NATURAL GAS (BCF) | | | Italy | | | Rest of Europe | | | North Africa | | | of which Egypt | | | Sub- Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | Americas | | | Australia and Oceania | | | Total reserves | | Consolidated subsidiaries1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year ended Dec. 31, 20142019 | | | 1,432752 | | | 1,171262 | | | 5,2912,738 | | | 5,191 | | | 4,103 | | | 1,969 | | | 1,349 | | | 240 | | | 507 | | | 17,111 | | developed | | | 657 | | | 242 | | | 1,374 | | | 4,777 | | | 1,858 | | | 1,969 | | | 685 | | | 186 | | | 322 | | | 12,070 | | undeveloped | | | 95 | | | 20 | | | 1,364 | | | 414 | | | 2,245 | | | | | | 2,744664 | | | 2,04954 | | | 846185 | | | 4685,041 | | Dec. 31, 2018 | | | 8071,199 | | | 14,808320 | | | 2,890 | | | 5,275 | | | 3,506 | | | 1,989 | | | 1,217 | | | 277 | | | 651 | | | 17,324 | | developed | | | 1,192980 | | | 887300 | | | 2,1101,447 | | | 3,331 | | | 1,871 | | | 1,846 | | | 822 | | | 154 | | | 452 | | | 11,203 | | undeveloped | | | 219 | | | 20 | | | 1,443 | | | 1,944 | | | 1,635 | | | 143 | | | 395 | | | 123 | | | 199 | | | 6,121 | | Dec. 31, 2017 | | | 1,131 | | | 896 | | | 3,145 | | | 4,351 | | | 3,660 | | | 2,108 | | | 1,065 | | | 225 | | | 709 | | | 17,290 | | developed | | | 987 | | | 771 | | | 1,233 | | | 1,421 | | | 1,693 | | | 1,878 | | | 862 | | | 171 | | | 519 | | | 9,535 | | undeveloped | | | 144 | | | 125 | | | 1,912 | | | 2,930 | | | 1,967 | | | 230 | | | 203 | | | 54 | | | 190 | | | 7,755 | | Equity-accounted entities2 | | | | | | 1,271 | | | 1,553 | | | 261 | | | 393 | | | 675 | | | 8,342 | | undeveloped | | | 240 | | | 284 | | | 3,181 | | | | | | 1,473 | | | 496 | | | 585 | | | 75 | | | 132 | | | 6,466 | | Year ended Dec. 31, 2015 | | | 1,304 | | | 1,044 | | | 4,798 | | | | | | 2,714 | | | 2,354 | | | 878 | | | 439 | | | 771 | | | 14,302 | | developed | | | 1,051 | | | 919 | | | 2,566 | | | | | | 1,390 | | | 1,830 | | | 185 | | | 373 | | | 585 | | | 8,899 | | undeveloped | | | 253 | | | 125 | | | 2,232 | | | | | | 1,324 | | | 524 | | | 693 | | | 66 | | | 186 | | | 5,403 | | Year ended Dec. 31, 2016 | | | 977 | | | 878 | | | 9,258 | | | 5,520 | | | 2,767 | | | 2,485 | | | 1,003 | | | 353 | | | 741 | | | 18,462 | | developed | | | 845 | | | 801 | | | 2,531 | | | 799 | | | 1,651 | | | 2,239 | | | 280 | | | 338 | | | 559 | | | 9,244 | | undeveloped | | | 132 | | | 77 | | | 6,727 | | | 4,721 | | | 1,116 | | | 246 | | | 723 | | | 15 | | | 182 | | | 9,218 | | Equity-accounted entities | | | | | | | | | | | | Year ended Dec. 31, 20142019 | | | | | | 772 | | | 14 | | | | | | 287 | | | | | | | | | 151,648 | | | | | | 3512,721 | | developed | | | | | | 18597 | | | 3,35314 | | | | | | 3,73788 | | | | | | | | | 1,648 | | | | | | 2,347 | | undeveloped | | | | | | 175 | | | | | | | | | 199 | | | | | | | | | | | | | | | 374 | | Dec. 31, 2018 | | | | | | 360 | | | 14 | | | | | | 310 | | | | | | | | | 1,716 | | | | | | 2,400 | | developed | | | | | | 276 | | | 14 | | | | | | 57 | | | | | | | | | 1,716 | | | | | | 2,063 | | undeveloped | | | | | | 84 | | | | | | | | | 253 | | | | | | | | | | | | | | | 337 | | Dec. 31, 2017 | | | | | | | | | 14 | | | | | | 349 | | | | | | | | | 1,819 | | | | | | 2,182 | | developed | | | | | | | | | 1514 | | | | | | 8983 | | | | | | 10 | | | 61,819 | | | | | | 1201,916 | | undeveloped | | | | | | | | | | | | | | | 262 | | | | | | 8 | | | 3,347 | | | | | | 3,617 | | Year ended Dec. 31, 2015 | | | | | | | | | 13 | | | | | | 387 | | | | | | 12 | | | 3,581 | | | | | | 3,993 | | developed | | | | | | | | | 13 | | | | | | 85 | | | | | | 9 | | | 1,295 | | | | | | 1,402 | | undeveloped266 | | | | | | | | | | | | | | | 302 | | | | | | 3 | | | 2,286 | | | | | | 2,591 | | Year ended Dec. 31, 2016 | | | | | | | | | 15 | | | | | | 368 | | | | | | 4 | | | 3,484 | | | | | | 3,871 | | developed | | | | | | | | | 15 | | | | | | 104 | | | | | | 4 | | | 1,782 | | | | | | 1,905 | | undeveloped | | | | | | | | | | | | | | | 264 | | | | | | | | | 1,702 | | | | | | 1,966266 | | Consolidated subsidiaries and equity accounted entities | | | | | | | | | | | | Year ended Dec. 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 | | undeveloped | | | 240 | | | 284 | | | 3,181 | | | | | | 1,735 | | Dec. 31, 2019 | | | 496752 | | | 5931,034 | | | 3,4222,752 | | | 1325,191 | | | 10,083 | | Year ended Dec. 31, 20154,390 | | | 1,3041,969 | | | 1,0441,349 | | | 4,8111,888 | | | 507 | | | 19,832 | | developed | | | 657 | | | 839 | | | 1,388 | | | 4,777 | | | 1,946 | | | 1,969 | | | 685 | | | 1,834 | | | 322 | | | 14,417 | | undeveloped | | | 95 | | | 195 | | | 1,364 | | | 414 | | | 2,444 | | | | | | 3,101664 | | | 2,35454 | | | 890185 | | | 4,0205,415 | | Dec. 31, 2018 | | | 1,199 | | | 680 | | | 2,904 | | | 5,275 | | | 3,816 | | | 1,989 | | | 1,217 | | | 1,993 | | | 651 | | | 19,724 | | developed | | | 980 | | | 576 | | | 1,461 | | | 3,331 | | | 1,928 | | | 1,846 | | | 822 | | | 1,870 | | | 452 | | | 13,266 | | undeveloped | | | 219 | | | 104 | | | 1,443 | | | 1,944 | | | 1,888 | | | 143 | | | 395 | | | 123 | | | 199 | | | 6,458 | | Dec. 31, 2017 | | | 1,131 | | | 896 | | | 3,159 | | | 4,351 | | | 4,009 | | | 2,108 | | | 1,065 | | | 2,044 | | | 709 | | | 19,472 | | developed | | | 987 | | | 771 | | | 18,295 | | developed1,247 | | | 1,0511,421 | | | 9191,776 | | | 2,5791,878 | | | 862 | | | 1,4751,990 | | | 1,830519 | | | 194 | | | 1,668 | | | 585 | | | 10,30111,451 | | undeveloped | | | 253144 | | | 125 | | | 2,2321,912 | | | 2,930 | | | 1,6262,233 | | | 524230 | | | 696203 | | | 2,35254 | | | 186190 | | | 7,9948,021 | | Year ended Dec. 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 | | undeveloped | | | 132 | | | 77 | | | 6,727 | | | 4,721 | | | 1,380 | | | 246 | | | 723 | | | 1,717 | | | 182 | | | 11,184 | | |
(1)
Include Eni’s share of reserves held by a joint-operation in Mozambique which is proportionally consolidated in the Group consolidated financial statements in accordance to IFRS. (2)
Reserves volumes of the Rest of Europe area, in 2018, are affected by the merger agreement that provided for the sale of the reserves of the former subsidiary Eni Norge as part of the business combination with Point Resources and the acquisition of Eni’s share of the reserves held by the combined company Vår Energi, an equity-accounted entity participated by Eni with a 69.6% interest.
Proved reserves of natural gas liquids are immaterial to the Group operations. Volumes of oil and natural gas applicable to long-termlong- term supply agreements with foreign governments in mineral assets where Eni is operator totaled 212128 mmBOE as of December 31, 2016 (1392019 (148 and 282178 mmBOE as of December 31, 20152018 and 2014,2017, respectively). Said volumes are not included in reserves volumes shown in the table herein. | | Subsidiaries | | Equity-accounted entities | | | Subsidiaries | | Equity-accounted entities | | | | 2014 | | 2015 | | 2016 | | 2014 | | 2015 | | 2016 | | | | | (mmBOE) | | | Additions to proved reserves | | | | 643 | | | | | 849 | | | | | 1,254 | | | | | 11 | | | | | 98 | | | | | (10) | | | | (mmBOE) | | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 | | Revisions of previous estimates | | | | | 459 | | | | | 590 | | | | | 466 | | | | | 62 | | | | | (99) | | | | | (285) | | | Improved recovery | | | | | | | | | | 13 | | | | | 20 | | | | | | | | | | | | | | | | | | Extensions and discoveries | | | | | 101 | | | | | 169 | | | | | 483 | | | | | 6 | | | | | | | | | | | | | Purchases of minerals-in-place | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 30 | | | | | 332 | | | | | 2 | | | | | 184 | | | | | 363 | | | | | | | | Sales of minerals-in-place | | | | (8) | | | | | (17) | | | | | | | | | | | | | | | | | | | | | | | | Production for the year (a) | | | | (575) | | | | | (629) | | | | | (616) | | | | | (8) | | | | | (13) | | | | | (28) | | | | | | Sales of minerals-in-place(a) | | | | | (42) | | | | | (528) | | | | | (523) | | | | | (6) | | | | | (1) | | | | | | | | Total additions to proved reserves | | | | | 548 | | | | | 576 | | | | | 448 | | | | | 246 | | | | | 263 | | | | | (285) | | | Production for the year(b) | | | | | (617) | | | | | (650) | | | | | (631) | | | | | (62) | | | | | (26) | | | | | (32) | | |
(a)
Sales of minerals-in-place include approximately 4 million boe of volumes (mainly gas) as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause. Management has estimated to be highly probable that the buyer will not redeem its contractual right to lift the pre-paid volumes within the contractual terms. (b)
The difference overcompared to production sold of 608.6630.6 mmBOE (549.5(622.3 mmboe in 20142017 and 642.4625.0 mmboe in 2015)2018) reflected natural gashydrocarbons volumes of 32.145.4 mmBOE consumed in operations (29.4(35.2 mmBOE in 20142017 and 26.443.5 mmBOE in 2015)2018), changes in inventories and other factors. | | | Subsidiaries and equity-accounted entities | | | | | 2014 | | | 2015 | | | 2016 | | | | | (%) | | Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources | | | | | 112 | | | | | | 145 | | | | | | 193 | | | Proved reserves replacement ratio of subsidiaries and equity-accounted entities, organic | | | | | 112 | | | | | | 148 | | | | | | 193 | | | |
| | | Subsidiaries and equity-accounted entities | | (%) | �� | | 2019 | | | 2018 | | | 2017 | | Proved reserves replacement ratio of subsidiaries and equity-accounted entities, all sources | | | | | 117 | | | | | | 124 | | | | | | 25 | | | Proved reserves replacement ratio of subsidiaries and equity-accounted entities, organic | | | | | 92 | | | | | | 100 | | | | | | 103 | | |
Eni’s proved reserves as of December 31, 20162019 totaled 7,4907,268 mmBOE (liquids 3,3983,601 mmBBL; natural gas 22,33319,832 BCF). Eni’s proved reserves reported an increase of 600115 mmBOE, or 8.7%1.6%, from December 31, 2015. 2018 due to progress made in the year in exploring for and developing new reserves and property acquisitions net of property sales. Portfolio transactions entailed a net addition of 166 mmBOE and comprised: (i) the purchase of ExxonMobil producing and development assets in Norway by our equity-accounted joint venture Vår Energi; (ii) the purchase of a 100% interest of Oooguruk production field in Alaska; (iii) the disposal of our production assets in Ecuador, of a 20% interest at the Merakes discovery in Indonesia, as well as other minor assets in Norway; and (iv) sales of minerals-in-place of approximately 4 million boe of volumes (mainly gas) as part of a long-term supply agreement to a state- owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause. Management has estimated to be highly probable that the buyer will not redeem its contractual right to lift the pre-paid volumes within the contractual terms. All sources additions to proved reserves booked in 20162019 were 1,244794 mmBOE; of which 1,254548 mmBOE came from Eni’s subsidiaries, and negativewhich include sales of reserves as part of a long-term supply agreement as discussed above, while 246 mmBOE from Eni’s share of equity-accounted entities. Due to a lowereddecrease in oil and gas prices compared to the Brent reference price used in the reserve estimation process at $42.8$62.7 per barrel in 20162019 ($5471.4 per barrel in 2015)2018), our all sources additions were adversely affecteddecreased by a downward revision of 7658 mmBOE, due to our having to remove certainthe removal of volumes of reserves which have become uneconomical in that environment, which were partially offset by higher volume entitlements at our PSA contracts because of the cost recovery mechanism. Further information about how to determine year-end amounts of proved reserves and the relevant net present value is provided in “Item 3 – Risk factors – Risk associated with the exploration and production of oil and natural gas”.
