Eni

Annual Report • Apr 12, 2017

Fact Book 2016

Mission

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.

4	Eni at a glance
6	Performance and strategy
8	Main data
12	Exploration & Production
39	Gas & Power
47	Refining & Marketing and Chemicals
	Tables
60	Financial Data
72	Employees
73	Supplemental oil and gas information
93	Quarterly information

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.

Eni at a glance

Eni is an energy company, operating in 73 Countries in the world, with 33,536 employees. Eni engages in oil and natural gas exploration, field development and production, mainly in Italy, Algeria, Angola, Congo, Egypt, Ghana, Libya, Mozambique, Nigeria, Norway, Kazakhstan, the United Kingdom, the United States and Venezuela, overall in 44 Countries1 .

Eni sells gas, electricity, LNG and oil products in the European and extra-European markets, also leveraging on trading activities. Products availability is ensured by oil and gas production in the upstream segment, long-term gas supply contracts, CCGT power plants, Eni's refinery system as well by Versalis' chemical plants. The supply of commodities is optimized through trading activity.

The Company boasts a solid competitive position leveraging on competences and exploration successes, a higher portion of natural gas reserves, a reduction in the full-cycle cost of the produced barrel consistently with a weakened trading environment, mid-downstream sustainability and, in the long-term, the ability to adapt to decarbonization by growing in the renewable energy segment exploiting synergies with Eni's industrial assets.

Performance and strategy

Eni's future growth trajectory will leverage on the key achievements made in the last three years: a strong production of 1,759 million boe/d, a record proved reserve replacement ratio, a well-stocked pipeline of new, high quality projects which will contribute to an expected growth rate of 4.5% in 2017, and the advanced restructuring of our mid-downstream businesses. The solidity of Eni's balance sheet has been preserved by maintaining a sustainable level of gearing, while Eni has been the only Major to reduce its leverage during the 2014-2016 period. Looking to the future, a progressive remuneration policy has been reaffirmed in line with the expected improvement of commodity prices and the Group financial performance.

Exploration

Continuing strong exploration track record. Discovered 1.1 billion boe of additional resources at a cost of 0.6 \$/boe. Additions to the Company's resources backlog were 3.4 billion boe in the last three years, at a cost of 1 \$/boe. Promising new prospects to be drilled in future years. Our dual exploration model proved to be successful (sale of 40% of Zohr).

Capex optimization

Improved prospects of organic production growth over the next four years notwithstanding a 19% capex reduction y-o-y.

E&P efficiency

Opex efficiency above expectations at 6.2 \$/boe compared to 7.2 \$/boe in 2015.

Disposals

Defined in the year disposals for a total consideration of €2.6 billion, 40% of the 2016-2019 four-year target announced in March 2016 (€7 billion).

Strategy

Cash flow

FY normalized cash flow from operations up to €8.3 billion covering the 90% of 2016 capex, reduced to €8.7 billion from €9.2 billion, when excluding the reimbursement related to Zohr disposal (€0.5 billion). All mid-downstream businesses cash positive in the year.

Since the beginning of the oil downturn in 2014, Eni's strategy has been refocused on three pillars: a successful exploration with low unit costs and a fast time to market; the deployment of the dual exploration model through the disposal of these successes anticipating the conversion in cash of resources as to reconcile organic growth and a robust balance sheet; a continuous focus on the cost base to adapt the business model to a low commodity price scenario both in upstream and in downstream businesses. In the next four-year plan, the main goal of Eni's growth strategy is to build a high-margin cash portfolio and will be pursued through the following levers:

• ➤ the portfolio consolidation through high impact exploration activity on conventional basins, in proximity of existing facilities and not far from the final market;
• ➤ the development of projects with a "design to cost" approach, aimed to accelerate production start-ups and reduce financial exposure;
• ➤ the maximization of value through the integration of our portfolio with gas marketing activities (with a more relevant role played by LNG), the improvement of middownstream businesses and the active management of portfolio based on Dual Exploration Model.

E&P projects

Progressed construction activities at our development projects expected to come on stream in 2017 (Jangkrik - Indonesia, OCTP oil - Ghana and Zohr - Egypt). In February 2017, started-up the East Hub project in Angola, five months earlier than scheduled. These projects, together with the ramp-up of 2016 new production from Kashagan and Goliat, will strongly contribute to the cash generation in 2017 and following years. In three years, projects break-even reduced leveraging on the exploration strategy, driven by the target of cost optimization in develop resources in production, effective development model and operating costs reduction.

Nooros

Reached a production plateau of 85.5 kboe/d net to Eni from the Nooros field located in Egypt. This record-setting production level was reached in just 13 months after the discovery in July 2015 and ahead of schedule. With the drilling of additional development wells, the field is expected to reach a maximum production capacity of about 160 kboe/d in 2017. Nooros is an important achievement by Eni's "near-field" exploration strategy, aimed at unlocking the presence of additional exploration potential located in proximity to existing infrastructures.

Mozambique

Authorities approved the development of the first development phase of Coral, targeting production of 5 tcf of gas. The Area 4 partners (Eni East Africa, joint operation between Eni and CNPC, Galp, Kogas and ENH) and BP signed a binding agreement for the sale, over a 20-year period, of approximately 3.3 million tons of LNG per annum (corresponding to about 5 bcm), which will be produced at the Coral South Floating facility. In March 2017, ExxonMobil and Eni signed a sale and purchase agreement to acquire a 25% indirect interest in the Area 4 block, offshore Mozambique. The agreed terms include a cash price of approximately \$2.8 billion. The completion of the deal is subject to satisfaction of certain conditions precedent, including clearance from Mozambican and other regulatory authorities.

Safety of people

In 2016, Eni launched "Eni in Safety", the new communication and training program, aimed to publicize among the company's levels the lesson learnt connected to near misses and injuries. This initiative and other investments in safety permits to reduce of 21% the total recordable injury rate of work force (down by 11% for employees and down by 25% for contractors), confirming the positive trend reported in the last years.

GHG emissions

GHG emissions for 2016 declined by 3.5% compared to 2015. This trend reflected lower emissions from combustion (down by 0.9 million tonnes), reduced methane emissions (down by 0.3 million tonnes) leveraging on initiatives to contain fugitive emissions as well as energy efficiency projects. The trend of GHG emission index compared to operated gross hydrocarbon of the upstream segment remains positive with a reduction of 9%.

Oil spills due to operations

Oil spills due to operations higher than one barrel (88% related to E&P segment) declined by 29% compared to 2015, the Refining & Marketing and Chemicals segment reported a significant improvement, down by 69%, the overall volume spilled decreased to 134 barrels in 2016 from 427 barrels in 2015. In Nigeria, activities are underway to replace certain cases covering holes caused by sabotages, which are a potential weakness.

Renewable energies

Defined renewable energy projects in Italy and certain Eni's countries of operations. The "Project Italy" targets the development of projects in the area of renewable energy (energy production mainly addressed for own consumption) leveraging on the industrial property areas with a total capacity of about 220 MWp. Outside Italy, Eni signed agreements for the development of new projects for the production of renewable energy, mainly in Algeria, Tunisia and Ghana.

Main data

Key financial data()(*)	(€ million)	2012	2013	2014	2015	2016
Net sales from operations		127,109	104,117	98,218	72,286	55,762
Operating profit		15,208	9,876	8,965	(3,076)	2,157
Special items		4,692	3,046	1,912	7,648	333
Profit (loss) on stock		(17)	716	1,460	1,136	(175)
Adjusted operating profit (loss)(b)		19,883	13,638	12,337	5,708	2,315
of which: Exploration & Production		18,537	14,643	11,679	4,182	2,494
Gas & Power		398	(622)	168	(126)	(390)
Refining & Marketing and Chemicals		(772)	(859)	(412)	695	583
Engineering & Construction		1,485	(99)
Corporate and other activities		(547)	(542)	(443)	(369)	(452)
Impact of unrealized intragroup profit elimination and consolidation adjustments		782	1,117	1,345	1,326	80
Group net profit (loss)(a)		7,790	5,160	1,303	(8,778)	(1,464)
of which: continuing operations		4,200	5,648	1,720	(7,952)	(1,051)
discontinuing operations		3,590	(488)	(417)	(826)	(413)
Adjusted net profit (loss)(a)(b)		7,325	4,430	3,723	803	(340)
of which: continuing operations		7,130	4,921	4,199	1,317	(340)
discontinuing operations		195	(491)	(476)	(514)
Net cash provided by operating activities(b)		12,567	11,026	14,742	11,649	7,673
of which: continuing operations		12,552	11,547	14,469	12,875	7,673
discontinuing operations		15	(521)	273	(1,226)
Capital expenditure		13,561	(12,800)	11,872	11,302	9,180
of which: continuing operations		12,805	(11,898)	11,178	10,741	9,180
discontinued operations		756	(902)	694	561
Shareholders' equity including non-controlling interest		62,417	61,049	65,641	57,409	53,086
Net borrowings		15,069	14,963	13,685	16,871	14,776
Leverage		0.24	0.25	0.21	0.29	0.28
Net capital employed		77,486	76,012	79,326	74,280	67,862
of which: Exploration & Production		42,369	45,699	51,061	53,968	57,910
Gas & Power		10,597	8,462	9,031	5,803	4,100
Refining & Marketing and Chemicals		8,871	11,393	9,711	6,986	6,981

(*) Pertaining to continuing operations. Following the divestment of Saipem in January 2016, the results of the segment have been classified as discontinued operations based on the guidelines of IFRS 5 for 2013, 2014 and 2015. 2102 results measure as discontinued operations only Regulated Businesses in Italy, divested in 2012.

(**) 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 for the FY 2016 have been restated. The retrospective application of the SEM has required adjustment of the opening balance of the retained earnings and other comparative amounts as of January 1, 2014. Specifically, the opening balance of the carrying amount of property, plant and equipment was increased by €3,524 million, intangible assets by €860 million and the retained earnings by €3,001 million. Other adjustments related to deferred tax liabilities and other minor line items. Concerning the FY 2015, the adoption of SEM determined a reduction of operating profit of €815 million. More information is disclosed in the notes of the consolidated financial statement of the 2016 Annual Report on Form 20-F. (a) Attributable to Eni's shareholders.

(b) Non-GAAP measures. Results of comparative periods 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.

Key market indicators		2012	2013	2014	2015	2016
Average price of Brent dated crude oil(a)	(\$/barrel)	111.58	108.66	98.99	52.46	43.69
Average EUR/USD exchange rate(b)		1.285	1.328	1.329	1.11	1.107
Average price of Brent dated crude oil	(€)	86.83	81.82	74.48	47.26	39.47
Standard Eni Refining Margin (SERM)(c)	(\$)	4.1	2.43	3.21	8.30	4.2
TTF	(€/kmc)	265	286	221	210	148
PSV	(€/kmc)	304	296	246	234	168

(a) Source: Platt's Oilgram.

(b) Source: Reuters (WMR).

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

Selected operating data(a)		2012	2013	2014	2015	2016
Employees at year end	(number)	36,018	36,678	34,846	34,196	33,536
of which: women		7,955	8,291	8,076	7,960	7,700
outside Italy		13,807	14,436	13,639	13,316	12,626
Local employees outside Italy	(%)	87	86	86	85	85
Female managers (senior managers and managers)	(%)	23	23	23	24	24
Pay gap (women vs men)	(%)	98	96	97	97	97
TRIR (Total Recordable Injury Rate)	(recordable injuries/worked hours) x 1,000,000	1.26	0.94	0.71	0.45	0.35
of which: employees		1.13	0.78	0.56	0.41	0.36
contractors		1.33	1.01	0.79	0.47	0.35
Fatality index (employees and contractors)	(Fatal injuries per one hundred millions of worked hours)	1.27		1.03	1.46	0.72
Near miss(b)	(number)	1,557	1,620	1,729	1,489	1,644
Training expenditures	(€ million)	39.3	57.6	39.1	29.1	26.6
Training hours	(thousand hours)	1,400	1,750	1,213	1,099	939
of which: e-learning		52	149	120	183	197
Total volume of oil spills (> 1 barrel)	(barrels)	12,419	7,891	15,562	16,481	5,648
of which: due to sabotage and terrorism		8,669	6,002	14,401	14,847	4,489
operational		3,750	1,889	1,161	1,634	1,159
Direct GHG emissions	(mmtonnes CO2 eq)	52.14	47.60	42.02	41.56	40.10
of which: CO2 equivalent from combustion and process		35.15	33.07	30.92	31.49	30.60
CO2 equivalent from flaring		9.46	9.13	5.73	5.51	5.40
CO2 equivalent from non-combusted methane and fugitive emissions		5.33	3.47	3.48	2.77	2.42
CO2 equivalent from flaring		2.20	1.92	1.89	1.80	1.67
R&D expenditure(c)	(€ million)	196	181	174	176	161
of which: new energy						51
First patent filing applications	(number)	61	45	64	33	40
of which: filed on renewable sources		21	28	29	16	12
Number of suppliers used	(number)	15,784	14,770	13,145	11,380	10,041
Total procurement	(€ million)	18,752	19,842	24,068	20,350	13,249
of which: local procurement		12,933	14,466	15,183	13,412	10,390
Interventions on the territory based on agreements, conventions and PSAs (Community investment)	(€ million)	61	56	65	76	67
		2012	2013	2014	2015	2016
Exploration & Production
Employees at year end	(number)	11,304	12,352	12,777	12,821	12,494
TRIR (Total Recordable Injury Rate)	(recordable injuries/worked hours) x 1,000,000	0.83	0.60	0.56	0.34	0.34
of which: employees		0.51	0.30	0.20	0.22	0.34
contractors		0.95	0.71	0.68	0.39	0.34
Net proved reserves of hydrocarbons	(mmboe)	7,166	6,535	6,602	6,890	7,490
Average reserve life index	(years)	11.5	11.1	11.3	10.7	11.6
Hydrocarbon production(d)	(kboe/d)	1,701	1,619	1,598	1,760	1,759
Organic reserve replacement ratio		147	105	112	148	193
Profit per boe(e)(f)	(\$/boe)	14.8	16.1	14.5	7.4	2.7
Opex per boe(e)		7.1	8.3	8.4	7.2	6.2
Cash flow per boe(d)		32.8	31.9	30.1	20.9	12.9
Finding & Development cost per boe(d)(f)		17.4	19.2	21.5	19.3	13.2
Direct GHG emissions	(mmtonnes CO2 eq)	29.4	27.4	23.4	22.8	20.4
CO2 emissions/100% operated hydrocarbon gross production(g)	(mmtonnes CO2 eq/tep)	0.230	0.232	0.201	0.182	0.166
% produced water re-injected	(%)	49	55	56	56	58
Volumes of hydrocarbon sent to flaring	(mmcm)	nd	3,450	1,767	1,989	1,950
of which: sent to flaring process		nd	3,320	1,678	1,564	1,530
Oil spills due to operations (> 1 barrel)	(barrels)	3,015	1,728	936	1,177	1,025
Interventions on the territory based on agreements, conventions and PSAs (Community investment)	(€ million)	60	53	63	72	63

(a) Pertaining to continuing operations.

(b) Incidental events which do not transform in damages or injuries.

(c) Net of general and administrative costs. (d) Includes Eni's share in joint ventures and equity-accounted entities.

(e) Related to consolidated subsidiaries.

(f) Three-year average.

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

		2012	2013	2014	2015	2016
Gas & Power
Employees at year end	(number)	4,836	4,616	4,561	4,484	4,261
TRIR (Total Recordable Injury Rate)	(recordable injuries/worked hours) x 1,000,000	2.23	1.48	0.82	0.89	0.28
of which: employees		1.77	1.39	0.87	0.91	0.27
contractors		3.98	1.80	0.70	0.81	0.31
Worldwide gas sales	(bcm)	95.32	93.17	89.17	90.88	88.93
- Italy		34.78	35.86	34.04	38.44	38.43
- outside Italy		60.54	57.31	55.13	52.44	50.50
Customers in Italy	(million)	7.45	8.00	7.93	7.88	7.76
Direct GHG emissions	(mmtonnes CO2 eq)	12.8	11.3	10.1	10.6	11.2
GHG emissions/kWheq (Eni Power)	(gCO2 eq/kWheq)	400	407	409	409	398
Installed capacity power plants	(GW)	5.30	4.80	4.90	4.90	4.70
Electricity produced	(TWh)	23.58	21.38	19.55	20.69	21.78
Electricity sold		42.58	35.05	33.58	34.88	37.05
		2012	2013	2014	2015	2016
Refining & Marketing and Chemicals
Employees at year end	(number)	14,276	14,146	11,884	10,995	10,858
TRIR (Total Recordable Injury Rate)	(recordable injuries/worked hours) x 1,000,000	3.03	2.33	1.51	1.07	0.38
of which: employees		2.76	2.12	1.60	0.97	0.44
contractors		3.32	2.56	1.40	1.17	0.32
Oil spills due to operations (> 1 barrel)	(barrels)	735	161	225	427	134
Direct GHG emissions	(mmtonnes CO2 eq)	9.80	8.90	8.45	8.19	8.50
SOx emissions (sulphur oxide)	(ktonnes SO2 eq)	19.18	12.33	6.84	6.17	4.35
Refinery throughputs on own account	(mmtonnes)	30.01	27.38	25.03	26.41	24.52
Retail market share in Italy	(%)	31.2	27.5	25.5	24.5	24.3
Retail sales of petroleum products in Europe	(mmtonnes)	10.87	9.69	9.21	8.89	8.59
Service stations in Europe at year end	(number)	6,384	6,386	6,220	5,846	5,622
Average throughput of service stations in Europe	(kliters)	2,064	1,828	1,725	1,754	1,742
Balanced capacity of refineries	(kbbl/d)	767	787	617	548	548
Capacity of biorefineries	(ktonnes/year)			360	360	360
Production of biofuels	(ktonnes)			105	179	191
GHG emissions/refining throughputs (traditional refineries)(h)	(tonnes CO2 eq/kt)	271	252	287	237	272
Production of petrochemical products	(ktonnes)	6,090	5,817	5,283	5,700	5,646
Sales of petrochemical products		3,953	3,785	3,463	3,801	3,759
Average plant utilization rate	(%)	67	65	71	73	72

(h) Livorno, Sannazzaro, Taranto, Gela related to 2014 and Livorno, Sannazzaro e Taranto related to 2015.

Share data		2012	2013	2014	2015	2016
Net profit (loss)(a)(b)(*)	(€)	1.16	1.56	0.48	(2.21)	(0.29)
Dividend		1.08	1.10	1.12	0.80	0.80
Cash dividends to Eni's shareholders(c)	(€ million)	3,840	3,949	4,006	3,457	2,881
Cash flow(*)	(€)	3.46	3.19	4.01	3.58	2.13
Dividend yield(d)	(%)	5.9	6.5	7.6	5.7	5.4
Net profit (loss) per ADR(b)(e)(*)	(USD)	2.98	4.14	1.27	(4.90)	(0.65)
Dividend per ADR(e)		2.82	2.99	2.65	1.77	1.77
Cash flow per ADR(e)		8.77	8.47	10.66	7.95	4.72
Dividend yield per ADR(d)(e)	(%)	5.9	6.5	7.6	5.7	5.4
Pay-out		50	77	310	(33)	(197)
Number of shares at period-end	(million)	3,634.2	3,634.2	3,634.2	3,634.2	3,634.2
Average number of share outstanding in the year(f) (fully diluted)		3,622.8	3,622.8	3,610.4	3,601.1	3,601.1
Total Shareholder Return (TSR)	(%)	22.0	1.3	(11.9)	1.1	19.2

(*) Pertaining to continuing operations. Following the disinvestment of Saipem in January 2016, the results of the segment have been classified as discontinued operations based on the

guidelines of IFRS 5 in 2013-2015 period. (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 2016 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		2012	2013	2014	2015	2016
Share price - Milan Stock Exchange
High	(€)	18.70	19.48	20.41	17.43	15.47
Low		15.25	15.29	13.29	13.14	10.93
Average		17.18	17.57	17.83	15.47	13.42
Year end		18.34	17.49	14.51	13.80	15.47
ADR price(a) - New York Stock Exchange
High	(\$)	49.44	52.12	55.3	39.29	33.33
Low		36.85	40.39	32.81	29.28	25.00
Average		44.24	46.68	47.37	34.31	29.74
Year end		49.14	48.49	34.91	29.80	32.24
Average daily exchanged shares	(million shares)	15.63	15.44	17.21	20.30	18.41
Value	(€ million)	267.0	271.4	304.0	312.0	246.0
Weighted average number of shares outstanding(b)	(million shares) 3,622.8		3,622.8	3,610.4	3,601.1	3,601.1
Market capitalization(c)
EUR	(billion)	66.4	63.4	52.4	50.2	56.2
USD		87.7	87.4	63.6	55.7	59.3

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

(a) Refers to share capital at December 31, 2016.

Exploration & Production

Key performance indicators

		2014	2015	2016
TRIR (Total Recordable Injury Rate)	(recordable injuries/worked hours) x 1,000,000	0.56	0.34	0.34
of which: employees		0.20	0.22	0.34
contractors		0.68	0.39	0.34
Net sales from operations(a)	(€ million)	28,488	21,436	16,089
Operating profit (loss)		10,727	(959)	2,567
Adjusted operating profit (loss)		11,679	4,182	2,494
Adjusted net profit (loss)		4,569	991	508
Capital expenditure		10,156	9,980	8,254
Profit per boe(b)(c)	(\$/boe)	14.5	7.4	2.7
Opex per boe(b)		8.4	7.2	6.2
Cash Flow per boe(d)		30.1	20.9	12.9
Finding & Development cost per boe(c)(d)		21.5	19.3	13.2
Average hydrocarbons realizations(d)		65.49	36.47	29.14
Hydrocarbon production(d)	(kboe/d)	1,598	1,760	1,759
Estimated net proved hydrocarbon reserves(d)	(mmboe)	6,602	6,890	7,490
Reserves life index(d)	(years)	11.3	10.7	11.6
Organic reserves replacement ratio(d)	(%)	112	148	193
Employees at period end	(number)	12,777	12,821	12,494
Oil spills due to operations (>1 barrel)	(bbl)	936	1,177	1,025
Produced water re-injected	(%)	56	56	58
Direct GHG emissions	(mmtonnes CO2 eq)	23.4	22.8	20.4
CO2 emissions/100% operated hydrocarbon gross production(e)	(tonnes CO2 eq/toe)	0.201	0.182	0.166
Interventions on the territory based on agreements, conventions and PSAs (Community investment)	(€ million)	63	72	63

(a) Before elimination of intragroup sales.

