Eni announces results for the fourth quarter and the full year 2013

Rome, February 13, 2014 – Eni, the international oil and gas company, today announces its Group results for the fourth quarter and the full year 2013 (unaudited).

Financial highlights ¹

• Adjusted operating profit: €3.52 billion (down 29%) for the quarter; €12.62 billion (down 34%²) for the full year;
• Adjusted net profit: €1.30 billion for the quarter (down 14%); €4.43 billion for the full year (down 35%²);
• Reported net loss of €0.61 billion for the quarter (up 69%); reported net profit of €5.20 billion for the full year (up 24%);
• Operating cash flow: €3.18 billion for the quarter; €10.97 billion for the full year;
• Leverage at 0.25, unchanged from 2012;
• Dividend proposal for the full year of €1.10 per share, including an interim dividend of €0.55 per share paid in September 2013 (€1.08 in 2012);
• Activated the share buyback programme in January 2014.

Operational highlights

• Oil and gas production: 1.619 mmboe/d in the year, down 4.8% from 2012, (1.577 mmboe/d in the quarter, down 9.7%) mainly due to geopolitical factors;
• Preliminary year-end proved reserves estimate: 6.54 bboe. The organic reserve replacement ratio was 105%;
• Eni's interests in the upstream monetized for a total amount of €5.6 billion: Eni's interest in the joint venture Artic Russia sold for a total consideration of €2.2 billion, cashed-in in January 2014; Eni's 28.57% share in Eni East Africa, which retains interests in Area 4 mineral property in Mozambique, sold;
• 1.8 billion barrels added to the Company's resource base following exploration success in Mozambique, Ghana, Congo, Angola, Norway, Australia, Pakistan and Egypt;
• Renegotiated supply terms of 85% of long-term contracted gas;
• €2 billion cash flow improvement from the ongoing turnaround in mid-downstream businesses.

Paolo Scaroni, Chief Executive Officer, commented:
"In 2013 Eni achieved solid results in a particularly difficult market. Despite problems in Libya and Nigeria, our E&P Division confirmed its capability to deliver high profits thanks to its cost leadership and extraordinary exploration successes. Our Mid and Downstream businesses, while at a disadvantage from the Italian and European crisis, strengthened their restructuring actions achieving a significant improvement in cash generation. Finally, the portfolio rationalisation permitted by the new discoveries has allowed an anticipated monetization of results and cash. The overall effect of what we have done in this challenging year enabled us to deliver an increased net profit versus 2012, to pay a generous dividend and to launch a buyback program, while maintaining a constant debt".

(1)Throughout this press release, changes in the Group results are calculated with respect to results earned by the Group's continuing operations in 2012 considering that at the time Snam was consolidated in the Group accounts and reported as discontinued operations based on IFRS 5.
(2)These changes are calculated by excluding Snam's contribution to the Group results in the full year 2012. This is the result of Snam's transactions with Eni being included in the continuing operations results of the full year 2012 according to IFRS 5. Adjusted operating profit and adjusted net profit are not provided by IFRS.
 

Adjusted operating profit

In the fourth quarter of 2013, the adjusted operating profit was €3.52 billion, down 29.2% compared to the fourth quarter of 2012. This decline was mainly due to the Exploration & Production Division (down €1.55 billion, or 31.8%) as a result of extraordinary interruptions to production and the appreciation of the euro against the US dollar (up 4.9%).

In spite of an ongoing demand downturn, oversupplies and strong competitive pressures, Eni’s mid and downstream businesses have shown good progress in cost discipline and, more broadly, in implementing the Company's turnaround strategy. The Gas & Power Division reported adjusted operating profit of €357 million (up by €315 million compared to the fourth quarter of 2012), benefiting from the renegotiations of long-term gas supply contracts, some of which were retroactive to previous reporting periods. In the Refining & Marketing and Chemical Divisions efficiency improvements absorbed part of the negative impact of the trading environment (both sectors reported higher losses of €88 million and €14 million, respectively). The Engineering & Construction segment incurred a decrease of 51.9% in operating profit due to a slowdown in business activity and to the lower profitability of ongoing contracts.

