Eni

Annual Report • May 9, 2018

Fact Book 201 7

We are an energy company.

We are working to build a future where everyone can access energy resources efficiently and sustainably. Our work is based on passion and innovation, on our unique strengths and skills, on the quality of our people and in recognising that diversity across all aspects of our operations and organisation is something to be cherished. We believe in the value of long term partnerships with the countries and communities where we operate.

MISSION

Fact Book 201 7

Eni's Fact Book is a supplement to Eni's Integrated Annual Report and is designed to provide supplemental financial and operating information. It contains certain forward-looking statements regarding capital expenditure, dividends, allocation of future cash flow from operations, evolution of financial structure, future operating performance, targets of production and sale growth, execution 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 oil&gas 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 of oil, gas and refined products; operational problems; general economic conditions; geopolitical factors including international tensions, social and political instability, changes in the economic and legal frameworks in Eni's Countries of operations, regulation of the oil&gas industry, power generation and environmental field, development and use of new technologies; changes in public expectations and other changes in business conditions; the actions of competitors.

FACT BOOK

Eni at a glance	4
Main data	6
Exploration & Production	11
Gas & Power	52
Rening & Marketing and Chemicals	60
Tables
Financial data	73
Employees	85
Quarterly information	86

EUROPE	E&P	G&P R&M & C
Austria		•	•
Belgium		•	•
Croatia	•
Cyprus	•
Czech Republic			•
Denmark			•
France		•	•
Germany		•	•
Greece		•	•
Greenland	•
Hungary		•	•
Ireland	•
Italy	•	•	•
Luxembourg		•
Montenegro	•
Norway	•
Poland			•
Portugal	•
Romania			•
Slovakia			•
Slovenia		•
Spain		•	•
Sweden			•
Switzerland		•	•
the Netherlands		•	•
the United Kingdom	•	•	•
Turkey		•	•
Ukraine	•

ASIA AND

OCEANIA	E&P	G&P	R&M & C
Australia	•
China	•	•	•
India	•	•	•
Indonesia	•
Iraq	•
Japan		•
Jordan		•
Kazakhstan	•
Kuwait		•
Myanmar	•
Oman	•	•
Pakistan	•
Russia	•	•	•
Saudi Arabia			•
Singapore		•	•
South Korea		•	•
Taiwan		•
the United Arab Emirates	•	•
Timor Leste	•
Turkmenistan	•
Vietnam	•

AFRICA	E&P	G&P	R&M & C
Algeria	•
Angola	•
Congo	•		•
Egypt	•	•	•
Gabon	•		•
Ghana	•		•
Ivory Coast	•
Kenya	•
Liberia	•
Libya	•	•
Morocco	•
Mozambique	•
Nigeria	•	•
South Africa	•
Tunisia	•	•	•

E&P	G&P	R&M & C
•
•
		•
		•
		•
	• • • • •	•

ENI AT A GLANCE

2017 RESULTS

In 2017 Eni delivered outstanding results proving the effectiveness of the deep transformation process started in 2014. As a result of this, the Company is now on a strong footing and is able to create value even in the most difficult market conditions, such as the last price downturn that was among the most severe ever affecting the oil&gas industry. Adjusted operating profit more than doubled to €5.8 billion, with a net profit of €2.4 billion reverting the loss incurred in 2016, thanks to the growth in the upstream segment and the restructuring of the mid-downstream businesses. Cash flow from operating activities was robust at €10 billion, a 25% increase from 2016, when netted of advances cashed in by Egyptian State-owned partners with the aim of financing their capex share in the Zohr project. These inflows, after funding net capex of €7.6 billion, yielded a surplus of approximately €2.4 billion.

These results helped us reduce our target Brent price of cash neutrality to 57 \$/bbl, 50% lower than the price that allowed us achieve in 2014 full coverage of capex and cash dividend with funds from operations. At the end of 2017, Eni confirms a solid financial structure with a gearing of 18%, the lower end of the European peer group and a leverage of 0.23 well below the 0.30 threshold notwithstanding price downturn in the last three years and a half, and over €11 billion of cash dividend paid in the same period.

UPSTREAM

Dual Exploration Model

Closed the 40% disposal of the super-giant Zohr gas field in Egypt offshore – through two different transactions with BP (10%) and Rosneft (30%) – and the 25% disposal of Area 4 in Mozambique to ExxonMobil. In March 2018, signed an agreement with Mubadala Petroleum for the divestment of a further 10% interest in Zohr.

Zohr development

Achieved production start-up at the supergiant Zohr gas field in record time-to-market: in less than two years from the FID and two and a half years from discovery.

Exploration resources

In 2017 added 1 bln boe of new resources, of which 0.8 bln boe from in house exploration with a discovery cost of approximately 1 \$/bbl.

Mexico

Successfully completed the exploration campaign offshore Area 1, thanks to the appraisal of Tecoalli discovery which followed that of Amoca and Miztòn, resulting in a rise in estimated hydrocarbons in place of the Area to 2 bln boe, of which approximately 90% oil. Scheduled a fast-track development plan.

Exploration portfolio

• Reloading of approximately 97,000 square kilometers of new acreage:

• awarded 50% of the mineral rights of the Isatay Block in the Kazakh Caspian Sea;

• signed an Exploration and Production Sharing Agreement (EPSA) of Block 52, offshore Oman;

• acquired new exploration licenses in Morocco, Mexico, Cyprus and Ivory Coast.

Proved hydrocarbon reserves

7 billion boe with an organic replacement ratio of 103%. The ratio increases to 151% when excluding the reclassification of PUD reserves to the unproved category in Venezuela in accordance with the applicable US SEC regulation.

Coral project

Sanctioned by the partners the development project for the exclusive reserves in Area 4 in Mozambique amounting to 16 Tcf in place. The Floating LNG facilities construction will be realized through a multisource project financing of \$4.7 billion.

International development in the Chemical business

Completed, in South Korea, the construction of the industrial complex for production of premium elastomers, leveraging on Versalis technology and through the 50:50 joint venture Versalis - Lotte Chemical, local operator.

Licensing EST technology

Enhanced the refining know-how through two licensing agreements with the Chinese companies Sinopec and Zhejiang Petrochemicals for the use of the Eni Slurry Technology (EST) conversion proprietary technology.

FINANCIAL DISCIPLINE

GEARING

Peers: Total, Chevron, Statoil, BP, Shell, ConocoPhillips, Exxon

MID-DOWNSTREAM

MID-DOWNSTREAM RESTRUCTURING CUMULATIVE CFFO

Renewable energies

Eni's committment for renewable energies was implemented by the start-up of operations for the set-up of plants in Italy and Algeria and the development of other initiatives in Italy and abroad. Signed the collaboration agreement with General Electric and with the Kazakh Ministry of Energy; finalized a Memorandum of Understanding with the Egyptian Ministry of Electricity to jointly realize new renewable plants.

Safety of Eni's people

Total recordable injury rate (TRIR) reported a decrease of 6.8% vs. 2016. The reduction for the employees (down by 17.2%) and the contractors (down by 2%) was driven by specific program of education and awareness addressed to Eni's people. In 2017, was launched the new Safety Training Center in Gela for training in health, safety and environmental issues.

Climate change

Accordingly to Eni's carbon footprint reduction strategy, the development program on renewables was implemented by 20 projects on an executive phase or near to FID, which will contribute to increase Eni's generation capacity by around 250 MW. Furthermore, Eni is part of the TCFD (Task Force on Climaterelated Financial Disclosures) of the Financial Stability Board, targeted to a more trasparent disclosure about risks and opportunities relating to the climate change.

Commitment to flaring reduction

Eni joins the Global Gas Flaring Reduction Partnership (GGFR),

sponsored by the World Bank, a public-private initiative involving international oil companies, governments and international institutions. Eni reduced gas flaring of approximately 68% in the last ten years and promoted access to energy for over 18 million people in the Sub-Saharan Africa.

GHG emissions

GHG emissions increased by 2.5% vs. 2016 due to the production growth. GHG emission index per barrel produced was down by approximately 3% vs. 2016 and by 19% vs. 2014 in accordance with the long-term target of a 43% reduction by 2025.

Oil spills due to operations

Oil spills due to operations (higher than one barrel), 94% of which relating to the E&P segment, more than doubled from 2016. This was mainly due to the spill from a tank located in COVA in Val d'Agri where the Company implemented all the remediation actions to reduce the environmental damage and to prevent any future accident through infrastructure upgrading.

Human rights

Started in 2017 the working group on Human Rights in the business supported by the Danish Institute for Human Rights. The comparison between Company's processes and the International Standards (UN Guiding Principles on Business and Human Rights) allowed the definition of a roadmap aimed at further improvement of Eni's performance on Human Rights.

DIVIDEND CASH NEUTRALITY( *) (\$/bbl)

Gearing % (*) Organic coverage of Capex and Dividend through CFFO.

2017

MAIN DATA

KEY FINANCIAL DATA(*)(**)

	(€ million)	2017	2016	2015	2014	2013
Net sales from operations		66,919	55,762	72,286	98,218	104,117
of which: Exploration & Production		19,525	16,089	21,436	28,488	31,264
Gas & Power		50,623	40,961	52,096	73,434	79,619
Refining & Marketing and Chemicals		22,107	18,733	22,639	28,994	32,181
Corporate and other activities		1,462	1,343	1,468	1,429	1,496
Impact of unrealized intragroup profit elimination and consolidation adjustments		(26,798)	(21,364)	(25,353)	(34,127)	(40,443)
Operating profit (loss)		8,012	2,157	(3,076)	8,965	10,357
of which: Exploration & Production		7,651	2,567	(959)	10,727	15,349
Gas & Power		75	(391)	(1,258)	64	(2,923)
Refining & Marketing and Chemicals		981	723	(1,567)	(2,811)	(2,261)
Corporate and other activities		(668)	(681)	(497)	(518)	(736)
Impact of unrealized intragroup profit elimination and consolidation adjustments		(27)	(61)	1,205	1,503	928
Operating profit (loss)		8,012	2,157	(3,076)	8,965	10,357
Special items		(1,990)	333	6,426	798	2,157
Profit (loss) on stock		(219)	(175)	1,136	1,460	716
Adjusted operating profit (loss)(a)		5,803	2,315	4,486	11,223	13,230
of which: Exploration & Production		5,173	2,494	4,182	11,679	15,124
Gas & Power		214	(390)	(126)	168	(622)
Refining & Marketing and Chemicals		991	583	695	(412)	(859)
Corporate and other activities		(542)	(452)	(369)	(443)	(542)
Net profit (loss)(b)		3,374	(1,464)	(8,778)	1,303	5,320
of which: continuing operations		3,374	(1,051)	(7,952)	1,720	5,808
discontinuing operations			(413)	(826)	(417)	(488)
Adjusted net profit (loss)(a)(b)		2,379	(340)	803	3,723	4,707
Net cash flow from operating activities		10,117	7,673	12,875	14,469	11,547
Net cash flow from operating activities - standalone(a)		10,117	7,673	12,155	13,544	10,645
Capital expenditure		8,681	9,180	10,741	11,178	11,221
Shareholders' equity including non-controlling interests at year end		48,079	53,086	57,409	65,641	64,053
Net borrowings at year end		10,916	14,776	16,871	13,685	14,963
Leverage		0.23	0.28	0.29	0.21	0.23
Net capital employed at year end		58,995	67,862	74,280	79,326	79,016
of which: Exploration & Production		49,801	57,910	53,968	51,061	48,703
Gas & Power		3,394	4,100	5,803	9,031	8,462
Refining & Marketing and Chemicals		7,440	6,981	6,986	9,711	11,393

(*) Pertaining to continuing operations.

(**) Effective January 1, 2016, management modified on voluntary basis the criterion to recognize exploration expenses adopting the accounting of the successful-effort-method (SEM). Accordingly, the comparative amounts disclosed have been restated.

(a) Non-GAAP measures. 2013-2015 results are calculated on a standalone basis, i.e. by excluding the results of Saipem earned from both third parties and the Group's continuing operations, therefore determining its deconsolidation.

(b) Attributable to Eni's shareholders.

KEY MARKET INDICATORS

		2017	2016	2015	2014	2013
Average price of Brent dated crude oil in US dollars(a)	(\$/barrel)	54.27	43.69	52.46	98.99	108.66
Average EUR/USD exchange rate(b)		1.130	1.107	1.11	1.329	1.328
Average price of Brent dated crude oil	(€)	48.03	39.47	47.26	74.48	81.82
Standard Eni Refining Margin (SERM)(c)	(\$)	5.0	4.2	8.3	3.2	2.4
TTF	(€/kcm)	183	148	210	221	286
PSV	(€/kcm)	211	168	234	246	296

(a) Source: Platt's Oilgram.

(b) Source: BCE.

(c) Source: In \$/bbl FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni's refining system in consideration of material balances and refineries' product yields.

6

7

SELECTED OPERATING DATA(*)

		2017	2016	2015	2014	2013
Employees at year end	(number)	32,934	33,536	34,196	34,846	36,678
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.33	0.35	0.45	0.71	0.94
of which: employees		0.30	0.36	0.41	0.56	0.78
contractors		0.34	0.35	0.47	0.79	1.01
Total volume of oil spills (> 1 barrel)	(barrels)	6,464	5,913	16,481	15,562	7,891
of which: due to sabotage and terrorism		3,236	4,682	14,847	14,401	6,002
operational		3,228	1,231	1,634	1,161	1,889
Direct GHG emissions	(mmtonnes CO2 eq)	42.52	41.46	42.32	42.14	47.60
of which: CO2 equivalent from combustion and process		32.65	31.99	32.22	31.02	33.07
CO2 equivalent from flaring		6.83	5.40	5.51	5.73	9.13
CO2 equivalent from non-combusted methane and fugitive emissions		1.46	2.40	2.79	3.50	3.47
CO2 equivalent from venting		1.58	1.67	1.80	1.89	1.92

Exploration & Production		2017	2016	2015	2014	2013
Employees at year end	(number)	11,970	12,494	12,821	12,777	12,352
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.28	0.34	0.34	0.56	0.60
Net proved reserves of hydrocarbons	(mmboe)	6,990	7,490	6,890	6,602	6,535
Average reserve life index	(years)	10.5	11.6	10.7	11.3	11.1
Hydrocarbon production(a)	(kboe/d)	1,816	1,759	1,760	1,598	1,619
Organic reserve replacement ratio	(%)	103	193	148	112	105
Profit per boe(b)	(\$/boe)	8.7	2.0	(3.8)	9.9	16.2
Opex per boe(a)		6.6	6.2	7.2	8.4	8.3
Cash flow per boe(a)		20.2	12.9	20.9	30.1	31.9
Finding & Development cost per boe(a)(c)		10.4	13.2	19.3	21.5	19.2
Direct GHG emissions	(mmtonnes CO2 eq)	23.45	21.78	23.54	23.56	27.37
CO2 emissions/100% operated hydrocarbon gross production(d)	(mmtonnes CO2 eq/toe)	0.162	0.166	0.177	0.190	0.223
% produced water re-injected	(%)	59	58	56	56	55
Volumes of hydrocarbon sent to flaring	(mmcm)	2,283	1,950	1,989	1,767	3,450
of which: sent to flaring process		1,556	1,530	1,564	1,678	3,320
Oil spills due to operations (> 1 barrel)	(barrels)	3,022	1,097	1,177	936	1,728

(*) Pertaining to continuing operations. 2014-2016 results excluded Saipem contribution, divested in 2016.

(a) Includes Eni's share in joint ventures and equity-accounted entities.

(b) Related to consolidated subsidiaries.

(c) Three-year average.

(d) Hydrocarbon production from fields fully operated by Eni (Eni's interest 100%) amounting to 137 mln toe, 122 mln toe 125 mln toe, 117 mln toe and 118 mln toe in 2017, 2016, 2015, 2014 and 2013, respectively.

Gas & Power		2017	2016	2015	2014	2013
Employees at year end	(number)	4,313	4,261	4,484	4,561	4,616
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.37	0.29	0.89	0.82	1.48
Worldwide gas sales	(bcm)	80.83	86.31	87.72	86.11	90.56
of which: Italy		37.43	38.43	38.44	34.04	35.86
outside Italy		43.40	47.88	52.44	52.27	54.70
Customers in Italy	(million)	7.7	7.8	7.9	7.9	8.0
Direct GHG emissions	(mmtonnes CO2 eq)	11.23	11.17	10.57	10.12	11.27
GHG emissions/kWheq (Eni Power)	(gCO2 eq/kWheq)	395	398	409	409	407
Installed capacity power plants	(GW)	4.7	4.7	4.9	4.9	4.8
Electricity produced	(TWh)	22.42	21.78	20.69	19.55	21.38
Electricity sold		35.33	37.05	34.88	33.58	35.05
Customer satisfaction rate	(scale from 0 to 100)	86.7	86.2	85.6	81.4	80.0

Refining & Marketing and Chemicals		2017	2016	2015	2014	2013
Employees at year end	(number)	10,916	10,858	10,995	11,884	14,146
TRIR (Total Recordable Injury Rate)	(total recordable injuries/worked hours) x 1,000,000	0.62	0.38	1.07	1.51	2.33
Oil spills due to operations (> 1 barrel)	(barrels)	194	134	427	225	161
Direct GHG emissions	(mmtonnes CO2 eq)	7.82	8.50	8.19	8.45	8.90
SOx emissions (sulphur oxide)	(ktonnes SO2 eq)	5.18	4.35	6.17	6.84	12.33
Refinery throughputs on own account	(mmtonnes)	24.02	24.52	26.41	25.03	27.38
Retail market share in Italy	(%)	25.0	24.3	24.5	25.5	27.5
Retail sales of petroleum products in Europe	(mmtonnes)	8.54	8.59	8.89	9.21	9.69
Service stations in Europe at year end	(number)	5,544	5,622	5,846	6,220	6,386
Average throughput of service stations in Europe	(kliters)	1,783	1,742	1,754	1,725	1,828
Balanced capacity of refineries	(kbbl/d)	548	548	548	617	787
Capacity of biorefineries	(ktonnes/year)	360	360	360	360
Production of biofuels	(ktonnes)	206	181	179	105
GHG emissions/products (crude oil and semifinished) processed in refineries	(tonnes CO2 eq/kt)	258	278	253	301	252
Production of petrochemical products	(ktonnes)	5,818	5,646	5,700	5,283	5,817
Sales of petrochemical products		3,712	3,759	3,801	3,463	3,785
Average petrochemical plant utilization rate	(%)	73	72	73	71	65

8

ENI SHARE PERFORMANCE

Share data

		2017	2016	2015	2014	2013
Net profit (loss)(a)(b)	(€)	0.94	(0.29)	(2.21)	0.48	1.56
Dividend pertaining to the year		0.80	0.80	0.80	1.12	1.10
Dividend to Eni's shareholders pertaining to the year(c)	(€ million)	2,881	2,881	3,457	4,006	3,949
Cash flow	(€)	2.81	2.13	3.58	4.01	3.19
Dividend yield(d)	(%)	5.7	5.4	5.7	7.6	6.5
Net profit (loss) per ADR(b)(e)	(\$)	2.12	(0.65)	(4.90)	1.27	4.14
Dividend per ADR(e)		1.81	1.77	1.77	2.65	2.99
Cash flow per ADR(e)		6.35	4.72	7.95	10.66	8.47
Dividend yield per ADR(d)(e)	(%)	5.7	5.4	5.7	7.6	6.5
Pay-out		85	(197)	(33)	310	77
Number of shares at period-end	(million)	3,601.1	3,634.2	3,634.2	3,634.2	3,634.2
Weighted average number of shares outstanding(f) (fully diluted)		3,601.1	3,601.1	3,601.1	3,610.4	3,622.8
Total Shareholders Return (TSR)	(%)	(5.6)	19.2	1.1	(11.9)	1.3

(a) Calculated on the average number of Eni shares outstanding during the year.

(b) Pertaining to Eni's shareholders.

(c) The amount of dividends for the year 2017 is based on the Board's proposal.

(d) Ratio between dividend of the year and average share price in December.

(e) One ADR represents 2 shares. Net profit, dividends and cash flow data were converted using average exchange rates. Dividends data were converted at the Noon Buying Rate of the pay-out date.

(f) Calculated by excluding own shares in portfolio.

Share information

	2017	2016	2015	2014	2013
Share price - Milan Stock Exchange
High (€)	15.72	15.47	17.43	20.41	19.48
Low	12.96	10.93	13.14	13.29	15.29
Average	14.16	13.42	15.47	17.83	17.57
Year end	13.80	15.47	13.8	14.51	17.49
ADR price(a) - New York Stock Exchange
High (\$)	34.09	33.33	39.29	55.30	52.12
Low	29.54	25.00	29.28	32.81	40.39
Average	31.98	29.74	34.31	47.37	46.68
Year end	33.19	32.24	29.8	34.91	48.49
Average daily exchanged shares (million shares)	13.89	18.41	20.30	17.21	15.44
Value (€ million)	197.0	246.0	312.0	304.0	271.4
Weighted average number of shares outstanding(b) (million shares)	3,601.1	3,601.1	3,601.1	3,610.4	3,622.8
Market capitalization(c)
EUR (billion)	50.2	56.2	50.2	52.4	63.4
USD	60.2	59.3	55.7	63.6	87.4

(a) One ADR represents 2 Eni's shares.

(b) Excluding treasury shares.

(c) Number of outstanding shares by reference price at period end.

Data on Eni share placement

		2001	1998	1997	1996	1995
Offer price	(€/share)	13.60	11.80	9.90	7.40	5.42
Number of share placed	(million shares)	200.1	608.1	728.4	647.5	601.9
of which: through bonus share	(million shares)	39.6	24.4	15.0	1.9
Percentage of share capital(a)	(%)	5.0	15.2	18.2	16.2	15.0
Proceeds	(€ million)	2,721	6,714	6,869	4,596	3,254

(a) Refers to share capital at December 31, 2017.

9

Eni Source: Eni calculations based on BLOOMBERG data. Indexed FTSE MIB to Eni share price Source: Eni calculations based on BLOOMBERG data.

ENI ADR PRICE IN NEW YORK

SHAREHOLDERS DISTRIBUTION BY GEOGRAPHIC AREA( *)

(*) As of January 10, 2018.

CLASS OF SHAREHOLDERS( *)

DIVIDEND PER SHARE

Source: Eni calculations based on BLOOMBERG data.

Source: Eni calculations based on BLOOMBERG data.

(a) Refer to: BP, Chevron, Repsol, ExxonMobil, Royal Dutch Shell and Total.

ENI'S SHARE PERFORMANCE VS. MAIN OIL&GAS COMPANIES (last 12 months)

EXPLORATION & PRODUCTION

PERFORMANCE OF THE YEAR

• ● In 2017, safety performance continued on a positive trend, with a total recordable injury rate of 0.28, down by 18% from 2016. New training and continuing education initiatives as well as HSE awareness programs have been developed. Eni is engaged in maintaining a high safety standard in each of its operations.
• ● Upstream GHG intensity index was positive with a reduction of approximately 3% from 2016 leveraging on the continuous improvements in energy efficiency and planned initiatives to contain fugitive emissions due to ongoing maintenance of production sites and programs to improve plant set-up. These results confirm that we are well on track on our long-term targets of a reduction of 43% in 2025 vs. 2014.
• ● Water re-injection was 59% in 2017, leveraging on the ongoing programs in certain operational plants, in particular in Congo, Egypt and Ecuador as well as restart of certain production plants in Libya.
• ● In 2017 the E&P segment reported more than double of adjusted operating profit and more than four-fold increase of adjusted net profit compared to 2016. This performance was driven by the recovery in crude oil prices (with the Brent price up by 24%), production growth and significant reduction of tax rate.
• ● 2017 oil and natural gas production was a record level of 1.82 million boe/d, up by 3.2% compared to the previous year. In December 2017, production reached 1.92 million boe/d, marking an all-time high for Eni. Start-ups and ramp-ups added 243 kboe/d to the production level of 2017. Expected a 4% growth rate in 2018 full-year production.
• ● Net proved reserves at December 31, 2017 amounted to 7 bboe based on a reference Brent price of \$54 per barrel. The organic reserves replacement ratio was 103%. The ratio increased to 151% when excluding the reclassification of proved undeveloped reserves in Venezuela to the unproved category in accordance with the applicable US SEC regulation. The reserves life index was 10.5 years (11.6 years in 2016).

THE ZOHR PROJECT START-UP

Eni achieved production start-up of the super-giant Zohr gas field in a record time-to-market, in less than two years from the FID and two and a half years from discovery. The Zohr project is one of Eni's seven record-breaking project that were performed by means of the achievement of integrated model of exploration and development implemented over the last few years. Leveraging on parallelizing exploration, appraisal and development phases, we achieve a faster

time-to-market and a lower cost to production start-up of discoveries. The Zohr discovery is located in the Shorouk offshore block (Eni operator with a 60% interest) in Egypt offshore with estimated resources of over 30 Tcf gas in place (approximately 5.5 billion boe).

DUAL EXPLORATION MODEL

The Dual Exploration Model is a pillar of Eni's strategy which aims to create cash flow in advance of exploration successes by means of the partial diluition of the stakes in exploration leases where Eni retains the operatorship and control of the asset. During the year the following dispoals were closed with this approach:

• an overall 50% stake of the Zohr giant discovery. In particular, in 2017, closed the disposal of 10% stake to BP and 30% stake to Rosneft. In March 2018 signed an agreement with Mubadala Petroleum for the divestment of an additional 10% interest. The transaction is subject to the fulfillment of certain conditions and all necessary authorizations from Egypt's Authorities;
• a 25% indirect interest in the Area 4 block, offshore Mozambique, to ExxonMobil.

EXPLORATION ACTIVITY

● Exploration activity is also a distinctive approach of Eni's upstream model, ensuring a large amount of resources at low costs, flexibility in the short-term and fueling growth over the long-term. In 2017 additions to the Company's reserve backlog were 1 billion boe of new resources, of which 800 million boe from in-house exploration with a discovery cost of approximately \$1 per barrel.

From 2014, we discovered over 4 billion boe, approximately double of equity production in the same period.

• ● In February 2018, exploration activities yielded positive results with the Calypso 1 gas discovery in the Block 6 (Eni operator with a 50% interest) in the offshore of Cyprus. The first data collection marks a promising gas discovery and confirms the extension of the Zohr like play.
• ● In February 2018, signed two Exploration and Production Agreements with the Republic of Lebanon covering Blocks 4 and 9, located in the deep offshore Lebanon. Eni holds a 40% interest in both blocks.
• ● In Oman, signed with the Government of the Sultanate and the state oil company OOCEP an Exploration and Production Sharing Agreement for the Block 52, located offshore Oman. In addition,

at the same time, Eni signed an agreement to assign interest in the block to the Qatar Petroleum oil company. The agreement is subject to approval by the relevant Authorities of the country. Following approval of these agreements, Eni will retain the operatorship of the block with a 55% interest.

• ● In Kazakhstan, signed an agreement with the Ministry of Energy of the Republic of Kazakhstan and the state oil company KMG for the transfer to Eni of the 50% stake for exploration and production activities in the Isatay block located in the Kazakh sector of the Caspian Sea. The block will be operated by a joint operating company established by KMG and Eni on a 50/50 basis. Eni will leverage on its proprietary technologies, significant experience in exploration activities and an extensive know-how in challenging technical and environmental areas such as the Caspian Basin.
• ● Finalized in March 2017, a farm-in agreement to acquire a 50% interest of Block 11, offshore Cyprus, which will be operated by Total. The exploration area covers 2,215 square kilometers, nearby the Zohr discovery.
• ● Successfully completed the exploration campaign in Area 1, offshore Mexico. Exploration successes and the modelling reservoir revision resulted in a rise in estimated hydrocarbons in place of the block to 2 billion boe, of which approximately 90% oil. Eni submitted an integrated development plan of all the three discoveries to the relevant Authorities. Production start-up is expected in 2019.
• ● The exploration portfolio was renewed by means of new exploration acreage covering over 97,000 square kilometers net to Eni in Cyprus, Ivory Coast, Morocco and Mexico as well as Kazakhstan and Oman, as mentioned above.
• ● In 2017, exploration expenditure amounted to €442 million, and mainly concerned Cyprus, Norway, Mexico, Egypt, Libya and Ivory Coast as well as related to the completion of the 25 new exploratory wells (15.9 net to Eni). In addition, 78 exploratory drilled wells are in progress at year-end (41.2 net to Eni).