(b) Consolidated subsidiaries.

(c) Three-year average.

(d) Includes Eni's share of equity-accounted entities.

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

Performance of the year

• ➤ In 2016, safety performance continued on a positive trend, with a total recordable injury rate of 0.34 (unchanged from 2015). Eni is engaged in maintaining a high safety standard in each of its operations leveraging also on continuous HSE awareness programs by means of specific projects.
• ➤ Greenhouse gas emissions decreased by 11% compared to the previous year leveraging on the continuous improvements in energy efficiency, logistics optimization and initiatives to contain fugitive emissions, in particular developed for the 2016 in Egypt, Kazakhstan, the United Kingdom, Ecuador and United States. In March 2016, Goliat platform started-up, through advanced technology solutions thus contributing to the combustion emissions containment. The trend of GHG emission index compared to operated gross hydrocarbon production was positive with a reduction of 9%. This performance is better than the 2016 full year target.
• ➤ Water reinjection continues to achieve an excellent industry performance (58% in 2016), leveraging on the continuous campaign started in certain operational plants, in particular in Ecuador, Egypt and Congo in the full year.
• ➤ For the full year 2016, the E&P segment reported a decline of 40% in adjusted operating profit due to lower realization on commodities in dollar terms (down by 20%) as well as the Val d'Agri shutdown, which lasted four months and half. These effects were only partially offset by higher production in other areas and efficiency improvements with lower opex to 6.2 \$/boe (down by 14% from 7.2 \$/boe reported in 2015) and DD&A1 (down by 16% from 2015).
• ➤ 2016 oil and natural gas production was 1,759 kboe/d, in line with 2015, in spite of the Val d'Agri shutdown. Production start-ups and ramp-ups added approximately 280 kboe/d in 2016. 2017 expected production will achieve a record of 1.84 million boe/d increasing by approximately 5% from 2016.
• ➤ Estimated net proved reserves at December 31, 2016 amounted to 7.5 bboe based on a reference Brent price of \$42.8 per barrel. Organic reserves replacement ratio surged to 193%, the best ever performance in Eni's history. The 2016 reserves replacement ratio remains very robust at 139% also considering the 40% sale of Zohr on a pro forma basis. The reserves life index was 11.6 years (10.7 years in 2015).

Exploration activity

➤ Eni signed two agreements with major international players in the oil&gas business for the disposal of a 40% interest in the giant discovery Zohr, located in the operated block of Shoruk (Eni 100%) in Egypt. These transactions proved the validity 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 and reduce outlay in development expenditures. These agreements have economic efficacy from January 1, 2016 and contemplate the reimbursement to Eni of capex incurred until the closing date. The new partners have the option to acquire a further 5% stake at the same terms defined in the agreements. The first transaction closed on February 2017 following approval by the Egyptian authorities; the second one is expected to close by the first half of 2017. The total consideration of the deal amounts to approximately €2 billion as of January 1, 2017, including the reimbursement of costs incurred by Eni in 2016. Eni, applying its dual exploration model, has already disposed stakes worth €5.4 billion since 2013.

• ➤ Continuing strong exploration track record. Discovered 1.1 billion boe of additional resources at a cost of 0.6 \$/boe. Additions to the Company's resources backlog were 3.4 billion boe in the latest 3 years, at a cost of 1 \$/boe. Promising new prospects to be drilled in the future years.
• ➤ In Morocco, Eni signed a Farm-Out Agreement (FOA) with Chariot oil&gas that includes the operatorship to Eni and a 40% stake enter into Rabat Deep Offshore exploration permits I-VI offshore Morocco.
• ➤ In Montenegro, Eni was awarded a new exploration license related to four offshore blocks, covering an area of 1,228 square kilometers. The license will be operated by Eni, which will retain a 50% interest, in joint venture with Novatek.
• ➤ 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.
• ➤ Signed four agreements with the Bahrain national oil company to study and assess the potential of certain exploration and production assets in the Country. At the end of the studies, Bahrain Authorities and Eni will evaluate together the possibility of future initiatives for further developments of the Country's energy resources.
• ➤ The exploration portfolio was renewed by means of new exploration acreage covering approximately 10,500 square kilometers net to Eni in legacy areas such as, in particular, Egypt, Ghana, Norway and the United Kingdom, as well as in the high potential areas such as Montenegro and Morocco, as mentioned above.
• ➤ In 2016, exploration expenditure amounted to €417 million, mainly related to the completion of the 16 new exploratory wells (10.2 net to Eni). Commercial success rate recorded an outstanding industry performance reporting a 50% net to Eni. In addition, 79 exploratory drilled wells are in progress at year end (40 net to Eni).

Sustainability and portfolio developments

• ➤ Achieved start-ups in significant projects, such as:
• the Goliat Norwegian fields (Eni operator with a 65% interest) in the Barents Sea, achieving a production plateau of 100 kboe/d (65 kboe/d net to Eni);
• production re-start of the Kashagan field (Eni's interest 16.81%) with the fully replacement of the damaged pipelines. Production capacity of 370 kbbl/d is expected by the end of 2017;
• start-up of M'Pungi and M'Pungi North within the West Hub Development project in the offshore Block 15/06 (Eni operator with a 36.84% interest) in Angola, with a production ramp-up of approximately 81 kbbl/d in the area;
• in February 2017, start-up of the East Hub Development project in the Block 15/06, five months earlier than scheduled and with a time-to-market among the best in the industry. The East Hub project will develop the reservoir in the north-eastern area by means of a development program similar to the West Hub;
• the Great Nooros Area (Eni's interest 75%) in Egypt, achieving a peak production of 85.5 kboe/d net to Eni. This recordsetting production level was reached in just 13 months after the discovery and ahead of schedule. In addition, thanks to the mature operating environment and the conventional nature of the project, production costs are among the lowest in Eni's portfolio.

• ➤ Progressed construction activities at our development projects expected to come on stream in 2017 (Jangkrik in Indonesia, OCTP oil in Ghana as well as Zohr and East Hub, as discussed above). These projects, together with the ramp-up of 2016 new production from Kashagan and Goliat, will strongly contribute to the cash generation in 2017 and following years.

• ➤ Signed in Mozambique a binding agreement between the partners of the Area 4 and BP for the sale, over a 20-year period, of approximately 3.3 million tons of LNG per annum (corresponding to about 177 bcf), which will be produced at the Coral South Floating facility. The agreement is a fundamental step towards achieving the Final Investment Decision of the project, targeting production of 5 trillion cubic feet of gas.

• ➤ In March 2017, ExxonMobil and Eni signed sale and purchase agreement to acquire a 25% indirect interest in the Area 4 block, offshore Mozambique. The agreed terms include a cash price of approximately \$2.8 billion. The acquisition will be completed subject to satisfaction of certain conditions precedent, including clearance from Mozambican and other regulatory authorities.
• ➤ Eni's cooperation framework supports local development, seeks to minimize socio-economic gaps and involves all stakeholders. Eni is engaged in energy production for the domestic market, in the spread of access to electricity, diversification of energy mix and of local economies, in the supply know-how and technology as well as in the support of local development in health and education.
• ➤ Eni's long-term integrated strategy for achieving decarbonization targets is based on lowering CO2 emissions and enhancing efficiency in all Eni's activities, keeping low-carbon portfolio projects and supporting the natural gas to feed power generation and transport.
• ➤ Development expenditure was €7,770 million (down by 16.8% vs. 2015) to fuel the growth of major projects and to maintain production plateau particularly in Egypt, Angola, Kazakhstan, Indonesia, Iraq, Ghana and Norway.
• ➤ In 2016, overall R&D expenditure of the Exploration & Production segment amounted to €62 million (€78 million in 2015).

Activity Areas

Italy

Eni has been operating in Italy since 1926. In 2016, Eni's oil and gas production amounted to 133 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 20,818 square kilometers (16,767 square kilometers net to Eni).

Eni's exploration and development activities in Italy are regulated by concession contracts (50 operated onshore and 64 operated offshore) and exploration licenses (12 onshore and 9 offshore).

Adriatic and Ionian Seas

Production Fields in the Adriatic and Ionian Seas accounted for 52% of Eni's domestic production in 2016, mainly gas. Main operated fields are Barbara, Cervia/Arianna, Annamaria, Luna, Angela-Angelina, Hera Lacinia, Bonaccia and Porto Garibaldi. Production is operated by means of 72 fixed platforms (three 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 control, maintenance activities and production optimization.

Development Development activities concerned: (i) maintenance and production optimization, mainly at the Barbara, Cervia/Arianna and Morena fields; and (ii) start-up of the Clara NW development project.

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 is treated by the Viggiano oil center.

On August 12, 2016 the activity of the Val d'Agri Oil Centre in Viggiano gradually restarted following notification by the Italian Public Prosecutor of Potenza that has definitively repealed the plant seizure and by the National Mining Office for Hydrocarbons and Earth Resources of the Ministry of Economic Development that has authorized the plant's operation. The resumption of production is a result of the completion in June 2016 of certain plant upgrading, which do not alter the plant set up, authorized by the in-charge department of the Italian Ministry of Economic Development in order to address the alleged environmental crimes issued by the public prosecutor.

Development The development plan is progressing in line with the commitments agreed with the Basilicata Region, particularly in 2016: (i) the Environmental Monitoring Plan is being implemented. This project represents a benchmark in terms of environmental protection; and (ii) programs to support culture, enhancement of agricultural activities and socio-economic development in the area are in progress.

Sicily

Production Eni operates 12 production concessions onshore and 3 offshore Sicily. The main fields are Gela, Ragusa, Tresauro, Giaurone,

Fiumetto and Prezioso, which in 2016 accounted for approximately 12% of Eni's production in Italy.

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 project progressed. The project was submitted to the relevant Authorities and planned an optimization activities aiming to reduce environmental impact, to improve local economic and employment development and to recover areas of Eni's refinery already reclaimed for the construction of treatment plants. This program is subject to the authorization of the relevant Authorities. In addition, the Memorandum includes certain Eni's projects to support sustainable development in the area with an overall expense of €32 million. Three implementing agreements were signed: one of them was already completed and concerned the construction of an exhibition hall at the Gela Archaeological Museum. Others defined activities concerned projects to support young entrepreneurs and to upgrade and enhance the Gela harbor.

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 8,356 square kilometers (2,608 square kilometers net to Eni). Eni's production in Norway amounted to 133 kboe/d in 2016. 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 2016 accounted for 56% 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 Main activities concerned maintenance and optimization of production, mainly at the Åsgard, Heidrun and Norne Outside (Eni's interest 11.5%) fields.

Exploration Eni holds interests in 30 Prospecting Licenses ranging from 5% to 50%, 4 of these are operated.

Eni was awarded the following exploration licenses: (i) the PL 128D license with an 11.5% interest, in 2016; and (ii) the PL 128E license with an 11.5% interest, in January 2017.

Exploration activities yielded positive results at the beginning of 2017 with a new oil and gas discovery in the PL 128/128D license nearby the production facilities of the Norne field (Eni's interest 6.9%). This new discovery is in line with Eni's exploration strategy of focusing on near-field incremental activities for a fast-track development.

Norwegian section of the North Sea

Production Eni holds interests in 2 production licenses. The main producing field is Ekofisk (Eni's interest 12.39%) in PL 018, which in 2016, produced approximately 16 kboe/d net to Eni and

Development Activities concerned the drilling of infilling wells to support production at the Ekofisk and Eldfisk fields in the PL 018. Exploration Eni holds interests in 8 Prospecting Licenses ranging from 12.39% to 45%, of which one as operator.

In 2016, Eni was awarded the operatorship of the PL 816 exploration license with a 70% interest.

Barents Sea

Eni holds interests in 17 prospecting licenses, 11 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 In March 2016, production start-up was achieved at the Goliat field (Eni operator with a 65% interest) in the Barents Sea. Field production reached the target of 100 kboe/d (65 kboe/d net to Eni) and during the year peak production of approximately 114 kboe/d (approximately 74 kboe/d net to Eni) was achieved. The field is estimated to contain reserves amounting to approximately 180 mmbbl. 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.

Exploration Eni was awarded the following exploration licenses: (i) the PL 229D (Eni operator with a 65% interest) and PL 849 (Eni's interest 30%) licenses, during the 2016; and (ii) in January 2017, the PL 900 (Eni operator with a 90% interest) and PL 901 (Eni's interest 30%) licenses.

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 6,841 square kilometers (6,328 square kilometers net to Eni). In 2016, Eni's production of oil and gas averaged 63 kboe/d. Exploration and production activities in the UK are regulated by concession contracts.

Production Eni currently holds interests in 5 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 fields are Elgin/Franklin (Eni's interest 21.87%), J Block and Jasmine (Eni's interest 33%) and Jade (Eni's interest 7%), which in 2016 accounted for 63% of Eni's production in the UK.

Development The Phase 2 development activities of West Franklin field (Eni's interest 21.87%) was completed and during the year peak production of 61 kboe/d (13 kboe/d net to Eni) was achieved.

Exploration Eni holds interest in 18 exploration licenses, of which 2 are partially in development, with interest ranging from 7% to 100%. Out of the total, 11 are operated by Eni.

In 2016, Eni was awarded the operatorship of PL2287, PL2288 and PL2292 licences with a 100% interest in the Irish Sea and Liverpool Bay area, nearby Eni operated production assets.

North Africa

Algeria

Eni has been present in Algeria since 1981. In 2016, Eni's oil&gas production averaged 98 kboe/d. Developed and undeveloped acreage of Eni's interests was 3,409 square kilometers (1,179 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 2016. 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.

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 2016.

In 2016, Eni signed with the relevant Authorities a pre-unitization agreement of the SF-SFNE fields and a 10-year extension of the fields in the area.

Other activities concerned infilling activities and production optimization at the Rod field (Eni operator with a 66% interest), also by means of the application of the Enhanced Oil Recovery WAG (Water Alternate Gas injection) technology.

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 2016.

Block 404

Production The main fields in block 404 are HBN and HBNS and satellites, which accounted for approximately 21% of Eni's production in Algeria in 2016.

Block 405b

Production Production in block 405b comes mainly from MLE-CAFC projects and accounted for approximately 13% of Eni's production in the country in 2016. The natural gas treatment plant has a production and export 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.

Production start-up was achieved at the CAFC oil project at the end of the year, with start-up of 6 wells and linkage at the existing treatment facilities of the MLE project. The development activities are expected to be completed during 2017.

Development Development and optimization activities progressed at the MLE and CAFC gas fields by means of construction and infilling activities, as well as production optimization.

Block 208

Production The El-Merk field is the main production project in the block 208 and accounted for approximately 18% of Eni's production in Algeria in 2016. Production is treated by means of a gas treatment plant for approximately 600 mmcf/d and two oil trains for 65 kbbl/d each.

Egypt

Eni has been present in Egypt since 1954. In 2016, Eni's share of production in this country amounted to 185 kboe/d and accounted for 10% of Eni's total annual hydrocarbon production. Developed and undeveloped acreage in Egypt was 28,031 square kilometers (10,665 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%) and the Ras Qattara (Eni's interest 75%) concessions. Gas production mainly comes from the operated or participated concession 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 Abu Madi West (Eni's interest 75%), located offshore the Nile Delta. In 2016, production from these large concessions accounted for approximately 98% of Eni's production in Egypt.

In addition, Eni is the operator of the Shorouk offshore block (Eni's interest 100%), where the giant Zohr discovery is located. In December 2016, Concession Agreements were ratified for the North El Hammad (Eni operator with a 37.5% interest) and North Ras El Esh (Eni's interest 50%) blocks, located in the conventional offshore of the Mediterranean Sea.

In 2016, Eni started promoting initiatives to support socio-economic development and health of local communities, in particular in the Port Said area. Eni defined a first health program in the Al Garabaa area, west of Port Said, according to Ministry of Petroleum and Ministry of Health. The program includes activities to improve and strengthen emergency services and primary health care. Exploration and production activities in Egypt are regulated by Production Sharing Agreements.

Shorouk block

In February 2016, the Egyptian Ministry of Petroleum and Mineral Resources approved the award to Eni the Zohr Development Lease that allows the start-up of the development program at the Zohr gas field and, as a consequence, the FID was sanctioned and added proved reserves for the field. The first gas is expected at the end of 2017. Eni successfully performed the first production test of two wells and drilling delineation and development activities confirming the mineral potential of discovery at approximately 30 Tcf of gas in place. Drilling activities will continue in 2017 together with construction activities of onshore gas treatment plant and offshore facilities installation.

Eni signed two agreements with major international players in the oil&gas business for the disposal of a 40% interest in the giant discovery Zohr. 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 pro-quota reimbursement of past expenditures, which amount so far at approximately \$450 million. In addition, the new partners have an option to buy a further 5% interest under the same terms. In February 2017, Eni signed a deed completing the sale of 10% interest to BP, with all authorizations from Egypt's authorities. The sale agreement with Rosneft will be finalized in the first half of 2017 and subject to necessary authorizations from Country's authorities.

Gulf of Suez

Production Production mainly comes from the Belayim field, Eni's first large oil discovery in Egypt, which produced approximately 88 kbbl/d (48 kbbl/d net to Eni) in 2016.

Development Infilling activities and production optimization were performed at the Sinai 12 and Ashrafi (Eni's interest 25%) concessions to support production capacity.

Nile Delta

North Port Said

Production Production for the year amounted to approximately 22 kboe/d (approximately 15 kboe/d net to Eni), approximately 71 mmcf/d of natural gas and approximately 1.4 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 380 ktonnes of propane, 305 ktonnes of LPG and 1.5 mmbbl of condensates.

Baltim

Production In 2016, production amounted to approximately 29 kboe/d (approximately 9 kboe/d net to Eni); approximately 42 mmcf/d of natural gas and 1.2 kbbl/d of condensates. The potential at the Baltim South West field discovery, in the conventional offshore, was upped to approximately 1 Tcf of gas in place due to successful test of the delineation well. The discovery is located near the Great Nooros Area.

Abu Madi West

Production Production comes mainly from the Nidoco NW field and satellites as a part of the Great Nooros Area project. During the year, targeting production of 85.5 kboe/d net to Eni was achieved. The start-up was achieved in 13 months following the announcement of the commercial discovery in July 2015 by means of the exploration successes in the Nooros area and the drilling of the new development wells. Production plateau of 160 kboe/d is expected in 2017 with the completion of ongoing development activities.

Ras el Barr

Production In 2016, the production amounted to approximately 67 kboe/d (approximately 20 kboe/d net to Eni), mainly gas from Ha'py, Akhen, Taurt and Seth fields.

Development Development activities concerned the ongoing activity of the sub-sea END Phase 3 development project with the drilling and completion of two wells.

El Temsah

Production This concession includes the Temsah, Denise, Tuna and DEKA fields. Production in 2016 amounted to approximately 73 kboe/d (approximately 19 kboe/d net to Eni); approximately 106 mmcf/d of natural gas and approximately 1,000 bbl/d of condensates net to Eni.

Western Desert

Production Other operated production activities are located in the Western Desert, in particular in the Melehia, Ras Qattara, West Abu Gharadig (Eni's interest 45%) and West Razzak (Eni's interest 100%) development permits containing mainly oil. Concessions in the Western Desert accounted for approximately 14% of Eni's production in Egypt in 2016.

Development Development activities were performed at the Melehia concession and concerned: (i) infilling activities and production optimization to support production capacity; (ii) start-up of the onshore gas treatment plant.

Libya

Eni started operations in Libya in 1959. Developed and undeveloped acreage were 26,635 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%); and (iv) Area F with Block 118 (Eni's interest 50%). Offshore contract areas are: (i) Area C with the Bouri oil field (Eni's interest 50%); and (ii) Area D with Blocks NC 41 and NC 169 (onshore) that feed the Western Libyan Gas Project (Eni's interest 50%). In the exploration phase, Eni is operator in the onshore contract Areas A, B and offshore Area D.

In recent years, Eni's production levels in Libya were negatively impacted by an internal revolution and a change of regime in 2011, which has led to a prolonged period of political and social instability characterized by acts of local conflict, social unrest, protests, strikes and other similar events. Those political developments forced Eni to temporarily interrupt or reduce its producing activities. In 2016, Eni's production in Libya was 353 kboe/day in line with our planned level, the highest level since 2010. Although certain positive events, the geopolitical situation in Libya remains unstable and unpredictable. In case of major unfavorable geopolitical developments in Libya including but not limited to, a resurgence of civil war, renewed internal tensions, civil disorder or any other outbreak of violence, we could be forced to shut down our operations and interrupt production at plants located in the country, which could adversely affect Eni's results from operations, cash flow and business prospects.

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) planned facilities downtime at the Mellitah treatment plant, the Sabratha production platform and the Wafa treatment facilities of the Western Libyan Gas Project; (ii) positioning and installation activities as well as linkage of the new FSO unit at the Bouri production field and start-up at the beginning of 2017; (iii) a second development phase of the Bahr Essalam field (Eni's interest 50%) with the completion of 10 offshore wells of which 9 wells already drilled in 2016. The EPCI contract was awarded to supply and installation of flowlines. First gas is expected in 2018; and (iv) the linkage of one additional production well at the Wafa field (Eni's interest 50%) and activities in order to mitigate the natural production decline in the area.

Tunisia

Eni has been present in Tunisia since 1961. In 2016, Eni's production amounted to 11 kboe/d. Eni's activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet, over a developed and undeveloped 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.

Exploration Exploration activities yielded positive results with the Larich Est-1 discovery well, which put into production through a tiein to the existing treatment facilities of the MLD concession.

Sub-Saharan Africa

Angola

Eni has been present in Angola since 1980. In 2016, Eni's production averaged 124 kboe/d. Eni's activities are concentrated in the conventional and deep offshore, over a developed and undeveloped acreage of 21,052 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 development project with production start-up achieved in February 2017.

Eni participates in other producing blocks: (i) Block 0 in Cabinda (Eni's interest 9.8%) north of the Angolan coast; (ii) Development Areas in the former Block 3 (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. Eni retains interests in other non-producing concessions, particularly the Block 35/11 (Eni operator with a 30% interest), Block 3/05-A (Eni's interest 12%), onshore Cabinda North block (Eni's interest 15%) and the Open Areas of Block 2 assigned to the Gas Project (Eni's interest 20%).

Exploration and production activities in Angola are regulated by concessions and PSAs.

Block 15/06

The activities concerned to put in production approximately 450 mmbbl of reserves by means of the development of West Hub projects, sanctioned in 2010, and East Hub project, sanctioned in September 2013.