In 2013, adjusted operating profit was €12.62 billion, down by 36.3% from 2012, or 33.6% when excluding the contribution of Snam to continuing operations in 2012. This decline was driven by the same drivers for the quarter and extraordinary contract losses incurred by the Engineering & Construction segment in first half of the year.

Adjusted net profit

In the fourth quarter of 2013, adjusted net profit was €1.30 billion (down by 14.3%). This decline was due to a lower operating performance, partly offset by a lowered consolidated tax rate (down by approximately 7 percentage points) mainly reflecting a smaller contribution from the Exploration & Production Division to the Group consolidated earnings before tax. For the full year, adjusted net profit was €4.43 billion, down by 35% when excluding Snam’s contribution to continuing operations in 2012. The Group adjusted tax rate increased by 7 percentage points, due to a greater contribution to the Group profit before income taxes from the Exploration & Production segment which is subject to a larger fiscal take than other Group’s businesses.

Capital expenditure

Capital expenditure for the fourth quarter of 2013 amounted to €3.77 billion (€12.75 billion for the full year 2013), mainly related to the development of oil and gas reserves.

Balance sheet and Cash flow

In 2013, net cash generated by operating activities amounted to €10,969 million (€3,181 million in the fourth quarter), benefiting from a larger amount of receivables due beyond the end of the reporting period transferred to financing institutions (€552 million) compared to the amount made at the end of 2012.

Cash from disposals amounted to €6,360 million, mainly relating to the divestment of a 28.57% stake in Eni East Africa, retaining interests in the Area 4 mineral property in Mozambique, to China National Petroleum Corporation for €3,386 million, and the divestment of the financial interests in Snam and Galp (€2,289 million).

These inflows were used to fund almost completely the financing requirements for capital expenditure incurred in the year (€12,750 million) and the dividend payment to Eni’s shareholders (€3,949 million, related to the dividend balance for the year 2012 and the 2013 interim dividend) and to Saipem’s shareholders (€170 million).

As of December 31, 2013, net borrowings³ amounted to €15,428 million, substantially in line with 2012, while representing an increase of €282 million from September 30, 2013 mainly due to the financing requirements for capital expenditure being higher than the net cash generated by operating activities. The latter benefitted of a larger amount of receivables due beyond the end of the reporting period transferred to financing institutions (€940 million) compared to the third quarter of 2013.

The ratio of net borrowings to shareholders’ equity including non-controlling interest - leverage⁴ – was 0.25 at December 31, 2013, in line with December 31, 2012 (0.24 at September 30, 2013).

Dividend 2013

The Board of Directors will propose the distribution of a cash dividend of €1.10 per share⁵ (€1.08 in 2012) at the Annual Shareholders’ Meeting. Included in this annual payment is €0.55 per share which was paid as interim dividend in September 2013.

The balance of €0.55 per share will be payable to shareholders as of May 22, 2014, with the ex-dividend date being May 19, 2014.

Exploration & Production

In the fourth quarter of 2013, Eni’s liquids and gas production of 1,577 kboe/d declined by 9.7% from the fourth quarter of 2012, reflecting significant force majeure events in Libya and in Nigeria. The contribution of the start-up of new fields and continuing production ramp-ups mainly in Algeria and Egypt partly offset the effects of planned facility downtimes and technical problems, in the North Sea and in the Gulf of Mexico respectively, as well as mature field declines.
In 2013, hydrocarbon production declined by 4.8% from 2012 due to the drivers described in the quarterly disclosure and to the impact of the disposals made in the first half of 2012.

Gas & Power

In the fourth quarter of 2013, Eni’s natural gas sales were 25.56 bcm (including Eni’s own consumption, Eni’s share of sales made by equity-accounted entities and upstream sales in Europe and in the Gulf of Mexico), representing a slight increase compared to the fourth quarter of 2012 (up by 0.48 bcm, or 1.9%). Italian sales increased by 5.4% to 10.70 bcm driven by higher spot volumes. This positive was partly offset by lower sales to the industrial and residential sectors against the backdrop of an ongoing demand downturn, competitive pressure and oversupply.