SUSTAINABILITY AND PORTFOLIO DEVELOPMENTS

• ● Production start-up was achieved earlier than scheduled at the operated project of East Hub in Angola, Offshore Cape Three Points (OCTP) in Ghana, Jangkrik in Indonesia and Zohr giant field, as mentioned above. The success of Eni's model is mainly due to the high number of operated projects with a production of over 3.6 million boe/day, which is necessary for planning a fast-track approach in all the design phases, from appraisal, engineering and finally development and achieving high control of project costs, time and risks.
• ● In March 2018, Eni signed two Concession Agreements related to the acquisition of a 5% interest in the Lower Zakum oil field and a 10% interest in the Umm Shaif and Nasr oil, condensates and natural gas fields, in the offshore of Abu Dhabi, for a consideration of \$875 million with duration of 40 years.
• ● Acquired a 32.5% interest of the Evans Shoal gas field in the NT/ RL7 offshore license in the north of Australia, nearby the Darwin liquefaction gas plant, where Eni holds interests. Mineral potential

is estimated in approximately 8 Tcf of gas in place. The agreement received all necessary approvals. Following this acquisition Eni retains the operatorship with a 65% interest.

• ● Signed with the Sonangol state oil company an agreement to the transfer to Eni a 48% interest of the Cabinda North onshore block in Angola, where Eni held a 15% interest. Following the agreement, Eni retains the operatorship of the block. The block is located in an oil basin few explored in the north of the country, where Eni will leverage on the mining knowledge acquired in exploration and development activities progressed in nearby areas of the Republic of Congo. In case of exploration success, the block will benefit from the existing infrastructures. In addition, Eni and Sonangol signed a Memorandum of Understanding to define joint projects throughout the value chain of the energy sector.
• ● Sanctioned the development program of the Johan Castberg field (Eni's interest 30%) in the Norwegian offshore, with estimated resources of approximately 450-650 million boe. Start-up is expected in 2022.
• ● Achieved the financial close of project financing for the construction of a floating unit for the liquefaction of natural gas (FLNG) at the Coral South discovery. The Coral South FLNG is the first project sanctioned by Eni and its partner of the Area 4 block for the development of the large amount of gas discovery in the Rovuma Basin, in offshore Mozambique.
• ● Eni's integrated long-term strategy to perform its path to the decarbonization is leveraging on the reduction of direct CO2 emissions and further increase in the operating activities efficiency; sustaining projects portfolio with low CO2 emissions, supporting the development of natural gas as a transition source for power generation as well as the integration of the traditional business with the generation of energy from renewable sources leveraging all the industrial, logistic, contractual and commercial synergies. Eni's commitment to achieve these targets is confirmed by the recent agreements in Algeria, Angola and Ghana as well as by ongoing projects in particular in Mozambique, Egypt and Indonesia.
• ● The business sustainability over the medium-long-term is a pillar in Eni's growth strategy with programs to support local development further increasingly integrated into business activity. In particular, Eni is committed to the development of access to efficient and sustainable energy also by means of support for local power generation capacity and to sustainable industrial and economic development with know-how and technology sharing program as well as health, education and professional training initiatives. The key factor in the long-term strategy is linking our business development to the growth of the countries in which we operate.
• ● Development expenditure was €7,236 million to fuel the growth of major projects and to maintain production plateau particularly in Egypt, Ghana, Angola, Congo, Algeria, Iraq and Norway. Capex for the full year 2017 was netted of the disposals agreement of the Dual Exploration Model to €6 billion, down by 16% from 2016, on homogenous basis.
• ● In 2017, overall R&D expenditure of the Exploration & Production segment amounted to €83 million (€62 million in 2016).

Fact Book

2017

ITALY

Eni has been operating in Italy since 1926. In 2017, Eni's oil and gas production amounted to 134 kboe/d. Eni's activities in Italy are deployed in the Adriatic and Ionian Seas, the Central Southern Apennines, mainland and offshore Sicily and the Po Valley, on a total developed and undeveloped acreage of 20,332 square kilometers (16,380 square kilometers net to Eni).

Eni's exploration and development activities in Italy are regulated by concession contracts (50 operated onshore and 62 operated offshore) and exploration licenses (13 onshore and 9 offshore).

Adriatic and Ionian Seas

Production Fields in the Adriatic and Ionian Seas accounted for 48% of Eni's domestic production in 2017, mainly gas. Main operated fields are Barbara, Cervia/Arianna, Annamaria, Luna, Angela, Hera Lacinia, and Bonaccia. Production is operated by means of 69 fixed platforms (4 of these are manned) installed on the main fields, to which satellite fields are linked by underwater infrastructures. Production is carried by sealine to the mainland where it is input in the national gas network. The system is subject continuously to rigorous safety controls, maintenance activities and production optimization. Development Development activities in the Adriatic offshore concerned: (i) maintenance and production optimization, mainly at the Barbara and Porto Garibaldi-Agostino fields; (ii) start-up of the Poseidon project in collaboration with national scientific Authorities and Institutes to transform certain platforms into scientific stations for marine environment research; and (iii) within the agreement

with the Municipality of Ravenna, activities progressed with environmental protection projects and training initiatives to support youth employment by means of school-work alternation projects and first-level apprenticeship.

Central Southern Apennines

Production Eni is the operator of the Val d'Agri concession (Eni's interest 60.77%) in the Basilicata Region in Southern Italy. Production from the Monte Alpi, Monte Enoc and Cerro Falcone fields which accounts for 38% of Eni's domestic production, is treated by the Val d'Agri Oil Center ("COVA"). On July 18, 2017, Eni restarted operations at the COVA following approval from the Regional Council of the Basilicata Region. The resumption of the plant's operational activities follows approval from the relevant Authorities confirming the functionality of the plant and the presence of all necessary safety conditions. The shutdown of the plant occurred on April 18, 2017. For further information, see also Note No. 38 "Guarantees, commitments and risks" to Consolidated Financial Statements of the Annual Report on form 20-F 2017.

Development During the year, ten projects of the 35 projects launched as part of the 2014 Addendum to the agreement memorandum with the Basilicata Region were completed, with environmental and social initiatives as well as programs for sustainable development. In addition, school-work alternation projects and first-level apprenticeship were launched. Activities defined by the Gas Agreement progressed with a grant to support the gas consumption in the Municipalities of Val d'Agri and for energy efficiency programs.

Sicily

Production Eni operates 12 production concessions onshore and 3 offshore in Sicily, which in 2017 accounted for approximately 10% of Eni's production in Italy. The main fields are Gela, Tresauro, Giaurone, Fiumetto, Prezioso and Bronte.

Following the Memorandum of Understanding for the Gela area, signed with the Ministry of Economic Development in November 2014, the Argo and Cassiopea offshore development projects progressed. Projects were submitted to the relevant Authorities and planned an optimization activities aiming to reduce environmental impact. The plan provides significant synergies with the Gela Refinery leveraging on the recovery of certain areas already reclaimed for the construction of gas treatment plants. This program is subject to the authorization of the relevant Authorities.

In addition, within the framework of sustainable local development programs defined by Memorandum of Understanding and in agreement with the Municipality of Gela and the Sicily Region were: (i) signed implementation agreements for the local upgrading and to boost economic activities; and (ii) school-work alternation projects, first-level apprenticeship, programs to reduce school drop-out as well as university scholarship progressed.

REST OF EUROPE

Norway

Eni has been operating in Norway since 1965. Eni's activities are performed in the Norwegian Sea, in the Norwegian section of the North Sea and in the Barents Sea, on a total developed and undeveloped acreage of 6,740 square kilometers (2,117 square kilometers net to Eni). Eni's production in Norway amounted to 129 kboe/d in 2017. Exploration and production activities in Norway are regulated by Production Licenses (PL). According to a PL, the holder is entitled to perform seismic surveys and drilling and production activities for a given number of years with possible extensions.

Norwegian Sea

Production Eni currently holds interests in 10 production areas. The principal producing fields are Åsgard (Eni's interest 14.82%), Kristin (Eni's interest 8.25%), Heidrun (Eni's interest 5.17%), Mikkel (Eni's interest 14.9%), Tyrihans (Eni's interest 6.2%), Marulk (Eni operator with a 20% interest) and Morvin (Eni's interest 30%) which in 2017 accounted for 57% of Eni's production in Norway. The gas produced in the area is collected at the Åsgard facilities, carried by pipeline to the Karsto treatment plant and then delivered to the Dornum terminal in Germany. Liquids recovered in the area mainly through FPSO units are sold FOB. Development Development activities mainly concerned infilling activities to support production of the Asgard, Heidrun and Norne (Eni's interest 6.9%) fields.

Exploration Eni holds interests in 32 Prospecting Licensing, ranging from 5% to 50%, 4 of these are operated. Exploration activities yielded positive results with the Cape Vulture oil and gas discovery in the PL128/128D license (Eni's interest 11.5%) nearby the production facilities of the Norne field. Eni estimates the resources in place of oil and gas to be approximately 130 million boe.

Norwegian section of the North Sea

Production Eni holds interests in 2 production licenses. The main producing field is the Great Ekofisk Area (Eni's interest 12.39%) in PL 018, which includes the Ekofisk and Eldfisk and Embla satellites fields. In 2017, the Great Ekofisk Area produced approximately 23 kboe/d net to Eni and accounted for approximately 18% of Eni's production in Norway. Production from Ekofisk and satellites is carried by pipeline to the Teesside terminal in the United Kingdom for oil and to the Emden terminal in Germany for gas.

Development Development activities concerned infilling activities to support production of the Ekofisk and Eldfisk fields.

Exploration Eni holds interests in 6 Prospecting Licensing, ranging from 12% to 70%, 2 of these are operated.

Barents Sea

Eni holds interests in 13 Prospecting Licenses ranging from 30% to 90%, 8 of these are operated. Barents Sea is a strategic area with a huge resource base, which will be developed in compliance with the tightest environmental and safety standards provided for the people and environment protection, considering the fragile ecosystem.

Production Operations have been focused on the Goliat production field (Eni operator with a 65% interest). In 2017, Goliat produced 28 kboe/d or 22% of Eni's production in Norway.

The project includes a subsea system consisting of 22 wells linked to the largest cylindrical FPSO in the world by subsea production and injection flowlines. The use of well-advanced technologies, electricity supply provided to the platform from the mainland and the re-injection of produced water and natural gas into reservoir as well as zero gas flaring during production activities allow to minimize environmental impact.

Development Development activities concerned the drilling and production start-up of two new injection wells and an additional production well of the Goliat field.

The final investment decision (FID) of the Johan Castberg field (Eni's interest 30%) was sanctioned. The project is expected to retain approximately 450-650 million boe in place. Start-up is expected in 2022.

Exploration Eni yielded positive results with the Kayak oil discovery in the PL532 license (Eni's interest 30%); the well is located nearby to the Johan Castberg developing project in the area. The Kayak discovery is expected to retain 220 million boe in place.

United Kingdom

Eni has been present in the United Kingdom since 1964. Eni's activities are carried out in the British section of the North Sea and the Irish Sea, on a total developed and undeveloped acreage of 6,207 square kilometers (5,805 square kilometers net to Eni). In 2017, Eni's net production of oil and gas averaged 57 kboe/d. In line with the portfolio rationalization is completed the disposal of three exploration and productive assets of the country. Exploration and production activities in the UK are regulated by concession contracts.

Production Eni holds interests in 4 production areas of which the Liverpool Bay is operated by Eni with a 100% interest and Hewett Area is operated with an 89.3% interest. The other non-operated

fields are Elgin/Franklin (Eni's interest 21.87%), Glenelg (Eni's interest 8%), J-Block and Jasmine (Eni's interest 33%) as well as Jade (Eni's interest 7%).

Development In 2017, completed the drilling of infilling well of Elgin Franklin field and put into production at year-end.

Exploration Eni holds interest in 14 exploration licenses, 10 of these are operated, with interest ranging from 9% to 100%.

NORTH AFRICA

Algeria

Eni has been present in Algeria since 1981. In 2017, Eni's oil&gas production averaged 90 kboe/d. Developed and undeveloped acreage of Eni's interests was 3,359 square kilometers (1,141 square kilometers net to Eni).

Operated activities are located in the Bir Rebaa desert, in the Central-Eastern area of the country: (i) Blocks 403a/d (Eni's interest from 65% to 100%); (ii) Block ROM North (Eni's interest 35%); (iii) Blocks 401a/402a (Eni's interest 55%); (iv) Block 403 (Eni's interest 50%); (v) Block 405b (Eni's interest 75%); and (vi) Block 212 (Eni's interest 22.38%) with discoveries already made. In addition, Eni holds interest in the non-operated Block 404 and Block 208 with a 12.25% stake. Exploration and production activities in Algeria are regulated by Production Sharing Agreements (PSAs) and concession contracts.

Blocks 403a/d and ROM North

Production Production in Blocks 403a/d and ROM North comes mainly from the HBN and ROM and satellites fields and represented approximately 21% of Eni's production in Algeria in 2017. Production from ROM and satellites (ZEA, ZEK and REC) is treated at the ROM Central Production Facilities (CPF) and sent to the BRN treatment plant for final treatment, while production from the HBN field is treated at the HBNS oil center operated by the Groupment Berkine. Development Development activities concerned infilling activities and production optimization at the Zea field.

Blocks 401a/402a

Production Production in Blocks 401a/402a comes mainly from the ROD/SFNE and satellites fields and accounted for approximately 17% of Eni's production in Algeria in 2017.

Development Development activities concerned infilling activities and production optimization at the ROD and SF/SFNE fields.

Block 403

Production The main fields in Block 403 are BRN, BRW and BRSW, which accounted for approximately 9% of Eni's production in Algeria in 2017. In June 2017, Eni signed with the relevant Authorities a 15-year extension agreement of the Block 403 fields with a possible further 10 year extension. The agreement includes the option for the gas potential resources' development in the area also by means of the existing treatment facilities of the MLE project in the Block 405b. The agreement received all the necessary authorizations required by the country.

In December 2017, Eni and Sonatrach the state oil company signed a Memorandum of Understanding for the development project in the renewables sector. The agreement includes the feasibility studies to build solar power production units in the selected production areas operated by the state company. The MoU confirms Eni's commitment in promoting a sustainable development in the countries where Eni performs its activities, as an integral part of energy transition strategy aimed also at increasing the use of energy from renewable sources.

In addition, during the year the development activities started for the construction of a 10 MW photovoltaic plant to supply power generation to the Bir Rebaa North field in the Block 403, as defined by the agreement.

Block 404

Production The main fields in Block 404 are HBN and HBNS, which accounted for approximately 22% of Eni's production in Algeria in 2017.

Development Development activities concerned workover activities at the HBNS, HBNN and Ourhoud fields.

Block 405b

Production Production in Block 405b comes mainly from MLE-CAFC project and accounted for approximately 15% of Eni's production in the country in 2017. The natural gas treatment plant has a production capacity of 320 mmcf/d of gas, 15 kbbl/d of oil and condensates and 12 kbbl/d of LPG. Four export pipelines link it to the national grid system.

Development Development activities concerned: (i) the completion of the treatment plant with a capacity of 32 kbbl/d of the CAFC oil project; and (ii) the ongoing drilling planned activities in the area as well as infilling activities at the MLE project.

Block 208

Production The El-Merk field is the main production project in the Block 208 and accounted for approximately 16% of Eni's production in Algeria in 2017. Production is treated by means of a gas treatment plant for approximately 600 mmcf/d and two oil trains for 65 kbbl/d each. Development Development activities concerned the ongoing development activities of the El Merk field, with the drilling of production and water injection wells.

Libya

Eni started operations in Libya in 1959. Developed and undeveloped acreage were 26,636 square kilometers (13,294 square kilometers net to Eni). Production activity is carried out in the Mediterranean Sea near Tripoli and in the Libyan Desert area and includes six contract areas. Onshore contract areas are: (i) Area A, consisting in the former concession 82 (Eni's interest 50%); (ii) Area B, former concessions 100 (Bu Attifel field) and the NC 125 Block (Eni's interest 50%); (iii) Area E, with El Feel (Elephant) field (Eni's interest 33.3%); (iv) Area F, with Block 118 (Eni's interest 50%); and (v) Area D with Block NC 169 that feeds the Western Libyan Gas Project (Eni's interest 50%). Offshore contract areas are: (i) Area C, with the Bouri

17

oil field (Eni's interest 50%); and (ii) Area D, with Block NC 41 that feeds the Western Libyan Gas Project.

In the exploration phase, Eni is operator in the onshore Contract Areas A and B and offshore Area D.

In recent years, Eni's production levels in Libya were negatively impacted by the country's political instability. More recently, Eni's oil activities in the country have improved, reflecting a certain degree of normalization in the Country internal situation and improving security conditions. In 2017, Eni's production in Libya was 384 kboe/d, which represents the highest level of Eni's production in the Country. Despite this and other positive developments, Libya's geopolitical situation continues to represent a source of risk and uncertainty for the foreseeable future. For further information on this matter, see "Item 3 – Risk factors-Political considerations" to Consolidated Financial Statements of the Annual Report on form 20-F 2017.

Exploration and production activities in Libya are regulated by six Exploration and Production Sharing Agreement contracts (EPSA). The licenses of Eni's assets in Libya expire in 2042 and 2047 for oil&gas properties, respectively.

Development Development activities concerned: (i) the installation, commissioning and production start-up of a new FSO at the Bouri field; (ii) the second development phase of the Bahr Essalam field with the installation of the offshore facilities and the completion of wells. The development plan foresees drilling and completion of ten production wells. Start-up is expected in

2018; and (iii) the drilling and linkage of two additional production wells at the Wafa field. The upgrading activities of the compression capacity of Wafa plant progressed to support natural gas production. Start-up is expected in 2018.

In March 2017, Eni signed a Memorandum of Understanding to promote health and education initiatives of local communities. In particular, two starting programs were defined: (i) hospital renovation in the Jalo area; and (ii) the construction of a pipeline for the desalination plant to provide drinking water to communities in the area. In addition, Eni is committed in other programs to support local communities in the country: (i) initiatives in the health, water and energy access at the Bu Attifel and El Feel production areas; and (ii) training programs of medical field and oil&gas sector.

Exploration Exploration activity yielded positive results with a new gas and condensates discovery in the contractual area D. The discovery is located nearby to the Bouri and Bahr Essalam production fields. The exploration success is in line with Eni's exploration strategy of focusing on near-field incremental activities, leveraging on the synergies with existing facilities, reducing the time-to-market and providing for additional gas to the local market and export. In April 2017, the country's Authorities extended the exploration license period until 2019.

Tunisia

Eni has been present in Tunisia since 1961. In 2017, Eni's production amounted to 9 kboe/d. Eni's activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet, over a developed acreage of 3,600 square kilometers (1,558 square kilometers net to Eni).

Exploration and production in this country are regulated by concessions. Production Production mainly comes from operated Maamoura and Baraka offshore blocks (Eni's interest 49%) and the Adam (Eni operator with a 25% interest), Oued Zar (Eni operator with a 50% interest), Djebel Grouz (Eni operator with a 50% interest), MLD (Eni's interest 50%) and El Borma (Eni's interest 50%) onshore blocks.

Development Production optimization represents the main activity currently performed in the above listed concessions to mitigate the natural field production decline.

Egypt

Eni has been present in Egypt since 1954. In 2017, Eni's share of production in this country amounted to 230 kboe/d and accounted for 13% of Eni's total annual hydrocarbon production. Developed and undeveloped acreage in Egypt was 25,375 square kilometers (9,192 square kilometers net to Eni).

Eni's main producing liquid fields are located in the Gulf of Suez, primarily the Belayim field (Eni's interest 100%), and in the Western Desert, mainly the Melehia (Eni's interest 76%), the Ras Qattara (Eni's interest 75%), Raml (Eni's interest 45%) and West Razzaq and Kanayis (Eni's interest 100%) concessions.

Gas production mainly comes from the operated or participated concessions of North Port Said (Eni's interest 100%), El Temsah (Eni's interest 50%), Baltim (Eni's interest 50%), Ras el Barr (Eni's interest 50%, non-operated) and the Nile Delta (Eni's interest 75%). In 2017, production from these large concessions accounted for approximately 95% of Eni's production in Egypt.

In addition, Eni operates in the Shorouk concession (Eni's interest 60%), where the giant Zohr discovery is located. Production at the field started at the end of 2017.

Exploration and production activities in Egypt are regulated by Production Sharing Agreements.

Shorouk block

In 2017, Eni closed two agreements with major international players in the oil&gas business for the disposal of a 40% interest in the Zohr field, with the approval by Egyptian government. These transactions are a part of Eni's "Dual Exploration Model" which is targeting simultaneously the fast-track development of discovered resources and the partial dilution of the high stakes retained in exploration leases to monetize in advance part of discovered volumes. The agreements concerned the sale of: (i) a 10% interest to BP for a consideration amount of \$375 million and the pro-quota reimbursement of past expenditures, which amount so far at approximately \$150 million; and (ii) a 30% interest to Rosneft for a consideration amount of \$1,125 million and the proquota reimbursement of past expenditures, which amount so far at approximately \$450 million.

In March 2018, Eni signed an agreement with Mubadala Petroleum for the divestment of an additional 10% interest in Zohr for a cash consideration of \$934 million. The transaction is subject to the

fulfillment of certain conditions and all necessary authorizations from Egypt's Authorities.

In December 2017, production start-up was achieved by means of offshore wells and subsea facilities at the Zohr field in a record time-to-market, in less than two and a half years from discovery. The natural gas production is carried by sea-line to the first and second treatment train of onshore plant with a capacity of approximately 800 mmcf/d. The development plan includes the construction of additional six treatment trains that will support production ramp-up to achieve a production plateau of approximately 2.7 bcf/d. Development activities progressed with drilling activities to start-up 20 planned production wells, of which 6 wells already drilled, and the construction of treatment facilities. The field has estimated resources of over 30 Tcf gas in place (approximately 5.5 billion boe). Within the social responsibility initiatives, the renovation of the El Garabaa hospital and the supply of necessary medical equipment were completed. The hospital is located nearby Zohr onshore production facilities.

In March 2017, Eni signed a Memorandum of Understanding with the local relevant Authorities. The agreement, which integrates the development activities, is aimed at implementing certain socioeconomic and health programs of local communities in the next four years, in particular in the Zohr and Port Said areas. The programs will be fully financed by Eni and its partners in the Zohr project with an overall expense of \$20 million. The defined initiatives concern three main areas: (i) aquaculture and fisheries; (ii) health projects; and (iii) programs to support youth. In 2018, a hospital and a youth center will be built in the south-western area of Port Said; the start-up of activities to build an aquaculture center nearby to the Zohr onshore plants.

Gulf of Suez

Production Production mainly comes from the Belayim field, Eni's first large oil discovery in Egypt, which produced approximately 67 kbbl/d (39 kbbl/d net to Eni) in 2017.

Development Infilling activities and production optimization were performed to support production capacity.

North Port Said

Production Production for the year amounted to approximately 23 kboe/d (approximately 17 kboe/d net to Eni), approximately 106 mmcf/d of natural gas and approximately 2 kbbl/d of condensates. Part of the production of this concession is supplied to the United Gas Derivatives Co (Eni's interest 33.33%) with a treatment capacity of 1.3 bcf/d of natural gas and a yearly production of 133 ktonnes of propane, 72 ktonnes of LPG and approximately 1 mmbbl of condensates.

Development Infilling activities and production optimization were performed to support production capacity.

Baltim

Production In 2017, production amounted to approximately 23 kboe/d (approximately 7 kboe/d net to Eni); approximately 106 mmcf/d of natural gas and 3 kbbl/d of condensates. The Baltim South West offshore project was sanctioned which provides to put into

production six wells through the installation of a production platform and linkage facilities to the existing gas treatment plant in the Nooros area (Eni's interest 75%).

Nile Delta

Production Production comes mainly from the Nidoco NW field and satellites as part of the Great Nooros Area project, in the Abu Madi West concession; in 2017 produced 94 kboe/d net to Eni. Development Start-up of three additional wells and the completion of the second and third treatment unit of the Nooros field to achieve a production of approximately 1 bcf/d.

Ras el Barr

Production In 2017, the production amounted to approximately 60 kboe/d (approximately 20 kboe/d net to Eni), mainly gas from Ha'py, Akhen, Taurt and Seth fields.

El Temsah

Production This concession includes the Temsah, Denise, Tuna and Karawan fields. Production in 2017 amounted to approximately 67 kboe/d (approximately 17 kboe/d net to Eni); approximately 350 mmcf/d of natural gas and approximately 3 kbbl/d of condensates net to Eni.

Western Desert

Production Concessions in the Western Desert accounted for approximately 10% of Eni's production in Egypt in 2017. Development Development activities were performed at the Melehia concession and concerned infilling activities and production optimization to support production capacity.

Exploration Exploration activity yielded positive results with the nearfield Meleiha South 1X, Aman East 1X and Karnak Deep 1X oil wells in the Meleiha concession. The discoveries were already linked to the existing production facilities in the area.

SUB-SAHARAN AFRICA

Angola

Eni has been present in Angola since 1980. In 2017, Eni's production averaged 146 kboe/d. Eni's activities are concentrated in the conventional and deep offshore, over a developed and undeveloped acreage of 21,051 square kilometers (4,367 square kilometers net to Eni).

The main Eni's asset in Angola is the Block 15/06 (Eni operator with a 36.84% interest) with the West Hub project, where production started up in 2014 and the East Hub project with production start-up achieved in February 2017.

Eni participates in other producing blocks: (i) Block 0 in Cabinda offshore (Eni's interest 9.8%) north of the Angolan coast; (ii) Development Areas in the Block 3 and 3/05-A (Eni's interest 12%) offshore the Congo Basin; (iii) Development Areas in the Block 14 (Eni's interest 20%) in the deep offshore west of Block 0; (iv) the Lianzi Development Area in the Block 14 K/A IMI (Eni's interest 10%), where a unitization was implemented with the Congo-Brazzaville area; and (v) Development Areas in the former Block 15 (Eni's interest 20%) in the deep offshore of the Congo Basin. In November 2017, Eni signed with Sonangol an agreement to award a 48% interest and the operatorship of the onshore Cabinda North block, which was previously participated by Eni with a 15% interest. The block is located in an oil basin few explored in the north of the country, where Eni will leverage on the mining knowledge acquired in exploration and development activities progressed in nearby areas of the Republic of Congo. In case of exploration success, the block will benefit from the existing infrastructures. In addition, Eni and Sonangol signed a Memorandum of Understanding to define joint projects throughout the value chain of the energy sector. In particular, the MoU includes programs in the downstream business, exploration activities, development of associated and non-associated gas and renewable energy sector. Eni also continues its commitment to support socio-economic development in the southern region of the country. In particular, the ongoing initiatives, defined with the Ministry of Energy and Water Resources, the Ministry of Health and local communities, concerned: (i) an integrated project to improve access to energy and water; and (ii) agricultural projects as well as health training programs and activities. Finally, Eni supports the program aimed at demining and improving rural areas, particularly in the south of the country. Exploration and production activities in Angola are regulated by concessions and PSAs.

Block 15/06

Production Production mainly comes from the West Hub and the East Hub projects.

The West Hub project represents the first Eni-operated producing project in the country. The development program plans to hook up the Block's discoveries to the N'Goma FPSO in order to support production plateau.

In February 2017, production start-up was achieved at the East Hub project, five months earlier than scheduled and with a time-to-market among the best in the industry, by means of the linkage of Cabaça South East field to the FPSO Olombendo.

The development plan of the Block 15/06, with the West Hub and East Hub projects, includes water and gas injection wells in line with the zero flaring policy and zero water discharge.

Development Development activities carried out in 2017, mainly of the West Hub project, are: (i) the completion of project activities of the Ochigufu oil field, with production start-up achieved in March 2018, in one and a half year from the FID; and (ii) the Vandumbu project with production start-up expected in 2019.

Exploration In November 2017, Eni signed extension exploration rights of the block until 2020. This agreement will grant to Eni to exploit the full near-field exploration potential in a fruitful area.

Block 0

Production In 2017, production from this block amounted to approximately 298 kbbl/d (approximately 29 kbbl/d net to Eni). Oil production from Area A, deriving mainly from the Takula, Malongo and Mafumeira fields amounted to approximately 19 kbbl/d net to Eni. Production of Area B derives mainly from the Bomboco, Kokongo, Lomba, N'Dola, Nemba and Sanha fields, and amounted to approximately 10 kbbl/d net to Eni. Associated gas of the area was delivered via Congo River Crossing to the A-LNG liquefaction plant (see below) and partially supplied to the domestic market, for the power generation in Cabinda. Development Development activities concerned the drilling of development wells of the Mafumeira Sul project.