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 2016, production started up at the M'Pungi and M'Pungi North fields and the related production ramp-up allowed achieving an overall production of approximately 81 kbbl/d (approximately 28 kbbl/d net to Eni). According to the project, further 5 fields will be put into production with completion expected in 2019. The development plan includes water and gas injection wells in line with the zero flaring policy.

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 Armada Olombendo. In the Block 15/06, with the completion of the East Hub project, production derived from five fields. Management plans to put into production two additional discoveries by the end of 2018.

Block 0

Production Block 0 is divided into Areas A and B. In 2016, production from this block amounted to approximately 272 kbbl/d (approximately 27 kbbl/d net to Eni). Oil production from Area A, deriving mainly from the Takula, Malongo and Mafumeira fields amounted to approximately 16 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 11 kbbl/d net to Eni.

Early production phase started up at the Mafumeira Sul project. Development activities progressed, with the completion expected during 2017 and a peak production of 100 kboe/d.

During the year, Eni signed the Malembo Gas Supply Agreement with the national oil company Sonagas to supply associated gas deriving from production of the Block 0 to the power plant in the Malongo area. Activities concerned the completion of the Congo River Crossing project to supply gas production of Block 0 and 14 to Angola LNG liquefaction plant (see below).

Block 3

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 2016, production from this area amounted to approximately 51 kbbl/d (approximately 5 kbbl/d net to Eni).

Block 14

Production In 2016, Development Areas in Block 14 produced approximately 104 kbbl/d (approximately 15 kbbl/d net to Eni). It is one of the most fruitful areas in the West African offshore, recording 9 commercial discoveries to date.

Its main fields are Kuito, Landana and Tombua as well as Benguela-Belize/Lobito-Tomboco. Associated gas of the area was delivered via Congo River Crossing (see Block 0) to the A-LNG liquefaction plant (see below).

Block 15

Production The block produced approximately 329 kbbl/d (approximately 41 kbbl/d net to Eni) in 2016. Production derives mainly from the Kizomba discovery area with: (i) the Hungo/Chocalho fields, started-up in 2004 as part of phase A of the global development plan of the Kizomba reserves; (ii) the Kissanje/Dikanza fields, started up in 2005, as part of Phase Kizomba B; (iii) satellites Kizomba Phase 1 project, started up in 2012, and Phase 2 project, started up in 2015. In 2016, the fields of Kizomba area produced approximately 224 kbbl/d (approximately 29 kbbl/d net to Eni). Other main fields in Block 15 are Mondo and Saxi/Batuque fields which produced approximately 105 kbbl/d (approximately 12 kbbl/d net to Eni) in 2016. These fields are operated by FPSO units. Development Development activities concerned the Kizomba

satellites Phase 2 which will be started up leveraging on the production and treatment facilities in the area.

The LNG business in Angola

Eni holds a 13.6% interest of the Angola LNG consortium that manages a LNG plant, located in Soyo, with a processing capacity of approximately 1 bcf/d of natural gas, producing 5.2 mmtonnes/y of LNG and over 50 kbbl/d of condensates and LPG. The plant envisages the development of 10,594 bcf of gas in 30 years. Start-up was achieved in April 2016, with an average production of approximately 6 kboe/d net to Eni.

Congo

Eni has been present in Congo since 1968. In 2016, production averaged 98 kboe/d net to Eni. Eni's activities are concentrated in the conventional and deep offshore facing Pointe-Noire and onshore over a developed and undeveloped acreage of 2,451 square kilometers (1,168 square kilometers net to Eni).

In December 2016, Eni signed a framework agreement with the Republic of the Congo aimed at integrated development and monetization of gas produced in the Country, in line with three strategic guidelines of access to energy, local development and zero flaring in the development programs of oil and gas discoveries. 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 56%), 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 (Eni 65%), Litchendjili (Eni 65%), Zingali and Loufika (Eni's interest 100%) fields, with an overall production of approximately 89 kboe/d (approximately 74 kboe/d net to Eni). Other relevant not operated producing areas are represented by a 35% interest in the Pointe Noire Grand Fond, PEX and Likouala permits, with an overall production of approximately 68 kboe/d (approximately 24 kboe/d net to Eni).

In December 2016, production ramp-up was achieved at the Nené Marine field, in the Marine XII block with the completion of the second development phase, sanctioned in 2015.

Development activities progressed at the Litchendjili production field in the Marine XII block and during the year the peak production of approximately 16 kboe/d was achieved (approximately 11 kboe/d). Gas production feeds the CEC power plant (Eni's interest 20%). The Project Integreé Hinda (PIH) was completed in the year. The project provided to support 22 local communities in the M'Boundi area and involved approximately 25,000 people. In the 2010-2016 period, this program provided to improve primary education, access to water, maternal and child health as well as the construction of training center for the development of farming. Additional ongoing projects include the construction of facilities to support the enhancement of local culture with restructuring and rehabilitation initiatives in the Brazzaville, Pointe Noire and Makoua area.

Ghana

Eni has been present in Ghana since 2009 and currently is the operator of the Offshore Cape Three Points (Eni's interest 44.44%) permits which is regulated by a concession agreement. In March 2016, Eni was awarded the operatorship of the Cape Three Points Block 4 exploration license (Eni's interest 42.47%) in the offshore of the Country. The new block covers an area of approximately 1,000 square kilometers in water depths ranging from 100 to 1,200 meters and is located near the operated OCTP block. In case of exploration success, the block will benefit from the OCTP project infrastructures, under development.

Development Development activities concerned the OCTP integrated oil&gas development plan. First oil is expected in 2017 and first gas in 2018. In 2016, the drilling activity of 18 development wells was completed and the renovation of a FPSO unit was performed. Contracts were awarded for the installation of sea-lines and the construction of onshore gas plant.

The OCTP project will be developed in compliance with the highest

environmental requirements defined in the Performance Standards on Environmental and Social Sustainability of the International Finance Corporation (IFC), which is part of the World Bank Group. The use of the most advanced technologies, the re-injection of produced water as well as zero gas flaring during production activities will allow to minimize environmental impact. Furthermore, the non-associated gas, which will be produced, will be used in existing power plants and in the future will feed new plants. The Livelihood Restoration Plan started in the year. The project will support local communities nearby the OCTP development program during the 2016-2020 period. The target is to sustainably restore and improve living conditions of affected households through project options appropriate to the socio-economic context. The program provides initiatives in agriculture, livestock breeding, fishing and micro-entrepreneurship.

The sustainability project in the Sanzule area was completed in 2016 with the construction and rehabilitation of health facilities and the training of local health workers.

Mozambique

Eni has been present in Mozambique since 2006, following the acquisition of the Area 4 offshore Rovuma Basin block, located in the north of the country. Eni currently holds a 50% indirect interest in the block through a 71.4% stake in Eni East Africa,

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 34%), in the deep offshore of Zambesi.

In March 2017, ExxonMobil and Eni signed sale and purchase agreement to acquire a 25% indirect interest in the Area 4 block, offshore Mozambique. The agreed terms include a cash price of approximately \$2.8 billion. The acquisition will be completed subject to satisfaction of certain conditions precedent, including clearance from Mozambican and other regulatory authorities. Following completion of the transaction, Eni East Africa will be co-owned by Eni and ExxonMobil with a 35.7% stake and the remaining interest of 28.6% by CNPC. Eni will continue to lead the Coral Floating LNG project and all upstream operations in Area 4, while ExxonMobil will lead the construction and operation of natural gas liquefaction facilities onshore. This operating model will enable 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 Coral South Development Plan, which was approved by the Government of Mozambique in February 2016, envisages the installation of a floating unit for the treatment, liquefaction and storage of natural gas (Floating LNG - FLNG) with a capacity of over 3.3 mmtonnes/y fed by 6 subsea wells. Eni expects to produce up to 5 TCF of gas with a start-up expected in mid-2022. In October 2016, Eni and its Area 4 partners signed a binding agreement with BP for the sale of the entire volumes of LNG produced by the Coral South Project, for a period of over twenty years. In November 2016, Eni's Board of Directors approved the investment for the first development phase of the Coral discovery. The FID on the project will turn effective once all Area 4 partners sanctioned it and the project financing, which is currently being finalized, will be underwritten.

The development plan of the Mamba comprises the construction of two onshore LNG trains with a combined capacity of 10 mmtonnes/y and the drilling of 16 subsea wells, with start-up in 2023. Eni expects to produce up to 14 TcF of gas according to its independent industrial plan, coordinated with the operator of Area 1 (Anadarko). The FID is expected in 2018.

Leveraging on Eni's cooperation model, a medium-long-term program was defined to support local communities also involving all local stakeholders as integrated part of the development activity. The guidelines of the program include projects to develop the socioeconomic conditions of local communities and respect for biodiversity.

In particular, during 2016, certain projects were completed, such as: (i) initiatives in the primary education in the Pemba area with professional and non-formal training programs and supply of school equipment and stuff; (ii) the renovation of the connecting road to the fish market in the Palma area; and (iii) specific training initiatives dedicated to doctors, nurses and hospital technicians.

Nigeria

Eni has been present in Nigeria since 1962. In 2016, Eni's oil&gas production averaged 117 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 85%) and OPL 245 (Eni's interest 50%), holding interests in OML 118 (Eni's interest 12.5%) and in OML 119 and 116 Service Contracts. As partners 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 and 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. On January 27, 2017, Eni's subsidiary Nigerian Agip Exploration Ltd became aware of an Interim Order of Attachment ("Order") issued by the Nigerian Federal High Court, sitting in Abuja, upon request from the Economic and Financial Crime Commission (EFCC), attaching the property OPL 245, pending the Nigerian proceeding. Both Eni and Shell made a prompt application to discharge the Order. On March 17, 2017, the Nigerian Court discharged the Order. On that basis, management has concluded that no impairment of the asset was required. After the inception of the judicial proceeding in Italy, which dates back to July 2014, Eni's Board of Statutory Auditors jointly with the Eni Watch Structure has engaged a US leading law firm to perform an independent review of the issue. Based on the outcome of this review, during which the law firm appointed by Eni has also assessed material and the information made available from the judicial authorities, no wrongdoing has been detected on Eni side in the awarding process to Eni of the license. For further information see also Notes No. 16 "Property, Plant and Equipment" and No. 38 "Guarantees, commitments and risks" to Consolidated Financial Statements of the Annual report on Form 20-F 2016.

In January 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 in the onshore, offshore and ultra-deep-water areas; (ii) cooperation requirements for the rehabilitation and enhancement

of Port Harcourt refinery; (iii) the fast track development 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.

In 2016, programs progressed to support the local community in the Niger Delta, with initiatives in the public infrastructure, primary education services, health and access to energy programs as well as training programs to promote the socioeconomic development, in particular in the agricultural sector.

In November 2016, the twentieth edition of the Farmer Day of the Green River Project was held. The Green River Project, which was launched in 1987, supports the development and sustainable management of farms and processing centers of agricultural products. The project directly involved 35,000 farmers, benefiting 500,000 people in 120 communities.

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 e 63

Production Onshore four licenses produced approximately 48 kboe/d and accounted for over 41% of Eni's production in Nigeria in 2016. 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 reserves 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 Kwale-Okpai with a 480 MW generation capacity. In 2016, supplies to this power station were an overall amount of approximately 53 mmcf/d, corresponding to approximately 10 kboe/d (approximately 2 kboe/d net to Eni).

Block OML 118

Production The Bonga oil field produced approximately 20 kboe/d net to Eni in 2016. 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, delivered to the Bonny liquefaction plant. Development The development activities concerned drilling activity and production start-up of three additional wells, two production and one water-injection, at the Bonga field.

Block OML 125

Production Production derived mainly from the Abo field, which yielded approximately 20 kboe/d net to Eni in 2016. Production is supported by an FPSO unit with a 40 kboe/d capacity and an 800 kboe storage capacity.

SPDC Joint Venture (NASE)

In 2016, production from the SPDC JV accounted for approximately 22% of Eni's production in Nigeria (approximately 25 kboe/d). The development activities concerned: (i) the drilling campaign within the integrated project in the Gbaran-Ubie area in the OML 28 block (Eni's interest 5%), aimed to supply natural gas to the Bonny liquefaction plant. Start-up was achieved in the second half of 2016; and (ii) the OML 43 block (Eni's interest 5%), where the development plan of the Forcados-Yokri field provides the hook-up the last 12 out of 23 production wells already drilled, the upgrading of existing flowstations and the construction of transport facilities. Start-up is expected in the first half of 2017.

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 on six trains. Natural gas supplies to the plant are currently provided under gas supply agreements from the SPDC JV and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 blocks (Eni's interest 20%) with an average amount of approximately 2,825 mmcf/d for the next four years (approximately 265 mmcf/d net to Eni corresponding to approximately 49 kboe/d). 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 Co.

Kazakhstan

Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field, partner in the North Caspian Sea PSA, which is in charge of Kashagan operations and holds a 50% interest for exploration and production activities of the Isatay block, located in the Kazakh sector of the Caspian Sea.

Kashagan

Eni holds a 16.81% working 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.

Production On September 28, 2016, production re-started at the Kashagan field (Eni's interest 16.81%) with the completion of works to fully replace the damaged pipelines following the gas leak occurred at the end of 2013. The production of 185 kboe/d was achieved by year-end. The production capacity of 370 kbbl/d planned for the Phase 1 is expected to be achieved during 2017, when gas reinjection comes online.

Within the agreements with local Authorities, Eni has been conducting training program 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 2016, production of the Karachaganak field averaged 231 kbbl/d of liquids (61 kbbl/d net to Eni) and 925 mmcf/d of natural gas (247 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 volumes 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 volumes of non-stabilized liquid production (approximately 16 kbbl/d) are marketed at the Russian terminal in Orenburg.

Development The Expansion Project is currently under study. The project targets to install, in stages, the gas treatment plants and re-injection facilities to support liquids' production profile. The development plan is currently in the phase of technical and marketing definition of its first development phase, aimed to increase the capacity of gas re-injection.

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, maintenance of hospitals and roads, building of heating plants and sport centers.

Moreover, following the re-definition of the Sanitary Protection Zone (SPZ) associated to the ongoing development projects and in accordance with the international standards and best practices, a project of relocation of the inhabitants from Berezovka and Bestau villages progressed. In 2016, the first phase of the project, which started in 2015, was completed with the relocation of part of the population, the construction of schools and roads and interventions to ensure the supply of gas and water. The activities progressed to relocate the remaining population and are expected to be completed during 2017.

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 2016, Eni's production mainly composed of gas, amounted to 16 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 34,489 square kilometers (25,181 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 consists mainly of gas and derives from the Sanga Sanga permit (Eni's interest 37.8%) with seven production fields. This gas is treated at the Bontang liquefaction plant, one of the largest in the world. Liquefied gas is exported to the Japanese, South Korean and Taiwanese markets.

In 2016, production start-up was achieved at the Bangka project (Eni's interest 20%) in the East Kalimantan.

Development The ongoing development activities that will ensure gas supplies to the Bontang liquefaction plant include the Jangkrik project (Eni operator with a 55% interest), in the Kalimantan offshore. This project is in the final execution phase with all the deepoffshore development subsea wells already drilled and the Floating Production Unit for gas and condensate treatment in the final stage of construction, as well as the construction of transportation and receiving facilities onshore. Production start-up is planned in 2017. 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, will leverage on the synergies with existing facilities to reduce costs and time of the execution of the future subsea development and confirms the success of Eni's near field exploration and appraisal strategy.

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 67 kbbl/d net to Eni in 2016. At the beginning of March 2016, three new generation plants for the oil, gas and water treatment (Initial Production Facilities –IPF) started. Those plants together with five existing restructured and modernized facilities increased oil and natural gas treatment capacity of Zubair field to approximately 650 kbbl/d and will ensure the maximization of the associated gas utilization. In addition, these new facilities have also a water re-injection capacity of approximately 300 kbbl/d that will boost the Zubair's hydrocarbons production and will achieve production plateau.

The first stage of development activities (Rehabilitation Plan) of Zubair field was completed with the start-up of these new facilities. Development Ongoing development activities concerned an additional development phase (Enhanced Redevelopment Plan) of the Zubair field, to achieve a production plateau of 700 kbbl/d and will ensure the application of associated gas to power generation.

Supporting programs for the local community progressed with main activities related to infrastructural projects aimed at strengthening basic services, to support teaching activities, renovate school buildings and access to water as well as sanitation programs and roads construction. In addition, in 2016, a primary school was opened in the Al Barjazia area.

Pakistan

Eni has been present in Pakistan since 2000. In 2016, Eni's production mainly composed of gas amounted to 32 kboe/d, over a developed and undeveloped acreage of 21,663 square kilometers (8,746 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), Latif (Eni's interest 33.33%) and Zamzama (Eni's interest 17.75%), which in 2016 accounted for approximately 79% 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 2016, Eni's production averaged 10 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 include: (i) a program to mitigate the natural field production decline; and (ii) projects in order to improve safety, efficiency and environment performance.

Americas

Ecuador

Eni has been present in Ecuador since 1988. Operations are performed in Block 10 (Eni's interest 100%) located in the Oriente Basin, in the Amazon forest, over a developed acreage of 1,985 square kilometers net to Eni. In 2016, Eni's production averaged 10 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 December 2016, development activities of the Villano Phase VI project started up with the drilling of the first of two infilling wells.

Trinidad and Tobago

Eni has been present in Trinidad and Tobago since 1970. In 2016, Eni's production averaged 70 mmCF/d (equal to 13 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 long-term contracts with prices linked to the United States, as well as alternative destinations markets.

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 2,317 square kilometers (1,186 square kilometers net to Eni). In 2016, Eni's oil&gas production was 93 kboe/d.

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

Gulf of Mexico

Eni holds interests in 84 exploration and production blocks in the shallow and deep offshore of the Gulf of Mexico, of which 44 are operated by Eni.

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. During the year, production start-ups were achieved at: (i) the Heidelberg project (Eni's interest 12.5%) in the deep-water Gulf of Mexico, with a production of approximately 3 kboe/d net to Eni. During 2017 planned development activities will be completed; (ii) the Phase 2 development of Lucius field with production ramp-up to 100 kboe/d (8 kboe/d net to Eni); and (iii) the Devil's Tower South-West production well within the development program of the operated Devil's Tower field, with a production of approximately 2 kboe/d.

Texas

Production Production comes from the Alliance area (Eni's interest 27.5%), in the Fort Worth basin. This asset was acquired following an

agreement with Quicksilver for unconventional gas reserves (shale gas). In 2016, Eni's production amounted to more than 4 kboe/d.

Alaska

Eni holds interests in 43 exploration and development blocks in Alaska, with interests ranging from 30 to 100%; Eni is the operator in 27 of these blocks.

Production The main fields are Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni's interest 30%) fields with a 2016 overall net production of approximately 24 kbbl/d.

Venezuela

Eni has been present in Venezuela since 1998. In 2016, Eni's production averaged 61 kboe/d. Activity is concentrated both offshore (Gulf of Venezuela and Gulf of Paria) 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). Exploration and production of the oil Junin 5 and Corocoro fields are regulated by the terms of the so-called Empresa Mixta. Under the new legal framework, only a company incorporated under the law of Venezuela is entitled to conduct petroleum operations. A stake of at least 60% in the capital of such company is held by an affiliate of the Venezuela state oil company, PDVSA, preferably Corporación Venezuelana de Petróleo (CVP). The Perla gas field is operated by Cardon IV, a joint venture 50%-50% Eni and Repsol.

Production Eni's production comes from the giant Perla gas field, located in the Gulf of Venezuela, the giant 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.

Development Development activities concerned: (i) ongoing drilling activities at the Junin 5 field. Possible optimization of development

program is currently under evaluation; and (ii) the completion of the first development phases at the Perla field. The project includes two additional development phases to achieve a production plateau of approximately 1,200 mmcf/d.

In 2016, certain wind farms were built to supply electricity to the Punta Macolla area.

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 2016, Eni's production of oil and natural gas averaged 24 kboe/d. Activities are focused on conventional and deep offshore fields, over a developed and undeveloped acreage of 16,868 square kilometers (10,383 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 32.5%). In addition,

Eni holds interest in 6 exploration licenses, of which 1 in the JPDA. 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 22 bcf/y in 2016 (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 140 kboe/d (approximately 13 kboe/d net to Eni) in 2016. 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.

