CORRESP 1 filename1.htm Response Letter

ENI HAS CLAIMED CONFIDENTIAL TREATMENT OF PORTIONS OF
THIS LETTER IN ACCORDANCE WITH 17 C.F.R. § 200.83

22 October, 2007

Mr. H. Roger Schwall,
Assistant Director,
Division of Corporation Finance,
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 September 11, 2007 setting forth comments of the Staff of the Commission (the “Staff”) relating to 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 caption and comment from the Staff’s comment letter in bold italicized text, and have provided our response immediately following the comment.

Operating and Financial Review and Prospects, page 76

We note you disclose on page 77 that the production start up of the Kashagan oilfield project has been delayed an additional two years, and you estimate your expenditures will significantly exceed the budgeted amounts, which had been

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approved by the consortium partners and relevant Kazakh authorities in 2004. Please expand your disclosure to specify the cumulative costs you have incurred for the project as of December 31, 2006. In addition, please clarify whether you are incurring 100% of the costs to develop this field or only your 18.52% participating interest. Finally discuss what mechanisms are in place for you to recover your costs, including any cost overruns.

Response:

As of December 31, 2006 the aggregate costs incurred by Eni for the Kashagan project that were capitalized by Eni in its financial statements amounted to $1.9 billion. This capitalized amount included:

(i)

$1.3 billion relating to expenditures incurred by Eni for the development of the oilfield; and

(ii)

$0.6 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.

The $1.9 billion amount was equivalent to €1.5 billion based on the 2006 year-end euro/US dollar exchange rate, corresponding to less than 3 % of Eni’s total consolidated non current assets. In response to the Staff’s comment, in our future filings we plan to expand our disclosure by adding information on expenditures capitalized in connection with development activities at Kashagan.

We confirm that Eni is funding the project according to its participating interest of 18.52% in the consortium.

With respect to the recoverability of these investments, as indicated on page 32 of our 2006 Form 20-F, the exploration and development activities of Kashagan are regulated by a Production Sharing Agreement. Accordingly, the mechanisms in place to recover costs incurred for exploring and developing this field are those contemplated by the PSA scheme, widely used in the industry, which we describe on page 64 of the 2006 Form 20-F as follows:

“In Product Sharing Agreements (PSAs), entitlements to production volumes are defined on the basis of contractual agreements drawn up with state oil companies which hold the concessions. Such contractual agreements regulate the recover of costs incurred for the exploration, development and operating activities (cost oil) and give entitlement to a portion of the production volumes exceeding volumes destined to cover costs incurred (profit oil).”

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In addition, at page vi of the 2006 Form 20-F, we indicate:

“....In this type of contract the national oil company assigns to the international 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 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. Further terms and conditions of these contracts may vary from country to country”.

Recoverability of the investments is subject to approval from the relevant State-owned or controlled entity who is party to the agreement. Cost overruns are recovered to the extent they are sanctioned by the State-owned or controlled entity who is party to the agreement. However, it should be noted that recoverability of the investments, from an accounting perspective, would also take into account profit oil.

Costs incurred to date for the development of the Kashagan oilfield relate to scheduled works and in accordance to the budget duly approved by the Kazakhstan authorities. Therefore these costs will be recovered through the cost oil, subject to the customary audit rights contemplated by the PSA. Future costs for further development activities on the field shall be recovered once the same Authorities have approved the relevant budget and plan. At present Eni, as operator of the field, is discussing the 2008 work program and budget filed with the Republic of Kazakhstan authorities for the purpose of obtaining the authorities’ approval, having already agreed on those matters with the other Consortium partners.

Financial Statements

Report of Independent Registered Public Accounting Firm, page F-1

Please obtain an audit opinion that indicates the location of the PricewaterhouseCoopers office that issued the audit report, as required by Rule 2-02(a) of Regulation S-X.

Response:

Please note that the original executed copy of our independent auditors’ opinion correctly indicates Rome as the location of the PricewaterhouseCoopers office that issued the report on the filing date of June 20, 2007. For your convenience, we have attached a copy of this document (see Annex A). The audit opinion filed as part of our 2006 Form 20-F did not indicate the location of the auditors’ office due to a clerical error

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in the course of the EDGAR filing process. In our future filings, we will ensure that such clerical error does not recur.

Note 25 – Guarantees, Commitments and Risks, page F-52

Other Risks and Commitments, page F-65

We note you disclose under (ii) that effective April 1, 2006, PDVSA unilaterally terminated the operating service agreement (OSA) governing activities at the Dacion oil field where you acted as a contractor, holding a 100% interest. Further, we note that you commenced an arbitration proceeding before the ICSID Tribunal to claim compensation for an amount equal to the market value of the OSA before the expropriation took place, which you believe exceeds the book value of the Dacion assets.

Please expand your disclosure to discuss your basis for concluding that the collection of this compensation from the arbitrating proceeding is probably, and to also describe the assumption you have made in anticipating compensation, such as the amount, form (e.g. cash or credits towards future contracts) and timing of payment you expect to receive.

For U.S. GAAP purposes, please explain how you have viewed the prospect of receiving such compensation, relative to the guidance in paragraph 16 of SFAS 144, which explains that estimates of future cash flows used to test the recoverability of a long lived asset should include only future cash flows that are directly associated with and that are expected to arise as a direct result of the use and eventual disposition of the assets. Given your disclosure, and as it appears you have removed proved reserve quantities associated with this field from your reserve total, it seems that disposition has occurred without compensation. Please indicate how this condition has been taken into account in your application of both IFRS and U.S. GAAP. Indicate whether your U.S. GAAP conclusions are based on the guidance in SFAS 144 or SFAS 5.

In conjunction with the foregoing, please address the guidance in paragraphs 8, 17 and 32 of SFAS 5; and clarify whether you believe you have effectively offset an impairment charge with the recognition of a gain contingency. Under this scenario, explain how you became comfortable with the timing difference between loss and recovery.

Response:

The investment of Eni Dacion BV, a Dutch affiliate of Eni that was formerly the operator of the Dacion oilfield in accordance with an Operating Service

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Agreement (OSA), was expropriated as a result of the unilateral termination of the OSA by the Venezuelan party on April 1, 2006. Eni has not received any compensation for this expropriation. In the 2006 reporting period, Eni removed the volume of proved reserves booked in connection with its interest in this oilfield.