Block 3 and 3/05-A

Production Block 3 is divided into three production offshore areas. Oil production is treated at the Palanca terminal and delivered to storage vessel unit and then exported. In 2017, production from this area amounted to approximately 32 kbbl/d (approximately 3 kbbl/d net to Eni).

Block 14

Production In 2017, Development Areas in Block 14 produced approximately 102 kbbl/d (approximately 14 kbbl/d net to Eni). Its main fields are Landana and Tombua as well as Benguela-Belize/ Lobito-Tomboco and Lianzi. Associated gas of the area was delivered via Congo River Crossing to the A-LNG liquefaction plant (see below).

Block 15

Production The block produced approximately 293 kbbl/d (approximately 38 kbbl/d net to Eni) in 2017. Its main fields are: (i) the Hungo/Chocalho, started-up in 2004 by means of the Kizomba A FPSO; (ii) the Kissanje/Dikanza, started-up in 2005 by means of the Kizomba B FPSO; (iii) Saxi/Batuque and Mondo, started-up in 2008 and operated by two added FPSO units; (iv) Clochas and Mavacola, started-up in 2012 as part of Kizomba Satellites Phase 1; and (v) Bavuca, Kakocha and Mondo South, started-up in 2015 as part of Kizomba Satellites Phase 2. Development Development activities in 2017 are the completion of development activities of the Kizomba Satellites Phase 2 project and

The LNG business in Angola

infilling activities.

Eni holds a 13.6% interest of Angola LNG (A-LNG) which runs the plant, located in Soyo, with a treatment capacity of approximately 350 bcf/year of feed gas and a liquefaction capacity of 5.2 mmtonnes/y of LNG.

In 2017 production net to Eni averaged approximately 20 kboe/d.

Congo

Eni has been present in Congo since 1968. In 2017, production averaged 83 kboe/d net to Eni. Eni's activities are concentrated in the conventional and deep offshore facing Pointe-Noire and onshore Koilou region over a developed and undeveloped acreage of 2,750 square kilometers (1,471 square kilometers net to Eni). Exploration and production activities in Congo are regulated by Production Sharing Agreements.

Production Eni's main operated producing interests in Congo are the Zatchi (Eni's interest 55.25%), Loango (Eni's interest 42.5%), Ikalou (Eni's interest 100%), Djambala (Eni's interest 50%), Foukanda and Mwafi (Eni's interest 58%), Kitina (Eni's interest 52%), Awa Paloukou (Eni's interest 90%), M'Boundi (Eni's interest 83%), Kouakouala (Eni's interest 75%), Nené Marine and Litchendjili (Eni's interest 65%), Zingali and Loufika (Eni's interest 100%) fields with an overall production of approximately 79 kboe/d (66 kboe/d net to Eni). Other non-operated producing areas are represented by a 35% interest in the Pointe-Noire Grand Fond and Likouala permits, with an overall production of approximately 48 kboe/d (17 kboe/d net to Eni). Development In 2017, the execution development phase of the Nené Marine Phase 2A production project in the Marine XII block progressed by means of: (i) installation and start-up of a new production platform; (ii) the construction of a sealine to export production to the Kitina hub; and (iii) start-up of seven additional production wells. Planned development activities include the drilling of additional production wells with start-up expected in 2018 and the construction of a sealine for the linkage to Litchendjili hub in the Marine XII block. The development activities of the area include natural gas and produced water re-injection as well as the use of gas production for the power generation in order to achieve zero routine flaring. Furthermore, with the completion of planned activities the associated gas will be used to feed the CEC power plant (Eni's interest 20%).

In April 2017, Eni signed with the relevant Authority an extension to the gas sale agreement to feed CEC power plant with the gas production of the Marine XII block. The agreement includes also an additional supply of 35 mmcf/d. Furthermore, Eni is also committed to protecting the country's biodiversity. In particular, in the production area of M'Boundi, in collaboration with international NGOs, a program to protect the flora and fauna of the areas nearby to the treatment and production plants progressed. The activities of the second phase of the Project Integrated Hinda (PIH) were started, aiming to improve life condition of local communities nearby to the M'Boundi, Kouakouala, Zingali and Loufika producing areas. The planned project includes certain initiatives to support socio-economic development of local communities with economic programs for a diversification purpose, primary education, access to water and health initiatives. In addition, a project for the construction of renewable energy training and research center started in Oyo, in the north of the country.

Ghana

Eni has been present in Ghana since 2009. In 2017, production averaged 9 kboe/d net to Eni.

Eni is the operator of the Offshore Cape Three Points (Eni's interest 44.44%) permits which is regulated by a concession agreement and also operates the offshore exploration license Cape Three Points Block 4 (Eni's interest 42.47%). Developed and undeveloped acreage in water depths was 1,353 square kilometers (579 square kilometers net to Eni).

Production The OCTP project start-up was achieved in just two years and a half as well as three months earlier than scheduled and with a record time-to-market. Production will be carried out via a floating production, storage and offloading unit (FPSO), which will produce up to 85 kboe/d through 18 underwater wells. The development activities progressed and in particular, in 2017, production wells planned were drilled and linked to the production facility achieving the planned peak production of 45 kbbl/d one year earlier than scheduled. The project includes the transportation of non-associated gas to the onshore facilities to be processed and linked to Ghana's national grid, supplying approximately 180 mmcf/d. Start-up is expected by mid-2018.

The OCTP project is the only non-associated gas development project in deep water entirely dedicated to the domestic market in Sub-Saharan Africa. This project will ensure at least 15 years of reliable gas supply with an affordable price, significantly supporting the access to energy and economic development of the country. The project has been developed in compliance with the highest environmental requirements, zero gas flaring and produced water re-injection, including the Performance Standards on Environmental and Social Sustainability of the International Finance Corporation (IFC), which is part of the World Bank Group.

Eni progressed its commitment to support local communities in the western region of the country, nearby the operated OCTP project. In particular, the ongoing initiatives concerned: (i) support for food needs, including training initiatives and specific projects aimed at restoring and increasing agro-zootechnical production and fishing activities; (ii) economic programs for a diversification purpose with initiatives to promote micro-entrepreneurial activities and professional training programs; (iii) improved access to drinking water and waste management; and (iv) the renovation of the primary school infrastructure in Sanzule. Healthcare initiatives continue to increase access to mother and child health services. Projects progressed to develop renewables power plant, particularly the photovoltaic plant.

Mozambique

Eni has been present in Mozambique since 2006, following the award of the exploration license relating to Area 4 offshore the Rovuma Basin block, located in the north of the country. The Rovuma Basin represents a new frontier in oil and gas industry thanks to extraordinary gas discoveries made during intense only

three-year exploration campaign. To date, resource base reached 85 Tcf located in the different sections of the area.

In addition, Eni operates the offshore exploration Block A-5A (Eni's interest 70%), in the deep offshore of Zambesi.

In December 2017, Eni and ExxonMobil closed the sale of a 25% indirect interest in the Area 4 block, offshore Mozambique, through a sale of 35.7% stake in Eni East Africa (EEA). The agreed terms, based on the agreements of March 2017, include a cash price of approximately \$2.8 billion plus the contractual adjustments up to the closing date, including the reimbursement to Eni of share of capex incurred from the beginning of 2016 up to the completion date.

Following completion of the transaction, Mozambique Rovuma Venture, former EEA, is co-owned by Eni and ExxonMobil with a 35.7% stake and the remaining interest of 28.6% by CNPC.

Eni continues to lead the Coral South FLNG project and all upstream operations in Area 4, while ExxonMobil leads the construction and operation of natural gas liquefaction facilities onshore. This operating model enables the use of best practices and skills within Eni and ExxonMobil with each company focusing on distinct and clearly defined scopes while preserving the benefits of a fully integrated project.

Development The Company is planning to develop as first target the Coral discovery and a portion of the Mamba straddling resources.

The development activities of the Coral South project provides for the installation of a floating unit for the treatment, liquefaction and storage of natural gas (FLNG) with a capacity of approximately 3.4 mmtonnes/y, fed by 6 subsea wells and start-up expected in the mid-2022.

During the 2017, the planned activities were started and the following agreements were signed: (i) the drilling, construction, installation and commissioning contracts for the production facilities; (ii) project financing for the construction, installation and commissioning of the FLNG to cover 60% of investment. In December 2017, the financing agreement was closed and subscribed by 15 major international banks and guaranteed by 5 Export Credit agencies; and (iii) agreements with the Mozambican government for the regulatory framework of the project.

Other development activities concerned the Mamba project according to its independent industrial plan, coordinated with the operator of Area 1 (Anadarko).

In the Cabo Delgado and Maputo areas, Eni engaged a significant program to support population, including access to energy, access to water, health and sanitation, as well as education and training activities.

Nigeria

Eni has been present in Nigeria since 1962. In 2017, Eni's oil&gas production averaged 109 kboe/d located mainly onshore and offshore the Niger Delta, over a developed and undeveloped acreage of 30,769 square kilometers (7,370 square kilometers net to Eni).

In the development/production phase Eni operates onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni's interest 20%) and offshore OML 125 (Eni's interest 100%), OPL 245 (Eni's interest 50%), holding interests in OML 118 (Eni's interest 12.5%) as well as OML 119 and 116 Service Contracts. As partner of SPDC JV, the largest joint venture in the country, Eni also holds a 5% interest in 17 onshore blocks and in 1 conventional offshore block as well as with a 12.86% interest in 2 conventional offshore blocks. In the exploration phase Eni operates offshore OML 134 (Eni's interest 85%), OPL 2009 (Eni's interest 49%), and onshore OPL 282 (Eni's interest 90%) and OPL 135 (Eni's interest 48%). Eni also holds a 12.5% interest in OML 135.

In 2017, Eni signed a Memorandum of Understanding with the Nigerian National Petroleum Corporation (NNPC) to promote new activities that can significantly boost Nigeria's social and economic development. In particular, the cooperation agreement includes: (i) an increased focus on development and exploration activities; (ii) cooperation requirements for the rehabilitation and enhancement of Port Harcourt refinery; (iii) the upgrade of the Okpai combined cycle power plant by means of doubling the power generation capacity; and (iv) the assessment of additional projects to secure energy accessibility to the country's most remote areas and possible application of new technologies in the renewable energy sector.

Programs progressed to support the local community in Nigeria, with initiatives in the access to off-grid energy, water and primary education; economic programs for diversification purposes with the ongoing Green River Project; professional training and scholarship programs as well as renovation and construction of health centers and supply of medical equipment.

In February 2018, Eni signed with the Food and Agriculture Organization (FAO) a collaboration agreement to foster access to safe and clean water in Nigeria by drilling boreholes powered with photovoltaic systems, both for domestic use and irrigation purposes.

Exploration and production activities in Nigeria are regulated mainly by Production Sharing Agreements and concession contracts as well as service contracts, in two blocks, where Eni acts as contractor for State-owned Company.

Blocks OMLs 60, 61, 62 and 63

Production Onshore four licenses produced approximately 44 kboe/d and accounted for approximately 40% of Eni's production in Nigeria in 2017. Liquid and gas production is supported by the NGL plant at Obiafu-Obrikom with a treatment capacity of approximately 1 bcf/d and by the oil tanker terminal at Brass with a storage capacity of approximately 3,5 mmbbl. A large portion of the gas production of these four OMLs is destined to supply the

Bonny Island liquefaction plant (see below). Another portion of gas production is employed in firing the combined cycle power plant at Okpai with a 480 MW generation capacity.

In 2017, supplies to this power station were an overall amount of approximately 70 mmcf/d.

Development Development activities concerned rigless programs to support production as well as maintenance and rehabilitation of the facilities damaged due to bunkering and sabotage.

Block OML 118

Production The Bonga oil field produced approximately 15 kboe/d net to Eni in 2017. Production is supported by an FPSO unit with a 225 kboe/d treatment capacity and a 2 mmboe storage capacity. Associated gas is carried to a collection platform on the EA field and, from there, is delivered to the Bonny liquefaction plant.

Block OML 125

Production Production derived mainly from the Abo field which yielded approximately 14 kboe/d net to Eni in 2017. Production is supported by an FPSO unit with a 40 kboe/d capacity and an 800 kboe storage capacity.

SPDC Joint Venture (NASE)

Production In 2017, production from the SPDC JV accounted for approximately 30% of Eni's production in Nigeria (approximately 33 kboe/d). Development The development activities mainly concerned the completion of the Forcados-Yokri project in the OML 43 Block (Eni's interest 5%) and the Gbaran 2A/2B and Associated gas project in the OML 28 Block (Eni's interest 5%) to supply natural gas to the Bonny liquefaction plant. In particular, in the year, the tie-in of production wells and the upgrading of existing treatment plants were completed.

The LNG business in Nigeria

Eni holds a 10.4% interest in the Nigeria LNG Ltd joint venture, which runs the Bonny liquefaction plant located in the Eastern Niger Delta. The plant is operational, with a treatment capacity of approximately 1,236 bcf/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG by six trains. Natural gas supplies to the plant are currently provided under a gas supply agreements from the SPDC JV, TEPNG JV and the NAOC JV. In 2017, the Bonny liquefaction plant processed approximately 1,130 bcf. LNG production is sold under long-term contracts and exported to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Ltd.

KAZAKHSTAN

Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and partner in the North Caspian Sea Production Sharing Agreement (NCSPSA). Developed and undeveloped acreage in Kazakhstan was 6,281 square kilometers (1,543 square kilometers net to Eni).

In 2017, Eni signed a number of strategic cooperation agreements in the upstream and renewable energy sectors in the country. Eni and KazMunayGas (KMG) signed an agreement, closed in December 2017, for the transfer to Eni the 50% stake for exploration and production activities in the Isatay block located in the Kazakh sector of the Caspian Sea. The Isatay block is estimated to have significant potential oil resources and will be operated by a joint operating company established by KMG and Eni on a 50/50 basis. In addition, Eni and KMG signed an agreement to further expand upstream technology co-operation and evaluate potential joint developments in new projects. The agreement includes technical and managerial training programs for local staff.

Eni, KMG and the other partners signed with the Ministry of Energy of the Republic of Kazakhstan, and the Kazakh Committee of Geology and subsoil use, a Memorandum of Understanding to evaluate future cooperation terms in the Kazakh-Russian Pre-Caspian Basin recording certain significant oil discoveries.

In addition, Eni and General Electric (GE) signed with the Minister of Energy of the Republic of Kazakhstan an agreement to promote the development of renewable energy projects in the country. In particular, Eni and GE will co-operate to evaluate the construction of a wind power plant with approximately 50 MW capacity and further future initiatives.

Kashagan

Eni holds a 16.81% interest in the North Caspian Sea Production Sharing Agreement (NCSPSA). The NCSPSA defines terms and conditions for the exploration and development of the giant Kashagan field, which was discovered in the Northern section of the contractual area in the year 2000 over an undeveloped area extending for 4,600 square kilometers. The NCSPSA expires at the end of 2041. Production Ramp-up and stabilization of the production level at the Kashagan field progressed. Although gas re-injection started later than initially planned, it has been stepped-up in the course of the year and will allow to achieve the target production capacity of 370 kbbl/d when fully operational. Development activity progressed to increase production capacity up to 450 kbbl/d by installing additional gas compression capacity through the conversion of production wells into injection wells and the upgrading of the existing facilities. Development The studies for the improvement of the CC01 gas re-injection project progressed. The project targets to install a new compressor unit to increase an additional gas reinjection capacity to support production ramp-up. Within the agreements with local Authorities, training program progressed for Kazakh resources in the oil&gas sector, in addition to the realization of infrastructures with social purpose.

Karachaganak

Located onshore in West Kazakhstan, Karachaganak (Eni's interest 29.25%) is a liquid and gas giant field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a PSA. Eni and Shell are co-operators of the venture. Production In 2017, production of the Karachaganak field averaged 247 kbbl/d of liquids (54 kbbl/d net to Eni) and 931 mmcf/d of natural gas (209 mmcf/d net to Eni).

This field is developed by producing liquids from the deeper layers of the reservoir. The gas is marketed (about 51%) at the Russian gas plant in Orenburg and the remaining volume is utilized for re-injecting in the higher layers and the production of fuel gas. Approximately 91% of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity of approximately 250 kbbl/d and exported to Western markets through the Caspian Pipeline Consortium (Eni's interest 2%) and the Atyrau-Samara pipeline. The remaining volume of non-stabilized liquid production (approximately 16 kbbl/d) is marketed at the Russian terminal in Orenburg.

Development Within the gas treatment expansion projects of the Karachaganak field, the detailed engineering development of the Karachaganak Debottlenecking project is expected to be completed shortly and the Final Investment Decision (FID) expected in the second quarter of 2018. Additional re-injection capacity will be ensured by installing a re-injection facility that will be added to the existing ones.

Eni continues its commitment to support local communities in the nearby area of Karachaganak field. In particular, activities focused on: (i) the professional training; and (ii) the construction of kindergartens and schools, maintenance of roads and bridges and building of sport centers. Moreover, following the re-definition of the Sanitary Protection Zone (SPZ) associated to the ongoing development projects and according to the international standards and best practices, a project of relocation of the inhabitants, which started in 2015, from Berezovka and Bestau villages was completed.

Eni continues to conduct monitoring activities on biodiversity and ecosystems in the nearby of the production areas.

REST OF ASIA

Indonesia

Eni has been present in Indonesia since 2001. In 2017, Eni's production mainly composed of gas, amounted to 41 kboe/d. Activities are concentrated in the Eastern offshore and onshore of East Kalimantan, offshore Sumatra, and offshore and onshore of West Timor and West Papua, over a developed and undeveloped acreage of 31,841 square kilometers (22,889 square kilometers net to Eni); in total, Eni holds interests in 14 blocks.

Exploration and production activities in Indonesia are regulated by PSAs. Production Production derives from the Sanga Sanga permit (Eni's interest 37.8%) and Muara Bakau block (Eni's interest 55%) where Jangkrik field started-up in 2017.

Production started up earlier than scheduled in the Jangkrik gas project by means of ten offshore wells linked to the Floating Production Unit (FPU) with a production of approximately 650 mmcf/d (corresponding to 120 kboe/d).

Natural gas production is processed by the FPU and then delivered by pipeline to the onshore plant, which is linked to the East Kalimantan transport system to feed Bontang liquefaction plant. The LNG is sold under long-term contracts, partly to state company Pertamina and to Eni, which will sell over 11 million tonnes for 15 years as part of the supply agreement signed with the Pakistan LNG state company. In Sanga Sanga permit were put into production seven fields. This gas is treated at the Bontang liquefaction plant. Liquefied gas is exported to the Japanese, South Korean and Taiwanese markets.

In April 2018, development plan of the Merakes gas field (Eni operator with a 75% interest) off Indonesia approved by the relevant authorities, leveraging synergies with nearby Jangkrik producing field.

Ongoing initiatives progressed in the field of environmental protection, health care and educational system to support local communities located in the operated areas of the Eastern Kalimantan, Papua and North Sumatra.

Exploration Exploration activities yielded positive results with the Merakes 2 appraisal well confirming the mineral potential of the Merakes gas discovery in the western area of the East Sepinggan block (Eni operator with an 85% interest). The discovery, nearby the Jangkrik project block, will leverage on the synergies with

existing facilities to reduce costs and time of the execution of the subsea development and confirms the success of Eni's near-field exploration and appraisal strategy.

In May 2018, Eni was awarded a 100% interest in the East Ganal deep offshore exploration block in the Kutei basin.

Iraq

Eni has been present in Iraq since 2009 and is performing development activities over a developed acreage of 1,074 square kilometers (446 square kilometers net to Eni).

Development and production activities are regulated by a technical service contract.

Production Production comes from Zubair oil field (Eni's interest 41.6%) with a production of 43 kbbl/d net to Eni in 2017. The first stage of development activities (Rehabilitation Plan) of Zubair field has been completed. The consortium commitment includes the execution of an additional development phase (Enhanced Redevelopment Plan) of the Zubair field, to achieve a production plateau of 700 kbbl/d. This phase also contemplates utilization of the associated gas to power generation.

Pakistan

Eni has been present in Pakistan since 2000. In 2017, Eni's production mainly composed of gas amounted to 24 kboe/d, over a developed and undeveloped acreage of 17,355 square kilometers (7,401 square kilometers net to Eni). Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore). Production Eni's main permits in the country are Bhit/Bhadra (Eni operator with a 40% interest), Sawan (Eni's interest 23.68%) and Zamzama (Eni's interest 17.75%), which in 2017 accounted for approximately 80% of Eni's production in Pakistan. Development Production optimization through drilling activities of new development wells represents the main activity currently performed in the above listed fields to mitigate the natural field production decline.

Turkmenistan

Eni started its activities in Turkmenistan with the purchase of the British company Burren Energy plc in 2008. Activities are focused on the onshore Nebit Dag Area in the Western part of the country, over a developed acreage of 200 square kilometers (180 square kilometers net to Eni), in four areas. In 2017, Eni's production averaged 9 kboe/d. Exploration and production activities in Turkmenistan are regulated by PSAs.

Production Production derives mainly from the Burun oil field. Oil production is shipped to the Turkmenbashi refinery plant. Eni receives, by means of a swap arrangement with the Turkmen Authorities, an equivalent amount of oil at the Okarem terminal, close to the South coast of the Caspian Sea. Eni's entitlement is sold FOB. Associated natural gas is used for gas lift system. The remaining amount is delivered to the national oil company Turkmenneft, via national grid. Development Development activities concerned a program to mitigate the natural field production decline.

AMERICAS

Ecuador

Eni has been present in Ecuador since 1988. Operations are performed in Block 10 (Eni's interest 100%) located in the Amazon Forest, over a developed acreage of 1,985 square kilometers net to Eni. In 2017, Eni's production averaged 12 kbbl/d.

Exploration and production activities in Ecuador are regulated by a service contract.

Production Production deriving from the Villano field, started in 1999, is processed by a Central Production Facility and transported to storage facility in the Pacific Coast through a pipeline network. Development In 2017, development activities of the Villano Phase VI project were complete with the drilling and production start-up of three infilling wells.

Mexico

Eni has been present in Mexico since 2015. Eni is operator of the offshore Area 1 (Eni's interest 100%) over a undeveloped acreage of 1,657 square kilometers kilometers (1,146 square kilometers net to Eni) where development activities progress in the Amoca, Miztón and Tecoalli discoveries, located in the shallow waters of the Gulf of Mexico, regulated by PSA.

In June 2017, Eni was awarded the operatorship of the Block 10 (Eni's interest 100%), the Block 14 (Eni's interest 60%) and the Block 7 (Eni's interest 45%) located in the Sureste basin. Furthermore, in February 2018, Eni was awarded a 65% interest and the operatorship of the Block 24. The new blocks are closed to Area 1 block and, in the case of a successful exploration campaign they will allow significant operational synergies.

In March 2018, Eni was awarded the operatorship of the Block 28 (Eni's interest 75%), located in Cuenca Salina Basin, in offshore Mexico. The contract award is subject to approval from the Authorities.

Exploration activities yielded positive results in the Area 1 block with the drilling of: (i) the Amoca-2 and Amoca-3 appraisal oil wells; (ii) the first delineation well of the Miztón oil discovery; and (iii) the Tecoalli 2 appraisal oil well. Exploration successes and the reservoir review of the Amoca and Miztón discoveries resulted in a rise in estimated hydrocarbons in place of the block to 2 billion boe, of which approximately 90% oil. Eni submitted an integrated development plan all of three discoveries located in the Area 1 block to the relevant Authorities. Production start-up is expected in 2019.

United States

Eni has been present in the United States since 1968. Activities are performed in the Gulf of Mexico, Alaska, and in Texas onshore, over a developed and undeveloped acreage of 2,105 square kilometers (1,052 square kilometers net to Eni). In 2017, Eni's oil&gas production was 77 kboe/d.

Exploration and production activities in the United States are regulated by concessions.

Gulf of Mexico

Eni holds interests in 75 exploration and production blocks in the shallow and deep offshore of the Gulf of Mexico, of which 35 are operated by Eni.

2017

Production The main operated fields are Allegheny and Appaloosa (Eni's interest 100%), Pegasus (Eni's interest 85%), Longhorn, Devils Towers and Triton (Eni's interest 75%). Eni also holds interests in Europa (Eni's interest 32%), Hadrian South (Eni's interest 30%), Medusa (Eni's interest 25%), Lucius (Eni's interest 8.5%), K2 (Eni's interest 13.4%), Frontrunner (Eni's interest 37.5%) and Heidelberg (Eni's interest 12.5%) fields.

In 2017, the FID of the Lucius Subsequent Development project was sanctioned. The development activities provide for the drilling and completion of three subsea production wells and linkage to the existing facilities in the area. Start-up is expected in 2019 with a production plateau of 2 kboe/d net to Eni.

Texas

Production Production comes from the Alliance area (Eni's interest 27.5%), in the Fort Worth Basin. This asset includes unconventional gas reserves (shale gas). In 2017, Eni's production amounted to more than 4 kboe/d.

Alaska

Eni holds interests in 42 exploration and development blocks in Alaska, with interests ranging from 30% to 100%; Eni is the operator in 26 of these blocks.

Production The main fields are Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni's interest 30%) fields with a 2017 overall net production of approximately 20 kbbl/d.

Trinidad and Tobago

Eni has been present in Trinidad and Tobago since 1970. In 2017, Eni's production averaged 55 mmcf/d (equal to 10 kboe/d). Activity is concentrated offshore North of Trinidad over a developed acreage of 382 square kilometers (66 square kilometers net to Eni). Exploration and production activities in Trinidad and Tobago are regulated by PSAs.

Production Production is provided by the Chaconia, Ixora, Hibiscus, Ponsettia, Bougainvillea and Heliconia gas fields, located in the North Coast Marine Area 1 block (Eni's interest 17.3%). Production is supported by two fixed platforms linked to the Hibiscus processing facility. Natural gas is used to feed trains 2, 3 and 4 of the Atlantic LNG liquefaction plant on Trinidad's coast and it is sold under longterm contracts with prices mainly linked to the United States.

Venezuela

Eni has been present in Venezuela since 1998. In 2017, Eni's production averaged 61 kboe/d. Activity is concentrated in Gulf of Venezuela and Gulf of Paria offshore and onshore in the Orinoco Oil Belt, over a developed and undeveloped acreage of 2,804 square kilometers (1,066 square kilometers net to Eni).

Production Eni's production comes from the Perla gas field (Eni's interest 50%) in the Gulf of Venezuela, the oil field Junin 5 (Eni's interest 40%) located in the Orinoco Oil Belt and from the Corocoro field (Eni's interest 26%) in the Gulfo de Paria.

Exploration Eni is also participating with a 19.5% interest in Petrolera Güiria for oil exploration and with a 40% interest in Punta Pescador and Gulfo de Paria Ovest for gas exploration, both located offshore in the eastern Venezuela.

AUSTRALIA AND OCEANIA

Australia

Eni has been present in Australia since 2001. In 2017, Eni's production of oil and natural gas averaged 22 kboe/d. Activities are focused on conventional and deep offshore fields, over a developed and undeveloped acreage of 16,707 square kilometers (11,061 square kilometers net to Eni).

The main production blocks in which Eni holds interests are WA-33-L (Eni's interest 100%) and JPDA 03-13 (Eni's interest 10.99%). In the appraisal and development phase, Eni holds interests in NT/RL8 (Eni's interest 100%) and NT/RL7 (Eni's interest 65%). In addition, Eni holds interest in 6 exploration licenses, of which 1 in the JPDA. In 2017, Eni acquired a 32.5% interest of the Evans Shoal gas field in the NT/RL7 offshore license in the northern Australia, nearby the Darwin liquefaction gas plant. The mineral potential of discovery is estimated approximately 8 Tcf of gas in place. The agreement received all necessary approvals. Following this acquisition Eni retains the operatorship with a 65% interest.

Exploration and production activities in Australia are regulated by concession agreements, whereas in the cooperation zone between Timor Leste and Australia (Joint Petroleum Development Area - JPDA) they are regulated by PSAs.

Block WA-33-L

Production The Blacktip gas field started-up in 2009 and produced approximately 21 bcf/y in 2017 (approximately 11 kboe/d). The project is supported by a production platform and carried by a 108-kilometer long pipeline to an onshore treatment plant with a capacity of 42 bcf/y. Natural gas extracted from this field is sold under a 25-year contract to supply a power plant, signed with Australian society Power & Water Utility Co.

Block JPDA 03-13

Production The liquids and gas Bayu Undan field started-up in 2004 and produced 124 kboe/d (approximately 11 kboe/d net to Eni) in 2017. Liquid production is supported by three treatment platforms and an FSO unit. Production of natural gas is carried by a 500-kilometer long pipeline and is treated at the Darwin liquefaction plant which has a capacity of 3.6 mmtonnes/y of LNG (equivalent to approximately 177 bcf/y of feed gas). LNG is sold to Japanese power generation companies under long-term contracts.