Estimated net proved hydrocarbon reserves by geographic area (mmboe)

(at December 31) Italy Rest of Europe North Africa* *Egypt (of which) Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total 2014 Net proved hydrocarbons reserves 503 544 1,756 1,320 1,069 290 960 160 6,602 Consolidated subsidiaries 503 544 1,740 1,239 1,069 285 232 160 5,772 Equity-accounted entities 16 81 5 728 830 Developed 401 335 919 725 589 115 214 135 3,433 Consolidated subsidiaries 401 335 904 702 589 112 188 135 3,366 Equity-accounted entities 15 23 3 26 67 Undeveloped 102 209 837 595 480 175 746 25 3,169 Consolidated subsidiaries 102 209 836 537 480 173 44 25 2,406 Equity-accounted entities 1 58 2 702 763 2015 Net proved hydrocarbons reserves 465 495 1,708 1,369 1,198 426 1,079 150 6,890 Consolidated subsidiaries 465 495 1,694 1,282 1,198 422 269 150 5,975 Equity-accounted entities 14 87 4 810 915 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 2016 Net proved hydrocarbons reserves 354 426 2,446 1,293 1,399 1,221 493 1,006 145 7,490 Consolidated subsidiaries 354 426 2,432 1,293 1,317 1,221 491 227 145 6,613 Equity-accounted entities 14 82 2 779 877 Developed 287 374 971 352 835 966 177 554 111 4,275 Consolidated subsidiaries 287 374 957 352 809 966 175 205 111 3,884 Equity-accounted entities 14 26 2 349 391 Undeveloped 67 52 1,475 941 564 255 316 452 34 3,215 Consolidated subsidiaries 67 52 1,475 941 508 255 316 22 34 2,729 Equity-accounted entities ^{56 430 486}

Estimated net proved liquids reserves by geographic area (mmbbl)

(at December 31) Italy Rest of Europe North Africa* *Egypt (of which) Sub-Saharan Africa Kazakhstan Rest of Asia Americas Australia and Oceania Total 2014 Net proved liquids reserves 243 331 790 756 697 132 264 13 3,226 Consolidated subsidiaries 243 331 776 739 697 131 147 13 3,077 Equity-accounted entities 14 17 1 117 149 Developed 184 174 534 477 306 64 142 12 1,893 Consolidated subsidiaries 184 174 521 470 306 64 116 12 1,847 Equity-accounted entities 13 7 26 46 Undeveloped 59 157 256 279 391 68 122 1 1,333 Consolidated subsidiaries 59 157 255 269 391 67 31 1 1,230 Equity-accounted entities 1 10 1 91 103 2015 Net proved liquids reserves 228 305 834 803 771 262 347 9 3,559 Consolidated subsidiaries 228 305 821 787 771 262 189 9 3,372 Equity-accounted entities 13 16 158 187 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 2016 Net proved liquids reserves 176 264 748 281 824 767 307 303 9 3,398 Consolidated subsidiaries 176 264 735 281 809 767 307 163 9 3,230 Equity-accounted entities 13 15 140 168 Developed 132 228 505 205 515 556 124 165 8 2,233 Consolidated subsidiaries 132 228 492 205 507 556 124 143 8 2,190 Equity-accounted entities 13 8 22 43 Undeveloped 44 36 243 76 309 211 183 138 1 1,165 Consolidated subsidiaries 44 36 243 76 302 211 183 20 1 1,040 Equity-accounted entities 7 118 125 Estimated net proved natural gas reserves by geographic area (bcf)

		Rest of Europe	North Africa*		Sub-Saharan				Australia and
				(of which) *Egypt	Africa	Kazakhstan	Rest of Asia	Americas	Oceania
(at December 31)	Italy									Total
2014
Net proved natural gas reserves	1,432	1,171	5,306		3,095	2,049	864	3,821	807	18,545
Consolidated subsidiaries	1,432	1,171	5,291		2,744	2,049	846	468	807	14,808
Equity-accounted entities			15		351		18	3,353		3,737
Developed	1,192	887	2,125		1,360	1,553	271	399	675	8,462
Consolidated subsidiaries	1,192	887	2,110		1,271	1,553	261	393	675	8,342
Equity-accounted entities			15		89		10	6		120
Undeveloped	240	284	3,181		1,735	496	593	3,422	132	10,083
Consolidated subsidiaries	240	284	3,181		1,473	496	585	75	132	6,466
Equity-accounted entities					262		8	3,347		3,617
2015
Net proved natural gas reserves	1,304	1,044	4,811		3,101	2,354	890	4,020	771	18,295
Consolidated subsidiaries	1,304	1,044	4,798		2,714	2,354	878	439	771	14,302
Equity-accounted entities			13		387		12	3,581		3,993
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
2016
Net proved natural gas reserves	977	878	9,273	5,520	3,135	2,485	1,007	3,837	741	22,333
Consolidated subsidiaries	977	878	9,258	5,520	2,767	2,485	1,003	353	741	18,462
Equity-accounted entities			15		368		4	3,484		3,871
Developed	845	801	2,546	799	1,755	2,239	284	2,120	559	11,149
Consolidated subsidiaries	845	801	2,531	799	1,651	2,239	280	338	559	9,244
Equity-accounted entities			15		104		4	1,782		1,905
Undeveloped	132	77	6,727	4,721	1,380	246	723	1,717	182	11,184
Consolidated subsidiaries	132	77	6,727	4,721	1,116	246	723	15	182	9,218
Equity-accounted entities					264			1,702		1,966

Production of oil and natural gas by Country(a)	(kboe/d)	2014	2015	2016
Italy		179	169	133
Rest of Europe		190	185	201
Croatia		7	4	5
Norway		112	105	133
United Kingdom		71	76	63
North Africa		567	662	647
Algeria		109	96	98
Egypt		206	189	185
Libya		239	365	353
Tunisia		13	12	11
Sub-Saharan Africa		325	341	339
Angola		84	101	124
Congo		106	103	98
Nigeria		135	137	117
Kazakhstan		88	95	111
Rest of Asia		98	135	127
China		4	3	2
India		1	1
Indonesia		16	17	16
Iran		1	22
Iraq		21	40	67
Pakistan		45	41	32
Turkmenistan		10	11	10
Americas		125	147	177
Ecuador		12	11	10
Trinidad & Tobago		11	13	13
United States		92	98	93
Venezuela		10	25	61
Australia and Oceania		26	26	24
Australia		26	26	24
Total outside Italy		1,419	1,591	1,626
		1,598	1,760	1,759
of which equity-accounted entities		22	34	75
Angola		2		6
Indonesia		5	5	4
Tunisia		5	4	4
Venezuela		10	25	61

(a) Includes volumes of gas consumed in operations (478, 397 and 442 mmcf/d in 2016, 2015 and 2014, respectively).

Oil and natural gas production sold	2014	2015	2016
Oil and natural gas production (mmboe)	583.1	642.4	643.8
Change in inventories other	(4.2)	(1.9)	(3.1)
Own consumption of gas	(29.4)	(26.4)	(32.1)
Oil and natural gas production sold(b)	549.5	614.1	608.6
Oil (mmbbl)	299.78	330.12	320.13
- of which to R&M	184.74	201.92	216.24
Natural gas (bcf)	1,371	1,560	1,574
- of which to G&P	371	394	347

(b) Includes 24 mmboe of equity-accounted entities production sold in 2016 (11.4 and 6.1 mmboe in 2015 and 2014, respectively).

Liquids production by Country	(kbbl/d)	2014	2015	2016
Italy		73	69	47
Rest of Europe		93	85	109
Norway		62	57	86
United Kingdom		31	28	23
North Africa		252	272	244
Algeria		83	79	77
Egypt		88	96	76
Libya		73	89	84
Tunisia		8	8	7
Sub-Saharan Africa		231	256	248
Angola		75	96	109
Congo		80	78	71
Nigeria		76	82	68
Kazakhstan		52	56	65
Rest of Asia		37	78	79
China		4	3	2
Indonesia		2	3	4
Iran		1	22
Iraq		21	40	64
Turkmenistan		9	10	9
Americas		84	87	83
Ecuador		12	11	10
United States		62	64	59
Venezuela		10	12	14
Australia and Oceania		6	5	3
Australia		6	5	3
Total outside Italy		755	839	831
		828	908	878
of which equity-accounted entities		15	17	19
Angola				1
Indonesia		1	1	1
Tunisia		4	4	3
Venezuela		10	12	14

Oil and natural gas production available for sale(a)	(kboe/d)	2014	2015	2016
Italy		171	161	127
Rest of Europe		184	179	195
North Africa		532	635	611
Sub-Saharan Africa		307	324	316
Kazakhstan		85	92	107
Rest of Asia		91	128	118
Americas		122	144	174
Australia and Oceania		25	25	23
		1,517	1,688	1,671
of which equity-accounted entities		20	33	71
North Africa		4	4	3
Sub-Saharan Africa		2		4
Rest of Asia		4	5	4
Americas		10	24	60

(a) Do not include natural gas consumed in operation.

Natural gas production by Country(a)	(mmcf/d)	2014	2015	2016
Italy		583.8	546.6	471.2
Rest of Europe		535.2	551.8	501.8
Croatia		38.2	21.2	26.5
Norway		274.2	264.6	258.3
United Kingdom		222.8	266.0	217.0
North Africa		1,724.2	2,143.2	2,197.1
Algeria		141.3	94.1	115.5
Egypt		649.8	510.1	597.4
Libya		911.2	1,517.3	1,464.8
Tunisia		21.9	21.7	19.4
Sub-Saharan Africa		517.8	469.2	493.4
Angola		48.6	32.5	78.1
Congo		145.1	136.8	148.5
Nigeria		324.1	299.9	266.8
Kazakhstan		200.7	218.3	254.0
Rest of Asia		333.6	313.9	264.6
India		3.7	2.6
Indonesia		75.8	78.9	67.3
Iraq				19.2
Pakistan		248.2	226.4	172.1
Turkmenistan		5.9	6.0	6.0
Americas		218.6	326.0	511.2
Trinidad & Tobago		60.3	70.4	69.7
United States		157.5	186.7	186.7
Venezuela		0.8	68.9	254.8
Australia and Oceania		110.5	111.8	113.9
Australia		110.5	111.8	113.9
Total outside Italy		3,640.6	4,134.2	4,336.0
		4,224.4	4,680.8	4,807.2
of which equity-accounted entities		39.6	99.1	307.6
Angola		10.3	0.9	29.1
Indonesia		23.2	24.1	18.8
Tunisia		5.3	5.2	4.9
Venezuela		0.8	68.9	254.8

(a) Includes volumes of gas consumed in operations (478, 397 and 442 mmcf/d in 2016, 2015 and 2014, respectively).

Natural gas production available for sale(b)	(mmcf/d)	2014	2015	2016
Italy		541	503	436
Rest of Europe		498	515	468
North Africa		1,536	1,993	2,003
Sub-Saharan Africa		418	378	369
Kazakhstan		181	199	234
Rest of Asia		297	278	214
Americas		205	311	495
Australia and Oceania		106	107	110
		3,782	4,284	4,329
of which equity-accounted entities		28	90	286
North Africa		3	3	3
Sub-Saharan Africa		7		16
Rest of Asia		18	19	15
Americas			68	252

(b) Do not include natural gas consumed in operation.

Average realizations		2014		2015 2016
Liquids	Consolidated	Equity-accounted	Consolidated	Equity-accounted	Consolidated	Equity-accounted
(\$/bbl)	subsidiaries	entities	subsidiaries	entities	subsidiaries	entities
Italy	87.80		43.46		33.19
Rest of Europe	88.80		45.88		39.97
North Africa	88.99	17.94	46.66	18.03	39.43	17.93
of which: Egypt					33.05
Sub-Saharan Africa	93.45		49.91		41.92
Kazakhstan	91.86		48.26		39.61
Rest of Asia	77.99	65.90	40.10	27.89	36.89	34.95
Americas	79.13	81.48	43.36	38.18	34.86	32.39
Australia and Oceania	91.61		45.84		37.96
	88.90	70.56	46.46	35.15	39.33	30.85
Natural gas
(\$/kcf)
Italy	8.74		6.92		4.93
Rest of Europe	8.49		6.30		4.49
North Africa	8.08	6.08	4.69	3.78	3.29	1.85
of which: Egypt					3.82
Sub-Saharan Africa	2.12		1.49		1.41
Kazakhstan	0.62		0.47		0.34
Rest of Asia	6.18	15.64	4.83	9.27	3.50	5.92
Americas	3.96		2.20	4.24	1.94	4.17
Australia and Oceania	7.46		5.07		3.60
	6.83	14.13	4.54	5.30	3.20	4.25
Hydrocarbons
(\$/boe)
Italy	64.80		40.36		29.27
Rest of Europe	67.87		40.21		33.27
North Africa	65.36	21.43	34.61	18.60	26.46	16.27
of which: Egypt					26.29
Sub-Saharan Africa	73.18		40.92		35.08
Kazakhstan	57.20		30.02		24.52
Rest of Asia	52.75	83.12	35.18	49.42	31.18	32.76
Americas	59.94	81.48	31.71	30.72	25.45	24.95
Australia and Oceania	52.46		31.51		22.00
	65.36	72.19	36.54	31.95	29.30	25.05
ENI's GROUP		2014		2015		2016
Liquids (\$/bbl)		88.71		46.30	39.18
Natural gas (\$/kcf)		6.87		4.55		3.27
Hydrocarbon (\$/boe)		65.49		36.47		29.14

Net developed and undeveloped acreage	(square kilometers)	2014	2015	2016
Europe		44,842	45,123	45,380
Italy		17,297	16,975	16,767
Rest of Europe		27,545	28,148	28,613
Africa		159,341	157,441	152,676
North Africa		21,693	25,699	29,392
Sub-Saharan Africa		137,648	131,742	123,284
Asia		109,237	117,183	109,761
Kazakhstan		869	869	869
Rest of Asia		108,368	116,314	108,892
Americas		7,943	6,628	5,696
Australia and Oceania		13,376	16,333	10,383
Total		334,739	342,708	323,896

Principal oil and natural gas interests at December 31, 2016

		Number	Gross	Net	Gross	Net		Number of	Number of
	Commencement of operations	of interests	developed(a)(b) acreage	developed(a)(b) acreage	undeveloped(a) acreage	undeveloped(a) acreage	Types of fields/acreage	producing fields	other fields
EUROPE		295	15,693	10,827	51,758	34,553		117	88
Italy	1926	146	10,498	8,775	10,320	7,992	Onshore/Offshore	78	60
Rest of Europe		149	5,195	2,052	41,438	26,561		39	28
Croatia	1996	2	1,975	987			Offshore	10	3
Cyprus	2013	3			12,523	10,018	Offshore
Greenland	2013	2			4,890	1,909	Offshore
Montenegro	2016	4			1,228	614	Offshore
Norway	1965	57	2,311	452	6,045	2,156	Offshore	19	23
Portugal	2014	3			4,547	3,182	Offshore
United Kingdom	1964	67	909	613	5,932	5,715	Offshore	10	2
Other countries		11			6,273	2,967	Onshore/Offshore
AFRICA		264	46,384	11,729	264,600	140,947		263	121
North Africa		121	14,292	5,738	54,122	23,654		104	54
Algeria	1981	42	3,222	1,148	187	31	Onshore	36	7
Egypt	1954	57	5,508	2,074	22,523	8,591	Onshore/Offshore	41	23
Libya	1959	11	1,962	958	24,673	12,336	Onshore/Offshore	6	20
Morocco	2016	1			6,739	2,696	Offshore
Tunisia	1961	10	3,600	1,558			Onshore/Offshore	21	4
Sub-Saharan Africa		143	32,092	5,991	210,478	117,293		159	67
Angola	1980	57	8,160	1,024	12,892	3,343	Onshore/Offshore	57	19
Congo	1968	25	1,794	971	657	197	Onshore/Offshore	23	2
Gabon	2008	4			6,217	6,217	Onshore/Offshore		1
Ghana	2009	3			1,353	579	Offshore		1
Ivory Coast	2015	1			954	286	Offshore
Kenya	2012	7			61,363	41,173	Offshore
Liberia	2012	1			2,341	585	Offshore
Mozambique	2007	6			3,911	1,956	Offshore		6
Nigeria	1962	34	22,138	3,996	8,631	3,374	Onshore/Offshore	79	38
South Africa	2014	1			65,696	26,279	Offshore
Other countries		4			46,463	33,304	Onshore
ASIA		59	18,165	6,016	198,024	103,745		26	17
Kazakhstan	1992	6	2,391	442	2,542	427	Onshore/Offshore	2	4
Rest of Asia		53	15,774	5,574	195,482	103,318		24	13
China	1984	8	77	13	7,056	7,056	Offshore	5
India	2005	1			13,110	5,244	Offshore
Indonesia	2001	14	4,246	1,603	30,243	23,578	Onshore/Offshore	8	12
Iraq	2009	1	1,074	446			Onshore	1
Myanmar	2014	4			24,080	13,558	Onshore/Offshore
Pakistan	2000	14	10,177	3,332	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		148	4,948	3,208	8,154	2,488		52	11
Ecuador	1988	1	1,985	1,985			Onshore	1	2
Mexico	2015	3			67	67	Offshore		3
Trinidad & Tobago	1970	1	382	66			Offshore	6
United States	1968	129	1,320	660	997	526	Onshore/Offshore	42	4
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		14	1,140	709	15,728	9,674		2	4
Australia	2001	14	1,140	709	15,728	9,674	Offshore	2	4
Total		780	86,330	32,489	538,264	291,407		460	241

(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.

Capital expenditure	(€ million)	2014	2015	2016
Acquisition of proved and unproved properties				2
North Africa				2
Exploration		1,030	566	417
Italy		1
Rest of Europe		132	133	11
North Africa		177	232	312
Sub-Saharan Africa		511	157	30
Rest of Asia		89	15	57
America		109	29	7
Australia and Oceania		11
Development		9,021	9,341	7,770
Italy		880	679	407
Rest of Europe		1,574	1,264	590
North Africa		832	1,570	2,447
Sub-Saharan Africa		3,085	2,998	2,176
Kazakhstan		521	835	707
Rest of Asia		1,105	1,333	1,213
America		921	637	220
Australia and Oceania		103	25	10
Other expenditure		105	73	65
		10,156	9,980	8,254

Reserves life index	(years)	2014	2015	2016
Italy		7.7	7.5	7.2
Rest of Europe		7.8	7.3	5.8
North Africa		8.5	7.1	10.4
Sub-Saharan Africa		11.1	11.0	11.2
Kazakhstan		33.4	34.5	30.5
Rest of Asia		8.1	8.6	10.5
America		21.3	20.1	15.5
Australia and Oceania		17.8	16.0	16.1
		11.3	10.7	11.6

Reserves replacement ratio	(%)	2014			2015		2016
		organic	all sources	organic	all sources	organic	all sources
Italy		106	106	38	38
Rest of Europe		77	81	28	28	5	5
North Africa		78	78	80	80	413	413
Sub-Saharan Africa		182	176	153	139	124	124
Kazakhstan		206	206	473	473	158	158
Rest of Asia		156	156	375	375	243	243
Americas		87	87	324	322
Australia and Oceania						44	44
		112	112	148	145	193	193

Exploratory wells activity

		Wells completed(a)						Wells in progress at Dec. 31(b)
	2014		2015		2016		2016
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Gross	Net
Italy		0.6				1.0	4.0	2.3
Rest of Europe		4.3		2.2	0.1	0.4	9.0	2.3
North Africa	3.5	4.3	3.3	5.8	6.0	1.8	16.0	12.3
Sub-Saharan Africa	7.3	7.3	0.6	2.9	0.1	1.1	32.0	17.0
Kazakhstan							6.0	1.1
Rest of Asia	1.3	4.3		3.4		0.9	8.0	3.2
Americas	2.0	1.4	1.0	0.3		1.0	3.0	1.5
Australia and Oceania		0.9					1.0	0.3
	14.1	23.1	4.9	14.6	6.2	6.2	79.0	40.0

Development wells activity

		Wells completed(a)						Wells in progress at Dec. 31(b)
	2014				2016		2016
(units)	Productive	Dry(c)	Productive	Dry(c)	Productive	Dry(c)	Gross	Net
Italy	12.5		6.0		4.0		1.0	1.0
Rest of Europe	9.8	1.0	10.2	0.1	5.6		4.0	0.6
North Africa	54.5	1.0	30.5	2.8	38.6	1.2	18.0	10.0
Sub-Saharan Africa	31.6		22.0	2.5	21.2	0.2	36.0	14.0
Kazakhstan	1.5		4.7		4.6		3.0	0.8
Rest of Asia	54.2	1.6	29.7	5.9	31.6	0.5	2.0	0.3
Americas	22.1	0.7	17.4	0.1	9.9	1.3	4.0	1.9
Australia and Oceania	0.1	0.4	0.5
	186.3	4.7	121.0	11.4	115.5	3.2	68.0	28.6

Productive oil and gas wells(d)

	2016
	Oil wells		Natural gas wells
(units)	Gross	Net	Gross	Net
Italy	243.0	197.1	616.0	532.4
Rest of Europe	395.0	72.5	160.0	88.1
North Africa	1,813.0	963.8	225.0	98.1
Sub-Saharan Africa	3,020.0	590.3	350.0	28.8
Kazakhstan	204.0	54.8
Rest of Asia	727.0	479.1	1,036.0	393.2
Americas	264.0	133.3	321.0	98.5
Australia and Oceania	7.0	3.8	18.0	3.8
	6,673.0	2,494.7	2,726.0	1,242.9

(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 2,128 (741.9 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.

Key performance indicators

		2014	2015	2016
TRIR (Total Recordable Injury Rate)	(recordable injuries/worked hours) x 1,000,000	0.82	0.89	0.28
of which: employees		0.87	0.91	0.27
contractors		0.70	0.81	0.31
Net sales from operations(a)	(€ million)	73,434	52,096	40,961
Operating profit (loss)		64	(1,258)	(391)
Adjusted operating profit (loss)		168	(126)	(390)
Adjusted net profit (loss)		86	(168)	(330)
Capital expenditure		172	154	120
Worldwide gas sales(b)	(bcm)	89.17	90.88	88.93
LNG sales(c)		13.3	13.5	12.4
Customers in Italy	(million)	7.93	7.88	7.76
Electricity sold	(TWh)	33.58	34.88	37.05
Employees at year end	(number)	4,561	4,484	4,261
of which: outside Italy	(mmtonnes CO2 eq)	2,494	2,461	2,229
Direct GHG emissions	(scale from 0 to 100)	10.12	10.57	11.22
Customer satisfaction index (CSC)(d)	(cm/kWheq)	81.4	85.6	86.2

(a) Before elimination of intragroup sales.

(b) Include volumes marketed by the Exploration & Production segment of 2.62 bcm (3.16 and 3.06 bcm in 2015 and 2014 respectively).

(c) Refers to LNG sales of the Gas & Power segment (included in worldwide gas sales) and the Exploration & Production segment.

(d) The average evaluation reflects results of customers interviews based on clarity, courtesy and waiting time.

Performance of the year

• ➤ In 2016, the total recordable incidence rate (TRIR) amounted to 0.28, improving by 68% compared to the previous year, due to both employees (down by 70%) and contractors (down by 61%) contribution.
• ➤ In 2016, greenhouse gas emissions (GHG) increased by 6%, reflecting higher power generation volumes (up by 5.3%) and the increase in transported natural gas.
• ➤ GHG emissions/kWheq relating to electricity production decreased by 3% compared to 2015 benefitting from progresses in energy saving actions.
• ➤ In 2016, adjusted operating loss of the Gas & Power segment amounted to €390 million, down by €264 million. This reflected the impact of a negative trading environment, particularly in the

LNG business, and lower non-recurring gains recorded in 2015. These effects were partly offset by optimization actions and better performance in trading activities.

• ➤ Eni worldwide gas sales amounted to 88.93 bcm, down by 1.95 bcm or 2.1% compared to 2015. Eni's sales in Italy were barely unchanged (38.43 bcm).
• ➤ Electricity sales recorded an increase of 6.2% (up by 2.17 TWh) compared to the previous year, mainly due to higher volumes traded on the wholesale segment.
• ➤ Capital expenditure amounting to €120 million mainly concerned gas marketing activities and flexibility and upgrading of combined cycle power stations.