Venezuela’s actions have violated the rights of Eni (and breached the obligations of Venezuela) under (a) the Treaty on Encouragement and Reciprocal Protection of Investments between the Government of the Netherlands and the Government of Venezuela dated 22 October 1991 (the “Treaty”); and (b) the Venezuelan Law on the Promotion and Protection of Investment dated 3 October 1999 (the “Foreign Investment Law”), and as such these actions have given rise to a dispute between Eni and Venezuela under both the Treaty and the Foreign Investment Law.

In accordance with the Treaty, Eni is entitled to a compensation for such expropriation in an amount equal to the market value of the OSA just before the expropriation took place. In particular, Article 6 of the Treaty provides that: “Neither Contracting Party shall take any measures to expropriate or nationalize investments of nationals of the other Contracting Party or take measures having an effect equivalent to nationalization or expropriation with regard to such investments, unless the following conditions are complied with: (a) the measures are taken in the public interest and under due process of law; (b) the measures are not discriminatory or contrary to any undertaking which the Contracting Party taking such measures may have given; (c) the measures are taken against just compensation. Such compensation shall represent the market value of the investments affected immediately before the measures were taken or the impending measures became public knowledge, whichever is the earlier, it shall include interest at a normal commercial rate until the date of payment and shall, in order to be effective for the claimants, be paid and made transferable, without undue delay, to the country designated by the claimants concerned and in the currency of the country of which the claimants are nationals or in any freely convertible currency accepted by the claimants”.

On this basis, on November 10, 2006, Eni commenced an arbitration procedure before the International Centre for Settlement of Investment Disputes (ICSID) against Venezuela to claim its rights. The request for arbitration was registered by ICSID on February 6, 2007, thus passing the ICSID’s preliminary prima facie jurisdictional review. Eni expects to receive compensation in an amount equal to the OSA’s market value just before the expropriation took place as provided by the above mentioned Article 6(c) of the Treaty. This market value would be calculated using the discounted cash flow method in accordance with a well established practice. With respect to the amount of Eni’s claim, based on the opinion of our internal and external legal consultants, an ICSID Tribunal is likely to rule that because there is a significant history of performance under the OSA, the market value of the OSA is the measure of its expected future profits.

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Accordingly, an ICSID Tribunal would calculate these future profits using the discounted cash flow (DCF) method and then award Eni the net present value of the cash flows Eni expected to receive under the OSA from the date before the expropriation took place on April 1, 2006 (plus interest, calculated from the same date). Our internal estimates of the OSA’s net present value of projected cash flows before expropriation result in a significantly higher value of the Dacion asset than its net book value (NBV) of $829 million (equivalent to €629 million at the euro/U.S. dollar exchange rate as of December 31 2006). Our internal estimates, fully supported by an independent evaluation carried out by a primary petroleum consulting firm, have been made based on our medium and long-term scenarios for oil prices (i.e. $40 dollar per barrel in real terms from 2010 onwards – see Item 5 – Management expectation of operation on our 2006 Form 20-F). We would expect an ICSID tribunal to estimate the OSA’s market value based on oil prices assumptions not lower than ours, especially in light of the current level of oil prices, leading to an evaluation of the OSA’s market value not lower than our internal evaluation.

In accordance with the ICSID Convention, a judgement by the ICSID Tribunal awarding compensation to Eni would be binding upon the parties and immediately enforceable as if it were a final judgement of a court of each of the States that have ratified the ICSID Convention. The ICSID Convention was ratified in 143 States.

In evaluating our ability to collect compensation based on the arbitration proceeding, we also considered that the Venezuelan State owns commercial assets outside Venezuelan borders, and that the total of the market values of these exceed the carrying amount of the expropriated asset. The history of voluntary performance by the Venezuelan State under unfavourable rulings of ICSID tribunals was also taken into account. However should Venezuela fail to comply with the award and pay compensation, Eni could take steps to enforce the award against commercial assets of the Venezuelan Government in most places where such assets are located (subject to national law provisions on sovereign immunity).

We made no assumptions regarding form (e.g. cash or credits towards future contracts) and timing of the compensation we expect to receive because at this stage of the arbitration procedure we have no evidence to evaluate such factors. However, we believe that these factors will be immaterial for the purpose of recovering the carrying amount of the expropriated asset. We also expect to recover the time value of money for any delay in collecting the compensation, because the Treaty provides for compensation to include finance income accrued from the date the expropriation took place, based on current market rates.

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Based on the above, we concluded that a positive outcome of such a procedure would be more likely than not and that the amount of the expected compensation for the expropriated asset would be higher than the carrying amount. Consequently, we did not recognize any impairment loss in connection with the expropriated asset in the 2006 reporting period.

We believe that the disclosure included on page 34 and on page F-65 of our 2006 Form 20-F provided all material information with respect to this matter. However, in response to the Staff’ comment, in the 2007 20-F we plan to expand our disclosure on the recoverability of our investment in the Dacion oilfield as follows (proposed changes are in bold):

“With effective date April 1, 2006, the Venezuelan State oil company Petróleos de Venezuela SA (PDVSA) unilaterally terminated the Operating Service Agreement (OSA) governing activities at the Dación oil field where Eni acted as a contractor, holding a 100% working interest. As a consequence, starting on the same day, operations at the Dación oil field are conducted by PDVSA. Eni proposed to PDVSA to agree on terms in order to recover the fair value of its Dación assets. In the lack of any agreement between the parties, in November 2006, Eni commenced an arbitration proceeding before an International Centre for Settlement of Investment Disputes (ICSID) Tribunal (i.e. a tribunal acting under the auspices of the ICSID Convention and being competent pursuant to the Netherlands-Venezuela bilateral investments treaty) to claim its rights. Despite this action, Eni would continue to consider a negotiated solution with PDVSA to obtain a fair compensation for its assets. Based on the opinion of its internal and external legal consultants, Eni believes to be entitled to a compensation for such expropriation in an amount equal to the market value of the OSA before the expropriation took place. The market value of the OSA depends upon its expected profits. In accordance with established international practice, Eni has calculated the OSA’s market value using the discounted cash flow method, based on Eni’s interest in the expected future hydrocarbon production and associated capital expenditures and operating costs, and applying to the projected cash flow a discount rate reflecting Eni’s cost of capital as well as the specific risk of concerned activities. Independent evaluations carried out by a primary petroleum consulting firm fully support Eni’s internal evaluation. The estimated net present value of Eni’s interest in the Dación field, as calculated by Eni, would not be lower than the net book value of the Dación assets amounting to $829 million (equal to euro 629 million based on the EUR/USD exchange rate as of December 31, 2006) which consequently have not been impaired. In accordance with the ICSID Convention, a judgment by the ICSID Tribunal awarding compensation to Eni would be binding upon the parties and immediately enforceable as if it were a final judgment of a court of each of the States that have ratified the ICSID Convention. The ICSID Convention was ratified in 143 States.