The methods (or technologies) used in the Eni’s proved reserves assessment in 20162019 depend on stage of development, quality and completeness of data, and production history availability. The methods include volumetric estimates, analogies, reservoir modelling, decline curve analysis or a combination of such methods. The data considered for these analyses are obtained from a combination of reliable technologies that produce consistent and repeatable results including well or field measurements (i.e. logs, core samples, pressure information, fluid samples, production test data and performance data) and indirect measurements (i.e. seismic data). However for each reservoir assessment the most suitable combination of technologies and methods is applied providing a high degree of confidence in establishing reliable reserves estimates. The all sources reserves replacement ratio achievedreported by Eni’s subsidiaries and equity-accounted entities was 193%117% in 2016 (145%2019 (124% in 20152018 and 112%25% in 2014).The2017). The organic reserves replacement ratio was 92% in 2019 (100% in 2018 and 103% in 2017) which excluded sales and purchases of minerals-in-place. The all sources reserves replacement ratio was calculated by dividing additions to proved reserves including sales and purchases of mineral-in-place by total production, each as derived from the tables of changes in proved reserves prepared in accordance with FASB Extractive Activities -– Oil & Gas (Topic 932) (see the supplemental oil and gas information in “Item 18 – Consolidated Financial Statements”). The reserves replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by booked reserves total additions. Management considers the reserve replacement ratio to be an important indicator of the Company’s ability to sustain its growth prospects. However, this ratio measures past performances and is not an indicator of future production because the ultimate recovery of reserves is subject to a number of risks and uncertainties. These include the risks associated with the successful completion of large-scale projects, including addressing ongoing regulatory issues and completion of infrastructures, reservoir performance, application of new technologies to improve the recovery factor as well as changes in oil&gas prices, political risks and geological and environmental risks. See “Item 3 – Risks associated with the exploration and production of oil and natural gas –Uncertainties– Uncertainties in estimates of oil and natural gas reserves”. The average reserves life index of Eni’s proved reserves was 11.610.6 years as of December 31, 2016,2019, which included reserves of both subsidiaries and equity-accounted entities. Eni’s subsidiaries Eni’s subsidiaries added 1,254548 mmBOE of proved oil&gas and gas reserves in 2016.2019 net of sales and purchase of minerals- in- place. This comprised 173236 mmBBL of liquids and 5,8081,525 BCF of natural gas. AdditionsThe breakdown of total additions to proved reserves derived from:is the following: (i) extensions and discoveries were 887up by 101 mmBOE with major increase booked in Egypt followingmainly due to the final investment decisiondecisions made for the projects of Dalma in the Zohr gas project;offshore United Arab Emirates, Assa North in Nigeria and Agogo field in the offshore operated Block 15/06 in Angola; (ii) revisions of previous estimates were 365up by 459 mmBOE and mainly reportedderived from the upward revisions of certain gas fields in Libya, IraqNigeria to feed the expansion project of the Bonny liquefaction plant, owned by Nigeria LNG (Eni’s interest 10.4%), and progress in development activities at the Zohr project in Egypt, Kashagan project in Kazakhstan and Berkine North in Algeria; (iii) purchases of mineral-in-place referred to Oooguruk production field in Alaska, as described above; and (v) sales of minerals-in-place referred to the disposal of a 20% stake of the Merakes discovery in Indonesia and entire participation of Ecuador production assets. In addition, sales of minerals- in- place include approximately 4 million boe of volumes (mainly gas) as part of a long-term supply agreement to a state- owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to continuous development activities and field performances; and (iii) improved recovery were 2 mmBOE mainly reported in Algeria and Norway.the take-or-pay clause, as discussed above. Eni’s share of equity-accounted entities Additions in Eni’s share of equity-accounted entities’entities added 246 mmBOE of proved oil&gas were negative and gas reserves in 20162019 net of sale and derived from downwardpurchase minerals-in-place. The breakdown of total additions to proved reserves is the following: (i) revisions of previous estimates reportedwere up by 62 mmBOE mainly due to the progress in Americas.development activities at the Balder X field in Norway; (ii) extensions and discoveries were up by 6 mmBOE mainly due to the production start-up of the Trestakk field in Norway; (iii) the purchase of ExxonMobil producing and development assets in Norway, as described above; and (v) sales of minerals-in-place referred to the minor producing assets in Norway.
Proved undeveloped reserves Proved undeveloped reserves as of December 31, 20162019 totaled 3,2152,114 mmBOE. At year-end, proved undeveloped reserves of liquids amounted to 1,1651,113 mmBBL, mainly concentrated in Africa.Africa and Asia. Proved
undeveloped reserves of natural gas amounted to 11,1845,415 BCF, mainly located in Africa and Americas.Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,040905 mmBBL of liquids and 9,2185,041 BCF of natural gas. In 2016, The table below provide a summary of changes in total proved undeveloped reserves increasedfor 2019.
Subsidiaries and equity-accounted entities (mmBOE) | | | 2019 | | Proved undeveloped reserves as of December 31, 2018 | | | | | 2,309 | | | Transfers to proved developed reserves | | | | | (655) | | | Extensions and discoveries | | | | | 101 | | | Revisions of previous estimates | | | | | 327 | | | Purchases of minerals-in-place | | | | | 44 | | | Sales of minerals-in-place | | | | | (12) | | | Proved undeveloped reserves as of December 31, 2019 | | | | | 2,114 | | |
In 2019, total proved undeveloped reserves decreased by 348195 mmBOE mainly due to:to progress made in maturing PUDs to proved developed (655 mmBOE). Additions to PUDs for the year included: (i) extensions and discoveries (up by 873101 mmBOE), in particular in Egypt mainly due to the final investment decision sanctioneddecisions made for the Zohr discovery;Dalma project in the United Arab Emirates, the Assa North project in Nigeria and the Agogo field in Angola; (ii) revisions of previous estimates (up by 121327 mmBOE) mainly reported in CongoNigeria due to the final investment decision made for an expansion project of the Bonny liquefaction plant and Iraq;in Egypt due to the development activity of the Zohr project; (iii) reclassificationpurchases (up by 44 mmBOE) mainly related to proved developed reservesthe Vår Energi acquisition in Norway as discussed above; and (iv) sales of minerals-in-place (down by 64612 mmBOE). related to minor assets in Norway and the Merakes discovery in Indonesia, as mentioned above. During 2016,2019, Eni converted 646matured 655 mmBOE of proved undeveloped reserves to proved developed reserves due to the progress ofin development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves related to the following fields/projects: Zohr and Nidoco in North West Egypt, Kashagan (Kazakhstan), Perla (Venezuela),in Kazakhstan, Litchendjili (Congo), Zubair (Iraq)in Congo, Ngl Eleme in Nigeria and Goliat (Norway).Area 1 in Mexico. In 2016,2019, capital expenditure amounted to approximately €7.5€6.8 billion and was made to progress the development of proved undeveloped reserves.PUDs. Reserves that remain proved undeveloped for five or more years are a result of several factors that affect the timing of the projects development and execution, such as the complex naturecomplexity of the development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. OfThe Company estimates that approximately 0.5 BBOE of proved undeveloped reserves have remained undeveloped for five years or more at the balance sheet date and decreased 0.1 BBOE from 2018. The decrease during 2019 was driven mainly by the progress in development activities made at the Kashagan field in Kazakhstan and by the Bahr Essalam phase 2 and Wafa compression projects in Libya. The proved undeveloped reserves that have been reportedremained undeveloped for five years or more years,at the largest arebalance sheet date mainly related to forthcoming development phases ofto: (i) the Kashagan project in Kazakhstan (approximately 0.2 BBOE) and certain assets in Venezuela (approximately 0.4 BBOE) andZubair field in Iraq (approximately 0.2(0.1 BBOE), as well aswhere development of PUDs has been conditioned by the drilling of additional production and injection wells to be linked to the production facilities, which were already completed to achieve the full field production plateau of 700 KBBL/d; (ii) certain Libyan gas fields (approximately 0.5(0.3 BBOE) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-termlong- term gas supply agreement currently in force. In order to secure fulfilmentfulfillment of the contractual delivery quantities, in Libya, Eni will implement phased production start-up from the relevant fields, which are expected to be put in production over the next several years.years; and (iii) other fields in Italy and Egypt (0.1 BBOE) where development activities are in progress. (See also our discussion under the “Risk factors” section regardingabout risks associated with oil&gas and gas development projects). Eni remains strongly committed to put these projects into production overin the next fewcoming years. The length of the development period is a function ofdepends on a range of external factors, such as for example the type of development, the location and physical operating environment of the field or the absence of infrastructure, considering that the majority of our projects are infrastructure-driven, and not a function of internal factors, such as an insufficient devotion of resources by Eni or a diminished commitment on the part of Eni to complete the project.
Delivery commitments Eni, through consolidated subsidiaries and equity-accounted entities, sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Some of these contracts, mostly relating to natural gas, specify the delivery of fixed and determinable quantities. Eni is contractually committed under existing contracts or agreements to deliver in the next three years mainly natural gas to third parties for a total of approximately 453555 mmBOE from producing assets located mainly in Algeria, Australia, Egypt, Ghana, Indonesia, Libya, Nigeria, Norway and Venezuela. The sales contracts contain a mix of fixed and variable pricing formulas that are generally referencedindexed to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available mainly from production of the Company’s proved developed reserves and supplies from third parties based on existing contracts. Production is expected to account for approximately 86%91% of delivery commitments. Eni has met all contractual delivery commitments as of December 31, 2016.2019. Oil and gas production, production prices and production costs The matters regarding future production, additions to reserves and related production costs and estimated reserves discussed below and elsewhere herein are forward-looking statements that involve risks and
uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties relating to future production and additions to reserves include political developments affecting the award of exploration or production interests or world supply and prices for oil and natural gas, or changes in the underlying economics of certain of Eni’s important hydrocarbons projects. Such risks and uncertainties relating to future production costs include delays or unexpected costs incurred in Eni’s production operations. In 2016,2019, oil and natural gas production available for sale averaged 1,6711,736 KBOE/d (1,688(1,732 KBOE/d in 2015) decreased2018). Production for the year expressed in barrel-of-oil equivalent was calculated assuming a natural gas conversion factor which was updated to 5,408 CF of gas equaling 1 barrel of oil without restating the comparative periods (it was 5,458 cubic feet of gas per barrel in previous reporting periods. For further information see “Item 3 – Selected operating information”). On a comparable basis, i.e. when excluding the effect of updating the gas conversion factor, production was barely unchanged from 2018. The full year period results were affected by 1.0%the divestment of Eni’s interest in certain assets as well as the effect of the business combination closed at the end of 2018 which involved our former subsidiary Eni Norge which was merged with Point Resources’ assets to establish the equity- accounted joint venture Vår Energi, and the termination of the Intisar production contract in Libya from 2015,the third quarter of 2018. Excluding the impact of portfolio transactions, marginal price effects at our PSAs and the termination of the Intisar contract, production would have grown by 4%. Production performance was driven by the ramp-up of the Zohr field and of other fields started in 2018, mainly in Libya, Ghana and Angola, and by the 2019 new project start-ups in Mexico, Norway, Egypt and Algeria. Other production increases were reported in Nigeria, as well as Kazakhstan and the United Arab Emirates. These positives were partly offset by lower gas production in Indonesia due to a scale-down in activity reflecting a significant slowdown in gas demand in Asia, in Venezuela due to the production shutdowncurrent situation in the Val d’Agri profit center (See also – oil and gas properties – Italy described above)Country, as well as planned facilities downtime,mature fields decline, mainly in the United Kingdom,Italy and the mature fields declines. These negatives were partially offset by new field start-ups and the continuing ramp-up of production at fields started in 2015, mainly reported in Angola, Egypt, Kazakhstan, Norway and Venezuela as well as higher production in Iraq and the price effects reported in PSA contracts.Angola. New field start-ups and ramp-ups of production added an estimated 280approximately 250 KBOE/d of new production. Production for the year excluded gas volumes which were not lifted by a long-term buyer who nonetheless paid the underlying price as provided by the take-or-pay clause of the long-term supply contract. Liquids production (878(890 KBBL/d) decreasedincreased by 306 KBBL/d, or 3.3%, due toapproximately 1% from the full year of 2018. Start- ups and ramp-ups of the period, mainly in Mexico, Libya and Ghana, and production shutdowngrowth in the Val d’Agri profit center, planned facilities downtimeUnited Arab Emirates and theNigeria were partly offset by facility shutdowns, mainly in Congo, lower production in Venezuela and mature fields decline. These negatives were partially offset by new fields start-up and production ramp-up in particular in Angola, Kazakhstan and Norway as well as higher production in Iraq. Natural gas production (4,329(4,576 mmCF/d) reported an increase of 45decreased by 54 mmCF/d, or 1.1% from 2015. Higherapproximately 1% compared to the full year of 2018. Lower production in Indonesia and Venezuela as well as mature fields decline were partly offset by production ramp-ups of the period, mainly in Egypt and Venezuela were partially offset by planned facilities downtimeGhana, and the declinegrowth in Nigeria.
Sales volumes of mature fields. Oiloil and gas production sold amounted to 608.6were 630.6 mmBOE. The 3.43.2 mmBOE difference over production on an available-for-saleavailable -for-sale basis (612 mmBOE)(633.8 mmBOE in 2019) reflected mainly changes in inventoriesinventory and other factors. Approximately 68%66% of liquids production sold (320(325.4 mmBBL) was destined to Eni’s mid-downstream sectors. About 22%18% of natural gas production sold (1,574(1,650 BCF) was destined to Eni’s Gas & Power segment.