Development Execution phase started-up of the Bayu Undan Phase 3b project which includes drilling and completion of three new wells aiming to increase the liquids production and to support GNL production.

Movements in net proved hydrocarbons reserves

		Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2017
Consolidated subsidiaries
Reserves at December 31, 2016	(mmboe)	354	426	1,139	1,293	1,317	1,221	491	227	145	6,613
of which: developed		287	374	605	352	809	966	175	205	111	3,884
undeveloped		67	52	534	941	508	255	316	22	34	2,729
Purchase of minerals in place						2					2
Revisions of previous estimates		117	59	86	198	56	(23)	(35)	8		466
Improved recovery			1	2	7			10			20
Extensions and discoveries			108		12	355		4	4		483
Production		(49)	(69)	(175)	(84)	(119)	(48)	(43)	(36)	(8)	(631)
Sales of minerals in place					(348)	(175)					(523)
Reserves at December 31, 2017		422	525	1,052	1,078	1,436	1,150	427	203	137	6,430
Equity-accounted entities
Reserves at December 31, 2016				14		82		2	779		877
of which: developed				14		26		2	349		391
undeveloped						56			430		486
Purchase of minerals in place
Revisions of previous estimates				1					(286)		(285)
Improved recovery
Extensions and discoveries
Production				(1)		(7)		(1)	(23)		(32)
Sales of minerals in place
Reserves at December 31, 2017				14		75		1	470		560
Reserves at December 31, 2017		422	525	1,066	1,078	1,511	1,150	428	673	137	6,990
Developed		350	360	546	463	876	891	239	535	101	4,361
consolidated subsidiaries		350	360	532	463	856	891	238	176	101	3,967
equity-accounted entities				14		20		1	359		394
Undeveloped		72	165	520	615	635	259	189	138	36	2,629
consolidated subsidiaries		72	165	520	615	580	259	189	27	36	2,463
equity-accounted entities						55			111		166
Reserves life index	(year)	8.6	7.6	6.1	12.8	12.0	24.0	9.7	11.4	17.1	10.5
Reserves replacement ratio, organic	(%)	239	243	51	258	326	(48)	(48)	(464)		103
Reserves replacement ratio, all sources		239	243	51	(156)	189	(48)	(48)	(464)		25

Movements in net proved hydrocarbons reserves

		Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2016
Consolidated subsidiaries
Reserves at December 31, 2015	(mmboe)	465	495	1,194	500	1,282	1,198	422	269	150	5,975
of which: developed		362	404	630	380	764	689	159	217	115	3,720
undeveloped		103	91	564	120	518	509	263	52	35	2,255
Purchase of minerals in place
Revisions of previous estimates		(62)	1	110	(20)	157	63	111	1	4	365
Improved recovery			1	1							2
Extensions and discoveries			2	1	881			3			887
Production		(49)	(73)	(167)	(68)	(122)	(40)	(45)	(43)	(9)	(616)
Sales of minerals in place
Reserves at December 31, 2016		354	426	1,139	1,293	1,317	1,221	491	227	145	6,613
Equity-accounted entities
Reserves at December 31, 2015				14		87		4	810		915
of which: developed				14		22		2	265		303
undeveloped						65		2	545		612
Purchase of minerals in place
Revisions of previous estimates				1		(2)			(9)		(10)
Improved recovery
Extensions and discoveries
Production				(1)		(3)		(2)	(22)		(28)
Sales of minerals in place
Reserves at December 31, 2016				14		82		2	779		877
Reserves at December 31, 2016		354	426	1,153	1,293	1,399	1,221	493	1,006	145	7,490
Developed		287	374	619	352	835	966	177	554	111	4,275
consolidated subsidiaries		287	374	605	352	809	966	175	205	111	3,884
equity-accounted entities				14		26		2	349		391
Undeveloped		67	52	534	941	564	255	316	452	34	3,215
consolidated subsidiaries		67	52	534	941	508	255	316	22	34	2,729
equity-accounted entities						56			430		486
Reserves life index	(year)	7.2	5.8	6.9	19.0	11.2	30.5	10.5	15.5	16.1	11.6
Reserves replacement ratio, organic	(%)	(127)	5	67	1,266	124	158	243	(12)	44	193
Reserves replacement ratio, all sources		(127)	5	67	1,266	124	158	243	(12)	44	193

Movements in net proved hydrocarbons reserves

		Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2015
Consolidated subsidiaries
Reserves at December 31, 2014	(mmboe)	503	544	1,740	1,239	1,069	285	232	160	5,772
of which: developed		401	335	904	702	589	112	188	135	3,366
undeveloped		102	209	836	537	480	173	44	25	2,406
Purchase of minerals in place
Revisions of previous estimates		23	19	168	169	164	163	76	(1)	781
Improved recovery				2						2
Extensions and discoveries		1		24	14		21	6		66
Production		(62)	(68)	(240)	(124)	(35)	(47)	(44)	(9)	(629)
Sales of minerals in place					(16)			(1)		(17)
Reserves at December 31, 2015		465	495	1,694	1,282	1,198	422	269	150	5,975
Equity-accounted entities
Reserves at December 31, 2014				16	81		5	728		830
of which: developed				15	23		3	26		67
undeveloped				1	58		2	702		763
Purchase of minerals in place
Revisions of previous estimates					6		1	91		98
Improved recovery
Extensions and discoveries
Production				(2)			(2)	(9)		(13)
Sales of minerals in place
Reserves at December 31, 2015				14	87		4	810		915
Reserves at December 31, 2015		465	495	1,708	1,369	1,198	426	1,079	150	6,890
Developed		362	404	1,024	786	689	161	482	115	4,023
consolidated subsidiaries		362	404	1,010	764	689	159	217	115	3,720
equity-accounted entities				14	22		2	265		303
Undeveloped		103	91	684	583	509	265	597	35	2,867
consolidated subsidiaries		103	91	684	518	509	263	52	35	2,255
equity-accounted entities					65		2	545		612
Reserves life index	(year)	7.5	7.3	7.1	11.0	34.5	8.6	20.1	16.0	10.7
Reserves replacement ratio, organic	(%)	38	28	80	153	473	375	324		148
Reserves replacement ratio, all sources		38	28	80	139	473	375	322		145

Movements in net proved liquids reserves

(mmbbl)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2017
Consolidated subsidiaries
Reserves at December 31, 2016	176	264	454	281	809	767	307	163	9	3,230
of which: developed	132	228	287	205	507	556	124	143	8	2,190
undeveloped	44	36	167	76	302	211	183	20	1	1,040
Purchase of minerals in place					2					2
Revisions of previous estimates	59	29	73	21	31	29	(69)	19	(1)	191
Improved recovery		1	6	7			9			23
Extensions and discoveries		103	1		18		4	3		129
Production	(20)	(37)	(58)	(26)	(90)	(30)	(19)	(23)	(1)	(304)
Sales of minerals in place				(3)	(6)					(9)
Reserves at December 31, 2017	215	360	476	280	764	766	232	162	7	3,262
Equity-accounted entities
Reserves at December 31, 2016			13		15			140		168
of which: developed			13		8			22		43
undeveloped					7			118		125
Purchase of minerals in place
Revisions of previous estimates					(2)			1		(1)
Improved recovery
Extensions and discoveries
Production			(1)		(1)			(5)		(7)
Sales of minerals in place
Reserves at December 31, 2017			12		12			136		160
Reserves at December 31, 2017	215	360	488	280	776	766	232	298	7	3,422
Developed	169	219	318	203	552	547	81	169	5	2,263
consolidated subsidiaries	169	219	306	203	546	547	81	144	5	2,220
equity-accounted entities			12		6			25		43
Undeveloped	46	141	170	77	224	219	151	129	2	1,159
consolidated subsidiaries	46	141	170	77	218	219	151	18	2	1,042
equity-accounted entities					6			111		117

Movements in net proved liquids reserves

	(mmbbl)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2016
Consolidated subsidiaries
Reserves at December 31, 2015		228	305	494	327	787	771	262	189	9	3,372
of which: developed		171	237	312	230	511	355	126	149	9	2,100
undeveloped		57	68	182	97	276	416	136	40		1,272
Purchase of minerals in place
Revisions of previous estimates		(35)	(4)	19	(26)	113	20	73	(1)	1	160
Improved recovery			1	1							2
Extensions and discoveries			2	1	8						11
Production		(17)	(40)	(61)	(28)	(91)	(24)	(28)	(25)	(1)	(315)
Sales of minerals in place
Reserves at December 31, 2016		176	264	454	281	809	767	307	163	9	3,230
Equity-accounted entities
Reserves at December 31, 2015				13		16			158		187
of which: developed				13		6			29		48
undeveloped						10			129		139
Purchase of minerals in place
Revisions of previous estimates				1		(1)			(13)		(13)
Improved recovery
Extensions and discoveries
Production				(1)					(5)		(6)
Sales of minerals in place
Reserves at December 31, 2016				13		15			140		168
Reserves at December 31, 2016		176	264	467	281	824	767	307	303	9	3,398
Developed		132	228	300	205	515	556	124	165	8	2,233
consolidated subsidiaries		132	228	287	205	507	556	124	143	8	2,190
equity-accounted entities				13		8			22		43
Undeveloped		44	36	167	76	309	211	183	138	1	1,165
consolidated subsidiaries		44	36	167	76	302	211	183	20	1	1,040
equity-accounted entities						7			118		125

Movements in net proved liquids reserves

	(mmbbl)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2015
Consolidated subsidiaries
Reserves at December 31, 2014		243	331	776	739	697	131	147	13	3,077
of which: developed		184	174	521	470	306	64	116	12	1,847
undeveloped		59	157	255	269	391	67	31	1	1,230
Purchase of minerals in place
Revisions of previous estimates		10	5	139	143	94	159	64	(2)	612
Improved recovery				2						2
Extensions and discoveries				2	14			6		22
Production		(25)	(31)	(98)	(93)	(20)	(28)	(28)	(2)	(325)
Sales of minerals in place					(16)					(16)
Reserves at December 31, 2015		228	305	821	787	771	262	189	9	3,372
Equity-accounted entities
Reserves at December 31, 2014				14	17		1	117		149
of which: developed				13	7			26		46
undeveloped				1	10		1	91		103
Purchase of minerals in place
Revisions of previous estimates					(1)			45		44
Improved recovery
Extensions and discoveries
Production				(1)			(1)	(4)		(6)
Sales of minerals in place
Reserves at December 31, 2015				13	16			158		187
Reserves at December 31, 2015		228	305	834	803	771	262	347	9	3,559
Developed		171	237	555	517	355	126	178	9	2,148
consolidated subsidiaries		171	237	542	511	355	126	149	9	2,100
equity-accounted entities				13	6			29		48
Undeveloped		57	68	279	286	416	136	169		1,411
consolidated subsidiaries		57	68	279	276	416	136	40		1,272
equity-accounted entities					10			129		139

Movements in net proved natural gas reserves(a)

(bcf)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2017
Consolidated subsidiaries
Reserves at December 31, 2016	977	878	3,738	5,520	2,767	2,485	1,003	353	741	18,462
of which: developed	845	801	1,732	799	1,651	2,239	280	338	559	9,244
undeveloped	132	77	2,006	4,721	1,116	246	723	15	182	9,218
Purchase of minerals in place					1					1
Revisions of previous estimates	315	163	66	969	134	(281)	188	(61)	6	1,499
Improved recovery			(19)							(19)
Extensions and discoveries		29		64	1,839			4		1,936
Production	(161)	(174)	(640)	(315)	(162)	(96)	(126)	(71)	(38)	(1,783)
Sales of minerals in place				(1,887)	(919)					(2,806)
Reserves at December 31, 2017	1,131	896	3,145	4,351	3,660	2,108	1,065	225	709	17,290
Equity-accounted entities
Reserves at December 31, 2016			15		368		4	3,484		3,871
of which: developed			15		104		4	1,782		1,905
undeveloped					264			1,702		1,966
Purchase of minerals in place
Revisions of previous estimates					13			(1,565)		(1,552)
Improved recovery
Extensions and discoveries
Production			(1)		(32)		(4)	(100)		(137)
Sales of minerals in place
Reserves at December 31, 2017			14		349			1,819		2,182
Reserves at December 31, 2017	1,131	896	3,159	4,351	4,009	2,108	1,065	2,044	709	19,472
Developed	987	771	1,247	1,421	1,776	1,878	862	1,990	519	11,451
consolidated subsidiaries	987	771	1,233	1,421	1,693	1,878	862	171	519	9,535
equity-accounted entities			14		83			1,819		1,916
Undeveloped	144	125	1,912	2,930	2,233	230	203	54	190	8,021
consolidated subsidiaries	144	125	1,912	2,930	1,967	230	203	54	190	7,755
equity-accounted entities					266					266

(a) Values lower than 1 bcf are not disclosed in this table.

Movements in net proved natural gas reserves(a)

(bcf)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2016
Consolidated subsidiaries
Reserves at December 31, 2015	1,304	1,044	3,851	947	2,714	2,354	878	439	771	14,302
of which: developed	1,051	919	1,744	822	1,390	1,830	185	373	585	8,899
undeveloped	253	125	2,107	125	1,324	524	693	66	186	5,403
Purchase of minerals in place
Revisions of previous estimates	(155)	18	471	25	223	224	200	8	12	1,026
Improved recovery
Extensions and discoveries				4,767			15			4,782
Production	(172)	(184)	(584)	(219)	(170)	(93)	(90)	(94)	(42)	(1,648)
Sales of minerals in place
Reserves at December 31, 2016	977	878	3,738	5,520	2,767	2,485	1,003	353	741	18,462
Equity-accounted entities
Reserves at December 31, 2015			13		387		12	3,581		3,993
of which: developed			13		85		9	1,295		1,402
undeveloped					302		3	2,286		2,591
Purchase of minerals in place
Revisions of previous estimates			4		(8)		(1)	(4)		(9)
Improved recovery
Extensions and discoveries
Production			(2)		(11)		(7)	(93)		(113)
Sales of minerals in place
Reserves at December 31, 2016			15		368		4	3,484		3,871
Reserves at December 31, 2016	977	878	3,753	5,520	3,135	2,485	1,007	3,837	741	22,333
Developed	845	801	1,747	799	1,755	2,239	284	2,120	559	11,149
consolidated subsidiaries	845	801	1,732	799	1,651	2,239	280	338	559	9,244
equity-accounted entities			15		104		4	1,782		1,905
Undeveloped	132	77	2,006	4,721	1,380	246	723	1,717	182	11,184
consolidated subsidiaries	132	77	2,006	4,721	1,116	246	723	15	182	9,218
equity-accounted entities					264			1,702		1,966

(a) Values lower than 1 bcf are not disclosed in this table.

Movements in net proved natural gas reserves(a)

	(bcf)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2015
Consolidated subsidiaries
Reserves at December 31, 2014		1,432	1,171	5,291	2,744	2,049	846	468	807	14,808
of which: developed		1,192	887	2,110	1,271	1,553	261	393	675	8,342
undeveloped		240	284	3,181	1,473	496	585	75	132	6,466
Purchase of minerals in place
Revisions of previous estimates		68	74	163	145	385	24	69	5	933
Improved recovery
Extensions and discoveries		4		124			114			242
Production		(200)	(201)	(780)	(171)	(80)	(106)	(94)	(41)	(1,673)
Sales of minerals in place					(4)			(4)		(8)
Reserves at December 31, 2015		1,304	1,044	4,798	2,714	2,354	878	439	771	14,302
Equity-accounted entities
Reserves at December 31, 2014				15	351		18	3,353		3,737
of which: developed				15	89		10	6		120
undeveloped					262		8	3,347		3,617
Purchase of minerals in place
Revisions of previous estimates					36		3	253		292
Improved recovery
Extensions and discoveries
Production				(2)			(9)	(25)		(36)
Sales of minerals in place
Reserves at December 31, 2015				13	387		12	3,581		3,993
Reserves at December 31, 2015		1,304	1,044	4,811	3,101	2,354	890	4,020	771	18,295
Developed		1,051	919	2,579	1,475	1,830	194	1,668	585	10,301
consolidated subsidiaries		1,051	919	2,566	1,390	1,830	185	373	585	8,899
equity-accounted entities				13	85		9	1,295		1,402
Undeveloped		253	125	2,232	1,626	524	696	2,352	186	7,994
consolidated subsidiaries		253	125	2,232	1,324	524	693	66	186	5,403
equity-accounted entities					302		3	2,286		2,591

(a) Values lower than 1 bcf are not disclosed in this table.

Oil and natural gas production(a)(b)

	(kbbl/d) Liquids	Natural gas (mmcf/d)	Hydrocarbons (kboe/d)	(kbbl/d) Liquids	Natural gas (mmcf/d)	Hydrocarbons (kboe/d)	(kbbl/d) Liquids	Natural gas (mmcf/d)	Hydrocarbons (kboe/d)
Consolidated subsidiaries		2017			2016			2015
Italy	53	441.6	134	47	471.2	133	69	546.6	169
Rest of Europe	102	476.4	189	109	501.8	201	85	551.8	185
Croatia		16.9	3		26.5	5		21.2	4
Norway	81	265.4	129	86	258.3	133	57	264.6	105
United Kingdom	21	194.1	57	23	217.0	63	28	266.0	76
North Africa	158	1,753.0	479	165	1,594.8	458	172	1,627.9	469
Algeria	68	117.2	90	77	115.5	98	79	94.1	96
Libya	87	1,623.1	384	84	1,464.8	353	89	1,517.3	365
Tunisia	3	12.7	5	4	14.5	7	4	16.5	8
Egypt	72	862.7	230	76	597.4	185	96	510.1	189
Sub-Saharan Africa	247	444.3	327	247	464.3	333	256	468.3	341
Angola	119	45.9	126	108	49.0	118	96	31.6	101
Congo	63	112.6	83	71	148.5	98	78	136.8	103
Ghana	8	2.7	9
Nigeria	57	283.1	109	68	266.8	117	82	299.9	137
Kazakhstan	83	263.7	132	65	254.0	111	56	218.3	95
Rest of Asia	53	345.9	116	78	245.8	123	77	289.8	130
China	2	0.1	2	2		2	3		3
India								2.6	1
Indonesia	3	188.8	38	3	48.5	12	2	54.8	12
Iran							22		22
Iraq	40	19.6	43	64	19.2	67	40		40
Pakistan		131.5	24		172.1	32		226.4	41
Turkmenistan	8	5.9	9	9	6.0	10	10	6.0	11
Americas	63	194.0	99	69	256.4	116	75	257.1	122
Ecuador	12		12	10		10	11		11
Trinidad and Tobago		55.4	10		69.7	13		70.4	13
United States	51	138.6	77	59	186.7	93	64	186.7	98
Australia and Oceania	2	105.0	22	3	113.9	24	5	111.8	26
Australia	2	105.0	22	3	113.9	24	5	111.8	26
	833	4,886.6	1,728	859	4,499.6	1,684	891	4,581.7	1,726
Equity-accounted entities
Angola	3	89.0	20	1	29.1	6		0.9
Indonesia	1	11.0	3	1	18.8	4	1	24.1	5
Tunisia	3	4.1	4	3	4.9	4	4	5.2	4
Venezuela	12	270.5	61	14	254.8	61	12	68.9	25
	19	374.6	88	19	307.6	75	17	99.1	34
Total	852	5,261.2	1,816	878	4,807.2	1,759	908	4,680.8	1,760

(a) Includes Eni's share of equity-accounted equities. (b) Includes volumes of gas consumed in operations (527, 478 and 397 mmcf/d in 2017, 2016 and 2015, respectively).

Hydrocarbons production available for sale(a)

(kboe/d)	2017	2016	2015
Italy	127	127	161
Rest of Europe	183	195	179
North Africa	460	441	458
Egypt	216	170	177
Sub-Saharan Africa	322	316	324
Kazakhstan	126	107	92
Rest of Asia	107	118	128
Americas	157	174	144
Australia and Oceania	21	23	25
	1,719	1,671	1,688
of which Eni share of equity-accounted entities	83	71	33
North Africa	3	3	4
Sub-Saharan Africa	17	4
Rest of Asia	2	4	5
Americas	61	60	24

Natural gas production available for sale(a)

(mmcf/d)	2017	2016	2015
Italy	402	436	503
Rest of Europe	443	468	515
North Africa	1,634	1,489	1,548
Egypt	784	514	445
Sub-Saharan Africa	400	369	378
Kazakhstan	231	234	199
Rest of Asia	291	214	278
Americas	448	495	311
Australia and Oceania	101	110	107
	4,734	4,329	4,284
of which Eni share of equity-accounted entities	350	286	90
North Africa	2	3	3
Sub-Saharan Africa	72	16
Rest of Asia	9	15	19
Americas	267	252	68

Oil and natural gas production sold

	2017	2016	2015
Oil and natural gas production (mmboe)	662.7	643.8	642.4
Change in inventories other	(5.2)	(3.1)	(1.9)
Own consumption of gas	(35.2)	(32.1)	(26.4)
Oil and natural gas production sold(b)	622.3	608.6	614.1
Oil (mmbbl)	308.34	320.13	330.12
- of which to R&M	216.55	216.24	201.92
Natural gas (bcf)	1,713	1,574	1,560
- of which to G&P	344	347	394

(a) It excludes production volumes of natural gas consumed in operations.

(b) Includes 27,3 mmboe of equity-accounted entities production sold in 2017 (24 and 11,4 mmboe in 2016 and 2015, respectively).

Principal oil and natural gas interests at December 31, 2017

	Commencement of operations	Number of interests	developed(a)(b) acreage Gross	developed(a)(b) acreage Net	undeveloped(a) acreage Gross	undeveloped(a) acreage Net	fields/acreage Types of	producing fields Number of	other fields Number of
EUROPE		280	15,232	10,414	59,373	40,792		113	92
Italy	1926	144	10,011	8,351	10,321	8,029	Onshore/Offshore	75	59
Rest of Europe		136	5,221	2,063	49,052	32,763		38	33
Croatia	1996	2	1,975	987			Offshore	10	3
Cyprus	2013	6			23,858	17,967	Offshore
Greenland	2013	2			4,890	1,909	Offshore
Montenegro	2016	1			1,228	614	Offshore
Norway	1965	54	2,337	462	4,403	1,655	Offshore	18	28
Portugal	2014	3			4,547	3,182	Offshore
United Kingdom	1964	60	909	614	5,298	5,191	Offshore	10	2
Other countries		8			4,828	2,245	Onshore/Offshore
AFRICA		264	46,319	11,723	260,611	150,258		272	117
North Africa		65	8,735	3,626	38,707	22,171		70	26
Algeria	1981	42	3,172	1,110	187	31	Onshore	36	7
Libya	1959	11	1,963	958	24,673	12,336	Onshore/Offshore	12	15
Morocco	2016	2			13,847	9,804	Offshore
Tunisia	1961	10	3,600	1,558			Onshore/Offshore	22	4
Egypt	1954	54	5,692	2,131	19,683	7,061	Onshore/Offshore	39	22
Sub-Saharan Africa		145	31,892	5,966	202,221	121,026		163	69
Angola	1980	58	8,098	1,027	12,953	3,340	Onshore/Offshore	59	22
Congo	1968	25	1,430	843	1,320	628	Onshore/Offshore	23	2
Gabon	2008	4			5,283	5,283	Onshore/Offshore		1
Ghana	2009	3	226	100	1,127	479	Offshore	1
Ivory Coast	2015	3			4,010	2,905	Offshore
Kenya	2012	6			50,677	43,948	Offshore
Liberia	2012	1			2,341	585	Offshore
Mozambique	2007	6			3,911	978	Offshore		6
Nigeria	1962	34	22,138	3,996	8,631	3,374	Onshore/Offshore	80	38
South Africa	2014	1			65,505	26,202	Offshore
Other countries		4			46,463	33,304	Onshore
ASIA		60	14,560	5,058	286,866	178,971		27	16
Kazakhstan	1992	7	2,391	442	3,890	1,101	Onshore/Offshore	2	4
Rest of Asia		53	12,169	4,616	282,976	177,870		25	12
China	1984	8	77	13	7,141	7,141	Offshore	5
India	2005	1			13,110	5,244	Onshore/Offshore
Indonesia	2001	14	4,949	1,990	26,892	20,899	Onshore/Offshore	9	11
Iraq	2009	1	1,074	446			Onshore	1
Myanmar	2014	4			24,080	13,558	Onshore/Offshore
Oman	2017	1			90,760	77,146	Offshore
Pakistan	2000	13	5,869	1,987	11,486	5,414	Onshore/Offshore	8	1
Russia	2007	3			62,592	20,862	Offshore
Timor Leste	2006	1			1,538	1,230	Offshore
Turkmenistan	2008	1	200	180			Onshore	2
Vietnam	2013	5			30,777	23,132	Offshore
Other countries		1			14,600	3,244	Offshore
AMERICAS		139	4,854	3,134	9,626	3,507		52	14
Ecuador	1988	1	1,985	1,985			Onshore	1	2
Mexico	2015	6			1,657	1,146	Offshore		3
Trinidad and Tobago	1970	1	382	66			Offshore	7
United States	1968	117	1,226	586	879	466	Onshore/Offshore	41	7
Venezuela	1998	6	1,261	497	1,543	569	Onshore/Offshore	3	1
Other countries		8			5,547	1,326	Offshore		1
AUSTRALIA AND OCEANIA		13	1,140	709	15,567	10,352		2	4
Australia	2001	13	1,140	709	15,567	10,352	Offshore	2	4
Total		756	82,105	31,038	632,043	383,880		466	243

(a) Square kilometers.

(b) Developed acreage refers to those leases in which at least a portion of the area is in production or encompasses proved developed reserves.

Net developed and undeveloped acreage

(square kilometers)	2017	2016	2015
Europe	51,206	45,380	45,123
Italy	16,380	16,767	16,975
Rest of Europe	34,826	28,613	28,148
Africa	161,981	152,676	157,441
North Africa	25,797	18,727	16,031
Egypt	9,192	10,665	9,668
Sub-Saharan Africa	126,992	123,284	131,742
Asia	184,029	109,761	117,183
Kazakhstan	1,543	869	869
Rest of Asia	182,486	108,892	116,314
Americas	6,641	5,696	6,628
Australia and Oceania	11,061	10,383	16,333
Total	414,918	323,896	342,708

Average realizations

		2017		2016		2015
Liquids	(\$/bbl)	Consolidated subsidiaries	Equity accounted entities	Consolidated subsidiaries	Equity accounted entities	Consolidated subsidiaries	Equity accounted entities
Italy		46.51		33.19		43.46
Rest of Europe		47.81		39.97		45.88
North Africa		52.68	45.39	42.37	17.93	46.66	18.03
Egypt		46.06		33.05
Sub-Saharan Africa		53.66	38.34	41.92		49.91
Kazakhstan		50.62		39.61		48.26
Rest of Asia		48.94	44.43	36.89	34.95	40.10	27.89
Americas		44.24	41.49	34.86	32.39	43.36	38.18
Australia and Oceania		49.36		37.96		45.84
		50.33	38.65	39.33	30.85	46.46	35.15
Natural gas	(\$/kcf)
Italy		6.45		4.93		6.92
Rest of Europe		5.81		4.49		6.30
North Africa		2.96	2.63	3.10	1.85	4.69	3.78
Egypt		4.19		3.82
Sub-Saharan Africa		1.87	7.34	1.41		1.49
Kazakhstan		0.58		0.34		0.47
Rest of Asia		3.75	6.06	3.50	5.92	4.83	9.27
Americas		2.35	4.19	1.94	4.17	2.20	4.24
Australia and Oceania		4.05		3.60		5.07
		3.62	4.64	3.20	4.25	4.54	5.30
Hydrocarbons	(\$/boe)
Italy		39.96		29.27		40.36
Rest of Europe		40.51		33.27		40.21
North Africa		28.62	30.51	26.52	16.27	34.61	18.60
Egypt		30.64		26.29
Sub-Saharan Africa		44.85	39.65	35.08		40.92
Kazakhstan		34.60		24.52		30.02
Rest of Asia		36.69	36.76	31.18	32.76	35.18	49.42
Americas		33.31	26.50	25.45	24.95	31.71	30.72
Australia and Oceania		25.29		22.00		31.51
		35.39	28.30	29.30	25.05	36.54	31.95

Eni's Group		2017	2016	2015
Liquids	(\$/bbl)	50.06	39.18	46.30
Natural gas	(\$/kcf)	3.69	3.27	4.55
Hydrocarbon	(\$/boe)	35.06	29.14	36.47

Exploratory wells activity

	Wells completed(a)						Wells in progress at of Dec. 31(b)
	2017		2016		2015		2017
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Gross	Net
Italy				1.0			4.0	2.3
Rest of Europe	1.2	1.3	0.1	0.4		2.2	9.0	2.5
North Africa	0.5		0.5	1.0		1.0	7.0	6.5
Egypt	2.5	5.4	5.5	0.8	3.3	4.8	7.0	4.9
Sub-Saharan Africa	2.9	0.3	0.1	1.1	0.6	2.9	28.0	14.1
Kazakhstan							6.0	1.1
Rest of Asia				0.9		3.4	11.0	5.0
Americas	0.5			1.0	1.0	0.3	5.0	4.5
Australia and Oceania							1.0	0.3
	7.6	7.0	6.2	6.2	4.9	14.6	78.0	41.2

Development wells activity

	Wells completed(a)						Wells in progress at of Dec. 31
	2017		2016		2015		2017
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Gross	Net
Italy	2.6		4.0		6.0		1.0	1.0
Rest of Europe	2.7	0.2	5.6		10.2	0.1	5.0	0.8
North Africa	5.1		6.2	0.7	4.5		10.0	5.5
Egypt	49.7	2.3	32.4	0.5	26.0	2.8	10.0	5.4
Sub-Saharan Africa	8.6		21.2	0.2	22.0	2.5	21.0	9.6
Kazakhstan	1.2		4.6		4.7		2.0	0.6
Rest of Asia	15.0	0.2	31.6	0.5	29.7	5.9
Americas	3.1		9.9	1.3	17.4	0.1
Australia and Oceania					0.5
	88.0	2.7	115.5	3.2	121.0	11.4	49.0	22.9

Productive oil and gas wells(d)

		2017
	Oil wells		Natural gas wells
(units)	Gross	Net	Gross	Net
Italy	231.0	184.7	573.0	495.7
Rest of Europe	378.0	65.0	177.0	92.2
North Africa	687.0	284.5	90.0	48.9
Egypt	1,186.0	729.4	139.0	46.8
Sub-Saharan Africa	2,786.0	585.7	330.0	29.1
Kazakhstan	205.0	55.6
Rest of Asia	739.0	477.5	1,032.0	402.0
Americas	273.0	134.1	296.0	86.7
Australia and Oceania	7.0	3.8	18.0	3.8
	6,492.0	2,520.3	2,655.0	1,205.2

(a) Number of wells net to Eni.