In evaluating its ability to collect compensation from the arbitrating proceeding, Eni considered that the Venezuelan State owns commercial assets outside Venezuelan borders, and that the total of the market values of these exceed the carrying amount of the expropriated asset. The history of voluntary performance by the Venezuelan State under unfavourable rulings of any ICSID tribunal was also taken into account.

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However, should Venezuela fail to comply with the award and to pay the compensation, Eni could take steps to enforce the award against commercial assets of the Venezuelan Government almost anywhere those may be located (subject to national law provisions on sovereign immunity).

Finally, Eni made no assumption regarding form (e.g. cash or credits towards future contracts) and timing of the compensation to receive, because at this stage of the arbitration procedure the Company has no evidence to evaluate such factors. However, the Company estimated that these factors will be immaterial for the purpose of recovering the carrying amount of the expropriated asset.”

Any material developments in the arbitration procedure will be taken into consideration in the future valuation of the recoverability of the carrying amount of the expropriated asset and will be disclosed as appropriate to investors in our future 20-F filings and 6-K current reports.

With reference to the representation in the financial statement for IFRS and U.S. GAAP purposes, the recoverability of Eni’s investments in the Dacion oilfield has been based on the probability that adequate compensation for the expropriated asset will be collected from the Venezuelan party. The NBV of the tangible assets of the OSA at the date of expropriation ($829 million equal to €629 million based on the Euro/U.S. dollar exchange rate as of December 31, 2006) has been reclassified in the balance sheet at December 2006 from the line item “property, plant and equipment” to the line item “Non current assets – other assets”.

For U.S. GAAP purposes, while not concluding that SFAS 144 paragraph 16 guidance is without relevance, we believe that SFAS 5 is the most appropriate basis for the accounting treatment under U.S. GAAP. Under SFAS 5, paragraph 8, the asset would be impaired if it were probable that the compensation awarded as a result of the arbitration proceedings will be lower than the NBV of the Daciòn Assets and the loss could be reasonably estimated. Consistent with paragraph 17 of SFAS 5, any gain would not be recognized until such contingency was resolved and the revenue realized.

As indicated above, Eni is entitled to compensation for such expropriation in an amount equal to the market value of the OSA before the expropriation took place and while the amount of the eventual compensation to be received remains uncertain, in-line with paragraph 32 of SFAS 5, available information indicates to us that the compensation will not be less than the carrying value since we believe it to be probable that we will at least be compensated by an amount equal to the NBV of the Daciòn Assets. Consequently, we have concluded that the condition for impairment in paragraph 8 (a) of SFAS 5 is not met. We do not believe the passage of time between the expropriation and the receipt of compensation is critical from an accounting standpoint because we believe the compensation on a discounted basis will not be reduced below the

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NBV and, in any case, we believe we will be entitled to interest over this time period (as established by article 6(c) of the Treaty). Therefore, no impairment has been recognized and, accordingly, no offset of an impairment charge has been made with the recognition of a gain contingency. Gain contingency would relate to any compensation in excess of the NBV of the Daciòn Asset and in accordance with paragraph 17 of SFAS 5 would not be recognized since such is contingent.

We believe that this approach is also consistent with paragraph 3 of FIN 30: “Accounting for Involuntary Conversions of Nonmonetary Assets to Monetary Assets” according to which in circumstances where a “nonmonetary asset is destroyed and or damaged in one accounting period, and the amount of monetary assets to be received is not determinable until a subsequent accounting period” the gain or loss shall be recognized in accordance with SFAS 5. This means that if it is probable that the amount to be received will be less than the current carrying value, an impairment adjustment would need to be recognized prior to the actual determination of the amount if the adjustment can be reasonably estimated; whereas, any amount expected in excess of the current carrying value would only be recognized once the amount was subsequently determined.

We view the expropriation as a change in the nature of our unconditional rights in respect to the Daciòn Assets. Prior to the expropriation, we had a contractual right to receive a service fee under the terms of the OSA which enables the company to recover costs incurred and to earn a certain remuneration on capital employed. Following the expropriation of assets we have lost control of our share of the Daciòn Assets, hence the decision to remove the proved reserve associated with the Dacion field from the Eni’s proved reserve. However, we believe that under the Treaty we have a current and unconditional right to be adequately compensated.

The same overall conclusion could have been reached on the basis of SFAS 144 paragraph 16, considering that an expected cash flow from compensation arises “as a result of the […] eventual disposition of the asset” since we expect that the eventual compensation value will be higher than the current carrying value of the asset. However, as forced disposal has already occurred and the compensation to be received for such forced disposal is not yet determined, we concluded that our analysis should focus on the uncertainty surrounding the amount of the eventual compensation and whether it was probable that such amount would be less than the current carrying value and, therefore, require an impairment adjustment.

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Note 36 – Adjustment of the Consolidated Financial Statements to U.S. GAAP, page F-84

A) Consolidation Policy, page F-84

We note you disclose that under U.S. GAAP, investments of less than 50% are accounted for by applying the equity method. Please note that similar to IFRS, the key element for consolidation under U.S. GAAP is control, even for investments of less than 50%, as long as control can be demonstrated. Please revise your disclosure to further clarify the basis for your consolidation policy under U.S. GAAP, relative to IFRS.