The tables below provide Eni subsidiaries and its equity-accounted entities’ production (annual volumes and daily averages), by final product marketed of liquids and natural gas by country and geographical area of each of the last three fiscal years. 2014 Production available for sale (a)
| | | Italy | | | Rest
of
Europe | | | North
Africa | | | Sub-
Saharan
Africa | | | Kazakhstan | | | Rest of
Asia | | | Americas | | | Australia
and
Oceania | | | | | Hydrocarbons production | | | | | | | | | | | | Eni consolidated subsidiaries | | | (KBOE/d) | | | 171 | | | 184 | | | 528 | | | 305 | | | 85 | | | 87 | | | 112 | | | 25 | | | 1,497 | | | | | (mmBOE) | | | 63 | | | 67 | | | 193 | | | 111 | | | 31 | | | 31 | | | 41 | | | 9 | | | 546 | | Eni share of equity-accounted entities | | | (KBOE/d) | | | | | | | | | 4 | | | 2 | | | | | | 4 | | | 10 | | | | | | 20 | | | | | (mmBOE) | | | | | | | | | 1 | | | 1 | | | | | | 2 | | | 4 | | | | | | 8 | | Liquids production | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni consolidated subsidiaries | | | (KBBL/d) | | | 73 | | | 93 | | | 249 | | | 230 | | | 52 | | | 36 | | | 74 | | | 6 | | | 813 | | | | | (mmBBL) | | | 27 | | | 34 | | | 91 | | | 84 | | | 19 | | | 13 | | | 27 | | | 2 | | | 297 | | Eni share of equity-accounted entities | | | (KBBL/d) | | | | | | | | | 4 | | | | | | | | | 1 | | | 10 | | | | | | 15 | | | | | (mmBBL) | | | | | | | | | 1 | | | | | | | | | | | | 4 | | | | | | 5 | | Natural gas production | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni consolidated subsidiaries | | | (mmCF/d) | | | 541 | | | 498 | | | 1,533 | | | 411 | | | 181 | | | 279 | | | 205 | | | 106 | | | 3,754 | | | | | (BCF) | | | 198 | | | 182 | | | 559 | | | 150 | | | 66 | | | 102 | | | 75 | | | 39 | | | 1,371 | | Eni share of equity-accounted entities | | | (mmCF/d) | | | | | | | | | 3 | | | 7 | | | | | | 18 | | | | | | | | | 28 | | | | | (BCF) | | | | | | | | | 1 | | | 3 | | | | | | 6 | | | | | | | | | 10 | | | | | | | | | | | | | | | |
Average daily production available for sale(a)(b) | | | 2019 | | | 2018 | | | 2017 | | | | | Liquids (KBBL/d) | | | Natural gas (mmCF/d) | | | Hydrocarbons (KBOE/d) | | | Liquids (KBBL/d) | | | Natural gas (mmCF/d) | | | Hydrocarbons (KBOE/d) | | | Liquids (KBBL/d) | | | Natural gas (mmCF/d) | | | Hydrocarbons (KBOE/d) | | Eni consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Italy | | | 53 | | | 338 | | | 116 | | | 60 | | | 386 | | | 130 | | | 53 | | | 402 | | | 127 | | Rest of Europe | | | 23 | | | 158 | | | 52 | | | 113 | | | 410 | | | 188 | | | 102 | | | 443 | | | 183 | | Croatia | | | | | | | | | | | | | | | 10 | | | 2 | | | | | | 16 | | | 3 | | Norway | | | | | | | | | | | | 89 | | | 225 | | | 131 | | | 81 | | | 250 | | | 126 | | United Kingdom | | | 23 | | | 158 | | | 52 | | | 24 | | | 175 | | | 55 | | | 21 | | | 177 | | | 54 | | North Africa | | | 166 | | | 1,023 | | | 356 | | | 154 | | | 1,188 | | | 372 | | | 158 | | | 1,632 | | | 457 | | Algeria | | | 62 | | | 33 | | | 69 | | | 65 | | | 35 | | | 72 | | | 68 | | | 35 | | | 75 | | Libya | | | 101 | | | 980 | | | 282 | | | 86 | | | 1,141 | | | 295 | | | 87 | | | 1,585 | | | 377 | | Tunisia | | | 3 | | | 10 | | | 5 | | | 3 | | | 12 | | | 5 | | | 3 | | | 12 | | | 5 | | Egypt | | | 75 | | | 1,425 | | | 338 | | | 77 | | | 1,147 | | | 287 | | | 72 | | | 784 | | | 216 | | Sub-Saharan Africa | | | 247 | | | 415 | | | 324 | | | 244 | | | 346 | | | 308 | | | 247 | | | 328 | | | 305 | | Angola | | | 101 | | | | | | 101 | | | 111 | | | | | | 111 | | | 119 | | | | | | 119 | | Congo | | | 59 | | | 93 | | | 77 | | | 65 | | | 104 | | | 84 | | | 63 | | | 68 | | | 74 | | Ghana | | | 23 | | | 42 | | | 30 | | | 15 | | | 9 | | | 17 | | | 8 | | | | | | 8 | | Nigeria | | | 64 | | | 280 | | | 116 | | | 53 | | | 233 | | | 96 | | | 57 | | | 260 | | | 104 | | Kazakhstan | | | 99 | | | 240 | | | 143 | | | 91 | | | 228 | | | 133 | | | 83 | | | 231 | | | 126 | | Rest of Asia | | | 85 | | | 350 | | | 150 | | | 77 | | | 412 | | | 152 | | | 53 | | | 282 | | | 105 | | China | | | 1 | | | | | | 1 | | | 1 | | | | | | 1 | | | 2 | | | | | | 2 | | Indonesia | | | 2 | | | 255 | | | 49 | | | 3 | | | 315 | | | 60 | | | 3 | | | 161 | | | 33 | | Iraq | | | 26 | | | | | | 26 | | | 28 | | | | | | 28 | | | 40 | | | | | | 40 | | Pakistan | | | | | | 92 | | | 17 | | | | | | 97 | | | 18 | | | | | | 121 | | | 22 | | Turkmenistan | | | 7 | | | | | | 7 | | | 6 | | | | | | 6 | | | 8 | | | | | | 8 | | United Arab Emirates | | | 49 | | | 3 | | | 50 | | | 39 | | | | | | 39 | | | | | | | | | | | Americas | | | 56 | | | 48 | | | 64 | | | 52 | | | 108 | | | 72 | | | 63 | | | 181 | | | 96 | | Ecuador | | | 6 | | | | | | 6 | | | 12 | | | | | | 12 | | | 12 | | | | | | 12 | | Mexico | | | 4 | | | 2 | | | 4 | | | | | | | | | | | | | | | | | | | | Trinidad & Tobago | | | | | | | | | | | | | | | 36 | | | 6 | | | | | | 55 | | | 10 | | United States | | | 46 | | | 46 | | | 54 | | | 40 | | | 72 | | | 54 | | | 51 | | | 126 | | | 74 | | Australia and Oceania | | | 2 | | | 134 | | | 27 | | | 2 | | | 110 | | | 22 | | | 2 | | | 101 | | | 21 | | Australia | | | 2 | | | 134 | | | 27 | | | 2 | | | 110 | | | 22 | | | 2 | | | 101 | | | 21 | | | | | 806 | | | 4,131 | | | 1,570 | | | 870 | | | 4,335 | | | 1,664 | | | 833 | | | 4,384 | | | 1,636 | | Eni share of equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Angola | | | 4 | | | 86 | | | 20 | | | 3 | | | 75 | | | 17 | | | 3 | | | 72 | | | 17 | | Indonesia | | | | | | | | | | | | | | | 2 | | | 1 | | | 1 | | | 9 | | | 2 | | Norway | | | 74 | | | 168 | | | 105 | | | | | | | | | | | | | | | | | | | | Tunisia | | | 3 | | | | | | 3 | | | 3 | | | 2 | | | 3 | | | 3 | | | 2 | | | 3 | | Venezuela | | | 3 | | | 191 | | | 38 | | | 8 | | | 216 | | | 47 | | | 12 | | | 267 | | | 61 | | | | | 84 | | | 445 | | | 166 | | | 14 | | | 295 | | | 68 | | | 19 | | | 350 | | | 83 | | Total | | | 890 | | | 4,576 | | | 1,736 | | | 884 | | | 4,630 | | | 1,732 | | | 852 | | | 4,734 | | | 1,719 | |
(a)
It excludes production volumes of natural gashydrocarbons consumed in operations. Said volumes were 442 mmCF/124, 119 and 97 KBOE/d or 29.4 mmBOE.in 2019, 2018 and 2017, respectively. (b)
Daily production for the year excludes approximately 10 KBOE/d of volumes (mainly gas) as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause. Management has estimated to be highly probable that the buyer will not redeem its contractual right to lift the pre-paid volumes within the contractual terms. Such volume is classified as sales of minerals-in-place within the reserves movements for the year.
2015 Production available for sale (a)
| | | Italy | | | Rest
of
Europe | | | North
Africa | | | Sub-
Saharan
Africa | | | Kazakhstan | | | Rest of
Asia | | | Americas | | | Australia
and
Oceania | | | | | Hydrocarbons production | | | | | | | | | | | | Eni consolidated subsidiaries | | | (KBOE/d) | | | 161 | | | 179 | | | 631 | | | 324 | | | 92 | | | 123 | | | 120 | | | 25 | | | 1,655 | | | | | (mmBOE) | | | 59 | | | 65 | | | 230 | | | 119 | | | 33 | | | 45 | | | 44 | | | 9 | | | 604 | | Eni share of equity-accounted entities | | | (KBOE/d) | | | | | | | | | 4 | | | | | | | | | 5 | | | 24 | | | | | | 33 | | | | | (mmBOE) | | | | | | | | | 1 | | | | | | | | | 2 | | | 9 | | | | | | 12 | | Liquids production | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni consolidated subsidiaries | | | (KBBL/d) | | | 69 | | | 85 | | | 268 | | | 256 | | | 56 | | | 77 | | | 75 | | | 5 | | | 891 | | | | | (mmBBL) | | | 25 | | | 31 | | | 98 | | | 93 | | | 20 | | | 28 | | | 28 | | | 2 | | | 325 | | Eni share of equity-accounted entities | | | (KBBL/d) | | | | | | | | | 4 | | | | | | | | | 1 | | | 12 | | | | | | 17 | | | | | (mmBBL) | | | | | | | | | 1 | | | | | | | | | 1 | | | 4 | | | | | | 6 | | Natural gas production | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni consolidated subsidiaries | | | (mmCF/d) | | | 503 | | | 515 | | | 1,990 | | | 378 | | | 199 | | | 259 | | | 243 | | | 107 | | | 4,194 | | | | | (BCF) | | | 183 | | | 188 | | | 727 | | | 138 | | | 73 | | | 94 | | | 89 | | | 39 | | | 1,531 | | Eni share of equity-accounted entities | | | (mmCF/d) | | | | | | | | | 3 | | | | | | | | | 19 | | | 68 | | | | | | 90 | | | | | (BCF) | | |
| | |
| | | 1
| | |
| | |
| | | 7
| | | 25
| | |
| | | 33
| | | | | | | | | | | | | | | |
Annual production available for sale(a)(b) | | | 2019 | | | 2018 | | | 2017 | | | | | Liquids (mmBBL) | | | Natural gas (BCF) | | | Hydrocarbons (mmBOE) | | | Liquids (mmBBL) | | | Natural gas (BCF) | | | Hydrocarbons (mmBOE) | | | Liquids (mmBBL) | | | Natural gas (BCF) | | | Hydrocarbons (mmBOE) | | Eni consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Italy | | | 19 | | | 123 | | | 42 | | | 22 | | | 141 | | | 48 | | | 19 | | | 147 | | | 46 | | Rest of Europe | | | 8 | | | 58 | | | 19 | | | 41 | | | 150 | | | 68 | | | 37 | | | 162 | | | 67 | | Croatia | | | | | | | | | | | | | | | 4 | | | 1 | | | | | | 6 | | | 1 | | Norway | | | | | | | | | | | | 33 | | | 82 | | | 47 | | | 29 | | | 91 | | | 46 | | United Kingdom | | | 8 | | | 58 | | | 19 | | | 8 | | | 64 | | | 20 | | | 8 | | | 65 | | | 20 | | North Africa | | | 61 | | | 374 | | | 130 | | | 56 | | | 434 | | | 136 | | | 58 | | | 596 | | | 167 | | Algeria | | | 23 | | | 12 | | | 25 | | | 24 | | | 13 | | | 26 | | | 25 | | | 13 | | | 27 | | Libya | | | 37 | | | 358 | | | 103 | | | 31 | | | 417 | | | 108 | | | 32 | | | 579 | | | 138 | | Tunisia | | | 1 | | | 4 | | | 2 | | | 1 | | | 4 | | | 2 | | | 1 | | | 4 | | | 2 | | Egypt | | | 27 | | | 520 | | | 123 | | | 28 | | | 419 | | | 105 | | | 26 | | | 286 | | | 79 | | Sub-Saharan Africa | | | 90 | | | 152 | | | 118 | | | 89 | | | 126 | | | 112 | | | 90 | | | 119 | | | 111 | | Angola | | | 37 | | | | | | 37 | | | 41 | | | | | | 41 | | | 43 | | | | | | 43 | | Congo | | | 22 | | | 34 | | | 28 | | | 24 | | | 38 | | | 30 | | | 23 | | | 24 | | | 27 | | Ghana | | | 8 | | | 16 | | | 11 | | | 5 | | | 3 | | | 6 | | | 3 | | | | | | 3 | | Nigeria | | | 23 | | | 102 | | | 42 | | | 19 | | | 85 | | | 35 | | | 21 | | | 95 | | | 38 | | Kazakhstan | | | 36 | | | 87 | | | 52 | | | 34 | | | 83 | | | 49 | | | 30 | | | 84 | | | 46 | | Rest of Asia | | | 32 | | | 127 | | | 56 | | | 28 | | | 150 | | | 55 | | | 20 | | | 103 | | | 38 | | China | | | 1 | | | | | | 1 | | | 1 | | | | | | 1 | | | 1 | | | | | | 1 | | Indonesia | | | | | | 93 | | | 18 | | | 1 | | | 115 | | | 22 | | | 1 | | | 59 | | | 11 | | Iraq | | | 10 | | | | | | 10 | | | 10 | | | | | | 10 | | | 15 | | | | | | 15 | | Pakistan | | | | | | 33 | | | 6 | | | | | | 35 | | | 6 | | | | | | 44 | | | 8 | | Turkmenistan | | | 3 | | | | | | 3 | | | 2 | | | | | | 2 | | | 3 | | | | | | 3 | | United Arab Emirates | | | 18 | | | 1 | | | 18 | | | 14 | | | | | | 14 | | | | | | | | | | | Americas | | | 20 | | | 18 | | | 23 | | | 19 | | | 40 | | | 26 | | | 23 | | | 66 | | | 35 | | Ecuador | | | 2 | | | | | | 2 | | | 4 | | | | | | 4 | | | 4 | | | | | | 4 | | Mexico | | | 1 | | | 1 | | | 1 | | | | | | | | | | | | | | | | | | | | Trinidad & Tobago | | | | | | | | | | | | | | | 13 | | | 2 | | | | | | 20 | | | 4 | | United States | | | 17 | | | 17 | | | 20 | | | 15 | | | 27 | | | 20 | | | 19 | | | 46 | | | 27 | | Australia and Oceania | | | 1 | | | 49 | | | 10 | | | 1 | | | 40 | | | 8 | | | 1 | | | 37 | | | 8 | | Australia | | | 1 | | | 49 | | | 10 | | | 1 | | | 40 | | | 8 | | | 1 | | | 37 | | | 8 | | | | | 294 | | | 1,508 | | | 573 | | | 318 | | | 1,583 | | | 607 | | | 304 | | | 1,600 | | | 597 | | Eni share of equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Angola | | | 2 | | | 31 | | | 7 | | | 1 | | | 27 | | | 6 | | | 1 | | | 27 | | | 6 | | Indonesia | | | | | | | | | | | | | | | | | | | | | 1 | | | 3 | | | 1 | | Norway | | | 27 | | | 61 | | | 39 | | | | | | | | | | | | | | | | | | | | Tunisia | | | 1 | | | | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | Venezuela | | | 1 | | | 70 | | | 14 | | | 3 | | | 79 | | | 18 | | | 4 | | | 97 | | | 22 | | | | | 31 | | | 162 | | | 61 | | | 5 | | | 107 | | | 25 | | | 7 | | | 128 | | | 30 | | Total | | | 325 | | | 1,670 | | | 634 | | | 323 | | | 1,690 | | | 632 | | | 311 | | | 1,728 | | | 627 | |
(a)
It excludes production volumes of natural gashydrocarbons consumed in operations. Said volumes were 397 mmCF/d or 26.4 mmBOE.45.4, 43.5 and 35.2 mmBOE in 2019, 2018 and 2017, respectively. 2016 Production available for sale (a)(b)
Production for the year excludes approximately 4 mmBOE of volumes (mainly gas) as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume due to the take-or-pay clause. Management has estimated to be highly probable that the buyer will not redeem its contractual right to lift the pre-paid volumes within the contractual terms. Such volume is classified as sales of minerals-in-place within the reserves movements for the year. | | | Italy | | | Rest
of
Europe | | | North
Africa | | | Sub-
Saharan
Africa | | | Kazakhstan | | | Rest of
Asia | | | Americas | | | Australia
and
Oceania | | | | | Hydrocarbons production | | | | | | | | | | | | Eni consolidated subsidiaries | | | (KBOE/d) | | | 127 | | | 195 | | | 608 | | | 312 | | | 107 | | | 114 | | | 114 | | | 23 | | | 1,600 | | | | | (mmBOE) | | | 47 | | | 71 | | | 222 | | | 114 | | | 39 | | | 42 | | | 42 | | | 8 | | | 585 | | Eni share of equity-accounted entities | | | (KBOE/d) | | | | | | | | | 3 | | | 4 | | | | | | 4 | | | 60 | | | | | | 71 | | | | | (mmBOE) | | | | | | | | | 1 | | | 2 | | | | | | 2 | | | 22 | | | | | | 27 | | Liquids production | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni consolidated subsidiaries | | | (KBBL/d) | | | 47 | | | 109 | | | 241 | | | 247 | | | 65 | | | 78 | | | 69 | | | 3 | | | 859 | | | | | (mmBBL) | | | 17 | | | 40 | | | 88 | | | 91 | | | 24 | | | 28 | | | 25 | | | 1 | | | 314 | | Eni share of equity-accounted entities | | | (KBBL/d) | | | | | | | | | 3 | | | 1 | | | | | | 1 | | | 14 | | | | | | 19 | | | | | (mmBBL) | | | | | | | | | 1 | | | | | | | | | 1 | | | 5 | | | | | | 7 | | Natural gas production | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni consolidated subsidiaries | | | (mmCF/d) | | | 436 | | | 468 | | | 2,000 | | | 353 | | | 234 | | | 199 | | | 243 | | | 110 | | | 4,043 | | | | | (BCF) | | | 159 | | | 171 | | | 732 | | | 129 | | | 86 | | | 73 | | | 89 | | | 40 | | | 1,479 | | Eni share of equity-accounted entities | | | (mmCF/d) | | | | | | | | | 3 | | | 16 | | | | | | 15 | | | 252 | | | | | | 286 | | | | | (BCF) | | |
| | |
| | | 1
| | | 6
| | |
| | | 6
| | | 92
| | |
| | | 105
| | |
It excludes production volumes of natural gas consumed in operations. Said volumes were 478 mmCF/d or 32.1 mmBOE.
