordingly, the results of operations of our equity-accounted entities are immaterial to the Group’s results of operations.
In light of the foregoing discussion, we believe that disclosing the geographic break-down of reserves of our equity-accounted entities would not provide any further meaningful information to the investor.

As we expect that our joint operations become more significant to us in the near future, we plan to disclose geographic area information about our equity-accounted entities starting with the 2011 Form 20-F.

6. We note your statement, "The current SEC rules allow the use of reliable technology to justify the reserves estimate if it produces consistent and repeatable results. We did not have any material additions of proved reserves due to application of "reliable technologies". Please explain to us the technology you used for the additional 776 MMBOE of additional proved reserves you booked at year-end 2010.

In our statement "We did not have any material additions of proved reserves due to application of reliable technologies", the term "reliable technologies" referred to reliable technologies other than those that would have allowed a determination of proved amounts under former SEC rules. In other words, by that statement we intended to signify that during the year, no material quantities were booked under current rules incremental to quantities allowable under former SEC rules as a result of the expanded range of technologies that may be used in the estimation.

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Eni S.p.A. has claimed confidential treatment of portions
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The actual methods (or technology) used in the proved reserves assessment depend on stage of development, quality and completeness of data, and production history available, and the methods include volumetric estimates, analogies, reservoir modelling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained with a combination of reliable technologies that include direct measurements (i.e. well logs, reservoir core samples, pressure information, fluid samples, production test data, and performance data) and indirect measurements (i.e. seismic data). All of the 776 MMBOE of additional proved reserves were booked using reliable technologies within the meaning of Rule 4-10 of Regulation S-X currently in force.

Of the total proved reserves additions (776 MMBOE) booked by Eni at year end 2010, 125 MMBOE refer to discovery and extension.
General revisions, which account for the remaining additions, mainly related to brown fields’ reservoir studies, where changes are predominantly based on field performances and decline curve analysis, development activities (infill drilling and production optimization projects), and the updating of natural gas conversion factor from 5,742 to 5,550 standard cubic feet of gas per barrel of oil equivalent.

Proved Undeveloped Reserves, page 31

7. We note your statement, "In 2010, total proved undeveloped reserves increased by 354 mmBOE. The principal reasons for the increase are revisions and new projects sanction, mainly in Libya, Venezuela and Iraq." Please expand this to present figures for PUD increases due to revisions and the figures due to new project sanctions.

In 2010, total proved undeveloped reserves increased by 354 MMBOE. Additions relating to new project sanctions amounted to approximately 280 MMBOE.
The remaining proved undeveloped reserves increase resulted from upwards and downwards revisions mainly related to contractual and technical revisions, price effects and the updating of the natural gas conversion factor from 5,742 to 5,550 standard cubic feet of gas per barrel of oil equivalent that is disclosed elsewhere in the 2010 Form 20-F.

8. We note that you have claimed PUD reserves at Kashagan for more than five years. Please tell us if your booked PUD reserves - .6 BBOE - are to be developed entirely in Phase 1. If not, please justify your claim to proved reserves beyond Phase 1 in light of the announced delay to initiation of Phase 2 until 2018 time frame. Tell us if a final

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Eni S.p.A. has claimed confidential treatment of portions
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investment decision has been made for Phase 2.

The proved reserves of the Kashagan field remained undeveloped for more than 5 years due to the time frame necessary to execute a project of such a magnitude and technical and environmental complexity. Development activities are progressing towards completion and the production start up of Phase 1 is targeted by the end of 2012.
Our booked PUD reserves for the Kashagan project – amounting to 0.6 BBOE at 2010 year-end – will be produced within the limits of the oil processing capacity that is planned to be available at the end of Phase 1. A small portion of such PUD reserves will require limited additional development activity intended to exploit the spare oil processing capacity which will be available at end of Phase 1. The Final Investment Decision related to Phase 2 has not yet been made.

9. Please expand your discussion of the delay in developing the Libyan gas fields. Include the figures for the associated PUD reserves.

In future filings we plan to expand our disclosure about Libyan gas fields and associated PUD reserves as follows:

"Proved undeveloped reserves related to gas fields located in Libya amounted to approximately 0.27 BBOE which have remained undeveloped for more than 5 years as of end of 2010. Development completion and production start up of those undeveloped reserves is planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force. In order to secure fulfilment of the contractual delivery quantities, we plan phased production start up from the relevant fields, which are expected to be put in production over the next several years."

Average Sales Prices and Production Cost per Unit of Production, page 33

10. Item 1204 of Regulation S-K requires the disclosure of historical price and cost data by geographical area. We note that this data for equity accounted properties is not presented by area. Please modify this in order to comply with Regulation S-K.

See our response to comment 5.

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Oil and gas properties, operations and acreage, page 35

11. Item 1208(b) of Regulation S-K requires the disclosure of minimum remaining terms of material leases and concessions. Please expand your disclosure to comply with Regulation S-K.

Please note that, where material, we disclosed the minimum remaining terms of our material lease and concessions in the section "Oil and gas properties, operations and acreage" starting on page 34 of the 2010 Form 20-F when describing operations in each country where the Group is active. For example on page 47 we disclosed that the Kashagan PSA contract will expire in 2041; the Karachaganak contract is due to expire in 2037 as disclosed on page 48.

Ecuador, page 51

12. We note the disclosure of "volumes in place of 300 mmBBL" and "35 BBBL of certified heavy oil in place" on page 53. These figures do not represent reserves and, as such, are not allowed in documents filed with us. Please omit such disclosures from your future documents.

We will omit disclosure of amounts of resources which do not represent reserves in our future filings.

Exhibit 15.a(ii)

13. We note the third party engineering report presents Africa and Asia average adjusted gas prices as $307.07/Mm3 and $355.43/Mm3, respectively. Please affirm to us that these gas prices are $8.68/MCFG and $10.05/MCFG. Tell us the properties and the disposition of the gas associated with these prices.

As indicated in the "Conversion table" (page vi of Form 20-F), 1 cubic meter of natural gas is equivalent to 35.3147 cubic feet of natural gas. Consequently, $307.07/Mm3 and $355.43/Mm3 are equivalent to $8.69/MCFG and $10.06/MCFG respectively. With respect to disposition of the gas associated with these prices, the gas from Africa is destined to Mediterranean Europe and the gas from Asia to LNG shipments to the Far East.
For the reasons indicated in or letter dated February 11, 2011 in response to a prior comment from the Staff, the third party engineering reports do not disclose prices relating to individual properties, which is confidential information.

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Eni S.p.A. has claimed confidential treatment of portions
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***

If you have any questions relating to this letter, please feel free to call the undersigned at +39-02-520-41730.
Eni acknowledges that it is responsible for the adequacy and accuracy of the disclosure in its Form 20-F, that Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to its Form 20-F, and that Eni may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Very truly yours,

/s/ ALESSANDRO BERNINI

Alessandro Bernini

Title: Chief Financial Officer

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