1. Marketing

1.1 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 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 natural gas from a total of 18 countries, where Eni signed long-term gas supply contracts or holds upstream activities and by access to

continental Europe's spot markets. In 2016 Eni consolidated subsidiaries supplied 82.64 bcm of natural gas, down by 2.75 bcm or 3.2% from 2015. Gas volumes supplied outside Italy (76.64 bcm from consolidated companies), imported in Italy or sold outside Italy, represented approximately 93% of total

supplies, down by 2.02 bcm or 2.6% from 2015. This reflected lower volumes purchased in Libya (down by 2.38 bcm), in Russia (down by 2.34 bcm) and in the Netherlands (down by 2.13 bcm), partially offset by higher purchases in Algeria (up by 6.85 bcm). Supplies in Italy (6 bcm) decreased by 10.8% from 2015 due to the production shutdown in the Val d'Agri district during the period April-August 2016.

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 9 million clients in Italy and Europe. Households, professionals, small and medium-sized enterprises and public bodies located all over Italy are approximately 7.8 million. In a trading environment characterized by a slight recover in demand (up by 0.4% in the Italian market and up by 7.3% in the European Union compared to the previous year), and a still depressed market characterized by an increased 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 in a weak demand scenario.

Sales and market shares on the Italian gas market	(bcm)	2015			2016
		Volumes sold	Market share (%)	Volumes sold	Market share (%)	% Ch. 2016 vs 2015
Italy to third parties		32.56	48.2	32.33	45.6	(0.7)
Wholesalers		4.19		3.83		(8.6)
Italian gas exchange and spot markets		16.35		17.08		4.5
Industries		4.66		4.54		(2.6)
Medium-sized enterprises and services		1.58		1.72		8.9
Power generation		0.88		0.77		(12.5)
Residential		4.90		4.39		(10.4)
Own consumption		5.88		6.10		3.7
TOTAL SALES IN ITALY		38.44	56.9	38.43	54.2
Gas demand(a)		67.50		70.90		5.0

(a) Source: Italian Ministry of Economic Development.

Gas sales by market	(bcm)	2014	2015	2016
ITALY		34.04	38.44	38.43
Wholesalers		4.05	4.19	3.83
Italian gas exchange and spot markets		11.96	16.35	17.08
Industries		4.93	4.66	4.54
Medium-sized enterprises and services		1.60	1.58	1.72
Power generation		1.42	0.88	0.77
Residential		4.46	4.90	4.39
Own consumption		5.62	5.88	6.10
INTERNATIONAL SALES		55.13	52.44	50.50
Rest of Europe		46.22	42.89	42.43
Importers in Italy		4.01	4.61	4.37
European markets		42.21	38.28	38.06
Iberian Peninsula		5.31	5.40	5.28
Germany/Austria		7.44	5.82	7.81
Benelux		10.36	7.94	7.03
Hungary		1.55	1.58	0.93
UK/Northern Europe		2.94	1.96	2.01
Turkey		7.12	7.76	6.55
France		7.05	7.11	7.42
Other		0.44	0.71	1.03
Extra European markets		5.85	6.39	5.45
E&P in Europe and in the Gulf of Mexico		3.06	3.16	2.62
WORLDWIDE GAS SALES		89.17	90.88	88.93

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

Benelux

Eni holds a leadership position in the Benelux countries (Belgium, the Netherlands and Luxembourg) granted by a direct presence, by the Belgium Gas & Power branch and by its subsidiaries, in the retail and middle market and its significant exposure to spot markets in Western Europe. In 2016, sales in Benelux were mainly directed to industrial companies, power generation and wholesalers and amounted to 7.03 bcm, down by 0.91 bcm, or 11.5% compared to 2015, 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 2016, sales in the Country amounted to 7.42 bcm, an increase of 0.31 bcm, or 4.4%, from a year ago.

Germany/Austria

Eni operates in Germany-Austria through Gas & Power branches. In 2016, total sales in Germany-Austria amounted to 7.81 bcm, an increase of 1.99 bcm, or 34.2% from 2015, mainly due to higher volumes marketed by Eni's direct sales force and the optimization actions.

Spain

Eni operates in the Spanish gas market through a direct marketing structure that markets its portfolio of LNG and through Unión Fenosa Gas (UFG) (Eni's interest 50%) which mainly supplies natural gas to industrial clients, wholesalers and power generation utilities. In 2016, UFG gas sales amounted to 3.48 bcm (1.74 bcm Eni's share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36% interest in a liquefaction plant in Oman. In 2016, total sales in the Iberian Peninsula amounted to 5.28 bcm, a decrease of 0.12 bcm, or down by 2.2%.

Turkey

Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2016, sales amounted to 6.55 bcm, a decrease of 1.21 bcm, or 15.6% from a year ago.

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 2016, sales amounted to 2.01 bcm, a slight increase of 2.6% from a year ago.

1.2 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 and South America. 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 2016, LNG sales (12.4 bcm) decreased from 2015 (down by 1.1 bcm), mainly due to lower volumes marketed in the Far East, lacking contracts renewal. In particular, LNG sales in the Gas & Power segment (8.1 bcm, included in worldwide gas sales) mainly concerned LNG from Qatar, Nigeria, Oman and Algeria and mainly marketed in Europe, the Far East, Kuwait and Egypt.

1.3 Power generation

Eni's power generation sites are located in Ferrera Erbognone, Ravenna, Mantova, Brindisi, Ferrara and Bolgiano.

In 2016, power generation was 21.78 TWh, up by 1.09 TWh or 5.3% from 2015, mainly due to increasing demand. As of December 31, 2016, installed operational capacity of EniPower's power plants was 4.7 GW (4.9 GW as of December 31, 2015). Electricity trading (15.27 TWh) reported an increase of 7.6% due to the optimization of inflows and outflows of power. In 2016, power sales of 37.05 TWh were directed to the free market (74%), the Italian power exchange (15%), industrial sites (9%) and others (2%). Compared to 2015, power sales were up by 2.17 TWh or 6.2%, due to higher volumes sold to wholesalers (up by 2.10 TWh) and middle market (up by 0.96 TWh), partially offset by lower volumes sold to small and medium-sized enterprises and large customers.

2. 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:

• 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.

Supply of natural gas	(bcm)	2014	2015	2016
Italy		6.92	6.73	6.00
Outside Italy
Russia		26.68	30.33	27.99
Algeria (including LNG)		7.51	6.05	12.90
Libya		6.66	7.25	4.87
Netherlands		13.46	11.73	9.60
Norway		8.43	8.40	8.18
United Kingdom		2.64	2.35	2.08
Hungary		0.38	0.21	0.02
Qatar (LNG)		2.98	3.11	3.28
Other supplies of natural gas		5.56	7.21	5.81
Other supplies of LNG		1.69	2.02	1.91
		75.99	78.66	76.64
Total supplies of Eni's own companies		82.91	85.39	82.64
Offtake from (input to) storage		(0.20)		1.40
Network losses, measurement differences and other changes		(0.25)	(0.34)	(0.21)
AVAILABLE FOR SALE BY ENI'S CONSOLIDATED SUBSIDIARIES		82.46	85.05	83.83
AVAILABLE FOR SALE OF ENI'S AFFILIATES		3.65	2.67	2.48
E&P volumes in Europe and Gulf of Mexico		3.06	3.16	2.62

Gas sales by entity	(bcm)	2014	2015	2016
Sales of consolidated companies		81.73	84.94	83.34
Italy (including own consumption)		34.04	38.44	38.43
Rest of Europe		43.07	41.14	40.52
Outside Europe		4.62	5.36	4.39
Sales of Eni's affiliates (net to Eni)		4.38	2.78	2.97
Italy
Rest of Europe		3.15	1.75	1.91
Outside Europe		1.23	1.03	1.06
E&P in Europe and in the Gulf of Mexico		3.06	3.16	2.62
Worldwide gas sales		89.17	90.88	88.93

GAS VOLUMES AVAILABLE FOR SALE 89.17 90.88 88.93

LNG sales	(bcm)	2014	2015	2016
G&P sales		8.9	9.0	8.1
Rest of Europe		5.0	4.8	5.2
Extra European markets		3.9	4.2	2.9
E&P sales		4.4	4.5	4.3
Liquefaction plants:
Soyo (Angola)		0.1		0.1
Bontang (Indonesia)		0.5	0.5	0.4
PointFortin (Trinidad & Tobago)		0.6	0.7	0.7
Bonny (Nigeria)		2.8	2.8	2.6
Darwin (Australia)		0.4	0.5	0.5
Total LNG sales		13.3	13.5	12.4

Electricity sales	(TWh)	2014	2015	2016
Free market		24.86	25.9	27.49
Italian Exchange for electricity		4.71	5.09	5.64
Industrial plants		3.17	3.23	3.11
Other(a)		0.84	0.66	0.81
Power sales		33.58	34.88	37.05
Power generation		19.55	20.69	21.78
Trading of electricity(a)		14.03	14.19	15.27

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

	Installed capacity as of	Effective/planned
EniPower power stations	December 31, 2016(a)(MW)	start-up	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		2014	2015	2016
Purchases
Purchases of natural gas	(mmcm)	4,074	4,270	4,334
Purchases of other fuels	(ktep)	338	313	360
Production
Power generation	(TWh)	19.55	20.69	22
Steam	(ktonnes)	9,010	9,318	7,974
Installed generation capacity	(GW)	4.9	4.9	4.7

Transport infrastructure

OUTSIDE ITALY	Lines	Lenght	Diameter	Transport capacity(a)	Transit capacity(b)	Compression stations
	(units)	(km)	(inch)	(bcm/y)	(bcm/y)	(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 lines 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)	2014	2015	2016
Italy		128	100	73
Outside Italy		44	54	47
		172	154	120
Market		164	138	110
Market		66	69	69
Italy		30	31	32
Outside Italy		36	38	37
Power generation		98	69	41
International transport		8	16	10
		172	154	120

Refining & Marketing

and Chemicals

Key performance indicators

		2014	2015	2016
Total recordable incident rate (TRIR)	(recordable injuries/worked hours) x 1,000,000	1.51	1.07	0.38
of which: employees		1.60	0.97	0.44
contractors		1.40	1.17	0.32
Net sales from operations(a)	(€ million)	28,994	22,639	18,733
Operating profit (loss)		(2,811)	(1,567)	723
Adjusted operating profit (loss)		(412)	695	583
- Refining & Marketing		(65)	387	278
- Chemicals		(347)	308	305
Adjusted net profit (loss)		(319)	512	419
- Refining & Marketing		(41)	282	157
- Chemicals		(278)	230	262
Capital expenditure		819	628	664
Refinery throughputs on own account	(mmtonnes)	25.03	26.41	24.52
Conversion index	(%)	51	48	50
Balanced capacity of refineries	(kbbl/d)	617	548	548
Green refinery throughputs	(ktonnes)	127	204	212
Retail sales of petroleum products in Europe	(mmtonnes)	9.21	8.89	8.59
Service stations in Europe at year end	(number)	6,220	5,846	5,622
Average throughput per service station in Europe	(kliters)	1,725	1,754	1,742
Retail efficiency index	(%)	1.19	1.14	1.10
Production of petrochemical products	(ktonnes)	5,283	5,700	5,646
Sale of petrochemical products		3,463	3,801	3,759
Average plant utilization rate	(%)	71	73	72
Employees at year end	(number)	11,884	10,995	10,858
of which: outside Italy		2,598	2,360	2,281
Direct GHG emissions	(mmtonnes CO2 eq)	8.45	8.19	8.50
SOx emissions (sulphur oxide)	(ktonnes SO2 eq)	6.84	6.17	4.35
GHG emissions/refining throughputs(b)	(tons CO2 eq/kt)	287	237	272

(a) Before elimination of intragroup sales.

(b) Relates only to traditional refineries.

Performance of the year

• ➤ In 2016 continued the positive trend in total recordable injury rate, down by 64% due to both employees (down by 54%) and contractors (down by 73%) contribution.
• ➤ Greenhouse gas emissions reported a decrease of 29.5% compared to 2015 driven by a different mix of processed fuels at Livorno, Taranto and Sannazzaro refineries; the trend was influenced by the shutdown of the Dunkerque plant (Versalis) in the second part of the year.
• ➤ In 2016 the Refining & Marketing and Chemicals segment reported an adjusted operating profit of €583 million, down by €112 million, or 16,1% from the previous year. In 2016, the Refining & Marketing business reported an adjusted operating profit of €278 million, down by 28% from 2015. This reflected negative impact of an unfavourable refining margin scenario (Eni's standard refining margin – SERM – in 2016 worsened to 4.2 \$/bbl, compared to 8.3 \$/bbl in 2015, down by 49.4%), the lower availability of domestic crude oil from the Val d'Agri field and higher incidence of scheduled standstills in 2016. These negatives were partly offset by improved plant efficiency and optimization. The refining break-even margin improved to 4.2 \$/bbl yearly average from the 2016 target of 4.5 \$/bbl. Results of the Marketing activity declined mainly due to lower margins reflecting the increasing competitive pressure and the assets disposals in Slovenia and Hungary. The Chemicals business reported an adjusted operating profit of €305 million, barely unchanged from the full year 2015 with an adjusted operating profit of €308 million. The unfavourable trading environment with worsening margins of crackers, polyethylenes and styrenes was partially offset by steady sale volumes and efficiency and optimization actions.
• ➤ In 2016 Eni's refining throughputs amounted to 24.52 mmtonnes, lower y-o-y (down by 7.2%) due to unavailability of domestic crude oil of the Val d'Agri field at the Taranto plant and planned shutdowns at Livorno and Milazzo refineries. These negatives were partially offset by higher throughputs at the Sannazzaro refinery, despite the incident occurred at the EST plant in December 2016. On a homogeneous basis, when excluding the impact of the disposal of CRC refinery in the Czech Republic finalized on April 30, 2015, refining throughputs were down by 4.5%.
• ➤ In 2016 biofuels produced from vegetable oil at the Venice Green Refinery amounted to 0.21 mmtonnes, up by 5% compared to a year earlier.
• ➤ Retail sales in Italy were 5.93 mmtonnes slightly decreasing from 2015 (down by approximately 30 ktonnes, or 0.5%).

• ➤ Retail sales in the Rest of Europe (2.66 mmtonnes) were down by 9.2% compared to the previous year, mainly due to assets disposals in the Czech Republic and Slovakia finalized in July 2015 as well as in Slovenia and Hungary in the second half of 2016. These negatives were partially offset by higher volumes traded in France, Austria and Germany.

• ➤ Sales of petrochemical products in Europe amounted to 3.76 mmtonnes, recording a slight reduction of 1.1% y-o-y, due to a slow recovery in consumptions. Higher intermediates sales were partially offset by lower sale volumes in the other businesses.

• ➤ Capital expenditure amounting to €664 million mainly related to: (i) refining activities in Italy and outside of Italy (€298 million), aiming mainly at maintain plants' integrity, as well as initiatives in health, security and environmental issues; (ii) marketing activity, mainly regulation compliance and stay in business initiatives in the refined product retail network in Italy and in the Rest of Europe (€123 million).

Integrated project for Gela reconversion

In 2016 Eni's activities progressed in line with the commitments foreseen in the Memorandum of Understanding, signed in 2014, with the Ministry for the Economic development and Local Authorities. In April 2016, following the fulfilment of certain conditions, Eni launched the construction activities at the Green Refinery project, being one of the pillar of the agreement. The refinery will have a capacity of 750 ktonnes/y. The conversion will leverage on the application of ecofining proprietary technology, developed and patented by Eni, to convert unconventional and second generation raw materials into green diesel, a high sustainable biofuel. Gela reconversion represents the first integrated and cross businesses project which Eni is developing in Italy to combine the needs of the business and those of the communities living in the area. The agreement foresees also: i) the launch of new hydrocarbon exploration and production activities in the Region of Sicily and the offshore area; ii) the realization of a modern hub for shipping locally produced crude oil and green fuel produced on the site; a feasibility study, to identify LNG and CNG storage and transport infrastructure in Gela, as well as the realization of a project for the production of natural latex from natural products with the relative development of the agricultural supply chain; iii) the set-up of a competence centre focused on safety issues; iv) a plan for the environmental remediation of plants and areas that will gradually lose their industrial destination.

Green Chemical Project

Confirmed another step into the conversion process of the bio-refinery of Porto Marghera, with the development of an integrated technology platform fed with renewables sources. The project is based on an agreement signed in 2015 with the US-based company Elevance Renewable Science Inc., including research, technological development and engineering for new plants processes. At these new plants, Versalis will produce bio-additives for chemicals used in the oil industry and green diesel for Eni bio-refinery, as well as applications such as detergents and bio-lubricants.

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 2016, Eni refinery capacity (balanced with conversion capacity) was approximately 27.4 mmtonnes (equal to 548 kbbl/d), with a conversion index of 50%.

Eni's 100% owned refineries have a balanced capacity of 19.4 mmtonnes (equal to 388 kbbl/d), with a 49% conversion index. In 2016, Eni's refineries throughputs in Italy and outside Italy were 24.52 mmtonnes down by 7.2 % from 2015 or 1.89 mmtonnes.

n 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 2016

	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)	(kbbl/d)
Wholly-owned refineries		388	90	49	34	16	90	29
Italy
Sannazzaro	100	200	98	71	34	16	51	29
Taranto	100	104	73	38			39
Livorno	100	84	91	11
Partially-owned refineries		160	93	52	143	25	75	27
Italy
Milazzo	50	100	90	60	45	25	32
Germany
Vohburg/Neustadt (Bayernoil)	20	41	96	36	49
Schwedt	8.33	19	100	42	49		43	27
Total		548	90	50	177	41	165	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 71%. 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 38%. 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 toppingvacuum unit, a platforming, two desulphurization units and a dearomatization unit (DEA) – for the production of fuels; a propane deasphalting (PDA), aromatics extraction and dewaxing 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 plants, one unit of fluid catalytic cracking (FCC), one hydrocracking unit for the conversion of middle distillates (HDCK) and one unit devoted to the residue treatment process (LC-Finer).

n Outside Italy

In Germany, Eni's share in the Schwedt refinery is 8.3% 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 (2016)	Capacity (at regime)	Throughput (2016)
Wholly owned	(%)	(Ktons/y)	(Ktons/y)	(Ktons/y)
Venice	100	360	560	212
Gela	100	-	750	-
Total green refineries		360	1,310	212

Green Diesel qualities

Green Diesel produced througout EcofiningTM can be blended until a 30% threshold to traditional gasoil; for these characteristics it can be used in the formulation of top quality products.

When compared to traditional FAME (Fatty Acid Methyl Esters), Green Diesel displays:

• Higher calorific value
• Low solvent characteristics and low water solubility - No low value liquid by-product
• Compatibility with automotive materials
• Stable blending component
• Relevant oxydation stability
• Performance at low temperature
• Sulphur and aromatics/poliaromatics absence
• Product is a high quality cetane component

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 regime, the production will satisfy approximately half of Eni bio-fuels needs required for being compliant with the EU environmental normative aimed at reducing the CO2 emission.

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 bio-refinery. The reconversion activities are ongoing and in line with the commitments signed with parties. The local crude oil production will be exported throughout facilities of the refinery.

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 17 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 seven Italian operators (Sigemi, Petrolig, Petroven, Petra, Seram, Disma and Toscopetrol) to optimize its logistic footprint and increase efficiency. Since the beginning of 2017 Petrolig joint venture ends. 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 trucks owners.

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), and methanol. About 80% 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 20% is purchased.

Marketing

1. Retail sales in Italy

Eni is a leader in the Italian retail market of refined products with a 24.3% market share, down by 0.2 percentage points from 2015. In 2016, retail sales in Italy were 5.93 mmtonnes with a decrease compared to 2015 (about 30 ktonnes from 2015 or 0.5%) due to a reduction in volumes marketed in Eni's highway segment, partially offset by a slight increase in volumes marketed in Eni's owned stations. Average gasoline and gasoil throughputs (1,551 kliters) decreased by approximately 20 kliters from 2015. As of December 31, 2016, Eni's retail network in Italy consisted of 4,396 service stations, lower by 24 units from December 31, 2015 (4,420 service stations), resulting from the release of low throughput stations (27 units), offset by positive balance of acquisitions/releases of lease concessions (3 units).

2. Retail Rest of Europe

Retail sales in the Rest of Europe were approximately 2.66 mmtonnes, recorded a slight reduction from 2015 (down by 9.2%). This result reflected mainly the asset disposals in the Czech Republic and Slovakia finalized in July 2015 as well as in Slovenia and Hungary in the second half of 2016. On a homogeneous basis, when excluding the impact of the asset disposal in Eastern Europe, sales slightly increased by 1%. At December 31, 2016, Eni's retail network in the Rest of Europe consisted of 1,226 units, decreasing by 200 units from December 31, 2015, due to the service stations disposal above mentioned. Average throughput (2,340 kliters) increased by 68 kliters compared to 2015 (2,272 kliters).

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 8.16 mmtonnes, up by approximately 0.32 mmtonnes or 4.1% from the previous year, mainly due to higher volumes marketed of jet fuel, gasoil and fuel oil partly offset by lower sales of bunkering.

Supplies of feedstock to the petrochemical industry (1.02 mmtonnes) decreased by 12,8% due to lower productions of virgin naphtha compared to 2015.

Wholesale sales in the Rest of Europe were 3.18 mmtonnes, down by 17% from 2015, net of the above-mentioned asset disposals. On a homogeneous basis, sales are barely unchanged from 2015. Other sales in Italy and outside Italy (12.03 mmtonnes) decreased by approximately 1.05 mmtonnes or 8%, 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 2016, Eni share of LPG market in Italy was 17.5%. Outside Italy, the main market of Eni is Ecuador, with a market share of 38%.

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 2016, Eni's share of lubricants market in Italy was 21%, in Europe 3% and on a worldwide base 0,6%. Eni operates in more than 80 countries by subsidiaries, licensees and distributors.