• (b) Includes temporary suspended wells pending further evaluation.
• (c) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas sufficient quantities to justify completion as an oil or gas well. (d) Includes 1,960 (716.2 net) multiple completion wells (more than one producing into the same well bore). Productive wells are producing wells and wells capable of production. One or more completions in the same bore hole are counted as one well.

Fact Book

Results of operations from oil and gas producing activities(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2017
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	1,619	1,897	1,056		3,888	681	911	932	3	10,987
- sales to third parties		481	3,184	2,128	547	713	291	96	168	7,608
Total revenues	1,619	2,378	4,240	2,128	4,435	1,394	1,202	1,028	171	18,595
Operations costs	(337)	(687)	(504)	(314)	(986)	(396)	(206)	(312)	(48)	(3,790)
Production taxes	(130)		(200)		(331)		(11)		(5)	(677)
Exploration expenses	(26)	(122)	(22)	(191)	(60)		(61)	(39)	(4)	(525)
D.D. & A. and Provision for abandonment(b)	(465)	(838)	(679)	(767)	(2,063)	(289)	(765)	(577)	(59)	(6,502)
Other income (expenses)	1,563	(141)	(162)	690	(716)	(221)	(84)	(342)	2	589
Pretax income from producing activities	2,224	590	2,673	1,546	279	488	75	(242)	57	7,690
Income taxes	(299)	(216)	(1,978)	(214)	(38)	(223)	(67)	(38)	(23)	(3,096)
Results of operations from E&P activities of consolidated subsidiaries	1,925	374	695	1,332	241	265	8	(280)	34	4,594
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties			14		129		22	517		682
Total revenues			14		129		22	517		682
Operations costs			(8)		(37)		(9)	(40)		(94)
Production taxes			(2)		(8)			(146)		(156)
Exploration expenses		(1)					(13)			(14)
D.D. & A. and Provision for abandonment			(1)		(54)		(13)	(271)		(339)
Other income (expenses)		(2)	(2)		26		3	(199)		(174)
Pretax income from producing activities		(3)	1		56		(10)	(139)		(95)
Income taxes			(1)				(4)	(20)		(25)
Results of operations from E&P activities of equity-accounted entities		(3)			56		(14)	(159)		(120)

(a) Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expenses or general corporate overheads and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are calculated by applying the local income tax rates to the pre-tax income from production activities. Eni is party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni's share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state to meet Eni's PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni's share of oil and gas production. (b) Includes asset impairment reversals amounting to €158 million.

Results of operations from oil and gas producing activities

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2016
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	1,217	1,673	932	9	3,178	252	1,027	833	4	9,125
- sales to third parties		432	2,841	1,471	485	606	114	102	165	6,216
Total revenues	1,217	2,105	3,773	1,480	3,663	858	1,141	935	169	15,341
Operations costs	(311)	(599)	(451)	(356)	(968)	(269)	(215)	(325)	(49)	(3,543)
Production taxes	(96)		(176)		(282)		(17)		(5)	(576)
Exploration expenses	(35)	(40)	(45)	(42)	(142)		(39)	(28)	(3)	(374)
D.D. & A. and Provision for abandonment(a)	(923)	(943)	(675)	(691)	(1,093)	(129)	(952)	(480)	(67)	(5,953)
Other income (expenses)	(342)	(232)	(201)	(265)	(917)	(57)	(130)	(120)	(8)	(2,272)
Pretax income from producing activities	(490)	291	2,225	126	261	403	(212)	(18)	37	2,623
Income taxes	159	(1)	(1,618)	(89)	97	(139)	32	(9)	(9)	(1,577)
Results of operations from E&P activities of consolidated subsidiaries	(331)	290	607	37	358	264	(180)	(27)	28	1,046
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties			15				36	493		544
Total revenues			15				36	493		544
Operations costs			(9)				(10)	(54)		(73)
Production taxes			(3)					(121)		(124)
Exploration expenses							(13)			(13)
D.D. & A. and Provision for abandonment			(1)		(26)		(32)	(240)		(299)
Other income (expenses)		(3)	(1)		(26)		(16)	(25)		(71)
Pretax income from producing activities		(3)	1		(52)		(35)	53		(36)
Income taxes			(2)				(6)	(162)		(170)
Results of operations from E&P activities of equity-accounted entities		(3)	(1)		(52)		(41)	(109)		(206)

(a) Includes asset impairment reversals amounting to €700 million.

Results of operations from oil and gas producing activities

(€ million)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
	2,124	1,828	1,403	3,514	231	628	1,118	29	10,875
		501	5,681	914	659	854	131	226	8,966
	2,124	2,329	7,084	4,428	890	1,482	1,249	255	19,841
	(403)	(642)	(948)	(1,099)	(239)	(235)	(453)	(108)	(4,127)
	(184)		(240)	(405)		(30)		(9)	(868)
	(35)	(205)	(164)	(216)		(210)	(35)	(6)	(871)
	(750)	(2,022)	(2,938)	(3,835)	(109)	(1,491)	(1,775)	(111)	(13,031)
	(215)	(142)	(564)	(290)	(156)	(282)	(9)	(23)	(1,681)
	537	(682)	2,230	(1,417)	386	(766)	(1,023)	(2)	(737)
	(182)	589	(2,148)	272	(142)	90	406	(25)	(1,140)
	355	(93)	82	(1,145)	244	(676)	(617)	(27)	(1,877)
			19			68	248		335
			19			68	248		335
			(9)			(13)	(49)		(71)
			(3)				(82)		(85)
						(16)			(16)
		(1)	(3)	(432)		(77)	(78)		(591)
		(3)	(1)	(35)		(6)	(48)		(93)
		(4)	3	(467)		(44)	(9)		(521)
			(3)			8	(29)		(24)
		(4)		(467)		(36)	(38)		(545)

(a) Includes asset impairments amounting to €5.051 million.

Capitalized cost(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2017
Consolidated subsidiaries
Proved mineral interests	16,277	17,600	12,514	15,211	36,976	10,547	12,493	14,840	1,950	138,408
Unproved mineral interests	18	356	471	32	2,157	3	1,023	785	185	5,030
Support equipment and facilities	359	39	1,436	191	1,212	101	34	46	14	3,432
Incomplete wells and other	681	345	2,050	1,297	2,679	1,417	421	280	124	9,294
Gross Capitalized Costs	17,335	18,340	16,471	16,731	43,024	12,068	13,971	15,951	2,273	156,164
Accumulated depreciation, depletion and amortization Net Capitalized Costs	(13,504)	(12,014)	(10,640)	(10,413)	(25,920)	(1,690)	(10,386)	(12,534)	(1,188)	(98,289)
consolidated subsidiaries(b)	3,831	6,326	5,831	6,318	17,104	10,378	3,585	3,417	1,085	57,875
Equity-accounted entities
Proved mineral interests			67		1,419		581	1,833		3,900
Unproved mineral interests		4					85			89
Support equipment and facilities			7					6		13
Incomplete wells and other		1	6		4		93	225		329
Gross Capitalized Costs		5	80		1,423		759	2,064		4,331
Accumulated depreciation, depletion and amortization			(61)		(475)		(611)	(785)		(1,932)
Net Capitalized Costs equity-accounted entities(b)		5	19		948		148	1,279		2,399
2016
Consolidated subsidiaries
Proved mineral interests	15,951	18,678	13,492	15,262	38,539	10,790	11,680	17,127	2,085	143,604
Unproved mineral interests	18	301	416	55	2,461	1	1,155	903	210	5,520
Support equipment and facilities	357	42	1,627	203	1,375	111	37	77	15	3,844
Incomplete wells and other	724	242	2,347	1,828	5,117	2,565	2,248	317	134	15,522
Gross Capitalized Costs	17,050	19,263	17,882	17,348	47,492	13,467	15,120	18,424	2,444	168,490
Accumulated depreciation, depletion and amortization	(13,022)	(12,113)	(11,374)	(11,022)	(27,264)	(1,608)	(11,000)	(14,301)	(1,227)	(102,931)
Net Capitalized Costs consolidated subsidiaries(b)	4,028	7,150	6,508	6,326	20,228	11,859	4,120	4,123	1,217	65,559
Equity-accounted entities
Proved mineral interests		2	82		14		657	2,037		2,792
Unproved mineral interests		15					96			111
Support equipment and facilities			8					7		15
Incomplete wells and other		9	5		1,596		24	253		1,887
Gross Capitalized Costs		26	95		1,610		777	2,297		4,805
Accumulated depreciation, depletion and amortization		(20)	(72)		(482)		(682)	(602)		(1,858)
Net Capitalized Costs equity-accounted entities(b)		6	23		1,128		95	1,695		2,947

(a) Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization.

(b) The amounts include net capitalized financial charges totalling €969 million in 2017 and €1,090 million in 2016 for the consolidates subsidiaries and €78 million in 2017 and €95 million in 2016 for equity-accounted entities.

Fact Book

Cost incurred(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	Australia and Oceania	Total
2017
Consolidated subsidiaries
Proved property acquisitions					5					5
Unproved property acquisitions
Exploration	31	242	77	110	65	3	76	106	5	715
Development(b)	251	364	785	3,041	1,939	246	714	292	14	7,646
Total costs incurred
consolidated subsidiaries	282	606	862	3,151	2,009	249	790	398	19	8,366
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		1					90			91
Development(c)			2		9		4	48		63
Total costs incurred equity-accounted entities		1	2		9		94	48		154
2016
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions				2						2
Exploration	27	51	58	306	70		80	26	3	621
Development(b)	387	437	694	1,752	2,019	651	1,232	(5)	1	7,168
Total costs incurred consolidated subsidiaries	414	488	752	2,060	2,089	651	1,312	21	4	7,791
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		1					13			14
Development(c)			1		28		12	95		136
Total costs incurred equity-accounted entities		1	1		28		25	95		150
2015
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration	28	176	289		196		71	54	6	820
Development(b)	207	1,006	1,574		2,957	819	1,332	745	18	8,658
Total costs incurred consolidated subsidiaries	235	1,182	1,863		3,153	819	1,403	799	24	9,478
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		1					14	1		16
Development(c)		1	1		112		35	554		703
Total costs incurred
equity-accounted entities		2	1		112		49	555		719

(a) Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities.

(b) Includes the abandonment costs of the assets for €355 million in 2017, negative for €665 million in 2016 and negative for €817 million in 2015.

(c) Includes the abandonment costs of the assets negative for €23 million in 2017, negative for €15 million in 2016 and costs for €54 million in 2015.

Standardized measure of discounted future net cash flows(a)

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
December 31, 2017
Consolidated subsidiaries
Future cash inflows	14,339	19,507	31,793	29,156	41,136	30,263	11,826	6,205	2,593	186,818
Future production costs	(5,091)	(5,711)	(6,677)	(6,153)	(14,790)	(6,992)	(3,653)	(2,351)		(590) (52,008)
Future development and abandonment costs	(3,943)	(5,483)	(4,350)	(4,496)	(6,522)	(2,787)	(3,694)	(1,011)		(318) (32,604)
Future net inflow before income tax	5,305	8,313	20,766	18,507	19,824	20,484	4,479	2,843	1,685	102,206
Future income tax	(859)	(4,490)	(10,836)	(5,709)	(6,418)	(3,970)	(757)	(699)	(303)	(34,041)
Future net cash flows	4,446	3,823	9,930	12,798	13,406	16,514	3,722	2,144	1,382	68,165
10% discount factor	(1,633)	(1,050)	(4,566)	(6,698)	(5,430)	(9,172)	(1,239)	(777)	(607)	(31,172)
Standardized measure of discounted future net cash flows	2,813	2,773	5,364	6,100	7,976	7,342	2,483	1,367	775	36,993
Equity-accounted entities
Future cash inflows			245		2,062		11	10,797		13,115
Future production costs			(119)		(930)		(6)	(3,291)		(4,346)
Future development and abandonment costs			(1)		(66)			(535)		(602)
Future net inflow before income tax			125		1,066		5	6,971		8,167
Future income tax			(21)		(57)		(1)	(2,459)		(2,538)
Future net cash flows			104		1,009		4	4,512		5,629
10% discount factor			(50)		(471)			(2,475)		(2,996)
Standardized measure of discounted future net cash flows			54		538		4	2,037		2,633
Total	2,813	2,773	5,418	6,100	8,514	7,342	2,487	3,404	775	39,626

(a) Estimated future cash inflows represent the revenues that would be received from production and are determined by applying the year-end average prices during the years ended. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved reserves at the end of the year. Neither the effects of price and cost escalations nor expected future changes in technology and operating practices have been considered. The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a yearly 10% discount factor. Future production costs include the estimated expenditures related to the production of proved reserves plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantlement and abandonment of wells and facilities, under the assumption that year-end costs continue without considering future inflation. Future income taxes were calculated in accordance with the tax laws of the countries in which Eni operates. The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FASB Extractive Activities — Oil & Gas (Topic 932). The standardized measure does not purport to reflect realizable values or fair market value of Eni's proved reserves. An estimate of fair value would also take into account, among other things, hydrocarbon resources other than proved reserves, anticipated changes in future prices and costs and a discount factor representative of the risks inherent in the oil and gas exploration and production activity.

Standardized measure of discounted future net cash flows

(€ million)	Italy	Rest of Europe	North Africa	Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
December 31, 2016
Consolidated subsidiaries
Future cash inflows	9,627	12,898	30,847	33,524	38,271	26,903	12,263	5,789	2,815	172,937
Future production costs Future development	(4,136)	(5,240)	(7,481)	(7,927)	(13,913)	(9,247)	(3,498)	(2,935)	(658)	(55,035)
and abandonment costs	(3,641)	(3,575)	(5,904)	(6,981)	(9,392)	(3,268)	(5,047)	(1,313)	(270)	(39,391)
Future net inflow before income tax	1,850	4,083	17,462	18,616	14,966	14,388	3,718	1,541	1,887	78,511
Future income tax	(237)	(1,308)	(9,253)	(5,941)	(4,525)	(2,596)	(953)	(298)	(341)	(25,452)
Future net cash flows	1,613	2,775	8,209	12,675	10,441	11,792	2,765	1,243	1,546	53,059
10% discount factor	(241)	(365)	(4,060)	(8,055)	(4,594)	(6,536)	(1,266)	(501)	(724)	(26,342)
Standardized measure of discounted future net cash flows	1,372	2,410	4,149	4,620	5,847	5,256	1,499	742	822	26,717
Equity-accounted entities
Future cash inflows			259		2,429		33	16,430		19,151
Future production costs Future development			(143)		(974)		(20)	(4,614)		(5,751)
and abandonment costs			(1)		(64)			(1,186)		(1,251)
Future net inflow before income tax			115		1,391		13	10,630		12,149
Future income tax			(21)		(115)		(4)	(3,667)		(3,807)
Future net cash flows			94		1,276		9	6,963		8,342
10% discount factor			(46)		(734)			(4,441)		(5,221)
Standardized measure of discounted future net cash flows			48		542		9	2,522		3,121
Total	1,372	2,410	4,197	4,620	6,389	5,256	1,508	3,264	822	29,838

Standardized measure of discounted future net cash flows

(€ million)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
December 31, 2015
Consolidated subsidiaries
Future cash inflows	16,760	18,692	58,390	44,114	34,589	13,027	8,101	3,519	197,192
Future production costs	(4,995)	(5,554)	(13,481)	(14,645)	(8,846)	(4,585)	(3,091)	(804)	(56,001)
Future development and abandonment costs	(4,299)	(4,379)	(9,457)	(9,359)	(4,108)	(4,964)	(1,644)	(218)	(38,428)
Future net inflow before income tax	7,466	8,759	35,452	20,110	21,635	3,478	3,366	2,497	102,763
Future income tax	(1,657)	(4,349)	(17,195)	(8,222)	(4,682)	(1,230)	(933)	(604)	(38,872)
Future net cash flows	5,809	4,410	18,257	11,888	16,953	2,248	2,433	1,893	63,891
10% discount factor	(2,077)	(817)	(7,844)	(4,976)	(10,561)	(1,276)	(970)	(901)	(29,422)
Standardized measure of discounted future net cash flows	3,732	3,593	10,413	6,912	6,392	972	1,463	992	34,469
Equity-accounted entities
Future cash inflows			313	3,047		85	18,519		21,964
Future production costs			(177)	(1,021)		(32)	(5,370)		(6,600)
Future development and abandonment costs			(5)	(95)		(22)	(2,118)		(2,240)
Future net inflow before income tax			131	1,931		31	11,031		13,124
Future income tax			(8)	(251)		(10)	(4,088)		(4,357)
Future net cash flows			123	1,680		21	6,943		8,767
10% discount factor			(70)	(1,016)		(2)	(4,358)		(5,446)
Standardized measure of discounted future net cash flows			53	664		19	2,585		3,321
Total	3,732	3,593	10,466	7,576	6,392	991	4,048	992	37,790

Changes in standardized measure of discounted future net cash flows

2017	(€ million)	Consolidated subsidiaries	accounted entities Equity	Total
Standardized measure of discounted future net cash flows at December 31, 2016		26,717	3,121	29,838
Increase (Decrease):
- sales, net of production costs		(14,125)	(432)	(14,557)
- net changes in sales and transfer prices, net of production costs		23,940	1,482	25,422
- extensions, discoveries and improved recovery, net of future production and development costs		1,697		1,697
- changes in estimated future development and abandonment costs		(2,817)	495	(2,322)
- development costs incurred during the period that reduced future development costs		7,203	45	7,248
- revisions of quantity estimates		5,269	(2,285)	2,984
- accretion of discount		3,864	438	4,302
- net change in income taxes		(6,498)	238	(6,260)
- purchase of reserves in-place		10		10
- sale of reserves in-place		(2,995)		(2,995)
- changes in production rates (timing) and other		(5,272)	(469)	(5,741)
Net increase (decrease)		10,276	(488)	9,788
Standardized measure of discounted future net cash flows at December 31, 2017		36,993	2,633	39,626
2016
Standardized measure of discounted future net cash flows at December 31, 2015		34,469	3,321	37,790
Increase (Decrease):
- sales, net of production costs		(11,222)	(347)	(11,569)
- net changes in sales and transfer prices, net of production costs		(24,727)	(1,586)	(26,313)
- extensions, discoveries and improved recovery, net of future production and development costs		4,563		4,563
- changes in estimated future development and abandonment costs		(2,357)	650	(1,707)
- development costs incurred during the period that reduced future development costs		7,578	151	7,729
- revisions of quantity estimates		2,840	(131)	2,709
- accretion of discount		5,705	514	6,219
- net change in income taxes		9,200	386	9,586
- purchase of reserves in-place
- sale of reserves in-place
- changes in production rates (timing) and other		668	163	831
Net increase (decrease)		(7,752)	(200)	(7,952)
Standardized measure of discounted future net cash flows at December 31, 2016		26,717	3,121	29,838
2015
Standardized measure of discounted future net cash flows at December 31, 2014		56,035	3,558	59,593
Increase (Decrease):
- sales, net of production costs		(14,846)	(179)	(15,025)
- net changes in sales and transfer prices, net of production costs		(70,909)	(2,858)	(73,767)
- extensions, discoveries and improved recovery, net of future production and development costs		524		524
- changes in estimated future development and abandonment costs		(1,711)	(241)	(1,952)
- development costs incurred during the period that reduced future development costs		8,960	604	9,564
- revisions of quantity estimates		12,322	915	13,237
- accretion of discount		11,288	629	11,917
- net change in income taxes		29,530	530	30,060
- purchase of reserves in-place
- sale of reserves in-place		(114)		(114)
- changes in production rates (timing) and other		3,390	363	3,753
Net increase (decrease)		(21,566)	(237)	(21,803)
Standardized measure of discounted future net cash flows at December 31, 2015		34,469	3,321	37,790

Capital expenditure

(€ million)	2017	2016	2015
Acquisition of proved and unproved properties	5	2
Egypt		2
Sub-Saharan Africa	5
Exploration	442	417	566
Italy	5
Rest of Europe	186	11	133
North Africa	55	42	64
Egypt	70	270	168
Sub-Saharan Africa	25	30	157
Kazakhstan	3
Rest of Asia	20	57	15
Americas	76	7	29
Australia and Oceania	2
Development	7,236	7,770	9,341
Italy	260	407	679
Rest of Europe	399	590	1,264
North Africa	626	747	641
Egypt	3,030	1,700	929
Sub-Saharan Africa	1,852	2,176	2,998
Kazakhstan	197	707	835
Rest of Asia	666	1,213	1,333
Americas	195	220	637
Australia and Oceania	11	10	25
Other	56	65	73
	7,739	8,254	9,980

PERFORMANCE OF THE YEAR

• ● In 2017, the total recordable injury rate (TRIR) amounted to 0.37, representing an increase of 28% compared to a year earlier, due to the higher number of accident events (employees up by 61% and contractors down by 26%).
• ● In 2017 the greenhouse gas emissions (GHG) reported an increase of approximately 0.5%, due to higher power generation (up by 2.9%) and higher volumes of natural gas transported.
• ● GHG emissions/kWheq relating to electricity production decreased by 0.8% compared to a year earlier due to progress in energy savings actions.
• ● In 2017, the Gas & Power segment recorded a structurally positive result, a year ahead of schedule thanks to the

business restructuring. Adjusted operating profit amounted to €214 million, up by €604 million compared to 2016, the best performance of the last seven years.

• ● Eni worldwide gas sales amounted to 80.83 bcm, down by 5.5 bcm or 6.3% compared to 2016, in line with the reduction of take-or-pay obligations. Eni's sales in Italy (37.43 bcm) decreased by 2.6% compared to 2016.
• ● Electricity sales recorded a decrease of 4.6% (down by 1.72 TWh) compared to 2016, mainly due to lower volumes traded on the wholesale segment and middle market partially offset by the increased volumes marketed to large customers.
• ● Capital expenditure amounting to €142 million mainly concerned the gas marketing activities and flexibility and upgrading of combined cycle power stations.

WORLDWIDE GAS SALES

(bcm)

38.44

49.28

87.72 86.31

Sales in Italy International sales

2015

8,8 million customers including households, professionals, small and medium-sized enterprises and public bodies in Italy and in the Rest of Europe.

MARKETING

1. Natural gas

Supply

The supply of natural gas is a free activity where prices are determined by free negotiations of demand and supply involving natural gas

resellers and producers. In order to secure mid and long-term access to gas availability, Eni has signed a number of long-term gas supply contracts with key producing Countries that supply the European gas markets. In recent years Eni renegotiated a number of the main long-term supply contracts, thus better aligning gas prices and related trends to market conditions 90% of supply concracts. Eni could also leverage on the availability of natural gas deriving from equity production, the access to all phases of the LNG

2016 38.43

47.88

2017 37.43

43.40

80.83

chain (liquefaction, shipping and regasification) and to other gas infrastructures, and by trading and risk management activity. Eni's long-term gas requirements are met by long-term natural gas supply contracts or holds upstream activities and by access to continental Europe's spot markets.

In 2017, Eni's consolidated subsidiaries supplied 78.28 bcm of natural gas, down by 4.36 bcm or by 5.3% from 2016. Gas volumes supplied outside Italy from consolidated subsidiaries (73.23 bcm), imported in Italy or sold outside Italy, represented approximately 94% of total supplies, down by 3.41 bcm or by 4.4% from 2016. This reflected lower volumes purchased in the Netherlands (down by 4.40 bcm) following a contractual termination, in Qatar (down by 0.92 bcm) and in Norway (down by 0.70 bcm) partially offset by higher purchases in the United Kingdom (up by 0.28 bcm) and in Algeria (up by 0.28 bcm). Supplies in Italy (5.05 bcm) decreased by 15.8% from 2016 due to lower supplied gas volumes from equity production.

GAS & POWER VALUE CHAIN

Eni's Gas & Power segment engages in all phases of the natural gas value chain: supply, trading and marketing of natural gas and and LNG. This segment also includes power generation and marketing of electricity. Eni's leading position in the European gas market is ensured by a set of competitive advantages, including our multi-Country approach, long-term gas availability, access to infrastructures, market knowledge and a strong customer base, in addition to long-term relations with producing Countries. Furthermore, integration with our upstream operations provides valuable growth options whereby the Company targets to monetize its large gas reserves.

Marketing in Italy and Europe

Eni operates in a liberalized market where energy customers are allowed to choose the gas supplier and, according to their specific needs, to evaluate the quality of services and offers. Overall Eni supplies approximately 8.8 million clients in Italy and Europe. Households, professionals, small and medium-sized enterprises and public bodies located all over Italy are approximately 7.7 million.

In a trading environment characterized by a slight recover in demand in 2017 (up by 6% in the Italian market compared to the previous year and up by 4% in the European Union), and a market still depressed and characterized by a raised competitive pressure, Eni carried out a number of initiatives − such as renegotiation of supply contracts, efficiency and optimization actions − in order to preserve the business profitability.

Sales and market shares on the Italian gas market

(bcm)	2017		2016
	Volumes sold	Market share (%)	Volumes sold	Market share (%)	% Ch. 2017 vs. 2016
Italy to third parties	31.25	41.6	32.33	45.6	(3.3)
Wholesalers	8.36		7.93		5.4
Italian gas exchange and spot markets	10.81		12.98		(16.7)
Industries	4.42		4.54		(2.6)
Medium-sized enterprises and services	0.93		1.72		(45.9)
Power generation	2.22		0.77
Residential	4.51		4.39		2.7
Own consumption	6.18		6.10		1.3
TOTAL SALES IN ITALY	37.43	49.8	38.43	54.2
Gas demand(a)	75.15		70.91		6.0

(a) Source: Italian Ministry of Economic Development.