Response:

In response to the Staff’s comment, in our Form 20-F for the year 2007 (the “2007 Form 20-F”) we intend to modify our disclosure regarding consolidation policy under the section “Adjustment of the Consolidated Financial Statements to U.S. GAAP – Summary of significant differences between IFRS and U.S. GAAP” to further clarify the basis for our adjustments arising from the implementation of our consolidation policy under U.S. GAAP, relative to IFRS, as follows (proposed changes are in bold):

“A) Consolidation policy

Eni’s consolidation policy is described under “Principles of Consolidation” in the Notes to the Consolidated Financial Statements. In particular, under IFRS, the consolidated financial statements include also companies in which Eni holds less than 50% of the voting rights, but over which it holds “de facto control” through its representation in shareholders’ meetings (due to the dispersion of voting power), despite not having legal or contractual rights to control the majority of those entities’ voting power or board of directors.

Under IFRS, Eni exercises “de facto control” of Saipem SpA without holding the majority of voting rights (Eni’s interest is 43.54%) exercisable in shareholders’ meetings.

Under U.S. GAAP, investments of less than 50%, which are not consolidated as variable interest entities and which are not under “effective control”, are accounted for by applying the equity method. “De facto control” as defined by IFRS is not sufficient to demonstrate “effective control” under U.S. GAAP. Under U.S. GAAP, as a non variable interest entity and in the absence of effective control, Saipem SpA and its subsidiaries are excluded from consolidation and are accounted for under the equity method.”

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Note 37 – Reconciliation of Net Profit and Shareholders’ Equity Determined under
IFRS to U.S. GAAP, page F-87

We note on page F-89 that you present minority interest as a component of shareholders’ equity. Minority interest should be presented separate from equity for U.S. GAAP purposes. Please revise your consolidated balance sheets prepared in accordance with U.S. GAAP accordingly.

Response:

Please note that in our 2006 Form 20-F we mistakenly added together minority interest and shareholders’ equity in the line item “total shareholders’ equity” of the consolidated balance sheet for U.S. GAAP purposes on page F-89. We regard this as a minor error which should not have confused investors because in the reconciliation of the shareholders’equity determined under IFRS to U.S. GAAP disclosed on page F-88 of our 2006 Form 20-F we clearly identified the net equity pertaining to Eni’s shareholders under both IFRS and U.S. GAAP. We will change the lay-out of our minority interest and shareholders’ equity in our 2007 Form 20-F. Please note that in our latest form 6-K furnished to the SEC on October 3, 2007 (interim consolidated report for 2007) we more clearly excluded on our balance sheet presented for US GAAP purposes minority interests from total shareholders’ equity.

In response to the Staff’s comment, in the 2007 Form 20-F we plan to modify our consolidated balance sheet in accordance with U.S. GAAP by eliminating the caption “total shareholders’ equity” as follows:

	December 31, 2006	December 31, 2007


Minority interests	1,321
Eni shareholders' equity:
Share capital: 4,005,358,876 fully paid shares nominal value euro 1 each (the same amount as of December 31, 2005)	4,005

Other reserves	29,020

Net profit	10,005

Treasury shares	(5,374)

Eni shareholders' equity	37,656

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	85,806

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Engineering Comments

Risk Factors, page 4

Development projects bear significant operational risks which may adversely affect
actual returns on such projects, page 5

Risk factors should be as specific to you as possible. Please revise your document to incorporate the fact that the cost estimate of the large Kashagan field has increased from $10.3 billion to $19 billion (not including costs for a pipeline to transport the oil to markets) and that the estimated start-up of the project has been changed from the year 2008 to 2010. Include in the disclosure how this delay may impact the economics of the project and your estimated results of operations in future periods or provide a cross-reference where this is discussed in more detail.

Response:

Our 2006 Form 20-F includes a discussion of the increased cost estimate for the Kashagan field and the re-scheduling of production start up from 2008 to the third quarter of 2010. See in particular the discussion in Item 4 on page 32 of our 2006 Form 20-F.

In response to the Staff’s comment and in order to reflect developments in 2007, we expect that the disclosure of operational risks related to development projects in our 2007 Form 20-F will be updated as follows (proposed changes are in bold). Further changes reflecting other developments will also be made if appropriate.

Development projects bear significant operational risks which may adversely affectactual returns on such projects

Eni is involved in numerous development projects for the production of hydrocarbon reserves, principally offshore. Eni’s future results of operations rely upon its ability to develop and operate major projects as planned. Key factors that may affect the economics of those projects include:

the outcome of negotiations with co-venturers, governments, suppliers, customers or others (including, for example, Eni’s ability to negotiate favorable long-term contracts with customers, the development of reliable spot markets that may be necessary to support the development of particular production projects, or commercial arrangements for pipelines and related equipment to transport and market hydrocarbons);

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timely issuance of permits and licenses by government agencies;
the ability to design development projects as to prevent the occurrence of technical inconvenience;
delays in manufacturing and delivery of critical equipment, or shortages in the availability of such equipment;
risks associated with the use of new technologies and the inability to develop advanced technologies to maximize the recoverability rate of hydrocarbons or gain access to previously inaccessible reservoirs;
changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping;
the actual performance of the reservoir and natural field decline; and
the ability and time necessary to build suitable transport infrastructures to export production towards final markets.

Furthermore, deep water and other hostile environments, where the majority of Eni’s planned and existing development projects are located, can exacerbate these problems. Delays and differences between estimated and actual timing of critical events may adversely affect the completion and start up of production from such projects and, consequently, the actual returns on such projects. Finally, developing and marketing hydrocarbons reserves typically requires several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commerciality, sanctioning a development project and building and commissioning related facilities. As a consequence, rates of return of such long-lead-time projects are exposed to the volatility of oil and gas prices which may be substantially lower with respect to prices assumed when the investment decision was actually made, leading to lower rates of return. For example, we have experienced increased estimated expenditures and a delay in the scheduling of production start up on the Kashagan field, where development is ongoing. Moreover, in August 2007 these matters triggered a pending dispute with the relevant Kazakh authorities that could prompt further risks and uncertainties to the Kashagan project. See “Item 4 —Business Overview—Exploration & Production”. If we are unable to develop and operate major projects as planned, it may have a material adverse effect on our results of operations and financial condition.

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Inability in replacing oil and natural gas reserves, page 6

Risk factors should be as specific to you as possible. Please revise your document to expand this risk factor to include the fact that in the last two years your proved reserves have declined by approximately 11% and you replaced 89% and 55% respectively of your produced reserves in 2005 and 2006.