Supply of oil	(mmtonnes)	2014	2015	2016
Equity crude oil		5.81	5.04	3.43
Other crude oil		17.21	19.76	19.92
Total crude oil purchases		23.02	24.80	23.35
Purchases of intermediate products		2.02	1.66	1.35
Purchases of products		11.07	10.68	11.20
TOTAL PURCHASES		36.11	37.14	35.90
Consumption for power generation		(0.57)	(0.41)	(0.37)
Other changes(a)		(0.62)	(1.22)	(1.92)
		34.92	35.51	33.61

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

Availability of refined products (mmtonnes)	2014	2015	2016
ITALY
At wholly-owned refineries	16.24	18.37	17.37
Less input on account of third parties	(0.58)	(0.38)	(0.27)
At affiliate refineries	4.26	4.73	4.51
Refinery throughputs on own account	19.92	22.72	21.61
Consumption and losses	(1.33)	(1.52)	(1.53)
Products available for sale	18.59	21.20	20.08
Purchases of refined products and change in inventories	7.19	6.22	6.28
Products transferred to operations outside Italy	(0.72)	(0.48)	(0.39)
Consumption for power generation	(0.57)	(0.41)	(0.37)
Sales of products	24.49	26.53	25.60
GREEN REFINERY THROUGHPUTS	0.13	0.20	0.21
OUTSIDE ITALY
Refinery throughputs on own account	5.11	3.69	2.91
Consumption and losses	(0.21)	(0.23)	(0.22)
Products available for sale	4.90	3.46	2.69
Purchases of finished products and change in inventories	4.48	4.77	4.72
Products transferred from Italian operations	0.72	0.48	0.40
Sales of products	10.10	8.71	7.81
Refinery throughputs on own account	25.03	26.41	24.52
Total equity crude input	5.81	5.04	3.43
Total sales of refined products	34.59	35.24	33.41
Crude oil sales	0.33	0.27	0.20
TOTAL SALES	34.92	35.51	33.61

Production and sales	(mmtonnes)	2014	2015	2016
Products:
Gasoline		6.07	6.36	6.13
Gasoil		10.31	10.66	9.93
Jet fuel/kerosene		1.45	1.51	1.49
Fuel oil		2.04	2.46	2.43
LPG		0.49	0.44	0.39
Lubricants		0.54	0.54	0.44
Petrochemical feedstock		1.67	1.86	1.46
Other		0.92	0.84	0.49
Total products		23.49	24.67	22.77
Sales:
Italy		24.48	26.53	25.60
Gasoline		2.00	1.97	2.02
Gasoil		7.61	7.64	7.69
Jet fuel/kerosene		1.59	1.60	1.82
Fuel oil		0.12	0.12	0.13
LPG		0.59	0.58	0.58
Lubricants		0.09	0.08	0.08
Petrochemical feedstock		0.89	1.17	1.02
Other		11.59	13.37	12.26
Rest of Europe		9.69	8.29	7.38
Gasoline		1.80	1.51	1.27
Gasoil		4.48	3.98	3.44
Jet fuel/kerosene		0.55	0.65	0.62
Fuel oil		0.18	0.17	0.13
LPG		0.14	0.10	0.07
Lubricants		0.09	0.09	0.08
Other		2.45	1.79	1.77
Extra Europe		0.42	0.42	0.43
LPG		0.41	0.41	0.42
Lubricants Worldwide		0.01	0.01	0.01
Gasoline		3.80	3.48	3.29
Gasoil		12.09	11.62	11.13
Jet fuel/kerosene		2.14	2.25	2.44
Fuel oil		0.30	0.29	0.26
LPG		1.14	1.09	1.07
Lubricants		0.19	0.18	0.17
Petrochemical feedstock		0.89	1.17	1.02
Other		14.04	15.16	14.03
Total sales		34.59	35.24	33.41

	6.14	5.96
Retail			5.93
Wholesale	7.57	7.84	8.16
	13.71	13.80	14.09
Petrochemicals	0.89	1.17	1.02
Other markets	9.89	11.56	10.49
Sales in Italy	24.49	26.53	25.60
Retail rest of Europe	3.07	2.93	2.66
Wholesale rest of Europe	4.60	3.83	3.18
Wholesale outside Europe	0.43	0.43	0.43
	8.10	7.19	6.27
Other markets	2.00	1.52	1.54
Sales outside Italy	10.10	8.71	7.81
Total sales	34.59	35.24	33.41

Retail and wholesale sales of refined products	(mmtonnes)	2014	2015	2016
Italy		13.71	13.80	14.09
Retail sales		6.14	5.96	5.93
Gasoline		1.71	1.60	1.53
Gasoil		4.07	3.96	3.99
LPG		0.32	0.36	0.36
Other		0.04	0.04	0.04
Wholesale sales		7.57	7.84	8.16
Gasoil		3.54	3.69	3.70
Fuel oil		0.12	0.12	0.14
LPG		0.28	0.22	0.22
Gasoline		0.30	0.38	0.49
Lubricants		0.09	0.07	0.08
Bunker		0.91	1.07	1.01
Jet fuel		1.59	1.60	1.82
Other		0.74	0.69	0.70
Outside Italy (retail + wholesale)		8.10	7.19	6.27
Gasoline		1.80	1.51	1.27
Gasoil		4.48	3.98	3.44
Jet fuel		0.56	0.65	0.62
Fuel oil		0.18	0.17	0.13
Lubricants		0.10	0.10	0.10
LPG		0.55	0.51	0.49
Other		0.43	0.27	0.22
Total		21.81	20.99	20.36

Number of service stations	(units)	2014	2015	2016
Italy		4,592	4,420	4,396
Ordinary stations		4,468	4,297	4,273
Highway stations		124	123	123
Outside Italy		1,628	1,426	1,226
Germany		469	472	472
France		160	154	156
Austria/Switzerland		591	604	598
Eastern Europe		408	196
Service stations selling Blu products		5,749	4,466	4,405
"Multi-Energy" service stations		6	6	4
Service stations selling LPG and natural gas		1,206	1,176	1,073
Non-oil sales	(€ million)	151	143	146

Average throughput	(kliters/No. of service stations)	2014	2015	2016
Italy		1,534	1,569	1,551
Germany		3,299	3,351	3,325
France		2,139	2,244	2,360
Austria/Switzerland		1,891	1,923	1,939
Eastern Europe		1,979	1,802
Average throughput		1,725	1,754	1,742

Market shares in Italy	(%)	2014	2015	2016
Retail		25.6	24.5	24.3
Gasoline		22.3	21.1	20.7
Gasoil		27.9	26.5	26.4
LPG (automotive)		20.1	22.2	21.6
Lubricants		25.1	24.5	38.5
Wholesale		26.4	27.5	28.3
Gasoil		27.1	27.1	27.1
Fuel oil		13.6	11.1	18.3
Bunker		39.1	40.8	34.2
Lubricants		23.2	19.4	20.5
Domestic market share		26.3	26.2	26.6

Retail market shares outside Italy	(%)	2014	2015	2016
Central Europe
Austria		12.1	12.6	12.4
Switzerland		7.3	8.3	8.3
Germany		3.2	3.3	3.3
France		0.8	0.8	0.9
Eastern Europe
Hungary		11.9	12.1
Czech Republic		8.9	8.5
Slovakia		9.5	9.1
Slovenia		2.4	2.4

Capital expenditure	(€ million)	2014	2015	2016
Italy		466	349	363
Outside Italy		71	59	58
		537	408	421
Refining, supply and logistic		362	282	298
Italy		357	274	293
Outside Italy		5	8	5
Marketing		175	126	123
Italy		109	75	70
Outside Italy		66	51	53
		537	408	421

Chemicals

Eni through Versalis performs activities of production and marketing of petrochemical products (basic petrochemicals and polymers), leveraging on a wide range of proprietary technologies (250), 71 advanced production facilities, as well as a large and efficient retail network present in 21 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 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 – the only vertically integrated company in Europe to manufacture and sell vegetable-based products at an industrial level. 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, and Solazyme for green solutions for the oil industry. Furthermore, the company has started off a major project to make natural rubber from guayule.

The activities of Petrochemical sector are mainly concentrated in Italy (Brindisi, Ferrara, Mantova, Porto Marghera, Porto Torres, Priolo, Ragusa, Ravenna) and in Western Europe, in France (Dunkerque), Germany (Oberhausen), Hungary (Szàzhalombatta), and the United Kingdom (Grangemouth).

1. Business areas

Petrochemical sales of 3,759 ktonnes slightly decreased from 2015 (down by 42 ktonnes, or 1.1%) mainly due to the stagnation of demand in Europe. The sharpest declines were registered in polyethylene (down by 9.8%) and styrene (down by 9.1%) following the shutdown of Ragusa and Mantova plants, partly offset by higher volumes in derivatives among intermediates (up by 14.8%) and elastomers (up by 6.7%), driven by demand increase in the Tyre sector. Average unit sales prices were 10% lower than in 2015. Monomers prices, particularly of butadiene (down by 2%) and benzene (down by 6%), reflected the weakness of the market and overcapacity. In the polymers business styrene prices were down by 6.3%, negatively affected by a decline in feedstock, and elastomers average prices decreased by 6.7% due to price competition from Asian producers. Also polyethylene prices decreased (down by 3.2%). Petrochemical production of 5,646 ktonnes decreased by 54 ktonnes (down by 0.9%) due to declines in polyethylene (down by 8.6%) affected by weak demand and in styrene (down by 7.2%) due to planned and unplanned standstills at the Mantova plant. Derivatives productions increased (up by 10.2%) as well as elastomers (up by 7.1%) due to the recovery in sales volumes compared to 2015. The main decreases in production were registered at the Ragusa site (down by 45%), due to a shutdown occurred at the plant, as well as at Ravenna and Dunkerque (olefins), Ferrara (elastomers) and Mantova sites (styrene) due to planned shutdowns. Productions at Brindisi plant increased (up by 15.7%) as well as Grangemouth site (up by 20.7%), due to the start-up of the new butadiene-based rubber production line. Nominal capacity of plants was barely unchanged from the previous year. The average plant utilization rate calculated on nominal capacity was 71.4% reporting a slight decrease from 2015 (72.7%).

2. 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 (€1,688 million) decreased by €211 million from 2015 (down by 11.1%) reflecting the lower commodity prices scenario that influences average intermediates prices. Sales increased by 4.6%, in particular in the ethylene segment (up by 19.3%). Derivatives sales increased by 14.8% driven by the combined effect of a recovery in demand and higher product availability. Average unit prices decreased by 11.1%, with aromatics down by 7% (benzene), derivatives down by 7.7% and olefins down by 17.8% driven by the weakness of the market and overcapacity in Europe.

Intermediates production (3,417 ktonnes) registered an increase of 2.5% from 2015 mainly in aromatics (up by 2.7%) and derivatives (up by 10.2%). Olefins production was barely unchanged (up by 0.8%).

3. Polymers

In the polymers business Versalis is active in the production of: - polyethylene that accounts for approximately 40% of the total volume of world production of plastic materials. It is a basic plastic material, used as a raw material by companies that transform it into a wide range of goods; - 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 (€2,380 million) decreased by €310 million or 11.5% from 2015 due to average unit prices (down by 5.5%) and sold volumes decrease (down by 6.7%), driven by continuing weak demand in the automotive segment and price competition from Asian producers. These negatives were further exacerbated by the decrease of average styrenics prices (down by 6.3%) and sold volumes down by 9.1%, also due to lower production availability following the Mantova plant shutdown. Reductions were recorded both at volumes (down by 9.8%) and average prices (down by 3.2%) in polyethylene. The recovery in elastomers sales was registered in all the segments: commodities rubbers (BR up by 12.6%), SBR (up by 7.8%), thermoplastic rubbers (up by 5.9%), special rubbers EPDM (up by 3.6%) and lattices (up by 2%). Lower sales of styrene is attributable to lower volumes sold of compact polystyrene (down by 13.8%), due to a weak demand in the food packaging, single-use products and building industry and lower sales of expandable polystyrene (down by 14.4%) partly offset by higher sales of ABS/SAN (up by 11.4%) driven by demand recovery and higher sales of styrol (up by 5.9%). The sales volumes of polyethylene reported a decrease (down by 9.8%) due to lower sales of EVA (down by 10.6%) and LDPE (down by 24.4%). HDPE sales increased (up by 7.8%). Polymers production (2,229 ktonnes) decreased by 5.8% from 2015. Styrene productions decreased (down by 7.2%) due to planned standstill at Mantova plant with lower production of styrol (down by 6.4%) and compact polystyrene (down by 11.2%) partly offset by higher productions of ABS/SAN (up by 9.9%). Polyethylene productions decreased (down by 8.6%) driven by scheduled standstills at Ragusa, Ferrara and Dunkerque plants partly offset by higher productions of HDPE (up by 9.4%). Elastomers productions increased (up by 7.1%), mainly in BR segment (up by 15.2%), driven by higher volumes sold compared to 2015.

Product availability	(ktonnes)	2014	2015	2016
Intermediates		2,972	3,334	3,417
Polymers		2,311	2,366	2,229
Production		5,283	5,700	5,646
Consumption and losses		(2,292)	(1,908)	(2,166)
Purchases and change in inventories		472	9	279
		3,463	3,801	3,759

Revenues by geographic area	(€ million)	2014	2015	2016
Italy		2,565	2,154	1,930
Rest of Europe		2,433	2,326	2,107
Asia		157	162	99
Americas		105	61	53
Africa		10	13	7
Other areas		14
		5,284	4,716	4,196

Revenues by product	(€ million)	2014	2015	2016
Olefins		1,305	1,275	1.087
Aromatics		610	327	290
Intermediates		394	297	311
Elastomers		628	543	539
Styrenics		745	764	647
Polyetilene		1,428	1,383	1.194
Other		174	126	128
		5,284	4,716	4.196

Capital expenditure	(€ million)	2014	2015	2016
of which:		282	220	243
- upkeeping		26	33	34
- plants upgrading		161	141	162
- HSE		30	36	37
- energy recovery		28	3	5

Financial Data

Profit and loss account	(€ million)	2014	2015	2016
Net sales from operations		98,218	72,286	55,762
Other income and revenues		1,079	1,252	931
Total revenues		99,297	73,538	56,693
Purchases, services and other		(77,404)	(56,848)	(44,124)
Payroll and related costs		(2,929)	(3,119)	(2,994)
Total operating expenses		(80,333)	(59,967)	(47,118)
Other operating income (expense)		145	(485)	16
Depreciation, depletion, amortization		(7,676)	(8,940)	(7,559)
Impairment losses (impairments reversals), net		(1,270)	(6,534)	475
Write-off		(1,198)	(688)	(350)
Operating profit (loss)		8,965	(3,076)	2,157
Finance (expense) income		(1,167)	(1,306)	(885)
Net income from investments		476	105	(380)
Profit (loss) before income taxes		8,274	(4,277)	892
Income taxes		(6,466)	(3,122)	(1,936)
Tax rate (%)		78.1
Net profit (loss) - continuing operations		1,808	(7,399)	(1,044)
Attributable to:
- Eni's shareholders		1,720	(7,952)	(1,051)
- Non-controlling interest		88	553	7
Net profit (loss) - discontinued operations		(949)	(1,974)	(413)
Attributable to:
- Eni's shareholders		(417)	(826)	(413)
- Non-controlling interest		(532)	(1,148)
Net profit (loss)		859	(9,373)	(1,457)
Attributable to:
- Eni's shareholders		1,303	(8,778)	(1,464)
- Non-controlling interest		(444)	(595)	7
Net profit (loss) attributable to Eni's shareholders - continuing operations		1,720	(7,952)	(1,051)
Exclusion of inventory holding (gains) losses		1,008	782	(120)
Exclusion of special items		1,471	8,487	831
Adjusted net profit (loss) attributable to Eni's shareholders - continuing operations		4,199	1,317	(340)
Adjusted net profit (loss) attributable to Eni's shareholders - discontinued operations		(343)	(642)
Adjusted net profit (loss) attributable to Eni's shareholders		3,856	675	(340)

Performance on a standalone basis	(€ million)	2014	2015	2016
Operating profit (loss) - continuing operations		8,965	(3,076)	2,157
Exclusion of inventory holding (gains) losses		1,460	1,136	(175)
Exclusion of special items		1,912	7,648	333
Adjusted operating profit (loss) - continuing operations		12,337	5,708	2,315
Reinstatement of intercompany transactions vs. discontinued operations		(1,114)	(1,222)
Adjusted operating profit (loss) - continuing operations on a standalone basis		11,223	4,486	2,315
Net profit (loss) attributable to Eni's shareholders - continuing operations		1,720	(7,952)	(1,051)
Exclusion of inventory holding (gains) losses		1,008	782	(120)
Exclusion of special items		1,471	8,487	831
Adjusted net profit (loss) attributable to Eni's shareholders - continuing operations		4,199	1,317	(340)
Reinstatement of intercompany transactions vs. discontinued operations		(476)	(514)
Adjusted net profit (loss) attributable to Eni's shareholders on a standalone basis		3,723	803	(340)
Tax Rate (%)		65.9	82.4	120.6

Summarized Group Balance Sheet	(€ million)	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2016
Fixed assets
Property, plant and equipment		75,991	68,005	70,793
Inventories - Compulsory stock		1,581	909	1,184
Intangible assets		4,420	3,034	3,269
Equity-accounted investments and other investments		5,187	3,513	4,316
Receivables and securities held for operating purposes		1,881	2,273	1,932
Net payables related to capital expenditure		(1,971)	(1,284)	(1,765)
		87,089	76,450	79,729
Net working capital
Inventories		7,555	4,579	4,637
Trade receivables		19,709	12,616	11,186
Trade payables		(15,015)	(9,605)	(11,038)
Tax payables and provisions for net deferred tax liabilities		(3,330)	(4,137)	(3,073)
Provisions		(15,882)	(15,375)	(13,896)
Other current assets and liabilities		222	1,827	1,171
		(6,741)	(10,095)	(11,013)
Provisions for employee post-retirement benefits		(1,313)	(1,123)	(868)
Discontinued operations and assets held for sale including related liabilities		291	9,048	14
CAPITAL EMPLOYED, NET		79,326	74,280	67,862
Shareholders' equity
attributable to: - Eni's shareholders		63,186	55,493	53,037
- Non-controlling interest		2,455	1,916	49
		65,641	57,409	53,086
Net borrowings		13,685	16,871	14,776
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		79,326	74,280	67,862

Summarized Group Cash Flow Statement	(€ million)	2014	2015	2016
Net profit (loss) - continuing operations		1,808	(7,399)	(1,044)
Adjustments to reconcile net profit (loss) to net cash provided by operating activities:
- depreciation, depletion and amortization and other non monetary items		10,898	17,216	7,773
- net gains on disposal of assets		(224)	(577)	(48)
- dividends, interest, taxes and other changes		6,600	3,215	2,229
Changes in working capital related to operations		2,199	4,781	2,112
Dividends received, taxes paid, interest (paid) received during the period		(6,812)	(4,361)	(3,349)
Net cash provided by operating activities - continuing operations		14,469	12,875	7,673
Net cash provided by operating activities - discontinued operations		273	(1,226)
Net cash provided by operating activities		14,742	11,649	7,673
Capital expenditure - continuing operations		(11,178)	(10,741)	(9,180)
Capital expenditure - discontinued operations		(694)	(561)
Capital expenditure		(11,872)	(11,302)	(9,180)
Investments and purchase of consolidated subsidiaries and businesses		(408)	(228)	(1,164)
Disposals		3,684	2,258	1,054
Other cash flow related to capital expenditure, investments and disposals		435	(1,351)	465
Free cash flow		6,581	1,026	(1,152)
Borrowings (repayment) of debt related to financing activities		(414)	(300)	5,271
Changes in short and long-term financial debt		(628)	2,126	(766)
Dividends paid and changes in non-controlling interests and reserves		(4,434)	(3,477)	(2,885)
Effect of changes in consolidation, exchange differences and cash and cash equivalent related to discontinued operations		78	(780)	(3)
NET CASH FLOW		1,183	(1,405)	465
NET CASH PROVIDED BY OPERATING ACTIVITIES ON STANDALONE BASIS		13,544	12,155	7,673

Changes in net borrowings	(€ million)	2014	2015	2016
Free cash flow Net borrowings of acquired companies		6,581 (19)	1,026	(1,152)
Net borrowings of divested companies			83	5,848
Exchange differences on net borrowings and other changes		(850)	(818)	284
Dividends paid and changes in non-controlling interest and reserves		(4,434)	(3,477)	(2,885)
CHANGE IN NET BORROWINGS		1,278	(3,186)	2,095

Net sales from operations	(€ million)	2014	2015	2016
Exploration & Production		28,488	21,436	16,089
Gas & Power		73,434	52,096	40,961
Refining & Marketing and Chemicals		28,994	22,639	18,733
Corporate and other activities		1,429	1,468	1,343
Impact of unrealized intragroup profit elimination		54
Consolidation adjustment		(34,181)	(25,353)	(21,364)
		98,218	72,286	55,762

Net sales to customers	(€ million)	2014	2015	2016
Exploration & Production		11,870	9,321	6,378
Gas & Power		59,183	42,179	32,063
Refining & Marketing and Chemicals		26,952	20,632	17,128
Corporate and other activities		159	154	193
Impact of unrealized intragroup profit elimination		54
		98,218	72,286	55,762

Net sales by geographic area of destination	(€ million)	2014	2015	2016
Italy		29,234	24,405	21,280
Other EU Countries		29,298	20,730	15,808
Rest of Europe		11,975	7,125	4,804
Americas		5,763	4,217	3,212
Asia		12,840	9,086	5,619
Africa		8,786	6,482	4,865
Other areas		322	241	174
Total outside Italy		68,984	47,881	34,482
		98,218	72,286	55,762

Net sales by geographic area of origin	(€ million)	2014	2015	2016
Italy		66,763	47,287	37,515
Other EU Countries		12,470	9,996	7,899
Rest of Europe		3,215	2,561	1,560
Africa		10,024	7,630	5,496
Americas		3,528	2,893	2,257
Asia		1,912	1,687	862
Other areas		306	232	173
Total outside Italy		31,455	24,999	18,247
		98,218	72,286	55,762

Purchases, services and other (€ million)	2014	2015	2016
Production costs - raw, ancillary and consumable materials and goods	60,987	39,812	27,783
Production costs - services	12,414	13,197	12,727
Operating leases and other	2,655	2,205	1,672
Net provisions	340	644	505
Gains on price adjustments under overlifting/underlifting	409	278	240
Other expenses	918	1,135	1,512
less:
capitalized direct costs associated with self-constructed tangible and intangible assets	(319)	(423)	(315)
	77,404	56,848	44,124

Principal accountant fees and services	(€ thousand)	2014	2015	2016
Audit fees		27,607	33,752	21,433
Audit-related fees		1,287	1,138	1,874
Tax fees		11	3
		28,905	34,893	23,307

Payroll and related costs	(€ million)	2014	2015	2016
Wages and salaries		2,590	2,648	2,491
Social security contributions		445	453	445
Cost related to defined benefit plans and defined contribution plans		73	85	81
Other costs		160	182	202
less:
capitalized direct costs associated with self-constructed tangible and intangible assets		(339)	(249)	(225)
		2,929	3,119	2,994

Depreciation, depletion, amortization, impairments (impairments reversal) net and write-off	(€ million)	2014	2015	2016
Exploration & Production		6,916	8,080	6,772
Gas & Power		335	363	354
Refining & Marketing and Chemicals		381	454	389
Corporate and other activities		70	71	72
Impact of unrealized intragroup profit elimination		(26)	(28)	(28)
Total depreciation, depletion and amortization		7,676	8,940	7,559
Exploration & Production		851	5,212	(700)
Gas & Power		25	152	81
Refining & Marketing and Chemicals		380	1,150	104
Corporate and other activities		14	20	40
Impairment losses (impairment reversal), net		1,270	6,534	(475)
Total DD&A and impairment losses (impairment reversal), net		8,946	15,474	7,084
Write-off		1,198	688	350
		10,144	16,162	7,434

Operating profit by segment	(€ million)	2014	2015	2016
Exploration & Production		10,727	(959)	2,567
Gas & Power		64	(1,258)	(391)
Refining & Marketing and Chemicals		(2,811)	(1,567)	723
Corporate and other activities		(518)	(497)	(681)
Impact of unrealized intragroup profit elimination		1,503	1,205	(61)
		8,965	(3,076)	2,157

Non-GAAP measures

Alternative performance measures

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. 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 actual performance:

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, adjusted net profit and cash flow from operating activities 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, adjusted net profit and cash flow from operating activities on a standalone basis.