Gas sales by market

(bcm)	2017	2016	2015
ITALY	37.43	38.43	38.44
Wholesalers	8.36	7.93	4.19
Italian gas exchange and spot markets	10.81	12.98	16.35
Industries	4.42	4.54	4.66
Medium-sized enterprises and services	0.93	1.72	1.58
Power generation	2.22	0.77	0.88
Residential	4.51	4.39	4.90
Own consumption	6.18	6.10	5.88
INTERNATIONAL SALES	43.40	47.88	49.28
Rest of Europe	38.23	42.43	42.89
Importers in Italy	3.89	4.37	4.61
European markets	34.34	38.06	38.28
Iberian Peninsula	5.06	5.28	5.40
Germany/Austria	6.95	7.81	5.82
Benelux	5.06	7.03	7.94
Hungary		0.93	1.58
UK/Northern Europe	2.21	2.01	1.96
Turkey	8.03	6.55	7.76
France	6.38	7.42	7.11
Other	0.65	1.03	0.71
Extra European markets	5.17	5.45	6.39
WORLDWIDE GAS SALES	80.83	86.31	87.72

A review of Eni's presence in key European markets is presented below:

Benelux

In line with the rationalization of gas retail business portfolio, Eni completed the disposal of the Gas & Power retail activities in Belgium to Eneco relating to approximately 850,000 electricity and gas connection points, representing a market share of around 10%. In 2017, sales in Benelux were mainly directed to industrial companies, power generation and wholesalers and amounted to 5.06 bcm, down by 1.97 bcm, or 28% compared to 2016, due to lower spot sales.

France

Eni sells natural gas to industrial clients, wholesalers and power generation, as well as to the segments of retail and middle market. Eni is present in the French market through its direct commercial activities and through its subsidiary Eni Gas & Power France SA. In 2017, sales in the Country amounted to 6.38 bcm, a decrease of 1.04 bcm, or 14%, from a year ago.

Eni operates in Germany through Gas & Power branches. In 2017, total sales in Germany-Austria amounted to 6.95 bcm, a decrease of 0.86 bcm, or 11% from 2016.

Spain

Eni operates in the Spanish gas market through Unión Fenosa Gas (UFG) joint venture (Eni's interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2017, UFG gas sales amounted to 3.92 bcm (Eni's share 1.96 bcm). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast, and a 7.36% interest in a liquefaction plant in Oman. In 2017, total sales in the Iberian Peninsula amounted to 5.06 bcm, a decrease of 0.22 bcm, or down by 4.2%.

Turkey

Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2017, sales amounted to 8.03 bcm, an increase of 1.48 bcm, or 22.6% from a year ago driven by higher sales to Botas.

United Kingdom

Eni, through its subsidiary ETS, markets in the United Kingdom the equity gas produced at Eni's fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF). In 2017, sales amounted to 2.21 bcm, an increase of 10% from a year ago.

2. LNG

Eni is present in all phases of the LNG business: liquefaction, gas feeding, shipping, regasification and sale through a direct presence and interests in joint ventures and associates.

The LNG business registered a good profitability, leveraging on the growing energy demand in Asia. In the next years Eni intends to increase sales in premium markets, redirecting the availability through portfolio optimization and a higher integration with the upstream segment. In 2017, LNG sales (14.2 bcm) increased from 2016 (up by 1.8 bcm), driven by higher volumes marketed in the E&P's terminals located in Angola and Indonesia following production ramp-ups and start-ups. This positive result confirmed production success of the Eni's business model founded on the integrated development of upstream and mid-downstream projects. In particular, LNG sales of the Gas & Power segment (8.3 bcm, included in worldwide gas sales) mainly concerned LNG from Qatar, Nigeria, Oman, Indonesia and Algeria and were mainly marketed in Europe, the Far East, Kuwait, India and Egypt.

3. Power generation

Eni's power generation sites are located in Ferrera Erbognone, Ravenna, Mantova, Brindisi, Ferrara and Bolgiano. As of December 31, 2017, installed operational capacity of Enipower's power plants was 4.7 GW (unchanged from December 31, 2016).

ENI PLANTS AND SITES IN ITALY Germany/Austria

Installed and operational generation capacity as of December 31, 2017; 4,662 MW.

The combined cycle gas red technology (CCGT) ensures an high level of eciency and low environmental impact. In particular, management estimates that for a given amount of energy (electricity and steam) produced, using the CCGT technology instead of conventional power generation technology, the emission of carbon dioxide is reduced by about 5 mmtonnes, on an energy production of 24.1 TWh. Eni owns photovoltaic plants in the Italian territory with an installed capacity of 10 MW.

In 2017, power generation was 22.42 TWh, up by 0.64 TWh, or 2.9%, from 2016. Electricity trading (12.91 TWh) reported a decrease of 15.5% thanks to the optimization of inflows and outflows of power.

In 2017, power sales of 35.33 TWh declined by 4.6% from the full year of 2016 and were directed to the free market (75%), the Italian power exchange (15%), industrial sites (8%) and other (2%). Compared to 2016, power sales marketed in the free market decreased by 0.96 TWh or by 3.5%, due to lower volumes sold to middle market (down by 2.69 TWh), wholesalers (down by 2.35 TWh), residential segment (down by 0.92 TWh) and small and medium-sized enterprises (down by 0.46 TWh) partially offset by higher volumes sold to large customers (up by 5.46 TWh).

INTERNATIONAL TRANSPORT

Eni, as shipper, has transport rights on a large European and North African networks for transporting natural gas in Italy and Europe, which link key consumption basins with the main producing areas (Russia, Algeria, the North Sea, including the Netherlands, Norway, and Libya). The Company participates to both entities which operate the pipelines and entities which manage transport rights. A description of the main international pipelines currently participated or operated by Eni is provided below:

Fact Book

2017

• the TTPC pipeline, 740-kilometer long, is made up of two lines that are each 370-kilometer long with a transport capacity of 34.3 bcm/y and five compression stations. This pipeline transports natural gas from Algeria across Tunisia from Oued Saf Saf at the Algerian border to Cap Bon on the Sicily Channel where it links with the TMPC pipeline;
• the TMPC pipeline for the import of Algerian gas is 775-kilometer long and consists of five lines that are each 155-kilometer long with a transport capacity of 33.5 bcm/y. It crosses the Sicily Channel from Cap Bon to Mazara del Vallo in Sicily, the point of entry into the Italian natural gas transport system;
• the Green Stream pipeline for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is 520-kilometer long with a transport capacity of 8 bcm/y crossing the Mediterranean Sea from Mellitah on the Libyan coast to Gela in Sicily, the point of entry into the Italian natural gas transport system;
• Eni holds a 50% interest in the Blue Stream underwater pipeline (with a record water depth of more than 2,150 meters) linking the Russian coast to the Turkish coast of the Black Sea. This pipeline is 774-kilometer long on two lines and has transport capacity of 16 bcm/y. It is part of a joint venture to sell gas produced in Russia on the Turkish market. These assets generate a steady operating profit thanks to the sale of transport rights on a long-term basis.

MAIN GAS TRANSPORT INFRASTRUCTURE IN EUROPE( *)

Supply of natural gas

(bcm)	2017	2016	2015
Italy	5.05	6.00	6.73
Outside Italy
Russia	28.09	27.99	30.33
Algeria (including LNG)	13.18	12.90	6.05
Libya	4.76	4.87	7.25
Netherlands	5.20	9.60	11.73
Norway	7.48	8.18	8.40
United Kingdom	2.36	2.08	2.35
Hungary	0.04	0.02	0.21
Qatar (LNG)	2.36	3.28	3.11
Other supplies of natural gas	6.71	5.81	7.21
Other supplies of LNG	3.05	1.91	2.02
	73.23	76.64	78.66
Total supplies of Eni's own companies	78.28	82.64	85.39
Offtake from (input to) storage	0.31	1.40
Network losses, measurement differences and other changes	(0.45)	(0.21)	(0.34)
AVAILABLE FOR SALE BY ENI'S CONSOLIDATED SUBSIDIARIES	78.14	83.83	85.05
AVAILABLE FOR SALE OF ENI'S AFFILIATES	2.69	2.48	2.67
GAS VOLUMES AVAILABLE FOR SALE	80.83	86.31	87.72

Gas sales by entity

(bcm)	2017	2016	2015
Sales of consolidated companies	77.52	83.34	84.94
Italy (including own consumption)	37.43	38.43	38.44
Rest of Europe	36.10	40.52	41.14
Outside Europe	3.99	4.39	5.36
Sales of Eni's affiliates (net to Eni)	3.31	2.97	2.78
Rest of Europe	2.13	1.91	1.75
Outside Europe	1.18	1.06	1.03
Worldwide gas sales	80.83	86.31	87.72

LNG sales

(bcm)	2017	2016	2015
G&P sales	8.3	8.1	9.0
Rest of Europe	5.2	5.2	4.8
Extra European markets	3.1	2.9	4.2
E&P sales	5.9	4.3	4.5
Liquefaction plants:
Soyo (Angola)	0.7	0.1
Bontang (Indonesia)	1.3	0.4	0.5
PointFortin (Trinidad and Tobago)	0.6	0.7	0.7
Bonny (Nigeria)	2.9	2.6	2.8
Darwin (Australia)	0.4	0.5	0.5
Total LNG sales	14.2	12.4	13.5

Electricity sales

(TWh)	2017	2016	2015
Free market	26.53	27.49	25.90
Italian Exchange for electricity	5.21	5.64	5.09
Industrial plants	3.01	3.11	3.23
Other (a)	0.58	0.81	0.66
Power sales	35.33	37.05	34.88
Power generation	22.42	21.78	20.69
Trading of electricity(a)	12.91	15.27	14.19

(a) Include positive and negative network imbalances (difference between electricity placed on the market vs. planned quantities).

2017

EniPower power stations

	Installed capacity as of December 31, 2017(a)
	(MW)	Effective/Planned	Technology	Fuel
Brindisi	1,321	2006	CCGT	Gas
Ferrera Erbognone	1,030	2004	CCGT	Gas/syngas
Mantova	836	2005	CCGT	Gas
Ravenna	972	2004	CCGT	Gas
Ferrara(b)	429	2008	CCGT	Gas
Bolgiano	64	2012	Power Station	Gas
Photovoltaic sites	10	2011-2014	Photovoltaic	Photovoltaic
	4,662

(a) Capacity available after completion of dismantling of obsolete plants.

(b) Eni's share of capacity.

Power generation

	2017	2016	2015
Purchases
Purchases of natural gas (mmcm)	4,359	4,334	4,270
Purchases of other fuels (ktoe)	392	360	313
Production
Power generation (TWh)	22.42	21.78	20.69
Steam (ktonnes)	7,551	7,974	9,318
Installed generation capacity (GW)	4,7	4,7	4,9

Transport infrastructure

OUTSIDE ITALY	Lines (units)	Lenght (km)	Diameter (inch)	Transport capacity(a) (bcm/y)	Transit capacity(b) (bcm/y)	Compression stations (No.)
TTPC (Oued Saf Saf-Cap Bon)	2 lines of 370 km	740	48	34.3	33.2	5
TMPC (Cap Bon-Mazara del Vallo)	5 lines of 155 km	775	20/26	33.5	33.5
GreenStream (Mellitah-Gela)	1 line of 520 km	520	32	8.0	8.0	1
Blue Stream (Beregovaya-Samsun)	2 lines of 387 km	774	24	16.0	16.0	1

(a) Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.

(b) The maximum volume of natural gas which is input at various entry points along the pipeline and transported to the next pipeline.

Capital expenditure

	(€ million)	2017	2016	2015
Italy		99	73	100
Outside Italy		43	47	54
		142	120	154
Market		138	110	138
Market		102	69	69
Italy		63	32	31
Outside Italy		39	37	38
Power generation		36	41	69
International transport		4	10	16
		142	120	154

REFINING & MARKETING AND CHEMICALS

PERFORMANCE OF THE YEAR

• ● In 2017 the total recordable injury rate (TRIR) increased by 63.2% compared to 2016.
• ● Greenhouse gas emissions reported a decrease of 8% in absolute terms. Energy efficiency projects and reduced methane emissions contributed to a 7.2% decrease GHG emissions related to refining throughputs.
• ● In 2017 the Refining & Marketing and Chemicals segment reported an adjusted operating profit of €991 million, up by €408 million, or 70% from 2016. The Refining & Marketing business reported an adjusted operating profit of €531 million (up by 91%), the best full year result in the last eight years. This result benefitted from the initiatives implemented over the last years, which were designed to improve the set-up of Eni's refining system allowing to reduce the break-even margin below the 4 \$/barrel threshold. The marketing business reported a positive performance driven by the effective commercial initiatives, which supported the premium segments. The Chemical business reported an adjusted operating profit of €460 million (up by 51%) from the €305 million reported in 2016. This result represents the best performance reported in the recent history of Eni's Chemical business and demonstrates the value of the progress in the turnaround process.
• ● In 2017 Eni's refining throughputs amounted to 24.02 mmtonnes, lower y-o-y (down by 2%) due to the downtime of some plants at the Sannazzaro refinery and the shutdown at the Taranto refinery, partly offset by a better performance of Milazzo and Livorno refineries.
• ● In 2017 the production of biofuels from vegetable oil at the Venice green refinery amounted to 0.24 mmtonnes, up by 14.3% compared 2016.
• ● Retail sales in Italy were 6.01 mmtonnes, up by about 8 ktonnes from 2016, or 1.3%.
• ● Retail sales in the rest of Europe (2.53 mmtonnes) were down by 4.9% compared to the previous year, mainly due to the assets disposal in Hungary and Slovenia finalized in the second half 2016. On a homogeneous basis, when excluding the impact of the above mentioned disposal, sales slightly increased by 1.1% due to higher volumes traded in Austria and Germany.
• ● Sales of petrochemical products in Europe amounted to 3.71 mmtonnes, recording a slight reduction of 1.3% y-o-y, due to

a weak growth in consumptions. Higher polymer sales were partially offset by lower sale volumes in the other businesses.

• ● Capital expenditure of €729 million mainly related to: (i) refining activities in Italy and outside Italy (€395 million), in particular the reconstruction of the EST conversion plant at the Sannazzaro refinery, plants' integrity, reconversion of the refinery system, as well as initiatives in the field of health, security and environment; (ii) marketing activity (€131 million), mainly regulation compliance and stay in business initiatives in the refined product retail network in Italy and in the Rest of Europe.
• ● Research and Development (R&D) expenditure in the Refining & Marketing and Chemicals segment amounted to approximately €58 million. During the year, 15 patent applications were filed.

LICENSING EST TECHNOLOGY

Enhanced the refining know-how through two licensing agreements with the Chinese companies Sinopec and Zhejiang Petrochemicals for the use of the Eni Slurry Technology (EST) conversion proprietary technology. Eni provides Sinopec with the basic engineering project related to the construction of refining plant based on the EST, able to convert refining residues entirely into high-quality light products, eliminating both liquid and solid refining residues with significant environmental benefits. The agreement signed in March 2018 with Zhejiang Petrochemicals provides for the construction of two production lines based on EST technology with a refining capacity of 3 mmtonnes per year each and will be part of a project for the construction of a new refinery with a capacity of 40 million of tonnes per year. Start-up is planned for 2020. The full agreement includes the license to use the EST technology, Process Design Package, training, technical services, Proprietary Equipment and the sale of the catalyst.

GELA GREEN REFINERY

The reconversion project at the Gela refinery is ongoing which the completion expected in 2018. This plant will produce green diesel also in compliance with the recently enacted regulatory constraints in terms of reduction of GHG emissions throughout the whole production chain. Furthermore, the whole capacity of the green refinery will be fully deployed in processing second-generation feedstock.

INTERNATIONAL DEVELOPMENT IN THE CHEMICAL BUSINESS

Signed a strategic partnership agreement between Versalis and Bridgestone to develop a technology platform to commercialize guayule in the agronomic, sustainable-rubber and renewablechemical sectors. The partnership combines Versalis' core strengths in guayule research, commercial-scale process engineering and market development for renewables with Bridgestone's leadership position in the cultivation and production technologies of guayule.

Started in November 2017, with a record time of 26 months, the plants for elastomers production of Lotte Versalis Elastomers (LVE), a 50:50 joint venture Versalis - Lotte Chemical. The industrial complex consists of three plants with a year total capacity of 200 ktonnes for the production of elastomers for tyre and other components in the automotive industries.

(mmtonnes) PRODUCTION CYCLE OF REFINED PRODUCTS IN 2017

REFINING & MARKETING

1. Refining

Eni is active in the refining segment in Italy and Germany. Furthermore, in Italy, Eni has converted the former Venice refinery into green refinery (the first case in the world of transformation in biorefinery) and also started the green reconversion project in the industrial site of Gela.

In 2017, Eni refinery capacity (balanced with conversion capacity) was approximately 27.4 mmtonnes (equal to 548 kbbl/d), with a conversion index of 54%.

Eni's 100% owned refineries have a balanced capacity of 19.4 mmtonnes (equal to 388 kbbl/d), with a 55% conversion index. In 2017, Eni's refineries throughputs in Italy and outside Italy were 24.02 mmtonnes down by 2% from 2016 or 0.5 mmtonnes due to the downtime of some plants at Sannazzaro refinery and the shutdown at the Taranto refinery, partly offset by a better performance of Milazzo and Livorno refineries.

Italy

Eni's refining system in Italy is composed by three wholly-owned refineries (Sannazzaro, Livorno and Taranto) and a 50% interest in the Milazzo refinery. Each of Eni's refineries in Italy has operating and strategic features that aim at maximizing the value associated to the asset structure, the geographic location with respect to end markets, the integration with Eni's other activities.

Refining system in 2017

	Ownership	Balanced refining capacity (Eni's share)	Utilization rate (Eni's share)	Conversion index(a)	Fluid catalytic cracking (FCC)(b)	Residue	conversion(b) Hydrocracking(b)	Visbreaking/ Thermal Cracking(b)
	(%)	(kbbl/d)	(%)	(%)	(kbbl/d)	(kbbl/d)	(kbbl/d)	(kbbl/d)
Wholly-owned refineries		388	83	55	34	40	71	29
Italy
Sannazzaro	100	200	83	73	34	14	51	29
Taranto	100	104	68	56		26	20
Livorno	100	84	99	11
Partially-owned refineries		160	104	52	143	25	75	27
Italy
Milazzo	50	100	109	60	45	25	32
Germany
Vohburg/Neustadt (Bayernoil)	20	41	93	36	49		43
Schwedt	8.33	19	102	42	49			27
TOTAL		548	89	54	177	65	146	56

(a) Conversion index: catalytic cracking equivalent capacity/topping capacity (% wt).

(b) Conversion unit capacities are 100%.

Sannazzaro: refinery has a balanced capacity of 200 kbbl/d and a conversion index of 73%. Located in the Po Valley, in the center of the North Italy, Sannazzaro is one of the most efficient refineries in Europe. The high flexibility and conversion capacity of this refinery allows it to process a wide range of feedstock. The main equipments in the refinery are: two primary distillation columns and two associated vacuum units, three desulphurization units, a fluid catalytic cracker (FCC), two hydrocrackers (HDC), two reforming units, a visbreaking thermal conversion unit integrated with a gasification producing a syngas used in a combined cycle power generation, and finally the Eni Slurry Technology (EST) plant, started up at the end of 2013. The EST plant exploits a proprietary technology to convert extra heavy crude residues (vacuum and visbreaking tar) into naphtha and middle distillates, with a conversion factor of 95%.

Taranto: refinery has a balanced capacity of 104 kbbl/d and a conversion index of 56%. Taranto has a strong market position due to the fact that is the only refinery in southern continental Italy, and is upstream integrated with the Val d'Agri fields in Basilicata (Eni 60.77%) through a pipeline. The main equipments are a topping-vacuum unit, an hydrocracking, a platforming and two desulphurization units.

Livorno: refinery, with a balanced refining capacity of 84 kbbl/d and a conversion index of 11%, is dedicated to the production of lubricants and specialties. The refinery is connected by pipeline to a depot in Florence (Calenzano). The refinery has a topping-vacuum unit, a platforming unit, two desulphurization units and a de-aromatization unit (DEA) – for the production of fuels; a propane de-asphalting (PDA), aromatics extraction and de-waxing units, for the production of base oils; a blending and filling plant – for the production of finished lubricants.

Milazzo: jointly-owned by Eni and Kuwait Petroleum Italy, the refinery has balanced primary refining capacity of 100 kbbl/d (Eni's share) and a conversion rate of 60%. Located on the Northern coast of Sicily, it is provided with two primary distillation columns and a vacuum unit, two desulphurization units, a fluid catalytic cracker (FCC), one hydrocracking unit for the conversion of middle distillates (HDC), one reforming unit and one unit devoted to the residue treatment process (LC-Finer).

Outside Italy

In Germany, Eni's share in the Schwedt refinery is 8.33% and 20% in Bayernoil, an integrated industrial hub that includes Vohburg and Neustadt refineries. Eni's refining capacity in Germany is approximately 60 kbbl/d mainly to supply Eni's distribution network in Bavaria and Eastern Germany.

2. Green Refining1

Green refineries

Ownership share	Capacity (2017)	Capacity (at regime)	Throughput (2017)
(%)	(Ktons/y)	(Ktons/y)	(Ktons/y)
100	360	560	242
100		750	-
	360	1,310	242

BIOPRODUCTS

Venice: green refinery entered into production in June 2014, with a production capacity of 360 ktonnes/y. The refinery exploits the proprietary EcofiningTM technology to transform vegetable oil in hydrogenated bio-fuels. A second phase of development is underway. At full capacity, the refinery production will satisfy approximately half of Eni bio-fuels needs required for being compliant with the EU environmental normative aimed at reducing CO2 emissions.

Gela: in November 2014, Eni defined with the Ministry for Economic Development, the Region of Sicily and interested stakeholders a plan to reconvert this plant in a biorefinery. The reconversion activities are ongoing and in line with the commitments signed with parties.

In August 2017 the project obtained the environmental impact assessment and authorization (VIA/AIA) by the Italian Ministry of the Environment and the Ministry of Cultural Heritage. The project is expected to come on stream by the end of 2018. The refinery will have a capacity of 750 ktonnes/y. The conversion will leverage on the application of the EcofiningTM proprietary technology, developed and licensed by Eni, to convert unconventional and second generation raw materials into green diesel, a highly sustainable biofuel. The plant properties will allow the production of green diesel in compliance with the last regulatory constraints in terms of reduction of GHG emissions throughout the whole production chain, deploying the full capacity in process second-generation feedstock.

ENI'S REFINING SYSTEM, LOGISTICS AND GREEN REFINERIES( *)

3. Logistics

Eni is a leading operator in the Italian oil and refined products storage and transportation business. It owns an integrated infrastructure consisting of 16 directly managed depots and a network of oil and refined products pipelines. Eni logistic model is organized in three hubs (Southern, Central and Northern Italy). These hubs manage the product flows in order to guarantee high safety and technical standards, as well as cost effectiveness. Eni is also in joint venture with six Italian operators (Sigemi, Petroven, Petra, Seram, Disma and Toscopetrol) to optimize its logistic footprint and increase efficiency. Eni transports oil and refined products: (i) by sea through spot and long-term contracts of tanker ships; and (ii) through a proprietary pipeline network

extending approximately 1,462 kilometers. Secondary distribution to retail and wholesale markets is outsourced to independent tanker carriers, selected as market leaders in their own field.

4. Oxygenates

Eni, through its subsidiary Ecofuel (100% Eni's share), sells approximately 1 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand, used as a gasoline octane booster), and methanol (mainly for petrochemical use). About 85% of oxygenates are produced in Eni's plants in Italy (Ravenna), in Saudi Arabia (in joint venture with Sabic) and Venezuela (in joint venture with Pequiven) and the remaining 15% is purchased.

MARKETING

1. Retail sales in Italy

Eni is a leader in the Italian retail market of refined products with a 25% market share, up by 0.7 percentage points from 2016. In 2017, retail sales in Italy were 6.01 mmtonnes with a slight increase compared to 2016 (about 80 ktonnes from 2016 or 1.3%). Average gasoline and gasoil throughputs (1,588 kliters) increased by approximately 40 kliters from 2016.

As of December 31, 2017, Eni's retail network in Italy consisted of 4,310 service stations, down by 86 units from December 31, 2016 (4,396 service stations), resulting from the release of low throughput stations (25 units) and negative balance of acquisitions/releases of lease concessions (56 units) and of motorway concessions (5 units).

2. Retail Rest of Europe

Retail sales in the Rest of Europe were approximately 2.53 mmtonnes, recorded a slight reduction from 2016 (down by 4.9%). This result reflected mainly the asset disposals in Hungary and Slovenia in the second half of 2016. On a homogeneous basis, when excluding the impact of the above mentioned disposal, sales slightly increased by 1.1% due to higher volumes traded in Austria and Germany. At December 31, 2017, Eni's retail network in the Rest of Europe consisted of 1,234 units, increasing by 8 units from December 31, 2016, mainly in Germany. Average throughput (2,440 kliters) increased by 100 kliters compared to 2016 (2,340 kliters).

No. of service stations: 478 unit Average throughput: 3.3 kliters/y Wholesale sales: 1,405 kton Retail sales: 1,267 kton Market share: 3.3%

No. of service stations: 319 unit Average throughput: 2.7 kliters/y Wholesale sales: 253 kton Retail sales: 691 kton Market share: 12.4%

No. of service stations: 280 unit Average throughput: 1.3 kliters/y Wholesale sales: 470 kton Retail sales: 276 kton Market share: 7.8%

3. Wholesale business

Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and fuel oil. Major customers are resellers, manufacturing industries, service companies, public utilities and transporters, as well as final users (transporters, condominiums, farmers, fishers, etc.). Eni provides its customers a wide range of products covering all market requirements leveraging on its expertise on fuels' manufacturing. Customer care and product distribution are supported by a widespread commercial and logistical

organization presence all over Italy and articulated in local marketing offices and a network of agents and dealers.

Wholesale sales in Italy amounted to 7.64 mmtonnes, decreased by 0.52 mmtonnes or 6.4% from the previous year, mainly due to lower volumes marketed of gasoil, bunkering and fuel oil partly offset by higher sales of jet fuel and bitumens.

Supplies of feedstock to the petrochemical industry (0.86 mmtonnes) decreased by 15.7%. Wholesale sales in the Rest of Europe were 3.03 mmtonnes, down by 4.7% from 2016 due to lower sold volumes in Austria and France and the above-mentioned asset disposals in the East Europe, offset by higher volumes in Switzerland and Germany.

Other sales in Italy and outside Italy (12.68 mmtonnes) decreased by approximately 0.65 mmtonnes or 5.4%, mainly due to lower sales volumes to oil companies.

The marketing of LPG in Italy is supported by the Eni's refining production logistic network made of five bottling plants, 1 owned storage site and three storage sites located in the coasts Livorno, Naples and Ravenna. LPG is used as heating and automotive fuel. In 2017, Eni share of LPG market in Italy was 17.7%. Outside Italy, the main market of Eni is Ecuador, with a market share of 37.9%. Eni operates six (owned and co-owned) blending and filling plants, in Italy, Spain, Germany, USA, Africa and in the Far East. With a wide range of products composed of over 650 different blends Eni masters international state of the art know-how for the formulation of products for vehicles (engine oil, special fluids and transmission oils) and industries (lubricants for hydraulic systems, industrial machinery and metal processing). In Italy, Eni is leader in the manufacture and sale of lubricant bases, manufactured at Eni's refinery in Livorno. Eni also owns one facility for the production of additives in Robassomero. In 2017, Eni's share of lubricants market in Italy was 19.58%, in Europe 3% and on a worldwide base 0.6%. Eni sales its products in more than 80 Countries by subsidiaries, licensees and distributors.

Supply of oil

(mmtonnes)	2017	2016	2015
Equity crude oil	3.51	3.43	5.04
Other crude oil	20.77	19.92	19.76
Total crude oil purchases	24.28	23.35	24.80
Purchases of intermediate products	0.96	1.35	1.66
Purchases of products	10.92	11.20	10.68
TOTAL PURCHASES	36.16	35.90	37.14
Consumption for power generation	(0.34)	(0.37)	(0.41)
Other changes(a)	(1.76)	(1.92)	(1.22)
	34.06	33.61	35.51

(a) Include changes in inventories, transport declines, consumption and losses.