Response:

Our 2006 Form 20-F discloses the decrease in our proved reserves of 5.9% in 2006 and the reserve replacement ratio of 38% in 2006 (with an average three-year replacement ratio of 55%). See in particular the discussion in Item 4 on page 17 of our 2006 Form 20-F.

In response to the Staff’s comment and in order to reflect developments in 2007, we expect that the disclosure in our 2007 Form 20-F of our ability to replace oil and natural gas reserves will be modified as follows (proposed changes in bold):

“Inability to replace oil and natural gas reserves could adversely impact results of operations and financial condition

Eni’s results of operations and financial condition are substantially dependent on its ability to develop and sell oil and natural gas. Unless the Company is able to replace produced oil and natural gas, its reserves will decline. Eni’s proved reserves [declined by [•] in 2007 and by 5.9% in 2006] or [increased by •% in 2007 but declined by 5.9% in 2006]. In addition, Eni’s average reserve replacement ratio for the last three years is [•]%. See “Item 4 —Business Overview—Exploration & Production”. Future oil and gas production are dependent on the company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiation with countries and other owners of known reserves and acquisitions. An inability to replace reserves could adversely impact future production and hence future results of operations and financial condition.”

It should be noted that the decline in proved reserves that we experienced in 2005 and 2006 was largely attributable to lower reserve entitlements in our PSAs resulting from higher oil prices. However, we expect that the impact of lower reserve entitlements on future production levels and cash flows will be more than offset by higher returns on relevant projects via a shorter payback period and a higher share of profit oil at a higher value. Therefore, it is not always the case that a decline in proved reserves or a

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reduction in the reserve replacement rate will have an adverse impact on results of operations and financial condition.

Uncertainties in Estimates of Oil and Natural Gas Reserves, page 7

The tone of this disclosure suggests something less than the “reasonable certainty” inherent in your estimates of proved reserves. Please advise or revise your disclosure.

Response:

In our view the overall tone of this disclosure conveys that there are inherent uncertainties in estimating reserves because of the number and complexity of the variables used to estimate reserves of hydrocarbons. Moreover, these variables may change over time causing actual results to be different from expectations, thereby having some potentially significant impact on future results of operations and financial condition. We believe this type of disclosure is consistent with that of other participants in the industry who have included such uncertainties as a risk factor.

However, we believe some minor changes in language may clarify that the risk, which derives from the inherent subjectivity of these variables, may adversely impact the future results of operations and financial condition reported by Eni, but that we do not intend to suggest that the reserve estimate is less than reasonably certain. We propose to amend the last paragraph of this risk factor in our 2007 Form 20-F as follows (proposed changes are in bold and deleted words are in strikethrough):

“Many of these factors, assumptions and variables involved in estimating proved reserves are beyond Eni’s control and may ~~prove to be incorrect~~ change over time and impact the estimates of oil and natural gas reserves. Accordingly, the estimated reserves could be ~~materially~~ significantly different from the quantities of oil and natural gas that ultimately will be recovered. Additionally, any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes which could adversely impact Eni’s results of operations and financial condition”

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Oil and Natural Gas Reserves, page 18

You state that volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where you are the operator are not included in reserve volumes shown in the table. Please explain to us why these volumes are not included.

Response:

Please note that in accordance with Appendix A to Item 4.D-Oil and Gas of Form 20-F, registrants are required to furnish the following information regarding reserves disclosures:

“As of the end of each of the last three fiscal years, estimated net quantities of: …(iii) oil and gas applicable to long-term supply or similar agreements with foreign governments or authorities in which the registrant act as producer.”

Accordingly, in our 2006 Form 20-F we have disclosed the amount of reserves that we are contractually committed to purchase under long-term agreements with foreign state entities in properties where we act as producer. We did not include these volumes in our proved net reserves of oil and gas in accordance with SFAS 69 which states that net quantities of proved reserves relating to a company’s properties shall not include volumes subject to purchase under such long-term supply agreements, including agreements with governments or authorities.

Mineral Right Portfolio and Exploration Activity, page 20

Production, page 20

Portfolio Developments, page 21

10.

We note that you have disclosed the production and nature of your interest information for your principal oil and gas fields. Please revise your filing to include all the information required by Item 4D of Form 20-F. This includes, at a minimum production, reserves, nature of your interest, location and development of these principal fields. For fields of major significance include additional information and maps. It appears that the Kashagan field is of major significance to Eni SpA. If you do not agree, please tell us why you do not believe the Kashagan field is of major significance to you. Please see Instruction to Item 4D for reference.

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Response:

We respectfully submit that the information on oil and gas properties as disclosed in our 2006 Form 20-F under Item 4 includes a description of our principal properties, nature of our interests, ongoing development activities and production profiles that satisfies the requirements of Item 4.D of Form 20-F. Information on proved reserves has been disclosed only with respect to geographic areas of major importance to us as prescribed by Appendix A to Item 4.D, since we assessed that none of our individual properties, including Kashagan, were of major importance to the Company as of the filing date such that disclosure of proved reserves would be required on an individual basis. With respect to Kashagan, we considered the following factors in assessing its materiality to our oil & gas operations:

With respect to reserves, we considered that the level of reserve volumes booked for the Kashagan field as of December 31, 2006 represented less than 10% of our total proved reserves as of that date.

ii)

With respect to production, the Kashagan field is not currently producing any oil and is expected to produce an immaterial amount over the 2007-2010 four-year plan; accordingly, developments at Kashagan, whether positive or negative, would not affect our production growth targets indicated in the 2006 Form 20-F. In the longer term up to 2013, we expect production from the Kashagan field to give a similar contribution to our production growth as several other development projects in our portfolio for which exploratory, sanctioning and engineering activities are progressing. Many of these long term projects are already disclosed in our filing.

iii)

With respect to results of operations and financial condition, we considered that cash flows from the Kashagan fields will materialize over a long term horizon and it will take several years before Kashagan begins to generate a significant contribution to our cash flow from operations or our profits.

Based on the foregoing, we do not regard the Kashagan field or any other Eni’s property discussed on pages 21-34 of the 2006 20-F to be individually of major significance to the Company. As a result, we believe that Instruction 1(a) to Item 4.D is not applicable to that discussion.

