23 January, 2008

Prot. 03/08/CFO

Mr. H. Roger Schwall,
Assistant Director
Division of Corporation Finance
United States Securities and Exchange Commission,
100 F Street, N.E.,
Washington, D.C. 20549-7010

Re: Eni Spa
Form 20-F for the Fiscal Year ended December 31, 2006
Filed June 20, 2007
File No. 1-14090

Dear Mr. Schwall,

        Thank you for your facsimile dated January 10, 2008 setting forth comments of the Staff of the Commission (the “Staff”) relating to Eni response letter dated December 18, 2007, on the annual report on Form 20-F for the year ended December 31, 2006 filed June 20, 2007 (the “2006 Form 20-F”) of Eni S.p.A. (“Eni”) (File No. 1-14090).

        To facilitate the Staff’s review, we have included in this letter the captions and comments from the Staff’s comment letter in bold italicized text, and have provided our response immediately following each comment.

        As outlined in our letter of December 18, 2007, Eni is proposing to file a Form 6-K (the “Form 6-K”) that will include (i) a discussion of recent developments relating to Kashagan and (ii) revised and additional disclosure relating to Kashagan in response to the Staff’s comments. A draft of the Form 6-K is attached as annex A. Eni undertakes to include the disclosures with respect to Kashagan as well as disclosure in other areas in response to the Staff comments in both the Italian and the English version of Eni’s annual report published in accordance with Italian law, which will be available to investors in mid March 2008, and in Eni’s 2007 Form 20-F which we plan to file by no later than mid-May 2008, i.e., a month earlier in the year than was done in the past.

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General

1. We have reviewed your responses to prior comments three and six from our letter dated December 4, 2007. Please provide us with your proposed expanded disclosures in reference to these two comments.

    Response:

        (i) Proposed expanded disclosure in response to comment three from the Staff’s letter dated December 4, 2007.

        As outlined in our prior response to the Staff’s comment letter dated December 4, 2007, in future filings we will furnish information on proved reserves on an individual basis for those fields of major significance to our oil and gas operations. We consider a field to be of major significance to our company if our interest in its proved reserves approximates 10% of our total net proved reserves and the field is expected to require a material amount of developing expenditures in future years according to management’s plans and commitment. On that basis, we have determined that only Kashagan fulfilled those conditions in the year 2006. In future filings we will furnish individual field information with regard to the Kashagan field and any other fields that we will determine to have acquired major significance for us in accordance with the above mentioned criteria.

        Accordingly, in response to the Staff’s comment, in future filings we plan to expand disclosures on our oil and gas properties under Item 4- Exploration & Production with respect to Kashagan in the Kazakhstan section, currently located on page 32 of our 2006 20-F, as follows, subject to the necessary updates. This paragraph will also appear in the Form 6-K.

“Kazakhstan.

        .....................

        As of December 31, 2007, Eni booked proved reserves at the Kashagan field amounting to .. Mboe, representing a .. Mboe decrease with respect to 2006 year-end due to the following factors…..

        As of December 31, 2006, Eni’s proved reserves of the Kashagan field amounted to 596 Mboe. This amount was revised upwardly in 2006 by 107 Mboe due to an extension of the proved area and project cost revision, offset in part by the year-end price variation.

        .....................”

        (ii) Proposed expanded disclosure in response to comment six from the Staff’s letter dated December 4, 2007.

        In response to the Staff’s comment, in future filings we plan to expand our disclosure on Kashagan’s operations under “Item 5 – Financial Review – Management expectations of operations –”,

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currently located on page 100 of our 2006 20-F, to include the following information, updated as necessary. The following will also be included in the Form 6-K.