Availability of refined products

(mmtonnes)	2017	2016	2015
ITALY
At wholly-owned refineries	16.03	17.37	18.37
Less input on account of third parties	(0.34)	(0.27)	(0.38)
At affiliate refineries	5.46	4.51	4.73
Refinery throughputs on own account	21.15	21.61	22.72
Consumption and losses	(1.36)	(1.53)	(1.52)
Products available for sale	19.79	20.08	21.20
Purchases of refined products and change in inventories	6.74	6.28	6.22
Products transferred to operations outside Italy	(0.46)	(0.39)	(0.48)
Consumption for power generation	(0.34)	(0.37)	(0.41)
Sales of products	25.73	25.60	26.53
GREEN REFINERY THROUGHPUTS	0.24	0.21	0.20
OUTSIDE ITALY
Refinery throughputs on own account	2.87	2.91	3.69
Consumption and losses	(0.22)	(0.22)	(0.23)
Products available for sale	2.65	2.69	3.46
Purchases of finished products and change in inventories	4.36	4.72	4.77
Products transferred from Italian operations	0.46	0.40	0.48
Sales of products	7.47	7.81	8.71
Refinery throughputs on own account	24.02	24.52	26.41
Total equity crude input	3.51	3.43	5.04
Total sales of refined products	33.20	33.41	35.24
Crude oil sales	0.86	0.20	0.27
TOTAL SALES	34.06	33.61	35.51

Production and sales

(mmtonnes)	2017	2016	2015
Products:
Gasoline	5.88	6.13	6.36
Gasoil	8.99	9.93	10.66
Jet fuel/kerosene	1.43	1.49	1.51
Fuel oil	2.60	2.43	2.46
LPG	0.46	0.39	0.44
Lubricants	0.56	0.44	0.54
Petrochemical feedstock	0.97	1.46	1.86
Other	1.56	0.49	0.84
Total products	22.44	22.77	24.67
Sales:
Italy	25.73	25.60	26.53
Gasoline	1.95	2.02	1.97
Gasoil	7.43	7.69	7.64
Jet fuel/kerosene	1.96	1.82	1.60
Fuel oil	0.08	0.13	0.12
LPG	0.59	0.58	0.58
Lubricants	0.08	0.08	0.08
Petrochemical feedstock	0.86	1.02	1.17
Other	12.78	12.26	13.37
Rest of Europe	7.03	7.38	8.29
Gasoline	1.21	1.27	1.51
Gasoil	3.29	3.44	3.98
Jet fuel/kerosene	0.50	0.62	0.65
Fuel oil	0.13	0.13	0.17
LPG	0.08	0.07	0.10
Lubricants	0.09	0.08	0.09
Other	1.73	1.77	1.79
Extra Europe	0.44	0.43	0.42
LPG	0.43	0.42	0.41
Lubricants	0.01	0.01	0.01
Worldwide
Gasoline	3.16	3.29	3.48
Gasoil	10.72	11.13	11.62
Jet fuel/kerosene	2.46	2.44	2.25
Fuel oil	0.21	0.26	0.29
LPG	1.10	1.07	1.09
Lubricants	0.18	0.17	0.18
Petrochemical feedstock	0.86	1.02	1.17
Other	14.51	14.03	15.16
Total sales	33.20	33.41	35.24

Sales in Italy and outside Italy by market

(mmtonnes)	2017	2016	2015
Retail	6.01	5.93	5.96
Wholesale	7.64	8.16	7.84
	13.65	14.09	13.80
Petrochemicals	0.86	1.02	1.17
Other markets	11.22	10.49	11.56
Sales in Italy	25.73	25.60	26.53
Retail rest of Europe	2.53	2.66	2.93
Wholesale rest of Europe	3.03	3.18	3.83
Wholesale outside Europe	0.45	0.43	0.43
	6.01	6.27	7.19
Other markets	1.46	1.54	1.52
Sales outside Italy	7.47	7.81	8.71
TOTAL SALES	33.20	33.41	35.24

Retail and wholesale sales of refined products

(mmtonnes)	2017	2016	2015
Italy	13.65	14.09	13.80
Retail sales	6.01	5.93	5.96
Gasoline	1.51	1.53	1.60
Gasoil	4.08	3.99	3.96
LPG	0.38	0.36	0.36
Other	0.04	0.04	0.04
Wholesale sales	7.64	8.16	7.84
Gasoil	3.36	3.70	3.69
Fuel oil	0.08	0.14	0.12
LPG	0.21	0.22	0.22
Gasoline	0.44	0.49	0.38
Lubricants	0.08	0.08	0.07
Bunker	0.85	1.01	1.07
Jet fuel	1.96	1.82	1.60
Other	0.66	0.70	0.69
Outside Italy (retail + wholesale)	6.01	6.27	7.19
Gasoline	1.21	1.27	1.51
Gasoil	3.29	3.44	3.98
Jet fuel	0.50	0.62	0.65
Fuel oil	0.13	0.13	0.17
Lubricants	0.10	0.10	0.10
LPG	0.51	0.49	0.51
Other	0.27	0.22	0.27
TOTAL	19.66	20.36	20.99

Number of service stations

(units)	2017	2016	2015
Italy	4,310	4,396	4,420
Ordinary stations	4,192	4,273	4,297
Highway stations	118	123	123
Outside Italy	1,234	1,226	1,426
Germany	478	472	472
France	157	156	154
Austria/Switzerland	599	598	604
Eastern Europe			196
Service stations selling Blu products	4,488	4,405	4,466
Service stations selling Green Diesel	4,471	4,388	4,437
"Multi-Energy" service stations	4	4	6
Service stations selling LPG and natural gas	1,050	1,073	1,176
Non-oil sales (€ million)	144	146	143

Average throughput
	(kliters/no. of service stations)	2017	2016	2015
Italy		1,588	1,551	1,569
Germany		3,336	3,325	3,351
France		2,302	2,360	2,244
Austria/Switzerland		2,009	1,939	1,923
Eastern Europe				1,802
Average throughput		1,783	1,742	1,754

Market shares in Italy

(%)	2017	2016	2015
Retail	25.0	24.3	24.5
Gasoline	21.2	20.7	21.1
Gasoil	27.0	26.4	26.5
LPG (automotive)	22.7	21.6	22.2
Lubricants	35.1	38.5	24.5
Wholesale	26.7	28.4	27.5
Gasoil	24.8	27.2	27.1
Fuel oil	13.4	21.5	11.1
Bunker	27.0	33.8	40.8
Lubricants	19.4	20.4	19.4
Domestic market share	26.0	26.6	26.2

Retail market shares outside Italy

(%)	2017	2016	2015
Central Europe
Austria	12.4	12.4	12.6
Switzerland	7.8	8.3	8.3
Germany	3.3	3.3	3.3
France	0.8	0.9	0.8
Eastern Europe
Hungary			12.1
Czech Republic			8.5
Slovakia			9.1
Slovenia			2.4

Capital expenditure

(€ million)	2017	2016	2015
Italy	463	363	349
Outside Italy	63	58	59
	526	421	408
Refining, supply and logistic	395	298	282
Italy	389	293	274
Outside Italy	6	5	8
Marketing	131	123	126
Italy	74	70	75
Outside Italy	57	53	51
	526	421	408

CHEMICALS

Eni through Versalis performs activities of production and marketing of petrochemical products basic petrochemicals and polymers), leveraging on a wide range of patents (250), 71 advanced production facilities, as well as a large and efficient retail network present in 25 European countries. Versalis' portfolio of patents and proprietary technologies covers the whole field of basic petrochemicals and polymers: phenol and its derivatives, polyethylene, styrenes and elastomers, as well as catalysts and special chemical products.

As a producer of intermediates, all types of polyethylene and a wide range of elastomers/latices and of the complete line of styrenic products, Versalis continues in the development of its proprietary technologies supported by the experience it gained in production and R&D. This approach favoured the optimization of the design of equipment and plants, of their performance, of proprietary catalysts and other products that allowed it to to speed up development and to achieve excellence in all technologies in the specific business areas in order to compete in markets worldwide. A key role is played by the most innovative proprietary catalysts, particularly those based on zeolites developed by Versalis as building blocks of some of its most advanced technologies and available worldwide.

THE MANUFACTURING CYCLE

The materials produced by Versalis are obtained following a manufacturing cycle which involves several processing stages. Virgin naphtha, a raw material which is a distillation product from petroleum, undergoes thermal cracking also known as steam-cracking. The component molecules split into simpler molecules: monomers (ethylene, propylene, butadiene, etc.) and into blends of aromatic compounds. The monomers are then reconstituted into more complex molecules: polymers. The following are produced from polymers: polyethylene, styrenes and elastomers used by processing companies to produce a whole variety of products for everyday use. The blends of aromatic compounds, properly treated, are used to produce intermediates, used in the manufacturing of products for everyday use.

The principal objective of basic petrochemicals is granting the adequate availability of monomers (ethylene, butadiene and benzene) covering the needs of further production processes: in particular olefins production is strictly linked with the polyethylene and elastomers business, aromatics grant the benzene availability necessary to produce intermediate products used in the production of resins, artificial fibres and polystyrene. In polymers business Versalis is one of the most relevant European producers of elastomers, where it is present in almost all the relevant sectors (in particular, in the automotive industry), polystyrene and polyethylene, whose most relevant use is in flexible packaging.

In the "green chemicals" Versalis' commitment began with Matrìca – a 50/50 joint venture with Novamont – an innovative platform that produces bio-intermediates for high-value-added applications from renewable resources. Matrìca has also launched a major reconversion of the Porto Torres plant. Versalis has signed agreements with companies in the fields of agro-technology and biotechnology: Genomatica to make bio-butadiene from renewable sources, Elevance Renewable Sciences to develop a technological platform for products based on vegetable oils. Furthermore, the company has started off a major project to make natural rubber from guayule. The recent agreement with Bridgestone, the leading global producer in the tyre industry, aims to develop a technology platform to commercialize guayule in the agricultural, sustainable-rubber and renewable-chemical sectors.

Fact Book

2017

^(*) Versalis International manages the activities of the European commercial branches (France, UK, Germany, Swiss, Austria, Hungary, Romania, Poland, Czech Rep., Slovakia, Russia, Denmark, Sweden, Spain, Greece), coordinates the companies in Turkey and in US, and delivers services to manufacturing companies in France, Germany, Hungary and UK.

1. Business areas

Petrochemical sales of 3,712 ktonnes slightly decreased from 2016 (down by 47 ktonnes, or 1.3%). The steepest declines were registered in olefins (down by 7.1%) and derivatives (down by 14.1%), partly offset by higher sales volumes of polyethylene (+10.8%). Average unit sales prices increased by 16% from 2016. The intermediates business up by 27%, in particular monomers prices, affected by the butadiene (up by 88.3%) and the polymers business up by 13%, reflecting styrene and elastomers prices increased (up by 14.8% and 24.1%, respectively). Petrochemical production of 5,818 ktonnes increased by 172 ktonnes

(up by 3%) mainly due to higher production of polyethylene (up by 14.6%) and elastomers businesses (up by 5.9%); the intermediates productions were slightly increased (+1.2%). The main increases in production were registered at the Ragusa site (up by 90%), due to a recovery of production capacity for a malfunctioning occurred at the plant in 2016, as well as Ravenna and Dunkerque (olefins), and Ferrara and Mantova sites (styrene) due to fewer production shutdowns of the plants. Decreasing productions at the Marghera, Mantova (derivatives) and Dunastyr sites due to planned shutdowns of the plants. Nominal capacity of plants is in line from the previous year. The average plant utilization rate calculated on nominal capacity was 72.8% increased from 2016 (71.4%).

Intermediates

Basic petrochemicals are one of the pillars of the activities of Versalis, whose products have a range of important industrial uses, such as the production of polyethylene, polypropylene, PVC and polystyrene. They are also used in the production of petrochemical

intermediates that converge, in turn, into a range of other productive processes: plastics, rubbers, fibres, solvents and lubricants. Intermediates revenues (€1,988 million) increased by €300 million from 2016 (up by 17.8%) reflecting the higher commodity prices scenario that influences average intermediates prices of the main product of the business unit. Sales decreased by 7.6%, in particular for ethylene business (down by 16%) and derivatives (down by 14.1%) driven by the planned shutdowns of Mantova plants. Average unit prices increased by 27.1%, in particular olefins (up by 25.8%), aromatics (up by 29.2%) and derivatives (up by 26.7%). Intermediates production (3,458 ktonnes) registered an increase of 1.2% from the last year. Increasing of olefins (up by 4.3%) and reduction of derivatives (down by 11.2%).

Polymers

In the polymers business Versalis is active in the production of:

• polyethylene, a basic plastic material, used as a raw material by companies that transform it into a wide range of goods, from basic product like film for packaging, phials, industrial containers to more sophisticated like automotive tanks, solar panels, medical prostheses;
• styrenics that are polymeric materials based on styrenes that are used in a very large number of sectors through a range of transformation technologies. The most common applications are for industrial packaging and in the food industry, small and large electrical appliances, building isolation, electrical and electronic devices, household appliances, car components and toys;
• elastomers that are polymers characterized by high elasticity that allow them to regain their original shape even after having

been subjected to extensive deformation. Versalis has a leading position in this sector and produces a wide range of products for the following sectors: tyres, footwear, adhesives, building components, pipes, electrical cables, car components and sealing, household appliances; they can be used as modifiers for plastics and bitumens, as additives for lubricating oils (solid elastomers); carpet backing, paper coating, moulded foams (synthetic latex). Versalis is one of the world's major producers of elastomers and synthetic latex.

Polymers revenues (€2,730 million) increased by €350 million or 14.7% from 2016 thanks to higher sales volumes (up by 6%), as well as to the increase of the average unit prices (up by 13%). The styrenics business benefited from the high commodities prices (styrene) with an increasing of average sold prices (up by 14.8%); slightly decrease of sold volumes (down by 2%).

Polyethylene volumes increased (up by 8.3%) and average prices recorded a decrease (down by 2.2%).

In the elastomers business, a recovery in sales was attributable to

commodities rubbers (BR up by 15.8%), special rubbers EPDM (up by 23.2%) and lattices (up by 0.8%); decreasing of thermoplastic rubbers (down by 14.5%) and SBR (down by 8.7%). Lower styrenics volumes sold (down by 2%) was mainly driven by lower sales of styrene (down by 18.4%) and compact polystyrene (down by 1.4%), partly offset by higher sales of ABS/SAN (up by 3.2%) and expandable polystyrene (up by 3.4%). Overall, the sold volumes of polyethylene business reported an increase (up by 10.8%) with higher sales of EVA, LDPE and HDPE (up by 17.7%, 31.6% and 7.8%, respectively).

Polymers productions increased by 5.9% (2.360 ktonnes) from 2016 mainly driven by higher production of polyethylene (up by 14.6%). Elastomers business productions increased (up by 5.9%), especially in BR rubbers (up by 12.4%) and EPDM (up by 25.1%). The styrenics business reported higher production of expandable polystyrene (up by 6%) and ABS/SAN (up by 17.9%), decreasing production of styrene (down by 5.9%) due to planned shutdowns of Mantova plant.

Product availability

(ktonnes)	2017	2016	2015
Intermediates	3,458	3,417	3,334
Polymers	2,360	2,229	2,366
Production	5,818	5,646	5,700
Consumption and losses	(2,584)	(2,166)	(1,908)
Purchases and change in inventories	478	279	9
Total availability	3,712	3,759	3,801
Intermediates	1,820	1,970	1,883
Polymers	1,892	1,789	1,918
Total sales	3,712	3,759	3,801

Revenues by geographic area

(€ million)	2017	2016	2015
Italy	2,201	1,930	2,154
Rest of Europe	2,145	2,107	2,326
Asia	352	99	162
Americas	93	53	61
Africa	57	7	13
Other areas	3
	4,851	4,196	4,716

Revenues by product

(€ million)	2017	2016	2015
Olefins	1,308	1,087	1,275
Aromatics	328	290	327
Intermediates	352	311	297
Elastomers	699	539	543
Styrenics	723	647	764
Polyetilene	1,308	1,194	1,383
Other	133	128	126
	4,851	4,196	4,716

Capital expenditure
(€ million)	2017	2016	2015
	203	243	220
of which:
- upkeeping	46	34	33
- plant upgrades	114	162	141
- HSE	34	37	36
- energy recovery	2	5	3

TABLES

FINANCIAL DATA

Profit and loss account

(€ million)	2017	2016	2015
Net sales from operations	66,919	55,762	72,286
Other income and revenues	4,058	931	1,252
Total revenues	70,977	56,693	73,538
Purchases, services and other	(52,461)	(44,124)	(56,848)
Payroll and related costs	(2,951)	(2,994)	(3,119)
Total operating expenses	(55,412)	(47,118)	(59,967)
Other operating income (expense)	(32)	16	(485)
Depreciation, depletion, amortization	(7,483)	(7,559)	(8,940)
Impairment losses (impairments reversals), net	225	475	(6,534)
Write-off	(263)	(350)	(688)
Operating profit (loss)	8,012	2,157	(3,076)
Finance (expense) income	(1,236)	(885)	(1,306)
Net income from investments	68	(380)	105
Profit (loss) before income taxes	6,844	892	(4,277)
Income taxes	(3,467)	(1,936)	(3,122)
Tax rate (%)	50.7
Net profit (loss) - continuing operations	3,377	(1,044)	(7,399)
Attributable to:
- Eni's shareholders	3,374	(1,051)	(7,952)
- Non-controlling interest	3	7	553
Net profit (loss) - discontinued operations		(413)	(1,974)
Attributable to:
- Eni's shareholders		(413)	(826)
- Non-controlling interest			(1,148)
Net profit (loss)	3,377	(1,457)	(9,373)
Attributable to:
- Eni's shareholders	3,374	(1,464)	(8,778)
- Non-controlling interest	3	7	(595)
Net profit (loss) attributable to Eni's shareholders - continuing operations	3,374	(1,051)	(7,952)
Exclusion of inventory holding (gains) losses	(156)	(120)	782
Exclusion of special items	(839)	831	8,487
Adjusted net profit (loss) attributable to Eni's shareholders - continuing operations	2,379	(340)	1,317
Adjusted net profit (loss) attributable to Eni's shareholders - discontinued operations			(642)
Adjusted net profit (loss) attributable to Eni's shareholders	2,379	(340)	675

(€ million)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fixed assets
Property, plant and equipment	63,158	70,793	68,005
Inventories - Compulsory stock	1,283	1,184	909
Intangible assets	2,925	3,269	3,034
Equity-accounted investments and other investments	3,730	4,316	3,513
Receivables and securities held for operating purposes	1,698	1,932	2,273
Net payables related to capital expenditure	(1,379)	(1,765)	(1,284)
	71,415	79,729	76,450
Net working capital
Inventories	4,621	4,637	4,579
Trade receivables	10,182	11,186	12,616
Trade payables	(10,890)	(11,038)	(9,605)
Tax payables and provisions for net deferred tax liabilities	(2,387)	(3,073)	(4,137)
Provisions	(13,447)	(13,896)	(15,375)
Other current assets and liabilities	287	1,171	1,827
	(11,634)	(11,013)	(10,095)
Provisions for employee post-retirement benefits	(1,022)	(868)	(1,123)
Discontinued operations and assets held for sale including related liabilities	236	14	9,048
CAPITAL EMPLOYED, NET	58,995	67,862	74,280
Shareholders' equity
attributable to: - Eni's shareholders	48,030	53,037	55,493
- Non-controlling interest	49	49	1,916
	48,079	53,086	57,409
Net borrowings	10,916	14,776	16,871
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	58,995	67,862	74,280

Summarized Group Cash Flow Statement

(€ million)	2017	2016	2015
Net profit (loss) - continuing operations	3,377	(1,044)	(7,399)
Adjustments to reconcile net profit (loss) to net cash provided by operating activities:
- depreciation, depletion and amortization and other non monetary items	8,720	7,773	17,216
- net gains on disposal of assets	(3,446)	(48)	(577)
- dividends, interest, taxes and other changes	3,650	2,229	3,215
Changes in working capital related to operations	1,440	2,112	4,781
Dividends received, taxes paid, interest (paid) received during the period	(3,624)	(3,349)	(4,361)
Net cash provided by operating activities - continuing operations	10,117	7,673	12,875
Net cash provided by operating activities - discontinued operations			(1,226)
Net cash provided by operating activities	10,117	7,673	11,649
Capital expenditure - continuing operations	(8,681)	(9,180)	(10,741)
Capital expenditure - discontinued operations			(561)
Capital expenditure	(8,681)	(9,180)	(11,302)
Investments and purchase of consolidated subsidiaries and businesses	(510)	(1,164)	(228)
Disposals	5,455	1,054	2,258
Other cash flow related to capital expenditure, investments and disposals	(373)	465	(1,351)
Free cash flow	6,008	(1,152)	1,026
Borrowings (repayment) of debt related to financing activities	341	5,271	(300)
Changes in short and long-term financial debt	(1,712)	(766)	2,126
Dividends paid and changes in non-controlling interests and reserves	(2,883)	(2,885)	(3,477)
Effect of changes in consolidation, exchange differences and cash cash equivalent related to discontinued operations	(65)	(3)	(780)
NET CASH FLOW	1,689	465	(1,405)
NET CASH PROVIDED BY OPERATING ACTIVITIES ON STANDALONE BASIS	8,458	5,386	8,510

Changes in net borrowings

(€ million)	2017	2016	2015
Free cash flow	6,008	(1,152)	1,026
Net borrowings of divested companies	261	5,848	83
Exchange differences on net borrowings and other changes	474	284	(818)
Dividends paid and changes in non-controlling interest and reserves	(2,883)	(2,885)	(3,477)
CHANGE IN NET BORROWINGS	3,860	2,095	(3,186)

Net sales from operations

(€ million)	2017	2016	2015
Exploration & Production	19,525	16,089	21,436
Gas & Power	50,623	40,961	52,096
Refining & Marketing and Chemicals	22,107	18,733	22,639
Corporate and other activities	1,462	1,343	1,468
Consolidation adjustment	(26,798)	(21,364)	(25,353)
	66,919	55,762	72,286

Net sales to customers

(€ million)	2017	2016	2015
Exploration & Production	7,131	6,378	9,321
Gas & Power	39,846	32,063	42,179
Refining & Marketing and Chemicals	19,771	17,128	20,632
Corporate and other activities	171	193	154
	66,919	55,762	72,286

Net sales by geographic area of destination

(€ million)	2017	2016	2015
Italy	21,925	21,280	24,405
Other EU Countries	19,791	15,808	20,730
Rest of Europe	5,911	4,804	7,125
Americas	5,154	3,212	4,217
Asia	7,523	5,619	9,086
Africa	6,428	4,865	6,482
Other areas	187	174	241
Total outside Italy	44,994	34,482	47,881
	66,919	55,762	72,286

Net sales by geographic area of origin

(€ million)	2017	2016	2015
Italy	45,764	37,515	47,287
Other EU Countries	7,772	7,899	9,996
Rest of Europe	2,096	1,560	2,561
Americas	3,986	2,257	2,893
Asia	616	862	1,687
Africa	6,504	5,496	7,630
Other areas	181	173	232
Total outside Italy	21,155	18,247	24,999
	66,919	55,762	72,286

Purchases, services and other

(€ million)	2017	2016	2015
Production costs - raw, ancillary and consumable materials and goods	35,907	27,783	39,812
Production costs - services	12,228	12,727	13,197
Operating leases and other	1,684	1,672	2,205
Net provisions	886	505	644
Gains on price adjustments under overlifting/underlifting	145	240	278
Other expenses	1,844	1,512	1,135
less:
capitalized direct costs associated with self-constructed tangible and intangible assets	(233)	(315)	(423)
	52,461	44,124	56,848

Principal accountant fees and services

(€ thousand)	2017	2016	2015
Audit fees	23,193	21,433	33,752
Audit-related fees	1,712	1,874	1,138
Tax fees			3
All other fees	12
	24,917	23,307	34,893

Payroll and related costs

(€ million)	2017	2016	2015
Wages and salaries	2,447	2,491	2,648
Social security contributions	441	445	453
Cost related to defined benefit plans and defined contribution plans	113	81	85
Other costs	162	202	182
less:
capitalized direct costs associated with self-constructed tangible and intangible assets	(212)	(225)	(249)
	2,951	2,994	3,119

Depreciation, depletion, amortization, impairments (impairments reversal) net and write-off

(€ million)	2017	2016	2015
Exploration & Production	6,747	6,772	8,080
Gas & Power	345	354	363
Refining & Marketing and Chemicals	360	389	454
Corporate and other activities	60	72	71
Impact of unrealized intragroup profit elimination	(29)	(28)	(28)
Total depreciation, depletion and amortization	7,483	7,559	8,940
Exploration & Production	(158)	(700)	5,212
Gas & Power	(146)	81	152
Refining & Marketing and Chemicals	54	104	1,150
Corporate and other activities	25	40	20
Impairment losses (impairment reversal), net	(225)	(475)	6,534
Total DD&A and impairment losses (impairment reversal), net	7,258	7,084	15,474
Write-off	263	350	688
	7,521	7,434	16,162

Operating profit by segment

(€ million)	2017	2016	2015
Exploration & Production	7,651	2,567	(959)
Gas & Power	75	(391)	(1,258)
Refining & Marketing and Chemicals	981	723	(1,567)
Corporate and other activities	(668)	(681)	(497)
Impact of unrealized intragroup profit elimination	(27)	(61)	1,205
	8,012	2,157	(3,076)

ALTERNATIVE PERFORMANCE MEASURES (NON-GAAP MEASURE)

Management evaluates underlying business performance on the basis of Non-GAAP financial measures under IFRS ("Alternative performance measures"), such as adjusted operating profit and adjusted net profit, which are arrived at by excluding inventory holding gains or losses, special items and, in determining the business segments' adjusted results, finance charges on finance debt and interest income. From 2017, the recognition of the inventory holding (gains) losses has been revised in the Gas & Power segment considering a recently-enacted, less restrictive regulatory framework relating the legal obligation on part of gas wholesalers to retain gas volumes in storage to ensure an adequate level of modulation to the retail segment. On this basis, management has progressively reduced gas quantities held in storage and has commenced to leverage those quantities to improve margins by seeking to capture the seasonality in gas prices existing between the phase of gas injection (which typically occurs in summer months) vs. the phase of gas off-take (which typically occurs during the winter months). Therefore, from the closure of the statutory period of gas injection, i.e. from the fourth quarter of 2017, the determination of the stock profit or loss in the Gas & Power segment has changed and currently gas off-takes from storage are valued at the average cost incurred during the injection period net of the effects of hedging derivatives, ensuring when the purchased volumes are matched by the corresponding sales (net of the effects of hedging derivatives) the proper measurement and accountability of the economic performances.

The adjusted operating profit of each business segment reports gains and losses on derivative financial instruments entered into to manage exposure to movements in foreign currency exchange rates, which affect industrial margins and translation of commercial payables and receivables. Accordingly, also currency translation effects recorded through profit and loss are reported within business segments' adjusted operating profit. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them. Management includes them in order to facilitate a comparison of base business performance across periods, and to allow financial analysts to evaluate Eni's trading performance on the basis of their forecasting models.

Non-GAAP financial measures should be read together with information determined by applying IFRS and do not stand in for them. Other companies may adopt different methodologies to determine Non-GAAP measures. Follows the description of the main alternative performance measures adopted by Eni.

The measures reported below refer to the performance of the reporting periods disclosed in this press release.

Adjusted operating and net profit

Adjusted operating and net profit are determined by excluding inventory holding gains or losses, special items and, in determining the business segments' adjusted results, finance charges on finance debt and interest income. The adjusted operating profit of each business segment reports gains and losses on derivative financial instruments entered into to manage exposure to movements in

foreign currency exchange rates which impact industrial margins and translation of commercial payables and receivables. Accordingly, also currency translation effects recorded through profit and loss are reported within business segments' adjusted operating profit. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them.

Finance charges or income related to net borrowings excluded from the adjusted net profit of business segments are comprised of interest charges on finance debt and interest income earned on cash and cash equivalents not related to operations. Therefore, the adjusted net profit of business segments includes finance charges or income deriving from certain segment operated assets, i.e., interest income on certain receivable financing and securities related to operations and finance charge pertaining to the accretion of certain provisions recorded on a discounted basis (as in the case of the asset retirement obligations in the Exploration & Production segment).

Inventory holding gain or loss

This is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting as required by IFRS.

Special items

These include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones; or (iii) exchange rate differences and derivatives relating to industrial activities and commercial payables and receivables, particularly exchange rate derivatives to manage commodity pricing formulas which are quoted in a currency other than the functional currency. Those items are reclassified in operating profit with a corresponding adjustment to net finance charges, notwithstanding the handling of foreign currency exchange risks is made centrally by netting off naturally-occurring opposite positions and then dealing with any residual risk exposure in the exchange rate market.

As provided for in Decision No. 15519 of July 27, 2006 of the Italian market regulator (CONSOB), non-recurring material income or charges are to be clearly reported in the management's discussion and financial tables. Also, special items allow to allocate to future reporting periods gains and losses on re-measurement at fair value of certain non-hedging commodity derivatives and exchange rate derivatives relating to commercial exposures, lacking the criteria to be designed as hedges, including the ineffective portion of cash flow hedges and certain derivative financial instruments embedded in the pricing formula of long-term gas supply agreements of the Exploration & Production segment.