Profit per boe

Measures the return per oil and natural gas per 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.

ROACE (Return On Average Capital Employed)

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.

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 cash equivalents, 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.

2014

									Discontinued operations
(€ million)	Exploration & Production	Gas & Power	Refining & Marketing and Chemicals	Corporate and other activities	Engineering & Construction	intragroup profit elimination Impact of unrealized	GROUP	Engineering & Construction	Consolidation adjustments	TOTAL	CONTINUING OPERATIONS	intercompany transactions vs. discontinued operations Reinstatement of	OPERATIONS - on a standalone basis CONTINUING
Reported operating profit (loss)	10,727		64 (2,811)	(518)	18	398	7,878	(18)	1,105	1,087	8,965		7,860
Exclusion of inventory holding (gains) losses		(119)	1,746			(167)	1,460				1,460		1,460
Exclusion of special items: environmental charges impairment losses			138	41			179				179		179
(impairments reversals), net gains on disposal of assets	853 (70)	25	380 43	14 3	420 2		1,692 (22)	(420) (2)		(420) (2)	1,272 (24)		1,272 (24)
risk provisions	(5)	(42)		12	25		(10)	(25)		(25)	(35)		(35)
provision for redundancy incentives	24	9	(4)	(25)	5		9	(5)		(5)	4		4
commodity derivatives	(28)	(38)	41		9		(16)	(9)	9		(16)		(25)
exchange rate differences and derivatives	6	205	18				229				229		229
other	172	64	37	30			303				303		303
Special items of operating profit (loss)	952	223	653	75	461		2,364	(461)	9	(452)	1,912		1,903
Adjusted operating profit (loss)	11,679	168	(412)	(443)	479	231	11,702	(479)	1,114	635	12,337	(1,114)	11,223
Net finance (expense) income(a)	(273)	7	(12)	(564)	(6)		(848)	6	40	46	(802)	(40)	(842)
Net income (expense) from investments(a)	333	49	64	(156)	21		311	(21)		(21)	290		290
Income taxes(a)	(7,170)	(138)	41		311 (185)		(79) (7,220)	185	(51)		134 (7,086)	51	(7,035)
Tax rate (%)	61.1	61.6			37.4		64.7				59.9		65.9
Adjusted net profit (loss)	4,569	86	(319)	(852)	309	152	3,945	(309)	1,103	794	4,739	(1,103)	3,636
of which attributable to:
- non-controlling interest							89			451	540	(627)	(87)
- Eni's shareholders							3,856			343	4,199	(476)	3,723
Reported net profit (loss) attributable to Eni's shareholders						1,303			417	1,720		1,720
Exclusion of inventory holding (gains) losses							1,008				1,008		1,008
Exclusion of special items							1,545			(74)	1,471		1,471
Reinstatement of intercompany transactions vs. discontinued operations													(476)
Adjusted net profit (loss) attributable to Eni's shareholders							3,856			343	4.199		3,723

(a) Excluding special items.

									Discontinued operations
(€ million)	Exploration & Production	Gas & Power	Refining & Marketing and Chemicals	Corporate and other activities	Engineering & Construction	intragroup profit elimination Impact of unrealized	GROUP	Engineering & Construction	Consolidation adjustments	TOTAL	CONTINUING OPERATIONS	intercompany transactions vs. discontinued operations Reinstatement of	OPERATIONS - on a standalone basis CONTINUING
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 Special items of operating profit (loss)	195 5,141	535 1,000	30 1,385	25 128	597		785 8,251	(597)	(6)	(603)	785 7,648		785 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
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.

2016

(€ million)	Exploration & Production	Gas & Power	Refining & Marketing and Chemicals	Corporate and other activities	intragroup profit elimination Impact of unrealized	GROUP	DISCONTINUED OPERATIONS	OPERATIONS CONTINUING
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	(413.0)	831
Adjusted net profit (loss) attributable to Eni's shareholders						(340)		(340)

(a) Excluding special items.

(€ million)	2014	2015	2016
Net cash provided by operating activities	14,742	11,649	7,673
Net cash provided by operating activities - discontinued operations	273	(1,226)
Net cash provided by operating activities - continuing operations	14,469	12,875	7,673
Reinstatement of intercompany transactions vs. discontinued operations	(925)	(720)
Net cash provided by operating activities on a standalone basis	13,544	12,155	7,673

Breakdown of special items	(€ million)	2014	2015	2016
Special items of operating profit (loss)		2,364	8,251	333
- environmental charges		179	225	193
- impairment losses (impairments reversals), net		1,692	7,124	(459)
- impairment of exploration projects			169	7
- gains on disposal of assets		(22)	(406)	(10)
- risk provisions		(10)	211	151
- provision for redundancy incentives		9	42	47
- commodity derivatives		(16)	164	(427)
- exchange rate differences and derivatives		229	(63)	(19)
- other		303	785	850
Net finance (income) expense		203	292	166
of which:
exchange rate differences and derivatives		(229)	63	19
Net income (expense) from investments		(189)	488	817
of which:
gains on disposals of assets		(159)	(33)	(57)
impairments/revaluation of equity investments		(38)	506	896
Income taxes		(300)	(7)	(72)
of which:
net impairment of deferred tax assets of Italian subsidiaries		976	880	170
other net tax refund		(824)
deferred tax adjustment on PSAs		69
net impairment of deferred tax assets of upstream business outside Italy			860	6
taxes on special items of operating profit (outside Italy) and other special items		(521)	(1,747)	(248)
Total special items of net profit (loss)		2,078	9,024	1,244
attributable to:
- Non-controlling interest		533	353
- Eni's shareholders		1,545	8,671	1,244

Adjusted operating profit by segment	(€ million)	2014	2015	2016
Exploration & Production		11,679	4,182	2,494
Gas & Power		168	(126)	(390)
Refining & Marketing and Chemicals		(412)	695	583
Corporate and other activities		(443)	(369)	(452)
Impact of unrealized intragroup profit elimination		1,345	1,326	80
		12,337	5,708	2,315

Adjusted net profit by segment	(€ million)	2014	2015	2016
Exploration & Production		4,569	991	508
Gas & Power		86	(168)	(330)
Refining & Marketing and Chemicals		(319)	512	419
Corporate and other activities		(852)	(663)	(991)
Impact of unrealized intragroup profit elimination		1,255	1,250	61
		4,739	1,922	(333)
of which attributable to:
Non-controlling interest		540	605	7
Eni's shareholders		4,199	1,317	(340)

Finance income (expense)	(€ million)	2014	2015	2016
Finance income (expense) related to net borrowings		(802)	(814)	(726)
- Finance expense from banks on short and long-term debt		(871)	(838)	(757)
- Interest from banks		19	19	15
- Net finance income (expense) from financial assets held for trading		24	3	(21)
- Interest and other income from financial receivables and securities held for non-operating purposes		26	2	37
Income (expense) from derivative financial instruments		165	160	(482)
- Derivatives on exchange rate		51	96	(494)
- Derivatives on interest rate		46	31	(12)
- Options		68	33	24
Exchange differences		(415)	(354)	676
Other finance income (expense)		(278)	(464)	(459)
- Interest and other income on financing receivables and securities held for operating purposes		74	120	143
- Finance expense due to the passage of time (accretion discount)		(293)	(291)	(312)
- Other finance income (expense)		(59)	(293)	(290)
		(1,330)	(1,472)	(991)
Capitalized finance expense		163	166	106
		(1,167)	(1,306)	(885)

Income (expense on) from investments	(€ million)	2014	2015	2016
Share of profit of equity-accounted investments		188	150	77
Share of loss of equity-accounted investments		(77)	(615)	(370)
Gains on disposals		160	164	(14)
Dividends		385	402	143
Decreases (increases) in the provision for losses on investments from equity accounted investments		(1)	(6)	(33)
Other income (expense), net		(179)	10	(183)
		476	105	(380)

Property, plant and equipment by segment	(€ million)	2014	2015	2016
Property, plant and equipment by segment, gross
Exploration & Production		135,385	154,064	165,559
Gas & Power		5,985	6,169	6,276
Refining & Marketing and Chemicals		23,425	23,818	24,119
Engineering & Construction		13,657
Corporate and other activities		2,201	1,854	1,886
Impact of unrealized intragroup profit elimination		(572)	(656)	(568)
		180,081	185,249	197,272
Property, plant and equipment by segment, net
Exploration & Production		60,683	61,495	64,428
Gas & Power		1,985	1,882	1,692
Refining & Marketing and Chemicals		5,653	4,664	4,642
Engineering & Construction		7,616
Corporate and other activities		452	418	368
Impact of unrealized intragroup profit elimination		(398)	(454)	(337)
		75,991	68,005	70,793

Capital expenditure by segment	(€ million)	2014	2015	2016
Exploration & Production		10,156	9,980	8,254
Gas & Power		172	154	120
Refining & Marketing and Chemicals		819	628	664
Corporate and other activities		113	64	55
Impact of unrealized intragroup profit elimination		(82)	(85)	87
Capital expenditure - continuing operations		11,178	10,741	9,180
Capital expenditure - discontinued operations		694	561
Capital expenditure		11,872	11,302	9,180
Investments		408	228	1,164
Capital expenditure and investments		12,280	11,530	10,344

Capital expenditure by geographic area of origin (€ million)	2014	2015	2016
Italy	1,730	1,303	1,163
Other European Union Countries	571	444	331
Rest of Europe	1,346	1,101	460
Africa	4,658	5,009	5,004
Americas	1,039	674	233
Asia	1,717	2,186	1,978
Other areas	117	24	11
Total outside Italy	9,448	9,438	8,017
Capital expenditure - continuing operations	11,178	10,741	9,180
Italy	27	17
Other European Union Countries	256	264
Rest of Europe	32	50
Africa	31	11
Americas	126	53
Asia	187	140
Other areas	35	26
Total outside Italy	667	544
Capital expenditure - discontinued operations	694	561
Capital expenditure	11,872	11,302	9,180

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
2014
Short-term debt	6,575	(6,614)	(5,037)	(555)	(5,631)
Long-term debt	19,316				19,316
	25,891	(6,614)	(5,037)	(555)	13,685
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
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

Employees

Employees at year end	(units)	2014	2015	2016
Exploration & Production	Italy	4,534	4,572	4,608
Outside Italy		8,243	8,249	7,886
		12,777	12,821	12,494
Gas & Power	Italy	2,067	2,023	2,032
Outside Italy		2,494	2,461	2,229
		4,561	4,484	4,261
Refining & Marketing and Chemicals	Italy	9,286	8,635	8,577
Outside Italy		2,598	2,360	2,281
		11,884	10,995	10,858
Corporate and other activities	Italy	5,320	5,650	5,693
Outside Italy		304	246	229
		5,624	5,896	5,922
Total employees at year end	Italy	21,207	20,880	20,910
Outside Italy		13,639	13,316	12,626
		34,846	34,196	33,536
of which: senior managers		1,068	1,054	1,017

Breakdown by position	(number)	2014	2015	2016
Senior Managers		1,068	1,054	1,017
Middle Managers and Senior Staff		9,103	9,295	9,244
White collar workers		18,229	17,897	17,232
Blue collar workers		6,446	5,950	6,043
Total		34,846	34,196	33,536

Supplemental oil and gas information

Oil and natural gas reserves

Eni's criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the U.S. Securities and Exchange Commission and have been disclosed in accordance with FASB Extractive Activities — Oil & Gas (Topic 932). Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geo-scientific and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

In 2016, the average price for the marker Brent crude oil was \$42.8 per barrel.

Net proved reserves exclude interests and royalties owned by others. Proved reserves are classified as either developed or undeveloped. Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation1 of part of its proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserves audit is included in the third party audit report2 .

In the preparation of their reports, independent evaluators rely, without independent verification, upon data furnished by Eni with respect to property interest, production, current costs of operation and development, sale agreements, prices and other factual information and data that were accepted as represented by the independent evaluators. These data, equally used by Eni in its internal process, include logs, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/ injection data of wells, reservoir studies and technical analysis relevant to field performance, long-term development plans, future capital and operating costs. In order to calculate the economic value of Eni equity reserves, actual prices applicable to hydrocarbon sales,

price adjustments required by applicable contractual arrangements, and other pertinent information are provided.

In 2016, Ryder Scott Company and DeGolyer and MacNaughton and Gaffney, Cline & Associates2 provided an independent evaluation of about 41% of Eni's total proved reserves as of December 31, 20163 , confirming, as in previous years, the reasonableness of Eni's internal evaluations.

In the three-year period from 2014 to 2016, 94% of Eni's total proved reserves were subject to independent evaluation. As of December 31, 2016, the principal properties not subjected to independent evaluation in the last three years are Zubair (Iraq), Bu Attifel (Libya), and Cafc-Mle (Algeria).

Eni operates under production sharing agreements in several of the foreign jurisdictions where it has oil and gas exploration and production activities. Reserves of oil and natural gas to which Eni is entitled under PSA arrangements are shown in accordance with Eni's economic interest in the volumes of oil and natural gas estimated to be recoverable in future years. Such reserves include estimated quantities allocated to Eni for recovery of costs, income taxes owed by Eni but settled by its joint venture partners (which are state-owned entities) out of Eni's share of production and Eni's net equity share after cost recovery. Proved oil and gas reserves associated with PSAs represented 50%, 52% and 59% of total proved reserves as of December 31, 2014, 2015 and 2016, respectively, on an oil-equivalent basis. Similar effects as PSAs apply to service and "buy-back" contracts; proved reserves associated with such contracts represented 3%, 5% and 5% of total proved reserves on an oil-equivalent basis as of December 31, 2014, 2015 and 2016, respectively. Oil and gas reserves quantities include: (i) oil and natural gas quantities in excess of cost recovery which the company has an obligation to purchase under certain PSAs with governments or authorities, whereby the company serves as producer of reserves. Reserves volumes associated with oil and gas deriving from such obligation represent 0.6%, 0.6% and 1.8% of total proved reserves as of December 31, 2014, 2015 and 2016, respectively, on an oil equivalent basis; (ii) volumes of natural gas used for own consumption; (iii) the quantities of hydrocarbons related to the Angola LNG plant. Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni's proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced. The following table presents yearly changes in estimated proved

reserves, developed and undeveloped, of crude oil (including condensate and natural gas liquids) and natural gas as of December 31, 2014, 2015 and 2016.

⁽¹⁾ From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott, from 2015 also Gaffney, Cline & Associates.

⁽²⁾ The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2016.

⁽³⁾ Including reserves of equity-accounted entities.

Movements in net proved hydrocarbons reserves

		Rest of Europe
			North Africa	Sub-Saharan	Kazakhstan	Rest of Asia		and Oceania
	Italy			Africa			America	Australia	Total
(mmboe)
2014
Consolidated subsidiaries
Reserves at December 31, 2013	499	557	1,783	1,155	1,035	263	240	176	5,708
of which: developed	408	343	1,003	701	566	90	153	123	3,387
undeveloped	91	214	780	454	469	173	87	53	2,321
Purchase of minerals in place		4							4
Revisions of previous estimates	68	53	154	110	64	45	26	(7)	513
Improved recovery			3	1	2				6
Extensions and discoveries	1	1	5	98		11	8		124
Production	(65)	(70)	(205)	(118)	(32)	(34)	(42)	(9)	(575)
Sales of minerals in place		(1)		(7)					(8)
Reserves at December 31, 2014	503	544	1,740	1,239	1,069	285	232	160	5,772
Equity-accounted entities
Reserves at December 31, 2013			19	75		7	726		827
of which: developed			19			3	18		40
undeveloped				75		4	708		787
Purchase of minerals in place
Revisions of previous estimates			(1)	7			5		11
Improved recovery
Extensions and discoveries
Production			(2)	(1)		(2)	(3)		(8)
Sales of minerals in place
Reserves at December 31, 2014			16	81		5	728		830
Reserves at December 31, 2014	503	544	1,756	1,320	1,069	290	960	160	6,602
Developed	401	335	919	725	589	115	214	135	3,433
consolidated subsidiaries	401	335	904	702	589	112	188	135	3,366
equity-accounted entities			15	23		3	26		67
Undeveloped	102	209	837	595	480	175	746	25	3,169
consolidated subsidiaries	102	209	836	537	480	173	44	25	2,406
equity-accounted entities			1	58		2	702		763

Movements in net proved hydrocarbons reserves

		Rest of Europe
			North Africa	Sub-Saharan	Kazakhstan	Rest of Asia		and Oceania
	Italy			Africa			America	Australia	Total
(mmboe)
2015
Consolidated subsidiaries
Reserves at December 31, 2014	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

Movements in net proved hydrocarbons reserves

		Rest of Europe
			North Africa	(of which)	Sub-Saharan	Kazakhstan	Rest of Asia		and Oceania
(mmboe)	Italy			*Egypt	Africa			America	Australia	Total
2016
Consolidated subsidiaries
Reserves at December 31, 2015	465	495	1,694	500	1,282	1,198	422	269	150	5,975
of which: developed	362	404	1,010	380	764	689	159	217	115	3,720
undeveloped	103	91	684	120	518	509	263	52	35	2,255
Purchase of minerals in place
Revisions of previous estimates	(62)	1	90	(20)	157	63	111	1	4	365
Improved recovery		1	1							2
Extensions and discoveries		2	882	881			3			887
Production	(49)	(73)	(235)	(68)	(122)	(40)	(45)	(43)	(9)	(616)
Sales of minerals in place
Reserves at December 31, 2016	354	426	2,432	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	2,446	1,293	1,399	1,221	493	1,006	145	7,490
Developed	287	374	971	352	835	966	177	554	111	4,275
consolidated subsidiaries	287	374	957	352	809	966	175	205	111	3,884
equity-accounted entities			14		26		2	349		391
Undeveloped	67	52	1,475	941	564	255	316	452	34	3,215
consolidated subsidiaries	67	52	1,475	941	508	255	316	22	34	2,729
equity-accounted entities					56			430		486

Movements in net proved liquids reserves

		Rest of Europe
			North Africa	Sub-Saharan	Kazakhstan	Rest of Asia		and Oceania
	Italy			Africa			America	Australia	Total
(mmboe)
2014
Consolidated subsidiaries
Reserves at December 31, 2013	220	330	830	723	679	128	147	22	3,079
of which: developed	177	179	561	465	295	38	96	20	1,831
undeveloped	43	151	269	258	384	90	51	2	1,248
Purchase of minerals in place		1							1
Revisions of previous estimates	49	35	32	70	35	16	22	(7)	252
Improved recovery			3	1	2				6
Extensions and discoveries	1		2	36			5		44
Production	(27)	(34)	(91)	(84)	(19)	(13)	(27)	(2)	(297)
Sales of minerals in place		(1)		(7)					(8)
Reserves at December 31, 2014	243	331	776	739	697	131	147	13	3,077
Equity-accounted entities
Reserves at December 31, 2013			16	15		1	116		148
of which: developed			16				19		35
undeveloped				15		1	97		113
Purchase of minerals in place
Revisions of previous estimates			(1)	3			5		7
Improved recovery
Extensions and discoveries
Production			(1)	(1)			(4)		(6)
Sales of minerals in place
Reserves at December 31, 2014			14	17		1	117		149
Reserves at December 31, 2014	243	331	790	756	697	132	264	13	3,226
Developed	184	174	534	477	306	64	142	12	1,893
consolidated subsidiaries	184	174	521	470	306	64	116	12	1,847
equity-accounted entities			13	7			26		46
Undeveloped	59	157	256	279	391	68	122	1	1,333
consolidated subsidiaries	59	157	255	269	391	67	31	1	1,230
equity-accounted entities			1	10		1	91		103

Movements in net proved liquids reserves

		Rest of Europe
			North Africa	Sub-Saharan	Kazakhstan	Rest of Asia		and Oceania
	Italy			Africa			America	Australia	Total
(mmboe)
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 liquids reserves

		Rest of Europe
	Italy		North Africa	(of which) *Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
(mmboe) 2016
Consolidated subsidiaries
Reserves at December 31, 2015	228	305	821	327	787	771	262	189	9	3,372
of which: developed	171	237	542	230	511	355	126	149	9	2,100
undeveloped	57	68	279	97	276	416	136	40		1,272
Purchase of minerals in place
Revisions of previous estimates	(35)	(4)	(7)	(26)	113	20	73	(1)	1	160
Improved recovery		1	1							2
Extensions and discoveries		2	9	8						11
Production	(17)	(40)	(89)	(28)	(91)	(24)	(28)	(25)	(1)	(315)
Sales of minerals in place
Reserves at December 31, 2016	176	264	735	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	748	281	824	767	307	303	9	3,398
Developed	132	228	505	205	515	556	124	165	8	2,233
consolidated subsidiaries	132	228	492	205	507	556	124	143	8	2,190
equity-accounted entities			13		8			22		43
Undeveloped	44	36	243	76	309	211	183	138	1	1,165
consolidated subsidiaries	44	36	243	76	302	211	183	20	1	1,040
equity-accounted entities					7			118		125

Movements in net proved natural gas reserves(a)

		Rest of Europe
	Italy		North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
(bcf) 2014
Consolidated subsidiaries
Reserves at December 31, 2013	1,532	1,247	5,231	2,374	1,957	744	509	848	14,442
of which: developed	1,266	904	2,432	1,295	1,488	286	310	561	8,542
undeveloped	266	343	2,799	1,079	469	458	199	287	5,900
Purchase of minerals in place		21							21
Revisions of previous estimates	113	99	668	214	165	156	23	(1)	1,437
Improved recovery
Extensions and discoveries			19	341		59	16		435
Production	(213)	(195)	(627)	(185)	(73)	(113)	(80)	(40)	(1,526)
Sales of minerals in place		(1)							(1)
Reserves at December 31, 2014	1,432	1,171	5,291	2,744	2,049	846	468	807	14,808
Equity-accounted entities
Reserves at December 31, 2013			15	330		28	3,353		3,726
of which: developed			15			14	5		34
undeveloped				330		14	3,348		3,692
Purchase of minerals in place
Revisions of previous estimates			2	25		(2)			25
Improved recovery
Extensions and discoveries
Production			(2)	(4)		(8)			(14)
Sales of minerals in place
Reserves at December 31, 2014			15	351		18	3,353		3,737
Reserves at December 31, 2014	1,432	1,171	5,306	3,095	2,049	864	3,821	807	18,545
Developed	1,192	887	2,125	1,360	1,553	271	399	675	8,462
consolidated subsidiaries	1,192	887	2,110	1,271	1,553	261	393	675	8,342
equity-accounted entities			15	89		10	6		120
Undeveloped	240	284	3,181	1,735	496	593	3,422	132	10,083
consolidated subsidiaries	240	284	3,181	1,473	496	585	75	132	6,466
equity-accounted entities				262		8	3,347		3,617

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

Movements in net proved natural gas reserves(a)

		Rest of Europe		Sub-Saharan
(bcf)	Italy		North Africa	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.