“With regard to the Kashagan project, the magnitude of the reserves base, the results of the first four tests conducted on development wells and the subsurface studies completed so far support expectations for a full field production plateau of 1.5 mmBBL/d, which represents a 25% increase above the original plateau as presented in the 2004 development plan. An independent reserve evaluation performed by a petroleum engineer fully supports the target production plateau of the Kashagan field.
The achievement of the full field production plateau will require a material amount of expenditures in addition to the development expenditures needed to complete the execution of the phase one of the field development. However, taking into account that future development expenditures will be incurred over a long time horizon, management does not expect any material impact on the company’s liquidity or its ability to fund these capital expenditures.
The agreement reached with the Kazakh authorities on January 14, 2008 provided that the parties to the NCSPSA would present an updated technical configuration of the full field development for the Kazakh authorities’ review and approval by the end of May 2008.”
In future filings, we plan to disclose to investors the estimate of the expenditures of subsequent field development phases upon approval by the relevant Kazakh authorities.

2. We have reviewed your response to prior comment four. It would appear that the joint entities set up to build and operate the LNG plants are part of the Gas and Power division of your company and not Exploration and Production, which contains oil and gas activity. The calculations within the Standardized Measure should be limited to oil and gas activity within the Exploration and Production division. Therefore, it appears that a “netback” methodology incorrectly inflates the price of natural gas attributed to that produced by the Exploration and Production division in Nigeria and Australia, which have very limited local markets, at the expense of the Gas and Power division, which due to its processing and transportation functions (not oil and gas activities) is able to transport the gas to more developed markets, thereby obtaining a higher price for that gas. The margins that the Gas and Power divisions should realize is the difference between what it sells the gas for in a more developed market with what it paid the Exploration and Production division for the gas produced in a much less developed market. You appear to be attributing this margin to the Exploration and Production division which should only be realizing the price it receives from the LNG plants for this gas which should be based on the local markets for natural gas in Nigeria and Australia. If there are no markets in Nigeria and Australia for the sale of natural gas, the price assumed for the gas should be the production costs to produce it and a minimal assumed rate of return. Please revise your document to include only oil and gas activity and not gas and power activity in the Standardized Measure.

         Response:

        Eni’s investments in LNG plants in Australia and Nigeria, which are managed by the E&P division, are held by subsidiaries which record these investments of 11% and 10.4%, respectively, at cost.

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        Eni’s Standardized Measure of gas reserves produced in Nigeria and Australia and sold to LNG plants are determined applying the price formulas of the relevant long term gas supply agreements between Eni and the relevant LNG entity. These gas prices agreed between Eni and an LNG entity are the result of an arms-length negotiation involving all of the upstream companies joining the venture to build and operate the LNG plant. Terms and conditions regulating the supply of gas to the LNG entity are the same for all upstream producers supplying the LNG plant. Supply price formulas are linked to the final LNG entity’s selling prices on final markets and are designed to enable the LNG entity to earn a margin sufficient to cover operational expenses and investments and also to remunerate the business risk underlying the LNG activity according to standards of return on capital employed for the LNG industry. This is what we refer to as net-back mechanism. When deciding to invest in the development of new gas reserves, upstream producers, including Eni, typically take into account – amongst others factors – the estimated sales prices achievable in the transaction with the LNG entities. Mineral and extraction risks are borne by the upstream producers under supply-or-pay clauses which indemnify the LNG entities in case of failure to deliver agreed gas volumes on the part of the upstream producers. Local income taxes and/or contractual cost recovery for the upstream producers are based on the selling prices with the LNG entity. On the basis of the foregoing, we believe the net-back mechanism assures a fair return to both the LNG plant and the E&P activity; hence, we believe it appropriate to determine the Standardized Measure utilizing the prices for supplying gas to the LNG entities under the contracts in force between Eni E&P division and the LNG entities as of the date of the computation of the Standardized Measure. It should be noted that Eni’s share of the earnings of the LNG entities, all or a part of which are received by Eni in the form of dividends, are not included in the revenue stream for determining the Standardized Measure.

**

        We are available to discuss the foregoing with you at your convenience.

        We acknowledge that Eni 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 Eni’s Form 20-F, and that we 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.

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        If you have any questions relating to this letter, please feel free to call the undersigned at +39-06-5982-1000 or Richard Morrissey or Oderisio de Vito Piscicelli at Sullivan & Cromwell LLP at +44-207-959-8900.