Volumes of oil and natural gas purchased under long-term supply contracts with foreign governments or similar entities in properties where Eni acts as producer totaled 5671 KBOE/d, 8454 KBOE/d and 7855 KBOE/d in 2016, 20152019, 2018 and 2014,2017, respectively. The tables below provide Eni subsidiaries and its equity-accounted entities’ average sales prices per unit of liquids and natural gas by geographical area for each of the last three fiscal years. AlsoIn addition, Eni subsidiaries and its equity-accounted entities’ average production cost per unit of production are provided. The average Average sales prices and production cost does not include any ad valorem or severance taxes.
AVERAGE SALES PRICES AND PRODUCTION COST PER UNIT OF PRODUCTIONper unit of production
($) | | | Italy | | | Rest of Europe | | | North Africa | | | of which Egypt | | | Sub- Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | Americas | | | Australia and Oceania | | | Total | | 20142017 | | | | | | | | | | | | Consolidated subsidiaries | | | | | | | | | | | | Oil and condensates, per BBL | | | 87.80 | | | 88.80 | | | 88.99 | | | | | | 93.45 | | | 91.86 | | | 77.99 | | | 79.13 | | | 91.61 | | | 88.90 | | Natural gas, per KCF | | | 8.74 | | | 8.49 | | | 8.08 | | | | | | 2.12 | | | 0.62 | | | 6.18 | | | 3.96 | | | 7.46 | | | 6.83 | | Average production cost, per BOE | | | 15.19 | | | 13.61 | | | 6.79 | | | | | | 18.88 | | | 8.94 | | | 10.70 | | | 11.75 | | | 20.14 | | | 12.00 | | Equity-accounted entities | | | | | | | | | | | | Oil and condensates, per BBL | | | | | | | | | 17.94 | | | | | | | | | | | | 65.90 | | | 81.48 | | | | | | 70.56 | | Natural gas, per KCF | | | | | | | | | 6.08 | | | | | | | | | | | | 15.64 | | | | | | | | | 14.13 | | Average production cost, per BOE | | | | | | | | | 12.50 | | | | | | | | | | | | 9.79 | | | 42.27 | | | | | | 26.18 | | 2015 | | | | | | | | | | | | | | | | | | | | | | | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Oil and condensates, per BBL | | | 43.4646.51 | | | 45.8847.81 | | | 46.6652.68 | | | 46.06 | | | 49.9153.66 | | | 48.2650.62 | | | 40.1048.94 | | | 43.3644.24 | | | 45.8449.36 | | | 46.4650.33 | | Natural gas, per KCF | | | 6.926.45 | | | 6.305.81 | | | 4.692.96 | | | 4.19 | | | 1.491.87 | | | 0.470.58 | | | 4.833.75 | | | 2.202.35 | | | 5.074.05 | | | 4.543.62 | | Total hydrocarbons, per BOE | | | 39.96 | | | 40.51 | | | 28.62 | | | 30.64 | | | 44.85 | | | 34.60 | | | 36.69 | | | 33.31 | | | 25.29 | | | 35.39 | | Average production cost, per BOE | | | 11.088.12 | | | 10.938.85 | | | 5.723.08 | | | 4.35 | | | 9.64 | | | 6.68 | | | 5.96 | | | 8.36 | | | 7.11 | | | 6.33 | | Equity-accounted entities | | | | | | 14.08 | | | 7.93 | | | 6.48 | | | 11.61 | | | 14.49 | | | 9.18 | | Equity-accounted entities | | | | | | | | | | | | Oil and condensates, per BBL | | | | | | | | | 18.0317.95 | | | | | | 38.34 | | | | | | 27.8944.43 | | | 38.1841.49 | | | | | | 35.1538.65 | | Natural gas, per KCF | | | | | | | | | 3.782.63 | | | | | | 7.34 | | | | | | 6.06 | | | 4.19 | | | | | | 4.64 | | Total hydrocarbons, per BOE | | | | | | | | | | | | 9.27 | | | 4.2417.35 | | | | | | 5.3039.65 | | | | | | 36.76 | | | 26.50 | | | | | | 28.30 | | Average production cost, per BOE | | | | | | | | | 8.985.94 | | | | | | 3.45 | | | | | | 11.64 | | | 1.99 | | | | | | 2.71 | | 2018 | | | | | | | | | | | | 8.67 | | | 16.48 | | | | | | 14.51 | | 2016 | | | | | | | | | | | | | | | | | | | | | | | | Consolidated subsidiaries | | | | | | | | | | | | Oil and condensates, per BBL | | | 33.19 | | | 39.97 | | | 39.43 | | | 33.05 | | | 41.92 | | | 39.61 | | | 36.89 | | | 34.86 | | | 37.96 | | | 39.33 | | Natural gas, per KCF | | | 4.93 | | | 4.49 | | | 3.29 | | | 3.82 | | | 1.41 | | | 0.34 | | | 3.50 | | | 1.94 | | | 3.60 | | | 3.20 | | Average production cost, per BOE | | | 9.69 | | | 9.31 | | | 4.89 | | | 6.34 | | | 12.09 | | | 7.58 | | | 6.14 | | | 8.70 | | | 7.08 | | | 7.79 | | Equity-accounted entities | | | | | | | | | | | | Oil and condensates, per BBL | | | 61.58 | | | 64.51 | | | 17.9365.95 | | | 62.97 | | | 68.76 | | | 66.78 | | | 34.9568.35 | | | 32.3957.22 | | | 68.72 | | | 30.8565.79 | | Natural gas, per KCF | | | 8.37 | | | 7.99 | | | 1.854.97 | | | 4.85 | | | 2.38 | | | 0.77 | | | 5.926.11 | | | 4.172.38 | | | 4.80 | | | 4.255.17 | | Average production cost, per BOE | | | 9.97 | | | 8.39 | | | 9.743.16 | | | 3.87 | | | 10.25 | | | 6.53 | | | 8.194.68 | | | 8.8110.56 | | | 7.09 | | | 8.346.50 | | Total hydrocarbons, per BOE | | | 53.01 | | | 56.07 | | | 43.34 | | | 36.22 | | | 58.59 | | | 46.98 | | | 50.98 | | | 46.63 | | | 28.99 | | | 48.04 | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Oil and condensates, per BBL | | | | | | | | | 17.92 | | | | | | 39.48 | | | | | | 49.86 | | | 54.86 | | | | | | 45.19 | | Natural gas, per KCF | | | | | | | | | 3.58 | | | | | | 9.50 | | | | | | 9.32 | | | 4.28 | | | | | | 5.59 | | Total hydrocarbons, per BOE | | | | | | | | | 18.14 | | | | | | 48.79 | | | | | | 50.64 | | | 28.59 | | | | | | 33.63 | | Average production cost, per BOE | | | | | | | | | 6.84 | | | | | | 6.53 | | | | | | 11.03 | | | 2.47 | | | | | | 3.76 | | 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Oil and condensates, per BBL | | | 55.55 | | | 58.92 | | | 57.91 | | | 54.78 | | | 63.45 | | | 59.06 | | | 62.81 | | | 54.00 | | | 52.93 | | | 59.62 | | Natural gas, per KCF | | | 5.03 | | | 4.95 | | | 6.21 | | | 5.11 | | | 2.94 | | | 0.81 | | | 5.94 | | | 2.46 | | | 4.41 | | | 4.94 | | Total hydrocarbons, per BOE | | | 40.24 | | | 39.84 | | | 44.86 | | | 33.67 | | | 53.08 | | | 42.21 | | | 50.31 | | | 48.37 | | | 26.32 | | | 43.73 | | Average production cost, per BOE | | | 10.38 | | | 10.71�� | | | 4.48 | | | 2.99 | | | 8.02 | | | 5.46 | | | 5.20 | | | 13.07 | | | 4.83 | | | 6.05 | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Oil and condensates, per BBL | | | | | | 58.88 | | | 18.06 | | | | | | 23.72 | | | | | | | | | 59.94 | | | | | | 55.93 | | Natural gas, per KCF | | | | | | 5.07 | | | 7.23 | | | | | | 6.16 | | | | | | | | | 4.32 | | | | | | 4.94 | | Total hydrocarbons, per BOE | | | | | | 49.76 | | | 19.39 | | | | | | 30.84 | | | | | | | | | 25.67 | | | | | | 41.71 | | Average production cost, per BOE | | | | | | 9.78 | | | 8.51 | | | | | | 3.68 | | | | | | | | | 2.04 | | | | | | 7.26 | |
Development activitieswell activity In 2016,2019, a total of 296241 development wells were drilled (118.7(85.4 of which represented Eni’s share) as compared to 335209 development wells drilled in 2015 (132.42018 (80.2 of which represented Eni’s share) and 440178 development wells drilled in 2014 (1912017 (90.7 of which represented Eni’s share). The drilling of 6884 development wells (28.6(21.0 of which represented Eni’s share) is currently underway.
The table below summarizes the number of the Company’s net interest in productive and dry development wells completed in each of the past three years and the status of the Company’s development wells in the process of being drilled as of December 31, 2016.2019. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Development Well Activity
| | Net wells completed | | Wells in progress at 31 Dec. | | | Net wells completed | | Wells in progress at 31 Dec. | | | | 2014 | | 2015 | | 2016 | | 2016 | | | 2019 | | 2018 | | 2017 | | 2019 | | (units) | | Productive | | Dry | | Productive | | Dry | | Productive | | Dry | | Gross | | Net | | | Productive | | Dry | | Productive | | Dry | | Productive | | Dry | | Gross | | Net | | Italy | | 12.5 | | | | 6.0 | | | | 4.0 | | | | 1.0 | | 1.0 | | | 3.0 | | | | 3.0 | | | | 2.6 | | | | 2.0 | | 1.6 | | Rest of Europe | | 9.8 | | 1.0 | | 10.2 | | 0.1 | | 5.6 | | | | 4.0 | | 0.6 | | | 3.3 | | | | 2.8 | | 0.3 | | 2.7 | | 0.2 | | 25.0 | | 2.2 | | North Africa | | 54.5 | | 1.0 | | 30.5 | | 2.8 | | 38.6 | | 1.2 | | 18.0 | | 10.0 | | | 5.0 | | 1.1 | | 9.6 | | 0.5 | | 5.1 | | | | 2.0 | | 1.1 | | Egypt | | | 33.5 | | | | 30.7 | | | | 49.7 | | 2.3 | | 9.0 | | 3.5 | | Sub-Saharan Africa | | 31.6 | | | | 22.0 | | 2.5 | | 21.2 | | 0.2 | | 36.0 | | 14.0 | | | 7.0 | | | | 7.3 | | 0.1 | | 8.6 | | | | 19.0 | | 3.4 | | Kazakhstan | | 1.5 | | | | 4.7 | | | | 4.6 | | 3.0 | | 0.8 | | | | 0.9 | | | | 0.9 | | | | 1.2 | | | | 1.0 | | 0.3 | | Rest of Asia | | 54.2 | | 1.6 | | 29.7 | | 5.9 | | 31.6 | | 0.5 | | 2.0 | | 0.3 | | | 27.3 | | 2.2 | | 21.9 | | | | 15.0 | | 0.2 | | 25.0 | | 7.9 | | Americas | | 22.1 | | 0.7 | | 17.4 | | 0.1 | | 9.9 | | 1.3 | | 4.0 | | 1.9 | | | 2.1 | | | | 2.3 | | | | 3.1 | | | | 1.0 | | 1.0 | | Australia and Oceania | | 0.1 | | 0.4 | | 0.5 | | | | | | | | | | 0.8 | | | | | | | | | | | | Total including equity-accounted entities | | 186.3 | | 4.7 | | 121.0 | | 11.4 | | 115.5 | | 3.2 | | 68.0 | | 28.6 | | | 82.1 | | 3.3 | | 79.3 | | 0.9 | | 88.0 | | 2.7 | | 84.0 | | 21.0 | | | |
Exploration activitieswell activity In 2016,2019, a total of 1631 new exploratory wells were drilled (10.2(16.3 of which represented Eni’s share), as compared to 2924 exploratory wells drilled in 2015 (19.12018 (15.6 of which represented Eni’s share) and 4425 exploratory wells drilled in 2014 (25.82017 (15.9 of which represented Eni’s share).