Sales in Europe reported a slight decrease compared to the fourth quarter of 2012 (down by 1.4%) driven by lower volumes marketed in the Benelux and France due to competitive pressure, while higher spot sales were registered in the UK.

In 2013, Eni’s gas sales of 93.17 bcm were 2.3% lower than in 2012. When excluding the effect of the divestment of Galp, gas sales were broadly in line with the previous year. Eni’s sales in the domestic market increased by 1.08 bcm driven by higher spot sales and by higher sales to importers in Italy (up by 1.94 bcm). This positive trend was more than offset by lower volumes marketed in the main European markets (down by 5.61 bcm, particularly in the Benelux, the Iberian Peninsula and the United Kingdom) due to declining gas demand and competitive pressure. Higher sales in markets outside Europe (up by 0.56 bcm) were driven by higher LNG sales in the Far East, particularly in Japan and Korea.

Refining & Marketing

In the fourth quarter of 2013, refining margins in the Mediterranean area fell to an unprecedented level, down to less than one dollar per barrel (down by 81.1% from the fourth quarter of 2012; down by 45.3% from 2012) due to structural headwinds in the industry driven by overcapacity, lower demand and increasing competition from imported refined product streams. Furthermore, Eni’s results in the Refining & Marketing Division were affected by narrowing differentials between the heavy crudes processed by Eni’s refineries and the marker Brent which reflected the lower availability of the former in the Mediterranean area.

In the fourth quarter of 2013, retail sales in Italy were 1.57 mmtonnes (6.64 mmtonnes in 2013), decreasing by approximately 12.8% from the fourth quarter of 2012 (down by 0.23 mmtonnes; down by 1.19 mmtonnes, or 15.2% from 2012) driven by reduced consumption and increasing competition.

In 2013, Eni’s retail market share decreased by 3.7 percentage points to 27.5%, from 31.2% in 2012 when sales volumes benefited of the effect of a promotional campaign made during the summer weekends.

Currency

Results of operations for the fourth quarter and the full year 2013 were affected by the appreciation of the euro against the dollar (up by 4.9% in the quarter; up by 3.3% over the year).

Business developments

In 2013, Eni continued to invest selectively in the future growth of oil and gas production and to implement the Company’s turnaround strategy for the mid and downstream businesses.

In the Exploration & Production Division, exploration activity added 1.8 billion boe of fresh resources to the Company’s resource base. This was driven by large exploration successes achieved in Mozambique, with new discoveries and the appraisal of Area 4, and in core areas such as Ghana, Congo, Angola, Norway, Australia, Pakistan and Egypt. In line with the strategy of value creation for our shareholders, Eni monetized the discovered volumes in Mozambique by divesting an interest of 20% to its Chinese partner CNPC for a total net consideration of €3.4 billion. It also disposed of  its 60% stake in Artic Russia, a joint venture with Gazprom, engaged in the development of gas reserves in Siberia, for a total consideration of €2.2 billion which was cashed-in in January 2014. In the full year all of Eni’s eight planned start-ups were achieved and seven main projects were sanctioned.

Oil and natural gas production was adversely affected by several interruptions and temporary shutdowns due to geopolitical factors, particularly in Libya.

The Gas & Power, Refining & Marketing and Chemical Divisions were more exposed to the European slowdown and have intensified restructuring efforts and optimization initiatives in order to limit the impacts of the structural decline demand, poor industry fundamentals and strong competition.

In the Gas & Power Division Eni is progressing in the renegotiation of its long-term supply contracts in order to regain in competitiveness and mitigate the take-or pay risk. In December, Eni finalized the renegotiation of a relevant contract with a Dutch gas supplier.