Movements in net proved natural gas reserves(a)

	Italy	Rest of Europe	North Africa	(of which) *Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
(bcf)
2016
Consolidated subsidiaries
Reserves at December 31, 2015	1,304	1,044	4,798	947	2,714	2,354	878	439	771	14,302
of which: developed	1,051	919	2,566	822	1,390	1,830	185	373	585	8,899
undeveloped	253	125	2,232	125	1,324	524	693	66	186	5,403
Purchase of minerals in place
Revisions of previous estimates	(155)	18	496	25	223	224	200	8	12	1,026
Improved recovery
Extensions and discoveries			4,767	4,767			15			4,782
Production	(172)	(184)	(803)	(219)	(170)	(93)	(90)	(94)	(42)	(1,648)
Sales of minerals in place
Reserves at December 31, 2016	977	878	9,258	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	9,273	5,520	3,135	2,485	1,007	3,837	741	22,333
Developed	845	801	2,546	799	1,755	2,239	284	2,120	559	11,149
consolidated subsidiaries	845	801	2,531	799	1,651	2,239	280	338	559	9,244
equity-accounted entities			15		104		4	1,782		1,905
Undeveloped	132	77	6,727	4,721	1,380	246	723	1,717	182	11,184
consolidated subsidiaries	132	77	6,727	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.

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
2014
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	3,028	2,721	2,010	4,716	346	589	1,691	67	15,168
- sales to third parties		596	7,415	1,369	976	774	129	299	11,558
Total revenues	3,028	3,317	9,425	6,085	1,322	1,363	1,820	366	26,726
Operations costs	(423)	(687)	(694)	(935)	(208)	(223)	(357)	(124)	(3,651)
Production taxes	(293)		(291)	(648)		(33)		(15)	(1,280)
Exploration expenses	(36)	(245)	(72)	(681)		(204)	(171)	(69)	(1,478)
DD&A and Provision for abandonment(a)	(819)	(1,082)	(1,330)	(1,985)	(90)	(860)	(1,295)	(175)	(7,636)
Other income (expenses)	(184)	(96)	(773)	(358)	(251)	(124)	(78)	(30)	(1,894)
Pretax income from producing activities	1,273	1,207	6,265	1,478	773	(81)	(81)	(47)	10,787
Income taxes	(503)	(785)	(3,992)	(1,155)	(291)	(102)	29	43	(6,756)
Results of operations from E&P activities of consolidated subsidiaries	770	422	2,273	323	482	(183)	(52)	(4)	4,031
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties			19			87	232		338
Total revenues			19			87	232		338
Operations costs			(11)			(11)	(27)		(49)
Production taxes			(3)				(94)		(97)
Exploration expenses		(1)	(2)			(31)	(1)		(35)
DD&A and Provision for abandonment		(1)	(2)			(40)	(60)		(103)
Other income (expenses)		(1)	1	(32)		(3)	(41)		(76)
Pretax income from producing activities		(3)	2	(32)		2	9		(22)
Income taxes			(2)			(23)	(18)		(43)
Results of operations from E&P activities of equity-accounted entities		(3)		(32)		(21)	(9)		(65)

(a) Includes asset impairments amounting to €851 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
2015
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	2,124	1,828	1,403	3,514	231	628	1,118	29	10,875
- sales to third parties		501	5,681	914	659	854	131	226	8,966
Total revenues	2,124	2,329	7,084	4,428	890	1,482	1,249	255	19,841
Operations costs	(403)	(642)	(948)	(1,099)	(239)	(235)	(453)	(108)	(4,127)
Production taxes	(184)		(240)	(405)		(30)		(9)	(868)
Exploration expenses	(35)	(205)	(164)	(216)		(210)	(35)	(6)	(871)
DD&A and Provision for abandonment(a)	(750)	(2,022)	(2,938)	(3,835)	(109)	(1,491)	(1,775)	(111)	(13,031)
Other income (expenses)	(215)	(142)	(564)	(290)	(156)	(282)	(9)	(23)	(1,681)
Pretax income from producing activities	537	(682)	2,230	(1,417)	386	(766)	(1,023)	(2)	(737)
Income taxes	(182)	589	(2,148)	272	(142)	90	406	(25)	(1,140)
Results of operations from E&P activities of consolidated subsidiaries	355	(93)	82	(1,145)	244	(676)	(617)	(27)	(1,877)
Equity-accounted entities
Revenues:
- sales to consolidated entities
- sales to third parties			19			68	248		335
Total revenues			19			68	248		335
Operations costs			(9)			(13)	(49)		(71)
Production taxes			(3)				(82)		(85)
Exploration expenses						(16)			(16)
DD&A and Provision for abandonment		(1)	(3)	(432)		(77)	(78)		(591)
Other income (expenses)		(3)	(1)	(35)		(6)	(48)		(93)
Pretax income from producing activities		(4)	3	(467)		(44)	(9)		(521)
Income taxes			(3)			8	(29)		(24)
Results of operations from E&P activities of equity-accounted entities		(4)		(467)		(36)	(38)		(545)

(a) Includes asset impairments amounting to €5,051 million.

Results of operations from oil and gas producing activities

	Italy	Rest of Europe	North Africa	(of which) *Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
(€ million)
2016
Consolidated subsidiaries
Revenues:
- sales to consolidated entities	1,217	1,673	941	9	3,178	252	1,027	833	4	9,125
- sales to third parties		432	4,312	1,471	485	606	114	102	165	6,216
Total revenues	1,217	2,105	5,253	1,480	3,663	858	1,141	935	169	15,341
Operations costs	(311)	(599)	(807)	(356)	(968)	(269)	(215)	(325)	(49)	(3,543)
Production taxes	(96)		(176)		(282)		(17)		(5)	(576)
Exploration expenses	(35)	(40)	(87)	(42)	(142)		(39)	(28)	(3)	(374)
DD&A and Provision for abandonment(a)	(923)	(943)	(1,366)	(691)	(1,093)	(129)	(952)	(480)	(67)	(5,953)
Other income (expenses)	(342)	(232)	(466)	(265)	(917)	(57)	(130)	(120)	(8)	(2,272)
Pretax income from producing activities	(490)	291	2,351	126	261	403	(212)	(18)	37	2,623
Income taxes	159	(1)	(1,707)	(89)	97	(139)	32	(9)	(9)	(1,577)
Results of operations from E&P activities of consolidated subsidiaries	(331)	290	644	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)
DD&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 net (reversal) amounting to minus €700 million.

Capitalized cost

(€ million)	Italy	Rest of Europe	North Africa	(of which) *Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2015
Consolidated subsidiaries
Proved mineral interests	15,280	15,110	26,904		35,241	3,364	10,424	16,156	2,037	124,516
Unproved mineral interests	18	297	444		2,443	1	1,229	874	203	5,509
Support equipment and facilities	355	42	1,758		1,318	112	34	74	15	3,708
Incomplete wells and other	1,114	3,501	2,280		4,932	8,900	1,665	729	123	23,244
Gross Capitalized Costs	16,767	18,950	31,386		43,934	12,377	13,352	17,833	2,378	156,977
Accumulated depreciation, depletion and amortization	(12,184)	(11,431)	(20,268)		(25,235)	(1,422)	(9,691)	(13,344)	(1,122)	(94,697)
Net Capitalized Costs consolidated subsidiaries(a)	4,583	7,519	11,118		18,699	10,955	3,661	4,489	1,256	62,280
Equity-accounted entities
Proved mineral interests		3	89		23		624	2,010		2,749
Unproved mineral interests		17					93			110
Support equipment and facilities			8					6		14
Incomplete wells and other		10	5		1,508		23	112		1,658
Gross Capitalized Costs		30	102		1,531		740	2,128		4,531
Accumulated depreciation, depletion and amortization		(23)	(77)		(441)		(628)	(338)		(1,507)
Net Capitalized Costs equity-accounted entities(a)		7	25		1,090		112	1,790		3,024
2016
Consolidated subsidiaries
Proved mineral interests	15,951	18,678	28,754	15,262	38,539	10,790	11,680	17,127	2,085	143,604
Unproved mineral interests	18	301	471	55	2,461	1	1,155	903	210	5,520
Support equipment and facilities	357	42	1,830	203	1,375	111	37	77	15	3,844
Incomplete wells and other	724	242	4,175	1,828	5,117	2,565	2,248	317	134	15,522
Gross Capitalized Costs	17,050	19,263	35,230	17,348	47,492	13,467	15,120	18,424	2,444	168,490
Accumulated depreciation, depletion and amortization	(13,022)	(12,113)	(22,396)	(11,022)	(27,264)	(1,608)	(11,000)	(14,301)	(1,227)	(102,931)
Net Capitalized Costs consolidated subsidiaries(a)	4,028	7,150	12,834	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(a)		6	23		1,128		95	1,695		2,947

(a) The amounts include net capitalized financial charges totalling €1,029 million in 2015 and €1,090 million in 2016 for the consolidates subsidiaries and €92 million in 2015 and €95 million in 2016 for equity-accounted entities.

Cost incurred

(€ million)	Italy	Rest of Europe	North Africa	(of which) *Egypt	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
2014
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration	29	188	227		635		160	139	20	1,398
Development(a)	1,382	2,395	955		3,479	572	1,118	1,169	122	11,192
Total costs incurred consolidated
subsidiaries	1,411	2,583	1,182		4,114	572	1,278	1,308	142	12,590
Equity-accounted entities
Proved property acquisitions
Unproved property acquisitions
Exploration		2					33	1		36
Development(b)			1		22		38	375		436
Total costs incurred
equity-accounted entities		2	1		22		71	376		472
2015
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions
Exploration	28	176	289		196		71	54	6	820
Development(a)	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(b)		1	1		112		35	554		703
Total costs incurred
equity-accounted entities		2	1		112		49	555		719
2016
Consolidated subsidiaries
Proved property acquisitions
Unproved property acquisitions			2	2						2
Exploration	27	51	364	306	70		80	26	3	621
Development(a)	387	437	2,446	1,752	2,019	651	1,232	(5)	1	7,168
Total costs incurred consolidated
subsidiaries	414	488	2,812	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(b)			1		28		12	95		136
Total costs incurred equity-accounted entities		1	1		28		25	95		150

(a) Includes the abandonment costs of the assets for €2,062 million in 2014, negative for €817 million in 2015 and negative for €665 million in 2016. (b) Includes the abandonment costs of the assets negative for €47 million in 2014, costs for €54 million in 2015 and negative for €15 million in 2016.

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.

(€ million)	Italy	Rest of Europe	North Africa	Sub-Saharan Africa	Kazakhstan	Rest of Asia	America	and Oceania Australia	Total
December 31, 2014
Consolidated subsidiaries
Future cash inflows	24,951	29,140	96,372	65,853	55,740	13,664	10,955	4,849	301,524
Future production costs Future development	(6,374)	(6,856)	(19,906)	(18,236)	(9,878)	(4,158)	(2,680)	(1,092)	(69,180)
and abandonment costs	(4,698)	(5,292)	(9,673)	(9,139)	(4,576)	(4,600)	(1,892)	(356)	(40,226)
Future net inflow before income tax	13,879	16,992	66,793	38,478	41,286	4,906	6,383	3,401	192,118
Future income tax	(3,583)	(10,595)	(35,484)	(20,514)	(10,400)	(1,462)	(2,401)	(989)	(85,428)
Future net cash flows	10,296	6,397	31,309	17,964	30,886	3,444	3,982	2,412	106,690
10% discount factor	(4,064)	(1,464)	(13,905)	(7,164)	(19,699)	(1,900)	(1,353)	(1,106)	(50,655)
Standardized measure of discounted future net cash flows	6,232	4,933	17,404	10,800	11,187	1,544	2,629	1,306	56,035
Equity-accounted entities
Future cash inflows			485	3,861		200	18,871		23,417
Future production costs			(165)	(692)		(33)	(5,724)		(6,614)
Future development and abandonment costs			(18)	(104)		(51)	(2,032)		(2,205)
Future net inflow before income tax			302	3,065		116	11,115		14,598
Future income tax			(23)	(426)		(45)	(4,608)		(5,102)
Future net cash flows			279	2,639		71	6,507		9,496
10% discount factor			(158)	(1,442)		(11)	(4,327)		(5,938)
Standardized measure of discounted future net cash flows			121	1,197		60	2,180		3,558
Total	6,232	4,933	17,525	11,997	11,187	1,604	4,809	1,306	59,593

(€ 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 Future development	(4,995)	(5,554)	(13,481)	(14,645)	(8,846)	(4,585)	(3,091)	(804)	(56,001)
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

(€ million)	Italy	Rest of Europe	North Africa	(of which) *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	64,371	33,524	38,271	26,903	12,263	5,789	2,815	172,937
Future production costs	(4,136)	(5,240)	(15,408)	(7,927)	(13,913)	(9,247)	(3,498)	(2,935)	(658)	(55,035)
Future development and abandonment costs	(3,641)	(3,575)	(12,885)	(6,981)	(9,392)	(3,268)	(5,047)	(1,313)	(270)	(39,391)
Future net inflow before income tax	1,850	4,083	36,078	18,616	14,966	14,388	3,718	1,541	1,887	78,511
Future income tax	(237)	(1,308)	(15,194)	(5,941)	(4,525)	(2,596)	(953)	(298)	(341)	(25,452)
Future net cash flows	1,613	2,775	20,884	12,675	10,441	11,792	2,765	1,243	1,546	53,059
10% discount factor	(241)	(365)	(12,115)	(8,055)	(4,594)	(6,536)	(1,266)	(501)	(724)	(26,342)
Standardized measure of discounted future net cash flows	1,372	2,410	8,769	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			(143)		(974)		(20)	(4,614)		(5,751)
Future development 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	8,817	4,620	6,389	5,256	1,508	3,264	822	29,838

Changes in standardized measure of discounted future net cash flows

	Consolidated subsidiaries	Equity-accounted entities	Total
(€ million)
Standardized measure of discounted future net cash flows at December 31, 2013	56,177	2,327	58,504
Increase (decrease):
- sales, net of production costs	(21,795)	(192)	(21,987)
- net changes in sales and transfer prices, net of production costs	(12,053)	(500)	(12,553)
- extensions, discoveries and improved recovery, net of future production and development costs	1,667		1,667
- changes in estimated future development and abandonment costs	(6,047)	223	(5,824)
- development costs incurred during the period that reduced future development costs	8,745	451	9,196
- revisions of quantity estimates	8,085	(325)	7,760
- accretion of discount	11,064	512	11,576
- net change in income taxes	7,049	704	7,753
- purchase of reserves in-place	67		67
- sale of reserves in-place	(271)		(271)
- changes in production rates (timing) and other	3,347	358	3,705
Net increase (decrease)	(142)	1,231	1,089
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
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

Quarterly information

Main financial data of continuing operations(a)

			2015					2016
(€ million)		I quarter II quarter	III quarter	IV quarter			I quarter II quarter	III quarter	IV quarter
Net sales from operations	21,038	20,279	15,903	15,066	72,286	13,344	13,416	13,195	15,807	55,762
Operating profit (loss)	1,770	1,605	248	(6,699)	(3,076)	105	220	192	1,640	2,157
Adjusted operating profit (loss)	1,795	1,823	943	1,147	5,708	583	188	258	1,286	2,315
Exploration & Production	1,080	1,585	919	598	4,182	95	355	644	1,400	2,494
Gas & Power	294	31	(469)	18	(126)	285	(229)	(374)	(72)	(390)
Refining & Marketing	121	105	335	134	695	177	156	175	75	583
Corporate and other activities	(89)	(123)	(56)	(101)	(369)	(90)	(126)	(118)	(118)	(452)
Unrealized profit intragroup elimination and consolidation adjustments	389	225	214	498	1,326	116	32	(69)	1	80
Net (loss) profit(b)	832	(97)	(790)	(8,723)	(8,778)	(796)	(446)	(562)	340	(1,464)
- continuing operations	787	498	(783)	(8,454)	(7,952)	(383)	(446)	(562)	340	(1,051)
- discontinued operations	45	(595)	(7)	(269)	(826)	(413)				(413)
Capital expenditure	2,684	3,150	2,210	2,697	10,741	2,455	2,424	2,051	2,250	9,180
Investments	61	47	63	57	228	1,124	28	6	6	1,164
Net borrowings at period end	15,140	16,477	18,414	16,871	16,871	12,222	13,814	16,008	14,776	14,776

(a) Quarterly data are unaudited.

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

Key market indicators

	2015					2016
	I quarter		II quarter III quarter IV quarter			I quarter		II quarter III quarter IV quarter
Average price of Brent dated crude oil(a)	53.97	61.92	50.26	43.69	52.46	33.89	45.57	45.85	49.46	43.69
Average EUR/USD exchange rate(b)	1.126	1.105	1.112	1.095	1.110	1.102	1.129	1.116	1.078	1.107
Average price in euro of Brent dated crude oil	47.93	56.04	45.20	39.90	47.26	30.75	40.36	41.08	45.88	39.47
Standard Eni Refining Margin (SERM)(c)	7.6	9.1	10.0	6.6	8.3	4.2	4.6	3.3	4.7	4.2

(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.

Main operating data

		2015			2016
			I quarter II quarter	III quarter	IV quarter			I quarter II quarter	III quarter	IV quarter
Liquids production	(kbbl/d)	860	903	868	998	908	890	852	864	906	878
Natural gas production	(mmcf/d)	4,596	4,676	4,582	4,868	4,681	4,718	4,709	4,616	5,184	4,807
Hydrocarbons production	(kboe/d)	1,697	1,754	1,703	1,884	1,760	1,754	1,715	1,710	1,856	1,759
Italy		165	173	168	169	169	154	96	125	159	133
Rest of Europe		186	181	182	192	185	190	188	187	240	201
North Africa		638	681	647	684	662	616	651	638	680	647
Sub-Saharian Africa		342	343	336	343	341	343	350	330	334	339
Kazakhstan		100	98	82	100	95	118	90	103	133	111
Rest of Asia		109	113	117	201	135	132	141	133	103	127
America		128	140	148	170	147	178	174	171	184	177
Australia and Oceania		29	25	23	25	26	23	25	23	23	24
Production sold	(mmboe)	144.5	153.6	149.8	166.2	614.1	151.5	147.5	148.5	161,1	608.6
Sales of natural gas to third parties	(bcm)	23.47	20.38	18.30	20.07	82.22	21.82	19.18	17.76	21.10	79.86
Own consumption of natural gas		1.54	1.28	1.51	1.55	5.88	1.53	1.31	1.60	1.66	6.10
Sales to third parties and own consumption		25.01	21.66	19.81	21.62	88.10	23.35	20.49	19.36	22.76	85.96
Sales of natural gas of Eni's affiliates (net to Eni)		0.61	0.73	0.68	0.76	2.78	0.75	0.66	0.65	0.91	2.97
Total sales and own consumption of natural gas		25.62	22.39	20.49	22.38	90.88	24.10	21.15	20.01	23.67	88.93
Electricity sales	(TWh)	8.47	8.35	9.00	9.06	34.88	9.45	8.64	9.17	9.79	37.05
Sales of refined products	(mmtonnes)	8.36	9.43	8.85	8.60	35.24	7.69	8.70	8.65	8.37	33.41
Retail sales in Italy		1.36	1.51	1.58	1.51	5.96	1.37	1.50	1.59	1.48	5.93
Wholesale sales in Italy		1.69	1.99	2.17	1.99	7.84	1.84	2.01	2.23	2.08	8.16
Retail sales Rest of Europe		0.69	0.79	0.77	0.68	2.93	0.63	0.71	0.72	0.61	2.66
Wholesale sales Rest of Europe		1.08	0.98	0.90	0.87	3.83	0.70	0.81	0.83	0.84	3.18
Wholesale sales outside Europe		0.10	0.11	0.11	0.11	0.43	0.10	0.11	0.11	0.11	0.43
Other markets		3.44	4.05	3.33	3.43	14.25	3.05	3.57	3.17	3.26	13.05

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 oil	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 oil	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	(tLNG)	1.2	toe	8.9 bbl	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	5.492	1	159	0.158984
l	0.035315	0.0063	1	0.001
m3	35.31485	6.2898	103	1

Investor Relations

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

Eni SpA

Headquarters: Rome, Piazzale Enrico Mattei, 1 Capital Stock as of December 31, 2016: €4,005,358,876 fully paid Tax identification number: 00484960588 Branches: San Donato Milanese (Milan) - Via Emilia, 1 San Donato Milanese (Milan) - Piazza Ezio Vanoni, 1

Publications

Financial Statement pursuant to rule 154-ter paragraph 1 of Legislative Decree No. 58/1998 Integrated Annual Report Annual Report on Form 20-F for the Securities and Exchange Commission Fact Book (in Italian and English) Eni in 2016 (in 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)

Internet home page: eni.com Rome office telephone: +39-0659821 Toll-free number: 800940924 e-mail: segreteriasocietaria.azionisti@eni.com

ADRs/Depositary

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