The overall commercial success rate was 50% (50%36% (47% net to Eni) as compared to 16.7% (25.1%62% (66% net to Eni) and 31.3% (38%60% (52% net to Eni) in 20152018 and 2014,2017, respectively. The following table summarizes the Company’s net interests in productive and dry exploratory wells completed in each of the last three fiscal years and the number of exploratory wells in the process of being drilled and evaluated as of December 31, 2016.2019. A dry well is one found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. For further information on the ageing of suspended wells see note 11 on Consolidated Financial Statements. Exploratory Well Activity
| | Net wells completed | | Wells in progress at Dec. 31(1) | | | Net wells completed | | Wells in progress at Dec. 31(1) | | | | 2014 | | 2015 | | 2016 | | 2016 | | | 2019 | | 2018 | | 2017 | | 2019 | | (units) | | Productive | | Dry | | Productive | | Dry | | Productive | | Dry | | Gross | | Net | | | Productive | | Dry | | Productive | | Dry | | Productive | | Dry | | Gross | | Net | | Italy | | | | 0.6 | | | | | | | | 1.0 | | 4.0 | | 2.3 | | | | | 0.5 | | 1.8 | | | | | | | | | | | | Rest of Europe | | | | 4.3 | | | | 2.2 | | 0.1 | | 0.4 | | 9.0 | | 2.3 | | | 0.3 | | 1.4 | | | | 0.5 | | 1.2 | | 1.3 | | 14.0 | | 3.5 | | North Africa | | 3.5 | | 4.3 | | 3.3 | | 5.8 | | 6.0 | | 1.8 | | 16.0 | | 12.3 | | | 0.5 | | | | | | 0.5 | | 0.5 | | | | 12.0 | | 9.5 | | Egypt | | | 4.5 | | 1.5 | | 1.7 | | 1.5 | | 2.5 | | 5.4 | | 13.0 | | 9.7 | | Sub-Saharan Africa | | 7.3 | | 7.3 | | 0.6 | | 2.9 | | 0.1 | | 1.1 | | 32.0 | | 17.0 | | | 0.5 | | 0.9 | | 0.4 | | | | 2.9 | | 0.3 | | 38.0 | | 18.4 | | Kazakhstan | | | | | | | | | | | | | | 6.0 | | 1.1 | | | | | | | | | | | | | | | 6.0 | | 1.1 | | Rest of Asia | | 1.3 | | 4.3 | | | | 3.4 | | | | 0.9 | | 8.0 | | 3.2 | | | | | 1.7 | | 2.2 | | 2.6 | | | | | | 11.0 | | 3.8 | | Americas | | 2.0 | | 1.4 | | 1.0 | | 0.3 | | | | 1.0 | | 3.0 | | 1.5 | | | | | | | 4.0 | | | | 0.5 | | | | 3.0 | | 1.4 | | Australia and Oceania | | | | 0.9 | | | | | | | | | | 1.0 | | 0.3 | | | | | 0.5 | | | | | | | | | | 1.0 | | 0.3 | | Total including equity-accounted entities | | 14.1 | | 23.1 | | 4.9 | | 14.6 | | 6.2 | | 6.2 | | 79.0 | | 40.0 | | | 5.8 | | 6.5 | | 10.1 | | 5.1 | | 7.6 | | 7.0 | | 98.0 | | 47.7 | | | |
(1)
Includes temporary suspended wells pending further evaluation. Oil and gas properties, operations and acreage In 2016,2019, Eni performed its operations in 44 countries41 Countries located in five continents. As of December 31, 2016,2019, Eni’s mineral right portfolio consisted of 780873 exclusive or shared rights of exploration and development activities for a total acreage of 323,896357,854 square kilometers net to Eni (406,505 square kilometers net to Eni as of which developedDecember 31, 2018). Developed acreage of 32,489was 29,283 square kilometers and undeveloped acreage of 291,407was 328,571 square kilometers net to Eni. In 2016, changes in total net acreage mainly derived from: (i)2019 new leases were purchased or been awarded in Bahrain, the United Arab Emirates, Mozambique, Algeria, Argentina, Egypt, Cyprus, Norway, Tunisia, Kazakhstan, Ivory Coast and Mexico for a total increase in acreage of approximately 33,500 square kilometers. Interest increase were reported mainly in Egypt, Ghana, Morocco, Montenegro, NorwayMyanmar, Indonesia and the United KingdomStates for a total acreage of approximately 10,500970 square kilometers; (ii) the total relinquishment of licenses mainly in Australia, Gabon, India, Liberia, Norway and the United States covering an acreage of approximately 13,000 square kilometers; and (iii) partial relinquishment in Australia, Portugal and South Africa or interest reduction mainly in Myanmar, for approximately 17,000 square kilometers.
kilometers. Relinquishment for the year of licenses related mainly to India, China, Vietnam, Portugal, Ecuador and the United Kingdom covering an acreage of approximately 27,600 square kilometers. Partial relinquishment were reported mainly in Indonesia, South Africa and Pakistan or interest reduction mainly in Oman, Morocco, Cyprus, Indonesia and Mozambique for approximately 55,500 square kilometers. The table below provides certain information about the Company’s oil&gas properties. It provides the total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its equity-accounted entities had interest as of December 31, 2016.2019. A gross acreage is one in which Eni owns a working interest. | | | December 31,
20152018 | | | December 31, 20162019 | | | | | Total net acreage (a) | | | Number of interests | | | Gross developed acreage (a) (b) | | | Gross undeveloped acreage (a) | | | Total gross acreage (a) | | | Net developed acreage (a) (b) | | | Net undeveloped acreage (a) | | | Total net acreage (a) | | EUROPE | | | 45,12346,332 | | | 295309 | | | 15,69315,282 | | | 51,75858,616 | | | 67,45173,898 | | | 10,8279,278 | | | 34,55328,750 | | | 45,38038,028 | | Italy | | | 16,97514,987 | | | 146128 | | | 10,4989,545 | | | 10,3207,595 | | | 20,81817,140 | | | 8,7757,887 | | | 7,9925,845 | | | 16,76713,732 | | Rest of Europe | | | 28,14831,345 | | | 149181 | | | 5,1955,737 | | | 41,43851,021 | | | 46,63356,758 | | | 2,0521,391 | | | 26,56122,905 | | | 28,61324,296 | | Cyprus | | | 10,01817,111 | | | 37 | | | | | | 12,52326,614 | | | 12,52326,614 | | | | | | 10,01814,557 | | | 10,018 | | Croatia | | | 987 | | | 2 | | | 1,975 | | | | | | 1,975 | | | 987 | | | | | | 98714,557 | | Greenland | | | 1,909 | | | 2 | | | | | | 4,890 | | | 4,890 | | | | | | 1,909 | | | 1,909 | | Montenegro | | | 614 | | | 41 | | | | | | 1,228 | | | 1,228 | | | | | | 614 | | | 614 | | Norway | | | 3,1142,628 | | | 57131 | | | 2,3114,828 | | | 6,04514,577 | | | 8,35619,405 | | | 452777 | | | 2,1563,436 | | | 2,6084,213 | | Portugal | | | 6,370 | | | 33,182 | | | | | | 4,547 | | | 4,547 | | | | | | 3,182 | | | 3,182 | | | | | | | | United Kingdom | | | 1,9054,018 | | | 6738 | | | 909 | | | 5,9321,011 | | | 6,8411,920 | | | 613614 | | | 5,715506 | | | 6,3281,120 | | Other Countries | | | 3,8451,883 | | | 112 | | | | | | 6,2732,701 | | | 6,2732,701 | | | | | | 2,9671,883 | | | 2,9671,883 | | AFRICA | | | 157,441165,699 | | | 264260 | | | 46,38454,351 | | | 264,600273,494 | | | 310,984327,845 | | | 11,72915,194 | | | 140,947148,431 | | | 152,676163,625 | | North Africa | | | 25,69933,932 | | | 12169 | | | 14,29217,628 | | | 54,12251,716 | | | 68,41469,344 | | | 5,7387,966 | | | 23,65423,907 | | | 29,39231,873 | | Algeria | | | 1,1791,155 | | | 4247 | | | 3,22212,157 | | | 187279 | | | 3,40912,436 | | | 1,1485,472 | | | 31100 | | | 1,179 | | Egypt | | | 9,668 | | | 57 | | | 5,508 | | | 22,523 | | | 28,031 | | | 2,074 | | | 8,591 | | | 10,6655,572 | | Libya | | | 13,294 | | | 11 | | | 1,9621,963 | | | 24,673 | | | 26,63526,636 | | | 958 | | | 12,336 | | | 13,294 | | Morocco | | | 17,925 | | | 1 | | | | | | 6,73923,900 | | | 6,73923,900 | | | | | | 2,69610,755 | | | 2,69610,755 | | Tunisia | | | 1,558 | | | 10 | | | 3,6003,508 | | | 2,864 | | | 3,6006,372 | | | 1,5581,536 | | | 716 | | | 1,5582,252 | | Egypt | | | 5,248 | | | 56 | | | 5,659 | | | 15,710 | | | 21,369 | | | 2,113 | | | 5,500 | | | 7,613 | | Sub-Saharan Africa | | | 131,742126,519 | | | 143135 | | | 32,09231,064 | | | 210,478206,068 | | | 242,570237,132 | | | 5,9915,115 | | | 117,293119,024 | | | 123,284124,139 | | Angola | | | 4,4045,303 | | | 5745 | | | 8,1608,349 | | | 12,8927,841 | | | 21,05216,190 | | | 1,0241,073 | | | 3,3432,671 | | | 4,3673,744 | | Congo | | | 1,3541,471 | | | 25 | | | 1,7941,430 | | | 6571,320 | | | 2,4512,750 | | | 971843 | | | 197628 | | | 1,1681,471 | | Gabon | | | 7,6154,107 | | | 4 | | | | | | 6,2174,107 | | | 6,2174,107 | | | | | | 6,2174,107 | | | 6,2174,107 | | Ghana | | | 579 | | | 3 | | | 226 | | | 1,127 | | | 1,353 | | | 100 | | | 3 | | | | | | 1,353 | | | 1,353 | | | | | | 579479 | | | 579 | | Ivory Coast | | | 4292,905 | | | 5 | | | | | | 4,921 | | | 4,921 | | | | | | 3,724 | | | 3,724 | | Kenya | | | 43,948 | | | 6 | | | | | | 50,677 | | | 50,677 | | | | | | 43,948 | | | 43,948 | | Mozambique | | | 978 | | | 10 | | | | | | 25,304 | | | 25,304 | | | | | | 4,349 | | | 4,349 | | Nigeria | | | 7,722 | | | 32 | | | 21,059 | | | 8,631 | | | 29,690 | | | 3,099 | | | 3,543 | | | 6,642 | | South Africa | | | 26,202 | | | 1 | | | | | | 95455,677 | | | 95455,677 | | | | | | 28622,271 | | | 286 | | Kenya | | | 40,426 | | | 7 | | | | | | 61,363 | | | 61,363 | | | | | | 41,173 | | | 41,173 | | Liberia | | | 1,841 | | | 1 | | | | | | 2,341 | | | 2,341 | | | | | | 585 | | | 585 | | Mozambique | | | 1,956 | | | 6 | | | | | | 3,911 | | | 3,911 | | | | | | 1,956 | | | 1,956 | | Nigeria | | | 7,432 | | | 34 | | | 22,138 | | | 8,631 | | | 30,769 | | | 3,996 | | | 3,374 | | | 7,370 | | South Africa | | | 32,881 | | | 1 | | | | | | 65,696 | | | 65,696 | | | | | | 26,279 | | | 26,27922,271 | | Other Countries | | | 33,304 | | | 4 | | | | | | 46,463 | | | 46,463 | | | | | | 33,304 | | | 33,304 | | ASIA | | | 117,183181,414 | | | 5969 | | | 18,16512,686 | | | 198,024267,851 | | | 216,189280,537 | | | 6,0163,199 | | | 103,745139,497 | | | 109,761142,696 | | Kazakhstan | | | 8691,543 | | | 68 | | | 2,391 | | | 2,5425,124 | | | 4,9337,515 | | | 442 | | | 4271,718 | | | 8692,160 | | Rest of Asia | | | 116,314179,871 | | | 5361 | | | 15,77410,295 | | | 195,482262,727 | | | 211,256273,022 | | | 5,5742,757 | | | 103,318137,779 | | | 108,892140,536 | | ChinaBahrain | | | 7,069 | | | 8 | | | 77 | | | 7,056 | | | 7,133 | | | 13 | | | 7,056 | | | 7,069 | | India | | | 6,167 | | | 1 | | | | | | 13,1102,858 | | | 13,1102,858 | | | | | | 2,858 | | | 2,858 | | China | | | 5,228 | | | 6 | | | 77 | | | | | | 77 | | | 13 | | | | | | 13 | | India | | | 5,244 | | | 5,244 | | | | | | | | | | | | | | | | | | | | Indonesia | | | 25,12423,769 | | | 1413 | | | 4,2462,605 | | | 30,24320,898 | | | 34,48923,503 | | | 1,6031,029 | | | 23,57814,926 | | | 25,18115,955 | | Iraq | | | 446 | | | 1 | | | 1,074 | | | | | | 1,074 | | | 446 | | | | | | 446 | | Lebanon | | | 1,461 | | | 2 | | | | | | 3,653 | | | 3,653 | | | | | | 1,461 | | | 1,461 | | Myanmar | | | 20,05013,558 | | | 4 | | | | | | 24,080 | | | 24,080 | | | | | | 13,55814,147 | | | 13,55814,147 | | PakistanOman | | | 8,81077,146 | | | 14 | | | 10,177 | | | 11,486 | | | 21,663 | | | 3,332 | | | 5,414 | | | 8,746 | | Russia | | | 20,862 | | | 31 | | | | | | 62,59290,760 | | | 62,59290,760 | | | | | | 20,86249,918 | | | 20,86249,918 | | Pakistan | | | 5,786 | | | 12 | | | 3,390 | | | 8,370 | | | 11,760 | | | 872 | | | 2,907 | | | 3,779 | | Russia | | | 17,975 | | | 2 | | | | | | 53,930 | | | 53,930 | | | | | | 17,975 | | | 17,975 | | Timor Leste | | | 1,230 | | | 14 | | | | | | 1,5382,612 | | | 1,5382,612 | | | | | | 1,2301,620 | | | 1,2301,620 | | Turkmenistan | | | 180 | | | 1 | | | 200 | | | | | | 200 | | | 180 | | | | | | 180 | | United Arab Emirates | | | 1,472 | | | 9 | | | 2,949 | | | 17,058 | | | 20,007 | | | 217 | | | 10,170 | | | 10,387 | | Vietnam | | | 23,132 | | | 54 | | | | | | 30,77723,908 | | | 30,77723,908 | | | | | | 23,13218,553 | | | 23,13218,553 | | Other Countries | | | 3,244 | | | 1 | | | | | | 14,600 | | | 14,600 | | | | | | 3,244 | | | 3,244 | | AMERICAS | | | 6,6289,303 | | | 148229 | | | 4,9482,299 | | | 8,15417,763 | | | 13,10220,062 | | | 3,2081,024 | | | 2,4889,679 | | | 5,69610,703 | | Ecuador | | | 1,985 | | | 1 | | | 1,985 | | | | | | 1,985 | | | 1,985 | | | | | | 1,985 | | Mexico | | | 67 | | | 3 | | | | | | 67 | | | 67 | | | | | | 67Mexico | | | 67 | | Trinidad & Tobago3,000 | | | 6610 | | | 114 | | | 3825,455 | | | 5,469 | | | 38214 | | | 663,092 | | | | | | 663,106 | | United States | | | 2,1182,191 | | | 129205 | | | 1,3201,024 | | | 9971,683 | | | 2,3172,707 | | | 660513 | | | 5261,422 | | | 1,1861,935 | | Venezuela | | | 1,066 | | | 6 | | | 1,261 | | | 1,543 | | | 2,804 | | | 497 | | | 569 | | | 1,066 | | Other Countries | | | 1,3261,061 | | | 8 | | | | | | 5,5479,082 | | | 5,5479,082 | | | | | | 1,3264,596 | | | 1,3264,596 | | AUSTRALIA AND OCEANIA | | | 16,3333,757 | | | 146 | | | 1,140728 | | | 15,7282,860 | | | 16,8683,588 | | | 709588 | | | 9,6742,214 | | | 10,3832,802 | | Australia | | | 16,3333,757 | | | 146 | | | 1,140728 | | | 15,7282,860 | | | 16,8683,588 | | | 709588 | | | 9,6742,214 | | | 10,3832,802 | | Total | | | 342,708406,505 | | | 780873 | | | 86,33085,346 | | | 538,264620,584 | | | 624,594705,930 | | | 32,48929,283 | | | 291,407328,571 | | | 323,896357,854 | | |
(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.