In the Refining & Marketing Division, efficiency measures allowed the Company to save approximately €120 million and actions are underway to streamline refining capacity, among which the Venice plant’s conversion project, the first phase of which is expected to be completed by the first half of 2014.

In the Chemical sector Eni is progressing with the restructuring of its loss-making plants, deploying green chemistry projects, as well as entering into joint ventures with strategic international partners.

In 2013, Eni finalized the divestment of the available-for-sale interests in Snam and Galp, reinforcing the Group’s balance sheet.

Mozambique

On July 26, 2013, Eni concluded the sale of a 28.57% interest in Eni East Africa (EEA) to China National Petroleum Corporation (CNPC). EEA retains a 70% interest in the Area 4 mineral property, located offshore of Mozambique. CNPC indirectly acquires, through its equity investment in Eni East Africa, a 20% interest in Area 4, while Eni retains operatorship and a 50% interest through the remaining stake. The total consideration was equal to €3,386 million, with a gain of equivalent amount recorded in profit and loss (€3,359 million, €2,994 million net of tax charges).

The exploration campaign of the year regarded the appraisal of the Mamba and Coral discoveries and a new prospect in the Southern section of Area 4, where in September 2013 Eni made the Agulha discovery, the tenth discovery in Area 4. Management estimates that Area 4 may contain up to 2,650 billion cubic meters of gas in place. Agulha was drilled in 2,492 meters of water and reached a total depth of 6,203 meters. In 2014, Eni will continue appraisal activities, particularly regarding the new exploration prospect, where the drilling of two to three additional wells is planned.

Russia

Eni divested to Gazprom its 60% interest in Artic Russia, the subsidiary owing a 49% stake of Severenergia, which holds four licenses for the exploration and production of hydrocarbons in the region of Yamal Nenets (Siberia), among which in particular
the on-stream field of Samburgskoye, Eni’s first development in the Russian upstream.

On January 15, 2014, the consideration for the disposal equal to €2.16 billion ($2,940 million) was cashed in. At the balance sheet date, Eni’s interest in Artic Russia was classified as an asset held for sale and measured at fair value due to the loss of joint control over the investee following the occurrence of all conditions precedent of the SPA effectiveness on December 20, 2013 with a revaluation gain of €1,682 million recorded through profit.

With this disposal, Eni monetized a mature investment, but maintains a strong commitment in the Russian upstream through the partnership with Novatek, the projects in the Mediterranean offshore and, with Rosneft, the projects for exploration in the Russian section of the Black Sea and in the Barents Sea.

In June 2013, Eni and Rosneft signed a strategic cooperation agreement for exploration activities in the Russian section of the Barents Sea (Fedynsky and Central Barentsevsky licenses) where seismic surveys have been started, and in the Black Sea (Western Chernomorsky license). Furthermore, the two partners signed commercial agreements for oil supplies and joint logistic activities, including the project of the development of the new Eni Logistic Center in the Venice area.

Ukraine

On November 27, 2013, Eni signed a Production Sharing Agreement for the exploration and development of a high potential area located in Ukraine’s Black Sea. The area includes the licenses of Abiha, Mayachna and Kavkazka, in the oil and gas Pry Kerch block, as well as the Subbotina oil discovery, for total 1,400 square kilometers. Eni is the operator with 50% interest. The agreement is under the approval of the relevant authorities.

United States

On November 5, 2013, Eni signed an agreement with the American company Quicksilver, for explorating and developing an area with unconventional oil reservoirs (shale oil), onshore the United States. Eni is expected to acquire a 50% interest in the Leon Valley area (West Texas). The work plan provides for the drilling of up to five exploration wells, aiming at determining the hydrocarbon potential of the area and the subsequent development plan. Eni will invest up to $52 million, for the completion of the project’s exploration activities. The agreement also establishes that Eni will obtain 50% of another area located in the Leon Valley, without additional costs.

In March 2013, among the Lease Sale 227 international bidding round, Eni was awarded the exploration license for five offshore blocks in the Central Gulf of Mexico, located in the high potential areas of the Mississippi Canyon and the Desoto Canyon. The bid is under the approval of the relevant authorities.