Very truly yours,

/s/ MARCO MANGIAGALLI

Marco Mangiagalli
Chief Financial Officer
Eni S.p.A.

cc: Lily Dang
Jenifer Gallagher
Division of Corporation Finance
Securities and Exchange Commission

James Murphy
Petroleum Engineer
Division of Corporation Finance
Securities and Exchange Commission

Richard C. Morrissey
Oderisio de Vito Piscicelli
(Sullivan & Cromwell LLP)

ANNEX A:
DRAFT OF THE CURRENT REPORT ON FORM 6-K ON THE
KASHAGAN PROJECT

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

______________

Form 6-K

REPORT OF FOREIGN ISSUER
Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

Entry into a material definitive agreement

Eni S.p.A.
(Exact name of Registrant as specified in its charter)

Piazzale Enrico Mattei 1 — 00144 Rome, Italy
(Address of principal executive offices)

______________

             (Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.)

Form 20-F  Form 40-F 

______________

             (Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2b under the Securities Exchange Act of 1934.)

Yes  No 

      (If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):               )

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Table of Contents

TABLE OF CONTENTS

Material developments relating to the Kashagan field development project

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Table of Contents

SIGNATURES

             Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorised.

Eni S.p.A.

Name:  Fabrizio Cosco
Title:  Company Secretary

Date: January ___, 2008

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MATERIAL DEVELOPMENTS RELATING TO THE KASHAGAN FIELD DEVELOPMENT PROJECT

Background
Eni has been present in Kazakhstan since 1992. Eni is the single operator of the North Caspian Sea Production Sharing Agreement (NCSPSA) with a participating interest currently equal to 18.52% as of December 31, 2007. The other partners of this initiative are Total, Shell and ExxonMobil, each with a participating interest currently of 18.52%, ConocoPhillips currently with 9.26%, and Inpex and KazMunayGas each currently with 8.33%. Each partner’s participating interest in the project will change according to the terms of the Memorandum of Understanding signed among the parties, including the Kazakh authorities, on January 14, 2008. Information on this agreement is included below. The change in participating interests will apply retroactively as of January 1, 2008.
The NCSPSA defines terms and conditions for the exploration and development activities to be performed in the area covered by the contract.

The Kashagan field was discovered in the northern section of the contractual area in the year 2000. Management believes this field to contain a large amount of hydrocarbon resources.

Management estimates that Eni’s proved reserves booked for the Kashagan field as of December 31, 2007 amount to .. Mboe, recording a decrease of .. Mboe with respect to 2006 mainly due to the impact of increased year-end oil prices on reserve entitlements in accordance with the PSA scheme. Proved reserves for the field as of December 31, 2007 are determined according to Eni’s then current participating interest of 18.52%.
As of December 31, 2006, Eni’s proved reserves booked for the Kashagan field amounted to 596 Mboe, recording an increase of 107 Mboe with respect to 2005 due to an extension of the proved area and project cost revision, offset in part by the impact of price revisions.
Management estimates that the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements as of December 31, 2007 amount to $.. billion. This capitalized amount included: (i) $.. billion relating to expenditures incurred by Eni for the development of the oilfield; and (ii) $.. billion relating primarily to accrued finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre-emption rights in previous years. The $.. billion amount was equivalent to €.. billion based on the 2007 year-end euro/US dollar exchange rate. As of December 31, 2006 the aggregate costs incurred by Eni for the

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Kashagan project that were capitalized by Eni in its financial statements amounted to $1.9 billion, corresponding to €1.5 billion based on 2006 year-end exchange rates.
Costs borne by Eni to explore and develop this field are recovered in accordance with the mechanisms typically contemplated by a PSA scheme, which is widely used in the industry. In this type of contract the national oil company or State-owned entity assigns to the international oil company (the contractor) the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is generally divided into two portions: “cost oil” is used to recover costs borne by the contractor and “profit oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Accordingly, recoverability of the expenditures is subject to approval from the relevant State-owned or controlled entity who is party to the agreement. Similarly, cost overruns are recovered to the extent they are sanctioned by the State-owned or controlled entity who is party to the agreement.
To date, costs incurred for the development of the Kashagan oilfield relate to scheduled works and in accordance to the budget duly approved by the Kazakhstan authorities, and are therefore recoverable subject to customary audit rights.