The table below sets forth, as of December 31, 2019 and by main producing countries in each geographic area, Eni’s producing assets, the year in which Eni’s activities started, the Eni’s participating interest in each assets and whether Eni is operator of the asset. | | | | ITALY | | | (1926) | | | Operated | | | Adriatic and Ionian Sea: Barbara (100%), Cervia/Arianna (100%), Annamaria (100%), Clara NW (51%), Luna (100%), Angela (100%), Hera Lacinia (100%) and Bonaccia (100%) | | | | | | | | | | | | Basilicata Region: Val d’Agri (61%) | | | | | | | | | | | | Sicily: Gela (100%), Tresauro (45%), Giaurone (100%), Fiumetto (100%), Prezioso (100%) and Bronte (100%) | | | REST OF EUROPE | | | | | | | | | | | | Norway (a) | | | (1965) | | | Operated | | | Goliat (45.24%), Marulk (13.92%), Balder & Ringhorne (62.64%) and Ringhorne East (48.71%) | | | | | | | | | Non-operated | | | Åsgard (15.35%), Kristin (13.31%), Heidrun (3.60%), Mikkel (33.67%), Tyrihans (12.54%), Morvin (20.88%), Great Ekofisk Area (8.62%), Boyla (13.92%), Brage (8.53%) and Snorre (12.91%) | | | United Kingdom | | | (1964) | | | Operated | | | Liverpool Bay (100%) and Hewett Area (89.3%) | | | | | | | | | Non-operated | | | Elgin/Franklin (21.87%), Glenelg (8%), J Block (33%), Jasmine (33%) and Jade (7%) | | | NORTH AFRICA | | | | | | | | | | | | Algeria (b) | | | (1981) | | | Operated | | | Sif Fatima II (49%), Zemlet El Arbi (49%), Ourhoud II (49%), Blocks 403a/d (from 65% to 100%), Block ROM North (35%), Blocks 401a/402a (55%), Block 403 (50%) and Block 405b (75%) | | | | | | | | | Non-operated | | | Block 404 (12.25%) and Block 208 (12.25%) | | | Libya (b) | | | (1959) | | | Non-operated | | | Onshore contract areas: Area A (former concession 82 – 50%), Area B (former concession 100/Bu-Attifel and Block NC 125 – 50%), Area E (El Feel – 33.3%) and Area D (Block NC 169 – 50%) | | | | | | | | | | | | Offshore contract areas: Area C (Bouri – 50%) and Area D (Block NC 41 – 50%) | | | Tunisia | | | (1961) | | | Operated | | | Maamoura (49%), Baraka (49%), Adam (25%), Oued Zar (50%), Djebel Grouz (50%), MLD (50%) and El Borma (50%) | | | EGYPT (b)(c) | | | (1954) | | | Operated | | | Shorouk (Zohr – 50%), Nile Delta (Abu Madi West/Nidoco – 75%), Sinai (Belayim Land, Belayim Marine and Abu Rudeis – 100%), Meleiha (76%), North Port Said (Port Fouad – 100%), Temsah (Tuna, Temsah and Denise – 50%), South West Meleiha (100%), Baltim (50%), Ras Qattara (El Faras and Zarif – 75%), West Abu Gharadig (Raml – 45%), Ashrafi (50%) and West Razzak (100%) | | | | | | | | | Non-operated | | | Ras el Barr (Ha’py and Seth – 50%) and South Ghara (25%) | | | SUB-SAHARAN AFRICA | | | | | | | | | | | | Angola | | | (1980) | | | Operated | | | Block 15/06 (36.84%) | | | | | | | | | Non-operated | | | Block 0 (9.8%), Development Areas in the Block 3 and 3/05-A (12%), Development Areas in the Block 14 (Eni 20%), Development Area Lianzi in the Blocco 14 K/A IMI (10%) and the Development Areas in the Block 15 (18%) | | | Congo | | | (1968) | | | Operated | | | Nené Marine (65%), Litchendjili (65%), Zatchi (55,25%), Loango (42,5%), Ikalou (100%), Djambala (50%), Foukanda (58%), Mwafi (58%), Kitina (52%), Awa Paloukou (90%), M’Boundi (82%), Kouakouala (74.25%), Zingali (100%) and Loufika (100%) | | | | | | | | | Non-operated | | | Pointe-Noire Grand Fond (35%) and Likouala (35%) | | | Ghana | | | (2009) | | | Operated | | | Offshore Cape Three Points (44.44%) | | | Nigeria | | | (1962) | | | Operated | | | OMLs 60, 61, 62 and 63 (20%) and OML 125 (100%) | | | | | | | | | Non-operated (d) | | | OML 118 (12.5%) | | | KAZAKHSTAN (b) | | | (1992) | | | Operated (e) | | | Karachaganak (29.25%) | | | | | | | | | Non-operated | | | Kashagan (16.81%) | | | REST OF ASIA | | | | | | | | | | | | Indonesia | | | (2001) | | | Operated | | | Jangkrik (55%) | | | Iraq | | | (2009) | | | Operated (f) | | | Zubair (41.6%) | | | Pakistan | | | (2000) | | | Operated | | | Bhit/Bhadra (40%) and Kadanwari (18.42%) | | | | | | | | | Non-operated | | | Latif (33.3%), Zamzama (17.75%) and Sawan (23.7%) | | | Turkmenistan | | | (2008) | | | Operated | | | Burun (90%) | | | United Arab Emirates | | | (2018) | | | Non-operated | | | Lower Zakum (5%) and Umm Shaif and Nasr (10%) | | | AMERICAS | | | | | | | | | | | | Mexico | | | (2019) | | | Operated | | | Gulf of Mexico: Area 1 (100%) | | | United States | | | (1968) | | | Operated | | | Gulf of Mexico: Allegheny (100%), Appaloosa (100%), Pegasus (85%), Longhorn (75%), Devils Towers (75%) and Triton (75%) | | | | | | | | | | | | Alaska: Nikaitchuq (100%) and Oooguruk (100%) | | | | | | | | | Non-operated | | | Gulf of Mexico: Europa (32%), Medusa (25%), Lucius (8.5%), K2 (13.4%), Frontrunner (37.5%) and Heidelberg (12.5%) | | | | | | | | | | | | Texas: Alliance area (27.5%) | | | Venezuela | | | (1998) | | | Non-operated | | | Perla (50%), Corocoro (26%) and Junín 5 (40%) | |
(a)
Assets held by the Vår Energi equity-accounted entities (Eni’s interest 69.6%).
(b)
In certain extractive initiatives, Eni and the host Country agree to assign the operatorship of a given initiative to an incorporated joint venture, a so called operating company. The operating company in its capacity as the operator is responsible of managing extractive operations. Those operating companies are not controlled by Eni. (c)
Eni’s working interests (and not participating interests) are reported. This include Eni’s share of costs incurred on behalf of the first party accordingly to the terms of PSAs inforce in the Country. (d)
As partners of SPDC JV, Eni holds a 5% interest in 17 onshore blocks and in 1 conventional offshore block and with a 12.86% in 2 conventional offshore blocks. (e)
Eni and Shell are co-operators. (f)
Eni is leading a consortium of partners including international companies and the national oil company Missan Oil. The table below provides the number of gross and net productive oil and natural gas wells in which the Group companies and its equity-accounted entities had an interest as of December 31, 2016.2019. A gross well is a well in which Eni owns a working interest. The number of gross wells is the total number of wells in which Eni owns a whole or fractional working interest. The number of net wells is the sum of the whole or fractional working interests in a gross well. One or more completions in the same borehole are counted as one well. Productive wells are producing wells and wells capable of production. The total number of oil and natural gas productive wells is 9,399 (3,737.68,292 (2,848.8 of which represent Eni’s share). Productive oil and gas wells at Dec. 31, 2016 2019(a) (units) | | Oil Wells | | Natural gas Wells | | | Oil Wells | | Natural gas Wells | | | | Gross | | Net | | Gross | | Net | | | Gross | | Net | | Gross | | Net | | Italy | | | | 243.0 | | | | | 197.1 | | | | | 616.0 | | | | | 532.4 | | | | | | 204.0 | | | | | 158.2 | | | | | 441.0 | | | | | 383.0 | | | Rest of Europe | | | | 395.0 | | | | | 72.5 | | | | | 160.0 | | | | | 88.1 | | | | | | 657.0 | | | | | 106.2 | | | | | 207.0 | | | | | 67.0 | | | North Africa | | | | 1,813.0 | | | | | 963.8 | | | | | 225.0 | | | | | 98.1 | | | | | | 589.0 | | | | | 245.7 | | | | | 125.0 | | | | | 67.5 | | | Egypt | | | | | 1,196.0 | | | | | 513.2 | | | | | 141.0 | | | | | 43.6 | | | Sub-Saharan Africa | | | | 3,020.0 | | | | | 590.3 | | | | | 350.0 | | | | | 28.8 | | | | | | 2,620.0 | | | | | 538.0 | | | | | 201.0 | | | | | 27.0 | | | Kazakhstan | | | | 204.0 | | | | | 54.8 | | | | | | | | | | | | | | | | 204.0 | | | | | 55.8 | | | | | 1.0 | | | | | 0.3 | | | Rest of Asia | | | | 727.0 | | | | | 479.1 | | | | | 1,036.0 | | | | | 393.2 | | | | | | 990.0 | | | | | 367.7 | | | | | 180.0 | | | | | 63.6 | | | Americas | | | | 264.0 | | | | | 133.3 | | | | | 321.0 | | | | | 98.5 | | | | | | 250.0 | | | | | 128.4 | | | | | 284.0 | | | | | 81.6 | | | Australia and Oceania | | | | 7.0 | | | | | 3.8 | | | | | 18.0 | | | | | 3.8 | | | | | | | | | | | | | | | | 2.0 | | | | | 2.0 | | | Total including equity-accounted entities | | | | 6,673.0 | | | | | 2,494.7 | | | | | 2,726.0 | | | | | 1,242.9 | | | | | | 6,710.0 | | | | | 2,113.2 | | | | | 1,582.0 | | | | | 735.6 | | | | |
(a)
Multiple completion wells included above: approximateley 2,128 (741.9approximately 1,403 (382.8 net to Eni). Eni’s exploration and production activities are subject to a broad range of laws and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and condition of the leases, licenses and contracts under which these oil&gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These contractual arrangements usually take the form of concession agreements or production sharing agreements: - Concession contracts are currently applied mainly in OECD countries and regulate relationships between States and oil companies with regards to hydrocarbon exploration and production activity. The company holding the mining concession has an exclusive right on exploration, development and production activities, sustaining all the operational risks and costs related to the exploration and development activities, and it is entitled to the productions obtained. As compensation for mineral concessions, it pays royalties on production (which may be in cash or in-kind) and taxes on oil revenues to the state in accordance with local tax legislation. Both exploration and production licenses are granted generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases): the term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. Proved reserves to which Eni is entitled are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. In Particular, Eni’s exploration and production activities are regulated by concession contracts or a similar scheme mainly in Italy, Ghana, Tunisia, the United Arab Emirates, the United Kingdom, the United States, certain assets in Nigeria, Angola and Australia as well as onshore permits in Pakistan. In Norway, Eni’s activities 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.
- Eni operates under Production Sharing Agreement (PSA) in several of the foreign jurisdictions mainly in African, Middle Eastern, Far Eastern countries. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract, the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment (technologies) and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country. Pursuant to these contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognize at the same time an increase in the taxable profit, through the increase of the revenues, and a tax expense. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (Cost Oil) and recognize the Profit Oil set contractually (Profit Oil). A similar scheme applies to some Service contracts. Eni’s exploration and production activities are regulated by PSA or scheme similar in Algeria, Angola, China, Congo, Egypt, Indonesia, Libya, Mexico, certain assets in Nigeria, Kazakhstan and offshore assets in Pakistan. In addition, Eni’s activities are regulated by service contract in one block in Nigeria and in Ecuador. In Australia, the cooperation zone between Timor Leste and Australia (Joint Petroleum Development Area – JPDA) are regulated by PSAs. Development and production activities in Iraq are regulated by a technical service contract. This contractual scheme establishes an oil entitlement mechanism and an associated risk profile similar to those applicable to PSA. Eni’s principal oil and gas properties are described below. For further information on main activities of the year see also “Significant business portfolio”. In the discussion that follows, references to hydrocarbon production are intended to represent hydrocarbon production available for sale. Italy Eni has been operating in Italy since 1926. In 2016, Eni’s oil and gas production amounted to 127 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. Eni’s exploration and development activities in Italy are regulated by concession contracts (50 operatedEni operates 31 onshore and 64 operated offshore) and exploration licenses (1263 offshore productive concessions as well as 13 onshore and 9 offshore).offshore exploration licenses. In 2019, Italy accounted for approximately 7% of Eni’s total worldwide production of oil and natural gas.