Kazakhstan

On September 11, 2013, following the completion, test and delivery of all infrastructures, the first oil from the giant Kashagan field was produced.

From October 2013 production has been halted due to a technical issue that occurred to the pipeline transporting acid gas from offshore to onshore facilities, without any impact on the environment and local communities.

Recovery activities are ongoing. Management believes that from 2015 field production will recover to the originally expected level, nonetheless the field contribution to Eni’s production profile for the year 2014 has been prudently assumed to be marginal.

Congo

In September 2013, Eni acquired the Ngolo exploration block, which is part of the Cuvette Basin. Eni will be operator of the joint venture with the Congolese state company Société Nationale des Pétroles du Congo (SNPC). Exploration activities will take place over a period of 10 years. The Cuvette Basin is one of the new themes of frontier exploration in Africa.

Norway

In 2013, Eni was awarded the operatorship in the PL 717, PL 712 and PL 716 licenses, with an interest of 40%, as well as the interest of 65% in the PL 697 license and the interest of 30% in the PL 714 license.

Timor Sea

In April 2013, Eni was awarded an exploration license (Production Sharing Contract) covering an area of 662 square kilometers in the Timor Sea, within the Joint Petroleum Development Area (JPDA), which is administered by both Australia and Timor Leste. The PSC foresees the commitment to drill two exploration wells during the first two years and options for other two wells.

Cyprus

In January 2013, Eni signed Exploration and Production Sharing Contracts with the relevant authorities of the Republic of Cyprus, for Blocks 2, 3 and 9 located in the Cypriot deep offshore portion of the Levantine basin over an area of around 12,530 square kilometers, thus marking Eni’s entry into the Country.

Egypt

Eni was awarded a deepwater exploration block (Block 9) in the EGAS 2012 international bidding round, located in the Eastern Mediterranean offshore Egypt.

Vietnam

In February 2013, Eni signed an agreement with Vietnamese National oil company Vietnam Oil and Gas Group (Petrovietnam), for the joint evaluation of non conventional resources in the Country.

Versalis

In 2013, Eni’s chemical subsidiary Versalis progressed in the process of expansion in the growing Southeast Asian markets, by establishing a 50:50 joint venture with a south Korean company Lotte Chemical and by signing a shareholder agreement with Malaysian company Petronas. The agreements concern the development of joint production activities in the polymers and elastomers business.

Start-ups

In 2013, in line with production plans, the following main projects were started up:

(i)    in Algeria, the MLE-CAFC field (Eni’s interest 75%) with an overall plateau of approximately 33 kboe/d net to Eni by 2016 and the El Merk field (Eni’s interest 12.25%) with an expected peak at approximately 18 kbbl/d net to Eni expected in 2015;
(ii)   in Angola, the liquefaction plant managed by the Angola LNG consortium (Eni’s interest 13.6%) with the first cargo in June 2013. The plant will treat approximately 10,594 bcf of gas in 30 years;
(iii)  in Nigeria, the offshore Abo - Phase 3 project in Block OML 125 (Eni operator with an 85% interest);
(iv)  in Venezuela, the accelerated early production of the giant Junin 5 oil field (Eni’s interest 40%) in the Orinoco Faja.    
Early production is expected to reach a plateau of 75 kbbl/d in 2015;
(v)   in Norway, the offshore Skuld field (Eni’s interest 11.5%) with production of approximately 30 kboe/d (approximately 4 kboe/d net to Eni);
(vi)  in the United Kingdom, the offshore Jasmine field (Eni’s interest 33%), with an expected peak of 117 kboe/d (approximately 39 kboe/d net to Eni) in 2014.