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In the future we will monitor the contribution of the Kashagan field to: (i) our reserve base as further reserves are booked at Kashagan in conjunction with the progress of the project development activities; (ii) production profiles and growth rates; and (iii) results of operations and cash flows, with a view to ensuring continuing compliance with the instructions to Item 4.D of Form 20-F.

11.

We note your natural gas reserves that are produced in Africa and Australia – where the natural gas markets are not well developed – then sold to LNG plants for conversion to liquids and transported to more developed natural gas markets such as Japan. Tell us how you value the natural gas reserves that are produced in Africa and Australia in the standardized measure.

Response:

The standardized measures of gas reserves produced in Africa and Australia that are sold to LNG plants have been determined on a “netback basis” by applying the price formulas included in each supply agreement between Eni and the LNG plant owners.

In this context, netback basis means that the volumes of gas booked as reserves are valued in accordance with contractual LNG prices net of processing, transportation, shrinkage and other specific cost elements.

Kazakhstan, page 32

12.

We note that you are now estimating start up of the Kashagan field to occur in 2010 instead of your previous estimate of 2008 which you were disclosing as recently as your 2005 20-F. Given the past history of delays due to technological and recent political issues here and elsewhere, tell us why you now believe the most recent estimate of start-up in 2010 is reliable.

Response:

Since the time when our 2005 Form 20-F was filed, we have now completed the design enhancement of the first phase of the Kashagan project and resolved the major technical and technological issues we encountered. Additionally, all principal contracts for completing this phase have been assigned. Our estimated production start-up is based on scheduled programs as agreed upon with our contractors, for which detailed workflows have been prepared. Based on the foregoing, management currently expects production start up at the Kashagan field in 2010.

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However, these are our management’s current expectations based on the best information available and established budget and programs. Our risk factors section on page 5 of the 2006 Form 20-F describes the specific risks affecting the timing and returns of development projects. See also our response to Question No. 6.

13.

We note that you are now estimating a total cost of development of the Kashagan field to be $19 billion instead of the previous estimate of $10.3 billion. Given the prior large underestimation of costs, please tell us why you believe the most recent cost estimate is reliable.

Response:

As discussed in our 2006 Form 20-F, $19 billion is the development cost for the first phase of the project, which is designed to reach a production target rate of 300,000 barrels per day as compared with an estimated full-field plateau of 1,500,000 barrels per day associated with the full field development scheme. In our 2006 Form 20-F, we disclosed the reasons why the costs to complete the first development phase increased from $10.3 to $19 billion. As discussed under our response to Question No. 12, all major technological issues relating to the first phase have now been resolved and the scope and costs for this phase have been updated accordingly. Having completed the enhancement of the facilities and reviewed the project baseline, we now have better visibility on the expected future cost developments than a year ago, taking into account that work performed to date exceeds 50% of the total work program for both onshore and offshore activities. Based on the extrapolation of our trends in costs, manpower and deployment of resources until the end of 2010, we forecast a $19 billion total expenditure for the first phase of this project. These are our management’s current expectations based on the best information available and established budget and programs. Future developments at Kashagan are subject to the risks described in our 2006 Form 20-F and in response to Question No. 6.

14.

Due to the high degree of political and cost uncertainty surrounding the Kashagan field, tell us how this uncertainty has been factored into your most recent estimate of proved reserves for this field. Tell us if you have revised your proved reserves for the Kashagan field in each of the last two years, the revised quantities and the basis for any such revisions.

Response:

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Our proved reserves estimates follow the guidance provided by Regulation S-X Rule 4-10 of the Security Exchange Commission and are based on – among other factors – the best available estimates of future capital expenditures. Normally, in accordance with that guidance, we do not factor in any estimate of “political uncertainty” to the extent that we do not have evidence of any risk that could likely limit our ability to market reserves.

Proved reserves of the Kashagan field were revised in 2005 and 2006. In 2005, Kashagan proved reserves were increased by 61 Mboe due to (i) the change in Eni’s interest resulting from Eni’s acquisition of part of British Gas’s share, (ii) an extension of the proved area due to the collection of new data from drilling activities, and (iii) a technical revision. Those positive changes were partly offset by the impact of increased year-end oil prices on reserve entitlements in accordance with the PSA scheme. In 2006, proved reserves were increased by 107 Mboe to [CONFIDENTIAL INFORMATION HAS BEEN OMITTED AND FURNISHED SEPARATELY TO THE SECURITIES AND EXCHANGE COMMISSION] Mboe due to an extension of the proved area and project cost revision, offset in part by the year-end price variation.

15.

You disclose that the most recent cost estimate of $19 billion is to reach a production target rate of 300,000 barrels per day. However, you then estimate the field will eventually plateau at a full-field rate of 1.5 million barrels of oil per day. Tell us if it will cost additional investment to increase from 300,000 barrels per day to 1.5 million barrels per day and if so tell us how much it will cost and why this was not included in the cost estimate of $19 billion. If it will not cost any more to reach a production rate of 1.5 million barrels per day tell us why it will not.

Response:

We can confirm that the achievement of the target production plateau of 1.5 million barrels of oil per day will require a material amount of development expenditures in addition to the estimated $19 billion required to achieve the production target rate of 300,000 barrels per day in the first development phase. We are currently in the process of discussing with the Republic of Kazakhstan options, terms and costs for the full field development scheme, and, accordingly, at this time we have no reliable estimates for the additional cost required to achieve the full-field rate of 1,500,000 barrels. However, in response to the Staff’s comment and as part of our normal disclosure policy, in future filings we plan to disclose to investors the estimate for the full-field development expenditures once negotiations with relevant Kazakh Authorities have been finalized, if such amounts will be material and reasonably quantifiable.

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16.

You indicate you now estimate that production from the Kashagan field will plateau at a higher production rate of 1.5 million barrels of oil per day than the previous estimate of 1.2 million barrels of oil per day. Please tell us the basis for this increased estimate and if an independent engineer has verified this estimate.

Response:

The higher production rate of 1,500 thousand barrels a day has been estimated by taking into account the very promising results of the drilling campaign — the well tests conducted on the appraisal and producing wells have shown a daily rate per well in excess of 30,000 barrels per day. Our engineering estimate follows a complex purpose-built reservoir model and indicates that the 1,500 thousand barrels a day production rate can be sustained for several years. A study of the reservoir performed by an independent evaluator fully supports the target production plateau of the Kashagan field.