Eni’s domestic production in 2019 was accounted for 39% in the Adriatic and Ionian Seas, 47% in the Central Southern Apennines and 10% in Sicily.Development activities in 2019 mainly concerned: (i) maintenance and production optimization, at offshore fields in the Adriatic Sea; (ii) the progress in development activities at the Argo and Cassiopea operated projects (Eni’s interest 60%); and (iii) the completion of a digital transformation program at the Viggiano Oil Center in the Val d’Agri concession with improvement in environmental standards and plant safety as well in operational performance. In Italy, a new law has been enacted effective February 12, 2019, which requires Italian administrative bodies to adopt a plan indented to identify areas that are suitable for carrying out oil and gas activities. See “Risk Factors – Oil and gas activity may be subject to increasingly high levels of regulations throughout the world, which may impact our extraction activities and the recoverability of reserves”. Based on the review of all facts and circumstances and on the current knowledge of the matter, management does not expects any material impacts on the Group future results of operations and cash flow. Currently, thirty-three concessions for hydrocarbon development and production have expired, including Val d’Agri which is the largest Italian concession of the Company. Applications have been timely filed with Italian administrative authorities to obtain concessions’ renewals. The adoption of the above-mentioned plan is not expected to interfere with the administrative process of granting the renewals at the expired concessions.
The Adriatic and Ionian Seas represent Eni’s main production area, accountingPending the administrative resolution, the current law provides for 52% of Eni’s domestic production in 2016. Main operated fields are Barbara, Cervia/Arianna, Annamaria, Luna, Angela-Angelina, Hera Lacinia, Bonaccia and Porto Garibaldi. Development activities concerned: (i) maintenance and production optimization, mainly at the Barbara, Cervia/Arianna and Morena fields; and (ii) start-upprorogation of the Clara NWconcessions in accordance to the development project.Eni isplans agreed with 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.initial award.
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, with a four-month and half production shutdown, 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.
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.
Rest of Europe Eni’s operations in the Rest of Europe are mainly conducted mainly in Croatia,the United Kingdom and in Norway, through Eni’s equity accounted 69.6% interest in Vår Energi. In December 2018, it was finalized the business combination between Point Resources AS and Eni Norge AS, fully-owned by HitecVision and Eni respectively, with the UK. creation of Vår Energi AS, an equity-accounted joint venture. The governance of the new entity is designed to establish joint control of the two shareholders over the combined entity. Therefore, effective at the closing, Eni derecognized the assets and liabilities of Eni Norge and recognized the fair value of the interest retained in the merged company that will be equity-accounted going forward. In 2016,2019, the Rest of Europe accounted for 12%9% of Eni’s total worldwide production of oil and natural gas. CroatiaUnited Kingdom. Eni has been presentDevelopment activities mainly concerned the drilling of four wells, which were already started up in Croatia since 1996.production, at the Elgin Franklin field (Eni’s interest 21.87%) and Joanne and Jasmine fields (Eni’s interest 33%).
North Africa Eni’s operations in North Africa are mainly conducted in Algeria, Libya and Tunisia. In 2016,2019, North Africa accounted for 21% of Eni’s total worldwide production of oil and natural gas averaged approximately 24 mmCF/d. Activities are deployedgas. Algeria. In February 2019, Eni completed the acquisition of the 49% interest in the Adriatic Sea nearSif Fatima II, Zemlet El Arbi and Ourhoud II concessions in the cityBerkine Nord area, following the agreements signed in 2018. The ongoing activities concerned: (i) the fast-track development activity of Pula. Explorationthe three concessions. In particular, during the year, oil production start-up was achieved by means of 7 production wells and the connection to the existing facilities of the BRN area in the Block 403 (Eni’s interest 50%). In the first months of 2020, gas production activities in Croatia are regulated by PSAs.
The main producing gas fields are Annamaria, Ivana, Ika & Ida, Ika JZ, Ana, Marica and Katarina and are operated by Eni through a 50/50 joint operating companystarted up with the Croatian oil company INA.
Norway. Eni has been operating in Norway since 1965. Eni’s activities are performed indrilling of 2 wells and the Norwegian Sea, inconnection of 2 additional wells to the Norwegian sectionexisting facilities, following the completion of the North Sea andpipeline from BRN to the MLE treatment plant in the Barents Sea. Eni’s production in Norway amounted to 131 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.
Eni currently holds interests in 10 production areas in the Norwegian Sea. 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%), MarulkBlock 405b (Eni operator with a 20%75% interest); and Morvin (Eni’s interest 30%) which in 2016 accounted for 56% of Eni’s production in Norway.
Eni holds interests in 2 production licenses(ii) exploration and delineation activities in the Norwegian section of the North Sea. The main producing field is Ekofisk (Eni’s interest 12.39%)area. In particular, in PL 018, which in 2016 produced approximately 16 KBOE/d net to Eni and accounted for 12% of Eni’s production in Norway. The license expires in 2028, and negotiations are ongoing to grant an extension.
Eni holds interests in 17 exploration and development licenses in the Barents Sea, of which Eni operates 11 licenses.
Operations have been focused on developing the Goliat discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest).
In March 2016, production start-up was achieved at the Goliat field (Eni operator with a 65% interest) in PL 229 and in 2016 accounted for 25% of Eni’s production in Norway. 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 license expires in 2042.
Other development activities concerned: (i) the infilling activities in order to support production at the Ekofisk and Eldfisk in the PL 018; and (ii) the maintenance and optimization of the production at the Asgard (Eni’s interest 14.82%), Heidrun (Eni’s interest 5.17%) and Norne Outside (Eni’s interest 11.5%) in the Norwegian Sea.
In 2016 Eni was awarded the following exploration licenses: (i) an 11.5% interest in the PL 128D in the Norwegian Sea; (ii) the operatorship and a 70% interest in the PL 816 in the Norwegian section of the North Sea; and (iii) the operatorship and a 65% interest in the PL 229D and a 30% interest in the PL 849 in the Barents Sea.
In January 2017, Eni was awarded the PL 28E license (Eni’s interest 11.5%) in the Norwegian Sea and the PL 900 (Eni operator with a 90% interest) and PL 901 (Eni’s interest 30%) in the Barents Sea.
At the beginning of 2017,2019 exploration activity yielded positive results with an oil and gas discovery in the PL 128/128DOurhoud II concession.
Development activities in other blocks included: (i) production optimization in the operated Blocks 403a/d and ROM Nord (Eni’s interest 11.5%35%), Blocks 401a/402a (Eni’s interest 55%), Block 405b, Block 403 and Block 404 (Eni’s interest 12.25%); and (ii) the ongoing development activities of the El Merk field in the Norwegian Sea, nearby production facilities of the Norne fieldBlock 208 (Eni’s interest 6.9%12.25%). with the drilling of production and water injection wells.
United KingdomLibya. Eni has been present in the UK since 1964. Eni’s activities are carried out in the British sectionCurrently, Libya represents approximately 16% of the North Sea andGroup’s total production. Notwithstanding, the Irish Sea. In 2016,complexity of the geopolitical environment, in 2019 Eni’s net production of oil and gas averaged 60 KBOE/d. Exploration and production activities in the UK are regulated by concession contracts.CountryEni currently holds interests in 5progressed smoothly and achieving the planned production areasmainly from Wafa production optimization activities and new compression, upgrading 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 productiontreatment plants in the UK.The Phase 2 development activities of the 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.
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
Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2016, North Africa accounted for 37% of Eni’s total worldwide production of oil and natural gas.
Algeria. Eni has been present in Algeria since 1981. In 2016, Eni’s oil&gas production averaged 85 KBOE/d.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.
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 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. Development activities mainly concerned infilling and optimizations activities at the ROD field (Eni operator with a 66% interest).
The main fields in block 403 are BRN, BRW and BRSW, which accounted for approximately 9% of Eni’s production in Algeria in 2016.
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.
Production in block 405b comes mainly from MLE and CAFC projects and accounted for approximately 13% of Eni’s production in the country in 2016.
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 treatment facilities of the area. The development activities are expected to complete during 2017.
Development and optimization activities progressed at the MLE and CAFC gas fields by means of construction and infilling activities, as well as production optimization.
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.
Egypt. Eni has been present in Egypt since 1954. In 2016, Eni’s share of production in this country amounted to 170 KBOE/d and accounted for 10% of Eni’s total annual hydrocarbon production. 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.
Exploration and production activities in Egypt are regulated by Production Sharing Agreements.
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 in the operated Shorouk concession (Eni’s interest 100%) and, as a consequence, the FID was sanctioned and added proved undeveloped reserves for the field. The first gas is expected at the end of 2017. Based on the production test, delineation and development drilling activities management believes that this discovery contains a large amount of gas resources. Drilling activities will continue in 2017 together with construction activities of onshore gas treatment plant and offshore facilities installation.
In 2016, Eni signed two agreements to sell a 40% overall interest in the Shorouk concession. 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 the country’s authorities.
During the year targeting production of 85.5 KBOE/d net to Eni was achieved at the Nidoco NW field and satellites as a part of the Great Nooros Area project in the Abu Madi West concession. 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 NoorosMellitah 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.
Other development activities concerned: (i) ongoing activity of the sub-sea END Phase 3 development project in the Ras El Barr concession (Eni’s interest 50%) with the drillingSabratha platform, and completion of two wells; (ii) infilling activities and production optimization at the Sinai 12 (Eni’s interest 100%), Ashrafi (Eni’s interest 25%) and Meleiha (Eni’s interest 76%) concessions to support production capacity; (iv) start-upBahr Essalam phase 2. The worsening of the onshore gas treatment plant in the Meleiha concession.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.
Exploration activity yielded positive results with the delineation drilling activity of the Baltim South West (Eni operator with a 50% interest), nearby the Great Nooros Area. Based on this ongoing activity management believes that this discovery contains an important gas resource.
In the medium term, management expects to increase Eni’s production reflecting additions from ongoing development projects.
Libya. Eni started operationssituation in Libya in 1959.
In recent years, Eni’s production levels in Libya were negatively impacted byremains an internal revolution and a changearea of regime in 2011, which 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 development forced Eni to temporarily interrupt or reduce its production activities, negatively affecting Eni’s results of operations and cash flow until the situation began to stabilize. Although our production levels in Libya since 2015 have returned to the levels achieved prior to the outbreak of the civil war, the geopolitical situation remains unstable and unpredictable. In 2016, Eni’s facilities in Libya produced on average 346 KBOE/d, registering a decrease of approximately 3% compared to 2015.issue. For further information on this matter, see “Item 3 – Risk factors”factors – Political considerations”.
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,The rights of Eni is operator in the onshore contract Areas A, B and offshore Area D.
Exploration and production activities in Libya are regulated by six Exploration and Production Sharing Agreement contracts (EPSA). The licenses of Eni’sto produce at its assets in Libya will expire in 2038 for Contract Area C, in 2041 for Contract Area E, in 2042 for Contract Area A and 2047B as well as in 2043 for oil&gas properties, respectively.Contract Area D production.
Tunisia. Development activities concerned production optimization at the producing concessions to mitigate mature fields declines.
In 2019, Egypt accounted for 19% of Eni’s total worldwide production of oil and natural gas, the largest contributor to the Company overall production level. In February 2019, Eni was awarded two onshore exploration blocks: (i) a 100% interest in the South East Siwa block in the Western Desert nearby to the South West Meleiha concession; and (ii) the operatorship with a 50% interest in the West Sherbean block in the onshore Nile Delta nearby to the operated Nooros producing fields (Eni’s interest 75%). In 2019 development activities concerned:were completed: (i) planned facilities downtime at the MellitahNooros field with the installation of a new gas pipeline to the El Gamil treatment plant the Sabrathato production platformoptimization and treatment facilities of the Western Libyan Gas Project;reserves’ recovery maximization; (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 10Baltim South West 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 wells at the Wafa field (Eni’s interest 50%) and activities in order to mitigate the natural production decline in the area. Morocco. In March 2016, 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 October 2016, the relevant country’s Authorities approved the agreement.
Tunisia. Eni has been present in Tunisia since 1961. In 2016, Eni’s production amounted to 10 KBOE/d.
Eni’s activities are located mainly in the Southern Desert areas and in the Mediterranean offshore facing Hammamet.
Exploration and production in this country are regulated by concessions.
Production mainly comes from operated Maamoura and Baraka offshore blocks (Eni’s interest 49%) and the Adam (Eni operator with a 25% interest), Oued Zarproject (Eni operator with a 50% interest), Djebel Grouz with production start-up. Development activities concerned the installation of a production platform and the pipeline to the Abu Madi treatment plant; and (iii) at the South West Meleiha (Eni’s interest 100%) production area with the installation of a pipeline connecting to the Meleiha operated treatment plant.
In 2019, production at the Zohr field averaged approximately 143 KBOE/d net to Eni. Development activities to ramp-up production at the Zohr field (Eni operator with a 50% interest) concerned: (i) the completion of the remaining three treatment units reaching a total of eight units; (ii) the drilling and production start-up of additional four wells; and (iii) the completion and entry into operation of a second gas pipeline which increased installed capacity to more than 3.2 BCF/d. The rights of Eni to produce at the Zohr Development Lease will expire in 2037. As of December 31, 2019, the aggregate development costs incurred by Eni for developing the Zohr project and capitalized in the financial statements amounted to $5.4 billion (€ 4.8 billion at the EUR/USD exchange rate of December 31, 2019). Development expenditure incurred in the year were €1.1 billion. Going forward, planned capital expenditure to support continuing production ramp-up at the Zohr field will be funded through net cash provided by operating activities at the Eni Brent crude marker scenario. As of December 31, 2019, Eni’s proved reserves booked at the Zohr field amounted to 807 mmBOE. The Zohr proved reserves, both developed and undeveloped, related solely to the project phase 1. Development activities at other Eni’s fields in Egypt concerned infilling activities and production optimization in: (i) the Sinai concession (Eni operator with an 100% interest), MLDincluding the production start-up achieved at the recent discoveries as well as water injection optimization to support reservoir pressure; and (ii) the operated Meleiha (Eni’s interest 50%76%), Meleiha Deep (Eni’s interest 100%) and El BormaRas Qattara (Eni’s interest 50%75%) onshore blocks. Production optimization represents the main activity currently performedconcessions in the above listed concessions to mitigate the natural field production decline.Western Desert.
Exploration activities yielded positive results withwith: (i) a gas discovery in the Larich Est-1El Qar’a exploration license (Eni’s interest 75%), located in the Nile Delta; (ii) the Sidri oil discovery well, which put into in the Abu Rudeis development lease (Eni’s interest 100%), in the Gulf of Suez. Drilling activity has been completed and
production through a tie-inwells connected to the existing treatment facilities offacilities; (iii) the MLD concession.Basma and Shemy oil discoveries in the Meleiha development lease. Drilling activity has been completed at the Basma discovery and related production wells connected to existing facilities; (iv) the SWM-A-3X gas and condensates discovery in the South West Meleiha concession; and (v) the Nour-1 gas well in the Nour exploration license (Eni’s interest 40%). Sub-Saharan Africa Eni’s operations in Sub-Saharan Africa are conducted mainly in Angola, Congo, Ghana, Mozambique and Nigeria. In 2016,2019, Sub-Saharan Africa accounted for 19%20% of Eni’s total worldwide production of oil and natural gas. AngolaAngola. In 2019, Angola accounted for 7% of Eni’s total worldwide production of oil and natural gas. In January 2020 Eni has been present in Angola since 1980. In 2016, Eni’s production averaged 112 KBOE/d. Eni’s activities are concentratedwas awarded a 60% interest in the conventionalBlock 28 as operator. In November 2019 Eni and deep offshore. The main Eni’s asset in Angola is the Country’s Authority signed a Memorandum of Understanding which provides for the acquisition of the offshore Block 15/061/14 (Eni operator with a 36.84%35% 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 inonshore Cabinda Center block (Eni’s interest 9.8%42.5%) north.