Exploration successes

In 2013, main exploration successes occurred in:

(i)    Egypt, in the Meleiha development lease (Eni’s interest 56%) with three near field oil and gas discoveries and the Rosa North-1X oil discovery. The drilling activities of the Rosa North-1X field are underway. The activities on the field will leverage on the existing production facilities in the area; as well as with two near field oil discoveries in the Belayim concession (Eni 100%);
(ii)   Angola, in offshore Block 15/06 (Eni operator with a 35% interest), with the Vandumbu 1 oil discovery;
(iii)  Congo, in offshore Block Marine XII (Eni operator with a 65% interest) with the oil and gas discovery and the appraisal of the Nene Marine field and with the appraisal of gas and condensates discovery of Litchendjili Marine field. The overall discoveries potential is estimated in about 2.5 billion boe in place;
(iv)  Mozambique, in addition to the recent discovery of Agulha, with the delineation of Coral 3, Mamba South 3 and Mamba North Est 3 gas wells. The new discoveries allow to bring the estimated mineral potential up to 90 tcf of gas in place;
(v)   Ghana, with the Sankofa East-2A appraisal well, in the Offshore Cape Three Points license (Eni operator with a 47.22% interest), confirming its high oil potential. The total potential of the Sankofa East oil discovery is estimated at approximately 450 million barrels of oil in place with recoverable reserves up to 150 million barrels;
(vi)  Pakistan, with the onshore gas discovery of Lundali 1 in the Sukhpur Concession (Eni operator with a 45% interest) with a production capacity in excess of 3 kboe/d and with the gas discovery of Bhadra North-2 (Eni’s interest 40%);
(vii) Norway, with the oil and gas Skavl discovery located in the PL532 license (Eni’s interest 30%), and the gas and condensates Smørbuklk in the PL 479 license (Eni's interest 19.6%);
(viii) Nigeria, with the appraisal of the oil field of Zabazaba in OPL 245 Block (Eni operator with a 50% interest);
(ix)  Australia, with the Evans Shoal North-1 discovery, in the NT/P48 permit (Eni’s interest 32.5%) located in the Timor Sea. Eni estimated the full mineral potential of the reservoir at approximately 8 tcf of gas in place. 

Outlook

Eni is hosting a strategy presentation today to outline the Company’s targets and strategies for the 2014-2017 four-year plan.

The 2014 outlook features a moderate strengthening in the global economic recovery. Still a number of uncertainties are surrounding this outlook due to weak growth prospects in the Euro-zone and risks concerning the emerging economies. Crude oil prices are forecast on a solid trend driven by geopolitical factors and the resulting technical issues in a few important producing countries against the backdrop of well supplied global markets. Management expects that the trading environment will remain challenging in the Company’s businesses. We expect continuing weak conditions in the European industries of gas distribution, refining and marketing of fuels and chemical products, where we do not anticipate any meaningful improvement in demand, while competition, excess supplies and overcapacity will continue to weigh on selling margins of energy commodities. In this scenario, management reaffirms its commitment in restoring profitability and preserving cash generation at the Company’s mid and downstream businesses leveraging on cost cuts and continuing renegotiation of long-term gas supply contracts, capacity restructuring and reconversion and product and marketing innovation.

Management expects the key production and sales trends of Eni businesses to be as follows:

• Production of liquids and natural gas: production is expected to remain substantially in line to 2013, excluding the impact of the divestment of Eni’s interest in the Russian gas assets of Artic Russia;
• Gas sales: natural gas sales are expected to be slightly lower than 2013. Management plans to strengthen marketing efforts and innovation to fend off competitive pressures both in the large customers segment and in the retail segment considering an ongoing demand downturn and oversupplies, particularly in Italy;
• Refining throughputs on Eni’s account: volumes are expected to be slightly lower than those processed in 2013, due to capacity reductions only partially offset by higher output at the new EST technology conversion plant at the Sannazzaro Refinery;
• Retail sales of refined products in Italy and the Rest of Europe: retail sales are expected to be slightly lower than in 2013 due to an ongoing demand downturn in Italy and the expected impact of network reorganisation in Italy and in Europe;
• Engineering & Construction: 2014 will be a transitional year with a recovery in profitability, the dimension of which relies upon the effective execution of operational and commercial activities at low-margin contracts still present in the current portfolio, in addition to the speed at which bids underway will be awarded.