Adjusted operating profit and adjusted net profit on a standalone basis

Considering the significant impact of the discontinued operations in the comparative reporting periods of 2015, management used an adjusted performance measures calculated on a standalone basis. This Non-GAAP measure excludes as usual the items "profit/loss on stock" and extraordinary gains and losses (special items), while it reinstates the effects relating to the elimination of gains and losses on intercompany transactions with the Engineering & Construction segment which, as of December 31, 2015, was in the disposal phase, represented as discontinued operations under the IFRS5. These measures obtain a representation of the performance of the continuing operations which anticipates the effect of the derecognition of the discontinued operations. Namely: adjusted operating profit and adjusted net profit on a standalone basis.

Profit per boe

Measures the return per oil and natural gas barrel produced. It is calculated as the ratio between Results of operations from E&P activities (as defined by FASB Extractive Activities - oil&gas Topic 932) and production sold.

Opex per boe

Measures efficiency in the oil&gas development activities, calculated as the ratio between operating costs (as defined by FASB Extractive Activities - oil&gas Topic 932) and production sold.

Finding & Development cost per boe

Represents Finding & Development cost per boe of new proved or possible reserves. It is calculated as the overall amount of exploration and development expenditure, the consideration for the acquisition of possible and probable reserves as well as additions of proved reserves deriving from improved recovery, extensions, discoveries and revisions of previous estimates (as defined by FASB Extractive Activities oil&gas Topic 932).

Leverage

Leverage is a Non-GAAP measure of the Company's financial condition, calculated as the ratio between net borrowings and shareholders' equity, including non-controlling interest. Leverage is the reference ratio to assess the solidity and efficiency of the Group balance sheet in terms of incidence of funding sources including third-party funding and equity as well as to carry out benchmark analysis with industry standards.

Gearing

Gearing is calculated as the ratio between net borrowings and capital employed net and measures how much of capital employed net is financed recurring to third-party funding.

ROACE (Return On Average Capital Employed) adjusted

Is the return on average capital invested, calculated as the ratio between net income before minority interests, plus net financial charges on net financial debt, less the related tax effect and net average capital employed.

Net cash provided by operating activities before changes in working capital at replacement cost

Net cash provided from operating activities before changes in working capital and exlcuding inventory holding gain or loss.

Free cash flow

Free cash flow represents the link existing between changes in cash and cash equivalents (deriving from the statutory cash flows statement) and in net borrowings (deriving from the summarized cash flow statement) that occurred from the beginning of the period to the end of period. Free cash flow is the cash in excess of capital expenditure needs. Starting from free cash flow it is possible to determine either: (i) changes in cash and cash equivalents for the period by adding/deducting cash flows relating to financing debts/ receivables (issuance/repayment of debt and receivables related to financing activities), shareholders' equity (dividends paid, net repurchase of own shares, capital issuance) and the effect of changes in consolidation and of exchange rate differences; (ii) changes in net borrowings for the period by adding/deducting cash flows relating to shareholders' equity and the effect of changes in consolidation and of exchange rate differences.

Net borrowings

Net borrowings is calculated as total finance debt less cash, cash equivalents and certain very liquid investments not related to operations, including among others non-operating financing receivables and securities not related to operations. Financial activities are qualified as "not related to operations" when these are not strictly related to the business operations.

Coverage

Financial discipline ratio, calculated as the ratio between operating profit and net finance charges.

Current ratio

Measures the capability of the company to repay short-term debt, calculated as the ratio between current assets and current liabilities.

Debt coverage

Rating companies use the debt coverage ratio to evaluate debt sustainability. It is calculated as the ratio between net cash provided by operating activities and net borrowings, less cash and cashequivalents, securities held for non-operating purposes and financing receivables for non-operating purposes.

The following tables report the group operating profit and Group adjusted net profit and their breakdown by segment, as well as is represented the reconciliation with net profit attributable to Eni's shareholders of continuing operations.

2017	(€ million)	& Production Exploration	Gas & Power	Refining & Marketing and Chemicals	and other activities Corporate	Impact of unrealized intragroup profit elimination	GROUP
Reported operating profit (loss)		7,651	75	981	(668)	(27)	8,012
Exclusion of inventory holding (gains) losses				(213)		(6)	(219)
Exclusion of special items:
environmental charges		46		136	26		208
impairment losses (impairments reversals), net		(154)	(146)	54	25		(221)
gains on disposal of assets		(3,269)		(13)	(1)		(3,283)
risk provisions		366			82		448
provision for redundancy incentives		19	38	(6)	(2)		49
commodity derivatives			157	(11)			146
exchange rate differences and derivatives		(68)	(171)	(9)			(248)
other		582	261	72	(4)		911
Special items of operating profit (loss)		(2,478)	139	223	126		(1,990)
Adjusted operating profit (loss)		5,173	214	991	(542)	(33)	5,803
Net finance (expense) income(a)		(50)	10	5	(699)		(734)
Net income (expense) from investments(a)		408	(9)	19	22		440
Income taxes(a)		(2,807)	(163)	(352)	178	17	(3,127)
Tax rate (%)		50.8	75.8	34.7			56.8
Adjusted net profit (loss)		2,724	52	663	(1,041)	(16)	2,382
of which attributable to:
- non-controlling interest							3
- Eni's shareholders							2,379
Reported net profit (loss) attributable to Eni's shareholders							3,374
Exclusion of inventory holding (gains) losses							(156)
Exclusion of special items							(839)
Adjusted net profit (loss) attributable to Eni's shareholders							2,379

(a) Excluding special items.

2016	(€ million)	& Production Exploration	Gas & Power	Refining & Marketing and Chemicals	and other activities Corporate	Impact of unrealized intragroup profit elimination	GROUP	DISCONTINUED OPERATIONS	CONTINUING OPERATIONS
Reported operating profit (loss)		2,567	(391)	723	(681)	(61)	2,157		2,157
Exclusion of inventory holding (gains) losses			90	(406)		141	(175)		(175)
Exclusion of special items:
environmental charges			1	104	88		193		193
Impairment losses (impairments reversals), net		(684)	81	104	40		(459)		(459)
impairment of exploration projects		7					7		7
gains on disposal of assets		(2)		(8)			(10)		(10)
risk provisions		105	17	28	1		151		151
provision for redundancy incentives		24	4	12	7		47		47
commodity derivatives		19	(443)	(3)			(427)		(427)
exchange rate differences and derivatives		(3)	(19)	3			(19)		(19)
other		461	270	26	93		850		850
Special items of operating profit (loss)		(73)	(89)	266	229		333		333
Adjusted operating profit (loss)		2,494	(390)	583	(452)	80	2,315		2,315
Net finance (expense) income(a)		(55)	6	1	(721)		(769)		(769)
Net income (expense) from investments(a)		68	(20)	32	(6)		74		74
Income taxes(a)		(1,999)	74	(197)	188	(19)	(1,953)		(1,953)
Tax rate (%)		79.7		32.0			120.6		120.6
Adjusted net profit (loss)		508	(330)	419	(991)	61	(333)		(333)
of which attributable to:
- non-controlling interest							7		7
- Eni's shareholders							(340)		(340)
Reported net profit (loss) attributable to Eni's shareholders							(1,464)	413	(1,051)
Exclusion of inventory holding (gains) losses							(120)		(120)
Exclusion of special items							1,244	(413)	831
Adjusted net profit (loss) attributable to Eni's shareholders							(340)		(340)

(a) Excluding special items.

En
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Fa
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Bo
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20
17

									Discontinued operations
2015 (€ million)	Exploration & Production	Gas & Power	Refining & Marketing and Chemicals	and other activities Corporate	Engineering & Construction	Impact of unrealized intragroup profit elimination	GRUPPO	& Construction Engineering	Consolidation adjustments	TOTAL	CONTINUING OPERATIONS	of intercompany transactions vs. discontinued operations Reinstatement	CONTINUING OPERATIONS - on a standalone basis
Reported operating profit (loss)		(959) (1,258) (1,567)		(497)	(694)		(23) (4,998)	694	1,228		1,922 (3,076)		(4,304)
Exclusion of inventory holding (gains) losses		132	877			127	1,136				1,136		1,136
Exclusion of special items:
environmental charges			137	88			225				225		225
Impairment losses (impairments reversals), net	5,212	152	1,150	20	590		7,124	(590)		(590)	6,534		6,534
impairment of exploration projects	169						169				169		169
gains on disposal of assets	(403)		(8)	4	1		(406)	(1)		(1)	(407)		(407)
risk provisions		226	(5)	(10)			211				211		211
provision for redundancy incentives	15	6	8	1	12		42	(12)		(12)	30		30
commodity derivatives	12	90	68		(6)		164	6	(6)		164		170
exchange rate differences and derivatives	(59)	(9)	5				(63)				(63)		(63)
other	195	535	30	25			785				785		785
Special items of operating profit (loss)	5,141	1,000	1,385	128	597		8,251	(597)	(6)	(603)	7,648		7,654
Adjusted operating profit (loss)	4,182	(126)	695	(369)	(97)	104	4,389	97	1,222	1,319		5,708 (1,222)	4,486
Net finance (expense) income (a)	(272)	11	(2)	(686)	(5)		(954)	5	24	29	(925)	(24)	(949)
Net income (expense) from investments (a)	254	(2)	69	285	17		623	(17)		(17)	606		606
Income taxes (a)	(3,173)	(51)	(250)	107	(212)		(47) (3,626)	212	(53)		159 (3,467)		53 (3,414)
Tax rate (%)	76.2		32.8				89.4				64.3		82.4
Adjusted net profit (loss)	991	(168)	512	(663)	(297)	57	432	297	1,193	1,490		1,922 (1,193)	729
of which attributable to:
- non-controlling interest							(243)			848	605	(679)	(74)
- Eni's shareholders							675			642	1,317	(514)	803
Reported net profit (loss) attributable to Eni's shareholders							(8,778)				826 (7,952)		(7,952)
Exclusion of inventory holding (gains) losses							782				782		782
Exclusion of special items							8,671			(184)	8,487		8,487
Reinstatement of intercompany transactions vs. discontinued operations													(514)
Adjusted net profit (loss) attributable to Eni's shareholders							675			642	1,317		803

(a) Excluding special items.

Breakdown of special items

(€ million)	2017	2016	2015
Special items of operating profit (loss)	(1,990)	333	8,251
environmental charges	208	193	225
impairment losses (impairments reversals), net	(221)	(459)	7,124
impairment of exploration projects		7	169
gains on disposal of assets	(3,283)	(10)	(406)
risk provisions	448	151	211
provision for redundancy incentives	49	47	42
commodity derivatives	146	(427)	164
exchange rate differences and derivatives	(248)	(19)	(63)
other	911	850	785
Net finance (income) expense	502	166	292
of which:
exchange rate differences and derivatives	248	19	63
Net income (expense) from investments	372	817	488
of which:
gains on disposals of assets	(163)	(57)	(33)
impairments/revaluation of equity investments	537	896	506
Income taxes	277	(72)	(7)
of which:
net impairment of deferred tax assets of Italian subsidiaries		170	880
other net tax refund		6	860
deferred tax adjustment on PSAs	115
taxes on special items of operating profit (outside Italy) and other special items	162	(248)	(1,747)
Total special items of net profit (loss)	(839)	1,244	9,024
attributable to:
- Non-controlling interest			353
- Eni's shareholders	(839)	1,244	8,671

Adjusted operating profit by segment

(€ million)	2017	2016	2015
Exploration & Production	5,173	2,494	4,182
Gas & Power	214	(390)	(126)
Refining & Marketing and Chemicals	991	583	695
Corporate and other activities	(542)	(452)	(369)
Impact of unrealized intragroup profit elimination	(33)	80	1,326
	5,803	2,315	5,708

Adjusted net profit by segment

(€ million)	2017	2016	2015
Exploration & Production	2,724	508	991
Gas & Power	52	(330)	(168)
Refining & Marketing and Chemicals	663	419	512
Corporate and other activities	(1,041)	(991)	(663)
Impact of unrealized intragroup profit elimination	(16)	61	1,250
	2,382	(333)	1,922
of which attributable to:
Non-controlling interest	3	7	605
Eni's shareholders	2,379	(340)	1,317

Finance income (expense)

(€ million)	2017	2016	2015
Finance income (expense) related to net borrowings	(834)	(726)	(814)
- Finance expense from banks on short and long-term debt	(751)	(757)	(838)
- Interest from banks	12	15	19
- Net finance income (expense) from financial assets held for trading	(111)	(21)	3
- Interest and other income from financial receivables and securities held for non-operating purposes	16	37	2
Income (expense) from derivative financial instruments	837	(482)	160
- Derivatives on exchange rate	809	(494)	96
- Derivatives on interest rate	28	(12)	31
- Options		24	33
Exchange differences	(905)	676	(354)
Other finance income (expense)	(407)	(459)	(464)
- Interest and other income on financing receivables and securities held for operating purposes	128	143	120
- Finance expense due to the passage of time (accretion discount)	(264)	(312)	(291)
- Other finance income (expense)	(271)	(290)	(293)
	(1,309)	(991)	(1,472)
Capitalized finance expense	73	106	166
	(1,236)	(885)	(1,306)

Income (expense on) from investments

(€ million)	2017	2016	2015
Share of profit of equity-accounted investments	124	77	150
Share of loss of equity-accounted investments	(353)	(370)	(615)
Gains on disposals	163	(14)	164
Dividends	205	143	402
Decreases (increases) in the provision for losses on investments from equity accounted investments	(38)	(33)	(6)
Other income (expense), net	(33)	(183)	10
	68	(380)	105

Property, plant and equipment by segment

(€ million)	2017	2016	2015
Property, plant and equipment by segment, gross
Exploration & Production	152,608	165,559	154,064
Gas & Power	5,333	6,276	6,169
Refining & Marketing and Chemicals	24,554	24,119	23,818
Corporate and other activities	1,866	1,886	1,854
Impact of unrealized intragroup profit elimination	(584)	(568)	(656)
	183,777	197,272	185,249
Property, plant and equipment by segment, net
Exploration & Production	56,833	64,428	61,495
Gas & Power	1,379	1,692	1,882
Refining & Marketing and Chemicals	4,929	4,642	4,664
Corporate and other activities	341	368	418
Impact of unrealized intragroup profit elimination	(324)	(337)	(454)
	63,158	70,793	68,005

Capital expenditure by segment

(€ million)	2017	2016	2015
Exploration & Production	7,739	8,254	9,980
Gas & Power	142	120	154
Refining & Marketing and Chemicals	729	664	628
Corporate and other activities	87	55	64
Impact of unrealized intragroup profit elimination	(16)	87	(85)
Capital expenditure - continuing operations	8,681	9,180	10,741
Capital expenditure - discontinued operations			561
Capital expenditure	8,681	9,180	11,302
Investments	(510)	(1,164)	228
Capital expenditure and investments	8,171	8,016	11,530

Capital expenditure by geographic area of origin

(€ million)	2017	2016	2015
Italy	1,090	1,163	1,303
Other European Union Countries	316	331	444
Rest of Europe	387	460	1,101
Africa	5,699	5,004	5,009
Americas	278	233	674
Asia	898	1,978	2,186
Other areas	13	11	24
Total outside Italy	7,591	8,017	9,438
Capital expenditure - continuing operations	8,681	9,180	10,741
Italy			17
Other European Union Countries			264
Rest of Europe			50
Africa			11
Americas			53
Asia			140
Other areas			26
Total outside Italy			544
Capital expenditure - discontinued operations			561
Capital expenditure	8,681	9,180	11,302

Net borrowings

	(€ million)	Debt and bonds	Cash and cash equivalents	Securities held for trading and other securities held for non-operating purposes	Financing receivables held for non-operating purposes	Total
2017
Short-term debt		4,528	(7,363)	(6,219)	(209)	(9,263)
Long-term debt		20,179				20,179
		24,707	(7,363)	(6,219)	(209)	10,916
2016
Short-term debt		6,675	(5,674)	(6,404)	(385)	(5,788)
Long-term debt		20,564				20,564
		27,239	(5,674)	(6,404)	(385)	14,776
2015
Short-term debt		8,396	(5,209)	(5,028)	(685)	(2,526)
Long-term debt		19,397				19,397
		27,793	(5,209)	(5,028)	(685)	16,871

EMPLOYEES

Employees at year end

(units)	2017	2016	2015
Exploration & Production Italy	4,510	4,608	4,572
Outside Italy	7,460	7,886	8,249
	11,970	12,494	12,821
Gas & Power Italy	2,282	2,032	2,023
Outside Italy	2,031	2,229	2,461
	4,313	4,261	4,484
Refining & Marketing and Chemicals Italy	8,580	8,577	8,635
Outside Italy	2,336	2,281	2,360
	10,916	10,858	10,995
Corporate and other activities Italy	5,501	5,693	5,650
Outside Italy	234	229	246
	5,735	5,922	5,896
Total employees at year end Italy	20,873	20,910	20,880
Outside Italy	12,061	12,626	13,316
	32,934	33,536	34,196
of which: senior managers	1,007	1,017	1,054

Breakdown by position

(units)	2017	2016	2015
Senior Managers	1,007	1,017	1,054
Middle Managers and Senior Staff	9,131	9,244	9,295
White collar workers	16,952	17,232	17,897
Blue collar workers	5,844	6,043	5,950
Total	32,934	33,536	34,196

Main financial data of continuing operations(a)

			2017					2016					2015
(€ million)		I quarter II quarter III quarter		IV quarter			I quarter II quarter III quarter		IV quarter			I quarter II quarter III quarter		IV quarter
Net sales from operations	18,047	15,643	15,684	17,545	66,919	13,344	13,416	13,195	15,807	55,762	21,038	20,279	15,903	15,066	72,286
Operating profit (loss)	2,111	563	998	4,340	8,012	105	220	192	1,640	2,157	1,770	1,605	248	(6,699)	(3,076)
Adjusted operating profit (loss)	1,834	1,019	947	2,003	5,803	583	188	258	1,286	2,315	1,795	1,823	943	1,147	5,708
Exploration & Production	1,415	845	1,046	1,867	5,173	95	355	644	1,400	2,494	1,080	1,585	919	598	4,182
Gas & Power	338	(146)	(193)	215	214	285	(229)	(374)	(72)	(390)	294	31	(469)	18	(126)
Refining & Marketing and Chemicals	189	352	337	113	991	177	156	175	75	583	121	105	335	134	695
Corporate and other activities	(115)	(160)	(151)	(116)	(542)	(90)	(126)	(118)	(118)	(452)	(89)	(123)	(56)	(101)	(369)
Unrealized profit intragroup elimination
and consolidation adjustments	7	128	(92)	(76)	(33)	116	32	(69)	1	80	389	225	214	498	1,326
Net (loss) profit(b)	965	18	344	2,047	3,374	(796)	(446)	(562)		340 (1,464)	832	(97)	(790)	(8,723)	(8,778)
- continuing operations	965	18	344	2,047	3,374	(383)	(446)	(562)	340	(1,051)	787	498	(783)	(8,454)	(7,952)
- discontinued operations						(413)				(413)	45	(595)	(7)	(269)	(826)
Capital expenditure	2,831	2,092	1,570	2,188	8,681	2,455	2,424	2,051	2,250	9,180	2,684	3,150	2,210	2,697	10,741
Investments	36	14	453	7	510	1,124	28	6	6	1,164	61	47	63	57	228
Net borrowings at period end	14,931	15,467	14,965	10,916	10,916	12,222	13,814	16,008	14,776	14,776	15,140	16,477	18,414	16,871	16,871
(a) Quarterly data are unaudited.

(b) Net profit attributable to Eni's shareholders.

Key market indicators

			2017					2016					2015
		I quarter II quarter III quarter		IV quarter			I quarter II quarter III quarter		IV quarter			I quarter II quarter III quarter		IV quarter
Average price of Brent dated crude oil(a)	53.78	49.83	52.08	61.39	54.27	33.89	45.57	45.85	49.46	43.69	53.97	61.92	50.26	43.69	52.46
Average EUR/USD exchange rate(b)	1.065	1.101	1.175	1.177	1.130	1.102	1.129	1.116	1.079	1.107	1.126	1.105	1.112	1.095	1.110
Average price in euro of Brent dated crude oil	50.51	45.25	44.34	52.14	48.03	30.75	40.36	41.08	45.84	39.47	47.93	56.04	45.20	39.90	47.26
Standard Eni Refining Margin (SERM)(c)	4.2	5.3	6.4	4.3	5.0	4.2	4.6	3.3	4.7	4.2	7.6	9.1	10.0	6.6	8.3
(a) In USD per barrel. Source: Platt's Oilgram.

(b) Source: ECB.

(c) In USD per barrel. Source: Eni calculations. It gauges the profitability of Eni's refineries against the typical raw material slate and yields.

QUARTERLY INFORMATION

Main operating data

				2017					2016					2015
		I quarter II quarter		III quarter	IV quarter		I quarter II quarter		III quarter	IV quarter		I quarter II quarter		III quarter	IV quarter
Liquids production	(kbbl/d)	832	827	885	861	852	890	852	864	906	878	860	903	868	998	908
Natural gas production	(mmcf/d)	5,254	5,152	5,012	5,625	5,261	4,718	4,709	4,616	5,184	4,807	4,596	4,676	4,582	4,868	4,681
Hydrocarbons production	(kboe/d)	1,795	1,771	1,803	1,892	1,816	1,754	1,715	1,710	1,856	1,759	1,697	1,754	1,703	1,884	1,760
Italy		154	100	136	146	134	154	96	125	159	133	165	173	168	169	169
Rest of Europe		202	218	174	163	189	190	188	187	240	201	186	181	182	192	185
North Africa		483	453	455	542	483	450	478	453	464	462	459	457	455	524	473
Egypt		224	226	230	240	230	166	173	185	216	185	179	224	192	160	189
Sub-Saharan Africa		302	345	374	365	347	343	350	330	334	339	342	343	336	343	341
Kazakhstan		142	136	118	130	132	118	90	103	133	111	100	98	82	100	95
Rest of Asia		93	108	137	139	119	132	141	133	103	127	109	113	117	201	135
Americas		172	164	160	144	160	178	174	171	184	177	128	140	148	170	147
Australia and Oceania		23	21	19	23	22	23	25	23	23	24	29	25	23	25	26
Production sold	(mmboe)	151.3	149.7	156.3	165.0	622.3	151.5	147.5	148.5	161.1	608.6	144.5	153.6	149.8	166.2	614.1
Sales of natural gas to third parties	(bcm)	20.64	16.54	15.16	19.00	71.34	21.01	18.51	17.03	20.69	77.24	22.69	19.56	17.59	19.22	79.06
Own consumption of natural gas		1.59	1.40	1.55	1.64	6.18	1.53	1.31	1.60	1.66	6.10	1.54	1.28	1.51	1.55	5.88
Sales to third parties and own consumption		22.23	17.94	16.71	20.64	77.52	22.54	19.82	18.63	22.35	83.34	24.23	20.84	19.10	20.77	84.94
Sales of natural gas of Eni's affiliates (net to Eni)		1.05	0.69	0.73	0.84	3.31	0.75	0.66	0.65	0.91	2.97	0.61	0.73	0.68	0.76	2.78
Total sales and own consumption of natural gas		23.28	18.63	17.44	21.48	80.83	23.29	20.48	19.28	23.26	86.31	24.84	21.57	19.78	21.53	87.72
Electricity sales	(TWh)	9.37	8.39	8.91	8.66	35.33	9.45	8.64	9.17	9.79	37.05	8.47	8.35	9.00	9.06	34.88
Sales of refined products	(mmtonnes)	7.93	8.25	8.56	8.46	33.19	7.69	8.70	8.65	8.37	33.40	8.36	9.43	8.85	8.60	35.24
Retail sales in Italy		1.42	1.54	1.56	1.49	6.01	1.37	1.50	1.59	1.47	5.93	1.36	1.51	1.58	1.51	5.96
Wholesale sales in Italy		1.68	1.98	2.04	1.94	7.64	1.84	2.01	2.23	2.08	8.16	1.69	1.99	2.17	1.99	7.84
Retail sales Rest of Europe		0.58	0.65	0.68	0.62	2.53	0.63	0.71	0.72	0.61	2.66	0.69	0.79	0.77	0.68	2.93
Wholesale sales Rest of Europe		0.68	0.78	0.79	0.77	3.02	0.70	0.81	0.83	0.84	3.18	1.08	0.98	0.90	0.87	3.83
Wholesale sales outside Europe		0.11	0.11	0.11	0.12	0.45	0.10	0.11	0.11	0.11	0.43	0.10	0.11	0.11	0.11	0.43
Other markets		3.46	3.19	3.38	3.52	13.54	3.05	3.57	3.17	3.26	13.05	3.44	4.05	3.33	3.43	14.25

ENERGY CONVERSION TABLE

Oil

									(average reference density 32.35 f API, relative density 0.8636)
1 barrel	(bbl)	158.987		l oil(a) 0.159 m3 petrolio	162.602	m3 gas			5,458	ft3 gas
					5,800,000	btu
1 barrel/d	(bbl/d)	~50	t/y
1 cubic meter	(m3 )	1,000		l oil 6.47 bbl	1,033	m3 gas			36,481	ft3 gas
1 tonne oil equivalent	(toe)	1,160.49		l oil 7.299 bbl	1.161	m3 petrolio	1,187	m3 gas	41,911	ft3 gas

Gas

1 cubic meter	(m3 )	0.976	l oil 0.00647 bbl	35,314.67	btu			35,315	ft3 gas
1.000 cubic feet	(ft3 )	27.637	l oil 0.1742 bbl	1,000,000	btu	27.317	m3 gas	0.02386	toe
1.000.000 British thermal unit	(btu)	27.4	l oil 0.17 bbl	0.027	m3 oil	28.3	m3 gas	1,000	ft3 gas
1 tonne LNG	(tGNL)	1.2	toe 8.9 bbl n	52,000,000	btu			52,000	ft3 gas

Electricity

1 megawatthour=1.000 kWh	(MWh)	93.532	l oil 0.5883 bbl	0.0955	m3 oil	94.448	m3 gas	3,412.14	ft3 gas
1 terajoule	(TJ)	25,981.45	l oil 163.42 bbl	25.9814	m3 oil	26,939.46	m3 gas	947,826.7	ft3 gas
1.000.000 kilocalories	(kcal)	108.8	l oil 0.68 bbl	0.109	m3 oil	112.4	m3 gas	3,968.3	ft3 gas

(a) l oil:liters of oil.

Conversion of mass

	kilogram (kg)	pound (lb)	metric ton (t)
kg	1	2.2046	0.001
lb	0.4536	1	0.0004536
t	1,000	22,046	1

Conversion of length

	meter (m)	inch (in)	foot (ft)	yard (yd)
m	1	39.37	3.281	1.093
in	0.0254	1	0.0833	0.0278
ft	0.3048	12	1	0.3333
yd	0.9144	36	3	1

Conversion of volumes

	cubic foot (ft3 )	barrel (bbl)	liter (lt)	cubic meter (m3 )
ft3	1	0	28.32	0.02832
bbl	5.458	1	159	0.158984
l	0.035315	0.0065	1	0.001
m3	35.31485	6.2898	103	1

Eni SpA

Headquarters

Piazzale Enrico Mattei, 1 - Rome - Italy Capital Stock as of December 31, 2017: € 4,005,358,876.00 fully paid Tax identification number 00484960588

Branches

Via Emilia, 1 - San Donato Milanese (Milan) - Italy Piazza Ezio Vanoni, 1 - San Donato Milanese (Milan) - Italy

Publications

Financial Statement pursuant to rule 154-ter paragraph 1 of Legislative Decree No. 58/1998 (in Italian) Integrated Annual Report Annual Report on Form 20-F for the Securities and Exchange Commission Fact Book (in Italian and English) Interim Consolidated Report as of June 30 pursuant to rule 154-ter paragraph 2 of Legislative Decree No. 58/1998 Corporate Governance Report pursuant to rule 123-bis of Legislative Decree No. 58/1998 (in Italian and English) Remuneration Report pursuant to rule 123-ter of Legislative Decree No. 58/1998 (in Italian and English)

Eni in 2017 – Summary Annual Review (in English) Eni For 2017 – Sustainability Report (in Italian and English)

Internet home page www.eni.com

Rome office telephone +39-0659821

Toll-free number 800940924

e-mail segreteriasocietaria.azionisti@eni.com

Investor Relations

Piazza Ezio Vanoni, 1 - 20097 San Donato Milanese (Milan) Tel. +39-0252051651 - Fax +39-0252031929 e-mail: investor.relations@eni.com

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