The submission to the Kazakh authorities of an update to the development plan of the Kashagan field and developments which occurred in the second half 2007 and in January 2008

The development plan of the Kashagan field was originally sanctioned by the Kazakh authorities in February 2004, contemplating a three-phase development scheme including partial gas re-injection in the reservoir to enhance the recovery factor of the crude oil.
The sanctioned plan budgeted expenditures amounting to US $10.3 billion (in 2007 real terms) to develop phase-one, with a target production level of 300 Kbbl/d. First oil was originally scheduled to be produced by the end of 2008. Eni was expected to fund these expenditures according to its participating interest in this project. On June 29, 2007, Eni, as operator, filed with the relevant Kazakh authorities amendments to the sanctioned development plan. These amendments rescheduled the production start-up to 2010 and estimated development expenditures for phase-one at US $19 billion. The production delay and cost overruns were driven by a number of factors: depreciation of the US Dollar versus the Euro and other currencies; cost price escalation of goods and services required to execute the project; an original underestimation of the costs and complexity to operate in the North Caspian Sea due to lack of benchmarks; design changes to enhance the operability and safety standards of the off-shore facilities.

In July 2007, the Kazakh authorities rejected the proposed amendments to the sanctioned development plan. In August 2007, the Government of the Kazakh Republic sent to the companies forming the NCSPSA consortium a notice of dispute alleging failure on the part of the consortium to fulfil certain contractual obligations and violation of the Republic’s laws. Negotiations commenced with a view to settle this dispute.

On January 14, 2008, all parties to the NCSPSA consortium and the Kazakh authorities signed a memorandum of understanding for the amicable solution of this dispute. The material terms of the agreement are:
(i) the proportional dilution of the participating interest of all the international members of the Kashagan consortium, following which the stake held by the national Kazakh company KazMunayGas’ and the stakes held by the other four major shareholders will each be equal to 16.81%. These changes

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will be effective January 1, 2008. The Kazakh partner will pay to the other co-venturers an aggregate amount of US $1.78 billion;
(ii) a value transfer package to be implemented through changes to the terms of the NCSPSA, the amount of which will vary in proportion to future levels of oil prices. Eni is expected to contribute to the value transfer package in proportion to its new participating interest in the project;
(iii) an increased role of the Kazakh partner in operations and a new operating and governance model which will entail a greater involvement of the major international partners.
Although the project continued during the negotiation process, its progress was delayed. The parties have therefore agreed that Eni as operator will file with the Kazakh authorities a revised expenditure budget and schedule for the execution of the phase one by the end of March 2008. The parties have also agreed to present an updated technical configuration of the full field development for the Kazakh authorities’ review and approval by the end of May 2008.

   Future capital expenditures

The magnitude of the reserves base, the results of the first four tests conducted on development wells and the subsurface studies completed so far support expectations for a full field production plateau of 1.5 mmBBL/d, which represents a 25% increase above the original plateau as presented in the 2004 development plan. An independent reserve evaluation performed by a petroleum engineer fully supports the target production plateau of the Kashagan field. The achievement of the full field production plateau will require a material amount of expenditures in addition to the development expenditures needed to complete the execution of phase-one. However, taking into account that future development expenditures will be incurred over a long time horizon, management does not expect any material impact on the company’s liquidity or its ability to fund these capital expenditures.

In addition to the expenditures for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production to international markets, for which various options are currently under consideration by the consortium. These include: (i) the use of existing infrastructure, such as the Caspian Pipeline Consortium pipeline (Eni’s interest 2%) and the Atyrau-Samara pipeline, both of which are expected to undergo a capacity expansion; and (ii) the construction of a new transportation system. In this respect, it is worth mentioning the project aimed at building a line connecting the onshore Bolashak production centre with the Baku-Tbilisi-Cehyan pipeline (where Eni holds an interest of 5% corresponding to the right to transport 50 KBBL/d).