Turkey, page 33

17.

Please revise your document to disclose the estimated date to complete the Samsun-Ceyhan pipeline and the estimated cost to build it.

Response:

The Samsun-Ceyhan pipeline is expected to be built in a three-year time frame once a Final Investment Decision (FID) has been made. A FID is currently scheduled early next year. In the meantime, front end engineering studies are progressing and a cost estimate for this project is expected upon completion of these studies as well as market enquiries on the cost of materials and services. Eni’s current interest in the project is 50%.

In response to the Staff’s comment, we plan to expand our disclosure regarding this pipeline in the 2007 Form 20-F by disclosing any developments regarding time and expected expenditures for this project.

Management Expectations of Operations, page 100

18.

You state that your target of achieving a production growth of 4% in 2007 through 2010 is based on the assumption that oil prices will decline during this period from $55 to $40. These lower oil prices will allow you to claim more reserves and production from your PSA’s. However, as this appears to be a very optimistic forecast for oil prices, please revise your disclosure to also

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include how your production growth rate may change if oil prices remain at current levels.

Response:

For the current year, we estimate that our daily production entitlements would decrease on average by approximately 2,000 barrels for each $1 increase in oil prices compared to our assumptions. Applying the same criterion to the 2008-2010 period and assuming a constant $70 per barrel Brent scenario for the 2007-2010 period, we estimate that our planned production growth rate for that period would decline by approximately 0.8 percentage points (from the projected 4% to 3.2%). Please note that this sensitivity analysis relates to the Eni portfolio and contractual terms in place at the filing of the 2006 Form 20-F and might vary in the future.

In response to the Staff’s comment, in future filings we plan to expand our disclosure of management’s expectations of production growth presently on page 101 of our 2006 filing, by discussing in quantitative terms the sensitivity of our production growth rates to changes in oil prices as follows (proposed changes are in bold):

“Management plans to cover financial needs for capital expenditure and dividends by means of cash flows provided by operating activities. Management expects crude oil prices to remain high and volatile in the next two years. For the purpose of planning investments and liquidity management, management assumes a level of xx $/BBL for 2008 and 2009; then in the following years management assumes crude oil prices to stabilize until settling on the long-term level of xx $/BBL in real terms. Management’s target to achieve an average production growth rate of xx% in the 2008-2011 four-year period is based on the assumption of a Brent crude oil price of xx $/BBL in 2011, which forms the basis for management’s estimate of production entitlements under certain PSAs and buy-back contracts. For the current year, we estimate that our daily production entitlements would decrease on average by approximately x,xxx barrels for each $1 increase in oil prices compared to our assumptions. Applying the same criterion to the 2009-2011 period and assuming a constant $xx per barrel Brent scenario for the 2008-2011 period, we estimate that our planned production growth rate for that period would decline by approximately 0.xx percentage points (from the projected xx% to xx%). This sensitivity analysis relates to the existing Eni portfolio and might vary in the future.”

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Supplemental Oil and Gas Information, page F-98

Oil and Natural Gas Reserves, page F-102

19.

Revise your disclosure to more fully explain the term “independent evaluation” and the work performed by the independent engineers. This should include but is not limited to:

Disclose which systems, controls and approvals they evaluated in order to arrive at an opinion and what parameters they did not independently verify.
Disclose what their opinion letter stated.
Disclose the difference between a reserve evaluation that they performed and a reserve determination.
Disclose, if true, that the work performed in evaluating your reserves may not be the same work they perform when evaluating other companies’ reserves.
Disclose if any major properties have not been independently evaluated in the last three years.
Explain how these evaluations raise the confidence that the reserves reported meet the definition of proved reserves and are reasonably certain to be produced in the future.

Response:

Degolyer & MacNaughton and Ryder Scott Company, the two independent evaluators used in past years by Eni, did not perform a review of Eni’s booking reserves process. They executed a technical-economical evaluation at the same time as our internal evaluation in order to provide an independent appraisal of both gross reserves to be produced after year-end, and net reserves attributable to the Eni’s interest on the basis of the relevant agreements governing each property.

The independent evaluators provided reports which presented values for proved reserves estimated using year-end prices and costs. Values for proved reserves in those reports were expressed in terms of future gross revenues, future net revenues, and present value. Future gross revenues are defined as gross revenues to be realized by Eni from the sale of the net reserves. Future net revenues are defined as future gross revenues less host country taxes, direct operating expenses, royalties where applicable, transportation costs, capital costs, and abandonment costs where applicable. Direct operating expenses include field operating expenses, estimated expenses of direct supervision, and an allocation of overhead that directly relates to production activities.

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For this purpose, Eni provided the independent evaluators with all available data and information used for its own evaluations of proved reserves, including log, directional surveys, core and PVT analysis, maps, oil/gas/water monthly production/injection data of wells, reservoir, and field, field studies, reservoir studies; engineers comments relative to field performances, reservoir performances, development programs, work programs etc.; budget data for each field, long range development plans, future capital and operating costs, actual prices received from hydrocarbon sales, instructions on future prices, and other pertinent information to calculate NPV for the fields required to undertake an independent evaluation.

Accordingly, in the preparation of reports, the independent evaluators relied, without independent verification, upon information furnished by Eni with respect to property interest, production, current cost of operation and development, agreements relating to future operations and sale, prices and other factual information and data that were accepted as represented by the independent evaluators.

Based on the foregoing, we believe that the work performed by the independent evaluators is to be considered an evaluation of our proved reserves as opposed to a determination.

In the last three years, the most important Eni’s properties which were not subject to an independent evaluation were:

–

Karachaganak field (Kazakhstan); the latest evaluation was performed by Degolyer & MacNaughton in 2003. A new evaluation is planned in 2007.

–

Bayu Undan field (Australia): the latest evaluation was performed by Ryder Scott Company in 2003. A new evaluation is planned in 2008.

–

Bonga field (Nigeria): under evaluation in the current year.

–

Cerro Falcone and MonteAlpi-Monte Enoc fields (Italy): the latest evaluation was performed by Ryder Scott in 2003. A new evaluation is planned in 2008.