In 2014, management expects a capital budget in line with 2013 (€12.75 billion in capital expenditure and €0.32 billion in financial investments in 2013). Assuming a Brent price of $104 a barrel on average for the full year 2014, the ratio of net borrowings to total equity – leverage – is projected to be almost in line with the level achieved at the end of 2013, due to cash flows from operations and portfolio transactions.

(3) Information on net borrowings composition is furnished on page 34.
(4) Non-GAAP financial measures disclosed throughout this press release are accompanied by explanatory notes and tables to help investors gain a full understanding of said measures in line with guidance provided for by CESR Recommendation No. 2005-178b. See page 34 for leverage.
(5) Dividends are not entitled to tax credit and, depending on the receiver, are subject to a withholding tax on distribution or are partially cumulated to the receiver’s taxable income.

This press release has been prepared on a voluntary basis in accordance with the best practices on the marketplace. It provides data and information on the Company’s business and financial performance for the fourth quarter and the full year 2013 (unaudited). In this press release results and cash flows are presented for the third and fourth quarter of 2013, the fourth quarter of 2012 and the full year 2013 and 2012.

Information on liquidity and capital resources relates to the end of the periods as of December 31 and September 30, 2013, and December 31, 2012. Tables contained in this press release are comparable with those presented in the management’s disclosure section of the Company’s annual report and interim report.

Accounts set forth herein have been prepared in accordance with the evaluation and recognition criteria set by the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB) and adopted by the European Commission according to the procedure set forth in Article 6 of the European Regulation (CE) No. 1606/2002 of the European Parliament and European Council of July 19, 2002 and do not differ from the accounting standards adopted in the preparation of our statutory consolidated annual report for the year ended December 31, 2012 and the semi-annual consolidated statutory report at and for the six months ended June 30, 2013. Investors are urged to read the accounting standards and policies of such regulatory filings.

Non-GAAP financial measures and other performance indicators disclosed throughout this press release are accompanied by explanatory notes and tables to help investors to gain a full understanding of said measures in line with guidance provided by recommendation CESR/05-178b.

Eni’s Chief Financial Officer, Massimo Mondazzi, in his position as manager responsible for the preparation of the Company’s financial reports, certifies, that data and information disclosed in this press release correspond to the Company’s evidence and accounting books and records, pursuant to rule 154-bis paragraph 2 of Legislative Decree No. 58/1998.

Disclaimer

This press release, in particular the statements under the section “Outlook‘, contains certain forward-looking statements particularly those regarding capital expenditure, development and management of oil and gas resources, dividends, buy-back program, allocation of future cash flow from operations, future operating performance, gearing, targets of production and sales growth, new markets and the progress and timing of projects. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements, depending on a variety of factors, including the timing of bringing new fields on stream; management’s ability in carrying out industrial plans and in succeeding in commercial transactions; future levels of industry product supply; demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; development and use of new technology; changes in public expectations and other changes in business conditions; the actions of competitors and other factors discussed elsewhere in this document. Due to the seasonality in demand for natural gas and certain refined products and the changes in a number of external factors affecting Eni’s operations, such as prices and margins of hydrocarbons and refined products, Eni’s results from operations and changes in net borrowings for the fourth quarter of the year cannot be extrapolated on an annual basis.

The all sources reserve replacement ratio disclosed elsewhere in this press release is calculated as ratio of changes in proved reserves for the year resulting from revisions of previously reported reserves, improved recovery, extensions, discoveries and sales or purchases of minerals in place, to production for the year. A ratio higher than 100% indicates that more proved reserves were added than produced in a year. The Reserve Replacement Ratio is a measure used by management to indicate the extent to which production is replaced by proved oil and gas reserves. The Reserve Replacement Ratio is not an indicator of future production because the ultimate development and production of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructure, as well as changes in oil and gas prices, political risks and geological and other environmental risks.