We believe the two above mentioned engineering companies to be experienced and qualified in the marketplace. Based on our experience (Eni conducts independent reserve assessments since 1991), Eni’s assessments of proved reserves volumes and those performed by the independent evaluators have shown similar results for a vast majority of fields. Where discrepancies have arisen, Eni booked the volumes of estimated proved reserves indicated by the independent evaluators, whenever the latter was lower than the Company’s estimate. In any case, those differences were not significant.

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The double control performed on a rotational basis by the two independent evaluators on the vast majority of Eni’s fields support management’s confidence that the company’s booked reserves meet the regulatory definition of proved reserves and are reasonably certain to be produced in the future.

In response to the Staff’s comment, in our 2007 Form 20-F we plan to expand our disclosure on proved reserves currently at page F-101 of our 2006 filing as follows (proposed changes in bold):

“Oil and natural gas reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under technical, contractual, economic and operating conditions existing at the time. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Net proved reserves exclude royalties and interests owned by others.
Proved developed oil and gas reserves are proved reserves that can be estimated to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.
Additional oil and gas reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing natural forces and mechanisms of primary recovery are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed, through production response, that increased recovery will be achieved.
Eni’s proved reserves have been estimated on the basis of the applicable U.S. Securities & Exchange Commission Regulation, Rule 4-10 of Regulation S-X and its interpretations and have been disclosed in accordance with Statement of Financial Accounting Standard No. 69. The estimates of proved reserves, developed and undeveloped for years ended December 31, 2004, 2005, 2006 and 2007 are based on data prepared by Eni. Since 1991, Eni has requested qualified independent oil engineering companies carry out an independent evaluation¹¹ of its proved reserves on a rotational basis. Eni believes these independent evaluators to be experienced and qualified in the marketplace. In the preparation of their reports, these independent evaluators relied, without independent verification, upon information furnished by Eni with respect to property interest, production, current cost of operation and development, agreements relating to future operations and sale, prices and other factual information and data that were accepted as represented by the independent evaluators. This information was used by Eni in determining its proved reserves and included log, directional surveys, core and PVT analysis, maps, oil/gas/water monthly production/injection data of wells, reservoir, and field,; field studies, reservoir studies; engineers comments relative to field performances, reservoir performances, development programs, work programs etc.; budget data for each field, long range development plans, future capital and operating costs, actual prices received from hydrocarbon sales, instructions on future prices, and other pertinent information to calculate NPV for the fields required to undertake an independent evaluation. Accordingly, Eni believes that the work performed by the independent evaluators is to be considered an evaluation of Eni’s proved reserves as opposed to a determination. We also note that the work performed in evaluating our reserves may not be the same work that the independent evaluators perform when evaluating other companies’ reserves. Notwithstanding the above, the circumstance that the independent evaluations achieved the same results as those of the Company for the vast majority of fields support the management’s confidence that the company’s booked reserves meet the regulatory definition of proved reserves and are

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reasonably certain to be produced in the future. Additionally, for those fields where a discrepancy arose, the Company has adopted the reserve estimate indicated by the independent evaluators, whenever the latter was lower than the Company’s estimate. In any case, those differences were not significant.

In 2007 a total of xx BBOE of proved reserves, or about xx% of Eni’s total proved reserves at December 31, 2007, have been evaluated. In the 2005-2007 three-year period, xx% of Eni’s total proved reserves were subject to independent evaluations. In the last three years, the most important Eni’s properties which were not subject to an independent evaluation were:

i).............”

20.

We note in the West Africa geographic area, the reserve index of your gas reserves is almost 19 years. Please explain why the reserve index there is materially longer than the oil reserves in that area and is materially larger than other geographic areas. Tell us if you have identified definitive gas markets for all of your proved gas reserves in West Africa and if so what they are.

Response:

Both Eni’s proved gas reserves and its current gas production in West Africa are attributable almost entirely to Nigeria.

Eni has been active in Nigeria since 1962, while our business for developing and marketing gas reserves in that country only began in 1990. During the 30 years prior to commencing gas production, the gas fields and/or levels in Eni’s concessions have been preserved for future development. This explains the more extended gas reserves life index in comparison with the oil reserves.

The natural gas production volumes shown for West Africa in 2006 comprised almost exclusively Eni’s gas volumes supplied to the Nigerian LNG project at Bonny Island (please refer to our 2006 Form 20-F, page 28 for additional detail). A fifth train in the Bonny Island liquefaction plant started operation early in 2006 and a sixth train is presently under construction. Gas sales agreements for the LNG trains 1 to 6 were in place as of December 31, 2006 covering most of our Nigerian gas proved reserves.

Based on the incremental gas volumes we expect to supply to the Bonny Island LNG trains once trains 5 and 6 have achieved full operations, we estimate that the life index of Eni’s proved gas reserves in Nigeria will decrease to approximately 12 years by 2010 year-end as compared to 19 years at 2006 year-end.

Additionally, we plan to build a new LNG plant located at Brass in Nigeria expected to come online in 2011, which will further enhance our ability to book,

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develop and market gas reserves (please refer to the discussion on page 28 or our 2006 Form 20-F).

***

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.

If you have any questions relating to this letter, please feel free to call the undersigned at +39-02-5982-1000 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)

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Annex A

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[LETTERHEAD OF PRICEWATERHOUSECOOPERS]

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Eni SpA

We have completed an integrated audit of Eni SpA’s 2006 consolidated financial statements and of its internal control over financial reporting as of December 31, 2006 and audits of its 2005 and 2004 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets and the related consolidated profit and loss accounts, consolidated statements of changes in shareholders’ equity and consolidated statements of cash flows present fairly, in all material respects, the financial position of Eni SpA and its subsidiaries at December 31, 2006, and December 31, 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with International Financial Reporting Standards as adopted by the European Union. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

International Financial Reporting Standard as adopted by the European Union vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effect of such differences is presented in Notes 36, 37 and 38 of the financial statements.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Annual Report on Internal Controls over Financial Reporting appearing in Item 15 of this Form 20-F, that the Company maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control – Integrated Framework issued by the Committee

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of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the COSO.

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting standards and principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting standards and principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers SpA

PricewaterhouseCoopers SpA

Rome, June 20, 2007