In 2019 Eni finalized an extension 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 westexploitation rights until 2032 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 offshorenumber of the Congo Basin.Development Areas has been reduced, joining some of them together. 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.
The development program of the West Hub project plans to hook up the Block’s discoveries to the N’Goma FPSO in order to support production plateau. In 2016, production start-up was achieved at the M’Pungi and M’Pungi North fields, with a production ramp-up of approximately 81 KBBL/d (approximately 28 KBBL/d net to Eni) in the area. Planned activities included to be put into production 5 additional discoveries.
In February 2017, production start-up was achieved at the East Hub project 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 additions discoveries by the end of 2018.
Early production phase started up at the Mafumeira Sul project in the Block 0. Development activities progressed, with the completion expected during 2017 and a peak production of 100 KBOE/d.
Other development activities concerned: (i) the completion of the Congo River Crossingplanned activities at the Vandumbu field in the West Hub project to supply gasin the operated Block 15/06 (Eni’s interest 36.84%); and (ii) production ofoptimization at the Mpungi and Sangos fields in the Block 15/06 and in some fields in the Block 0 and 14 to(Eni’s interest 9.8%).
Eni owns a 13.6% interest of Angola LNG, liquefactionwhich runs the plant, (Eni’s interest 13.6%) which started uplocated in April 2016Soyo, with a treatment capacity of approximately 350 BCF/y of feed gas and a liquefaction capacity of 5.2 mmtonnes/y of LNG. In 2019 production net to Eni averaged approximately 22 KBOE/d. In October 2019 Eni, as operator of 6 KBOE/dnet to Eni; and (ii) development programa new joint venture (Eni interest 25.6%), signed a commercial agreement with the partners of the Kizomba satellites Phase 2 (Eni’s interest 20%) which will be started up leveraging onAngola LNG for the production and treatment facilities in the area. In the medium term, management expects to increase Eni’s production to 146 KBOE/d reflecting additions from ongoing development projects.
Congo. Eni has been present in Congo since 1968. In 2016, production averaged 92 KBOE/d net to Eni.
Eni’s activities are concentrated in the conventional and deep offshore facing Pointe Noire and onshore. Eni’s main operated oil 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%), Zingali and Loufika (Eni’s interest 100%) fields.
Other relevant not operated producing areas are represented by a 35% interest in the Pointe Noire Grand Fond, PEX and Likouala permits.Exploration and production activities in Congo are regulated by Production Sharing Agreements.
In December 2016, production ramp-up was achieved at the Nené Marine field with the completion of the secondgas fields to support the liquefaction plant. The first development phase,project is expected to be sanctioned in 2015.2020.
DevelopmentExploration activities progressed at the Litchendjili production field andBlock 15/06 during the year, peakafter resumed in 2018. Eni made a promising discoveries with the Agogo oil well and the Agogo -2 and Agogo-3 appraisal wells, then with the Ndungu and the Agidibo oil wells. These discoveries will undergo phased development in accordance to the production of approximately 16 KBOE/d was achieved. Gas production feeds the CEC power plant (Eni’s interest 20%).
In the medium term, management expects to maintain production on the present level.
Ghana. Eni has been present in Ghana since 2009 and currently is the operatorcapacity of the Offshore Cape Three Points (Eni’s interest 44.44%) permits which is regulated by a concession agreement. The license expirestwo FPSO units installed in 2036.
Development activities concerned the OCTP integrated oil&gas development plan to put intoarea. In 2020 the production the Sankofa, Sankofa East and Gye Nyame discoveries. 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.
In March 2016, Eni was awarded the operatorshipstart-up of the exploration license Cape Three Points Block 4 (Eni’s interest 42.47%), located in the offshore of the country.Agogo discovery was achieved.
MozambiqueMozambique.. Eni has been present in Mozambique since 2006, following the acquisitionaward of the exploration license relating to gas-rich Area 4 offshore Rovuma Basin block, located in the north Offshore of the country. Eni currently holds a 50% indirect interest in the block through a 71.4% stake in Eni East Africa, which is operator of the Area 4 concession with a 70% interest. The other partners in Area 4 are Galp, Kogas, ENH with a participating interest of 10% each and CNPC that holds a 20% indirect participation in Area 4 through its participation in the shareholding of Eni East Africa.Rovuma Block.In 2011, Eni made the important gas discovery of Mamba. The Mamba reservoir extends through Area 4 and the adjacent Area 1 operated by Anadarko.Total. In 2012, Eni made another large gas discovery at the Coral gas discoveryprospect, which falls entirely in Area 4.
During the exploration period, which has expired in 2015, six Discovery Areas (DA) were identified in Area 4. Pursuant to theidentified. Mozambique Decree Law 02/2014 multipleprovides that individual plans of development can be submitted in respect of each DA. Under the Area 4 EPCC (Exploration and Production Concession Contract), each Plan of Development once approved by the Government of Mozambique will give rightentitles the Concessionaires to develop and to produce in a Development and Production Period of the durationterm of 30 years, further extendablewith an extension option pursuant to the terms of the Area 4 EPCC and the applicable Petroleum Law. Following two separate transactions occurred respectively in 2013 and in 2017, Eni also operates the exploration offshore Block A-5A (Eni’s interest 34%),divested to CNPC and ExxonMobil indirect interests of 20% and 25% respectively in the deep offshorediscoveries of Zambesi.Area 4, by diluting its participating interest in Mozambique Rovuma Venture SpA, the operator of Area 4 which is a joint In March 2017, ExxonMobil and53
operation for IFRS accounting purposes, proportionally-consolidated in the Company Consolidated Financial Statements. Post transactions, Eni signed sale and purchase agreement to acquireretains a 25% indirect interest in the Area 4 block, offshore Mozambique.concession. The agreed terms includeother concessionaires of Area 4 are the state-owned oil company ENH, Galp and Kogas, each with a cash price10% working interest. Development activities continued at the Coral South project during 2019. The sanctioned Coral South project includes the construction of FPSO for the gas treatment, liquefaction, storage and export of LNG, with a capacity of approximately $2.8 billion.3.4 mmtonnes/y, fed by 6 subsea wells. Production start-up is expected in 2022. The acquisitionLNG produced will be completed subject to satisfaction of certain conditions precedent, including clearance from Mozambican and other regulatory authorities. Following completion ofsold by 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 whileConcessionaires to BP under a long-term contract for a period of twenty years, with an option for an additional ten-year term. Pre-Development activities progressed at the Mamba Complex discoveries where Eni is expected to coordinate the upstream development and production phase and ExxonMobil will lead the construction and operation phase of natural gas liquefaction facilities onshore. This operating model will enableIn 2019, the use of best practicesMozambique authorities approved the unitization agreement between the Area 1 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. The first plan of development was submitted to the Government of Mozambique in December 2014 in relation to the initial exploitation of the Coral gas resources. The Coral South Development Plan, which was approved by the Government 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.Area 4.
In October 2016, Eni and itsthis context, the Area 4 partners signedConcessionaire progressed activities towards a binding agreement with BP for the salefinal investment decision (FID) and towards finalization 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 for the Rovuma LNG project, which is currently being finalized, will be underwritten. The development plan ofprovides the Mamba project, comprises construction of two onshore LNG trains with a combined capacity of 10approximately 7.6 mmtonnes/y and the drilling of 16each, feed by 24 subsea wells and facilities for storing and exporting LNG. In May 2019, the plan of development (POD) was approved by the relevant Authorities.
In May 2019 Eni completed the purchase of a 10% interest of the deep offshore A5-B, Z5-C and Z5-D blocks from ExxonMobil. In July 2019 Eni divested a 25.5% interest of the offshore A5-A block to Qatar Petroleum. Following this acquisition Eni retains the operatorship 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.a 34% interest. Nigeria. Eni has been present in Nigeria since 1962. In 2016, Eni’s oil&gas production averaged 112 KBOE/d located mainly onshore and offshore the Niger Delta. 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.
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.
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.The development activities concerned: (i) drilling activity and production start-up of three additional wells, two production and one water-injection, at the Bonga field in the OML 118 block; (ii) 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 (iii) the OML 43 block (Eni’s interest 5%), where the development plan of the Forcados-Yokri field provides hook-up the last 12 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.
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 ahas treatment capacity of approximately 1,236 BCF/y of feed gas corresponding toand a production capacity of 22 mmtonnes/y of LNG on six trains.LNG. Natural gas supplies to the plant are currently provided under a gas supply agreements with an expiring date in fifteen years from the SPDC JV (Eni’s interest 5%), TEPNG JV and the NAOC JV (operating(Eni’s interest 20%). In 2019, the OMLs 60, 61, 62 and 63 blocks) with an average amount ofBonny liquefaction plant processed approximately 2,825 mmCF/d for the next four years (approximately 265 mmCF/d net to Eni corresponding to approximately 49 KBOE/d).1,165 BCF. LNG production is sold under long-term contracts and exported mainly to the United States, Asian and European markets by the Bonny Gas Transport fleet, wholly owned by Nigeria LNG Co.LNG. In December 2019 the final investment decision was sanctioned for the construction of an additional treatment unit which will increase production capacity until 30 mmtonnes/y of LNG. Development activity is expected to be completed in 2024 with production start-up. In January 2017, Eni signed withDevelopment activities of the Nigerian National Petroleum Corporation (NNPC)operated OMLs 60, 61, 62 and 63 blocks (Eni’s interest 20%) concerned: (i) the completion of planned activities and production start-up of the Obiafu 41 gas and condensates discovery; and (ii) increasing generation capacity of the combined cycle power plant at Okpai to achieve about 1 GW from the actual a Memorandum480 MW. Natural gas production of Understanding, which strengthen cooperationthe area will support the plant capacity.
Other development activities concerned: (i) infilling program and production optimization in the energy sector.OML 118 block (Eni’s interest 12.5%); (ii) the completion of drilling activities of two additional oil wells at the Abo field in the operated OML 125 block (Eni’s interest 100%). Peak production of 26 KBBL/d has been achieved during the year; (iii) the completion of the associated gas project in the OML 43 block (Eni’s interest 5%) and the SSAGS project in the OML 28 block (Eni’s interest 5%). Associated gas production will be sold in the domestic market; and (iv) the flaring down Assa North project (Eni’s interest 5%) has been sanctioned to support the domestic market. The acquisition of the OPL 245 property made by Eni in 2011 is the subject of certain judicial proceedings describe in “Item 18 – consolidated financial statement – Note 27”.
Kazakhstan Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and partner in the North Caspian Sea Production Sharing Agreement (NCSPSA). In 2016, Eni’s operations in Kazakhstan mainly regarded the Kashagan and the Karachaganak fields. In 2019, Kazakhstan accounted for 6%8% of itsEni’s total worldwide production of oil and natural gas.
KashaganKashagan.. 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 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. Management believes this field contains a large amount of hydrocarbon resources, which will eventuallyare expected to be developed in phases. The NCSPSA expires at the end of 2041. In addition to Eni, the partners of the Consortium are the Kazakh national oil company, KazMunayGas, with a participating interest of 16.88%, the international oil companies Total, Shell and ExxonMobil, each with a participating interest currently of 16.81%, CNPC with 8.33%, and Inpex with 7.56%. On September 28, 2016,In 2019, production re-started at the Kashagan field withaveraged 53 KBBL/d of liquids and 54 mmCF/d of natural gas net to Eni. The treated gas is delivered to the completion of works to fully replacenational gas marketing and transportation company (KazTransGas), and the damaged pipelines followingremaining volumes is utilized as fuel gas. The remaining untreated gas volumes (approximately 43%) is re-injected in the gas leak occurredreservoir. The liquid production is stabilized at the end of 2013. The production of 180 KBOE/d was achieved by year-end (31 KBOE/d netBolashak facilities and exported to Eni). The production capacity of 370 KBBL/d plannedWestern markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline.
Current development plans envisage for increasing the Phase 1 is expected to be achieved during 2017, when gas reinjection comes online. The Phase 1 includes a further increase available production capacity up to 450 KBBL/d by installing additionalupgrading the existing gas compression capacity, for reinjection in the reservoir. The partners submittedconversion of production wells into injection wells, the schemedebottlenecking and the revamping of this additional phaseexisting facilities with the construction of a new onshore gas treatment plant. A final investment decision has yet to the relevant Kazakh Authorities.be made.
Management believes that significant capital expendituresexpenditure will be required in case the partners of the venture would sanction a second development phase and possibly other additional phases. Eni will fund those investments in proportion to its participating interest of 16.81%. However, taking into account that future development expenditures will be incurred over a long time horizon and subsequentsubsequently to the production start-up, management does not expect any material impact on the Company’s liquidity or its ability to fund these capital expenditures. In addition to the expenditures for developing the field, further capital expenditures will be required to build the infrastructures needed for exporting the production to international markets. As of December 31, 2016,2019, Eni’s proved reserves booked for the Kashagan field amounted to 608661 mmBOE, barely unchangedincreased from 2015.614 mmBOE in 2018. As of December 31, 2015, Eni’s proved reserves booked for the Kashagan field amounted to 611 mmBOE, recording an increase of 31 mmBBL compared to 2014 mainly due to lower marker Brent price. As of December 31, 2014, Eni’s proved reserves booked for the Kashagan field amounted to 580 mmBOE, barely unchanged compared to 2013.
As of December 31, 2016,2019, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $9.7$10 billion (€9.28.9 billion at the EUR/USD exchange rate of December 31, 2016)2019). This capitalized amount included: (i) $7.2$7.4 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $2.5$2.6 billion relating primarily to accrueaccrued finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years.
As of December 31, 2015, the aggregate costs Cost incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $9.2 billion (€8.4 billion at the EUR/USD exchange rate of December 31, 2015). This capitalized amount included: (i) $6.8 billion relating to expenditure incurred by Eni for the development of the oil field; and (ii) $2.4 billion relating primarily to accrue finance charges and expenditures for the acquisition of interests in the Consortium from exiting partners upon exercise of pre-emption rights in previous years.year were €106 million.
Karachaganak. Located onshore in West Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a PSA lasting 40 years, until 2037. Eni and Shell are co-operators of the venture. Eni’s interest in the Karachaganak project is 29.25%. In 2016,2019, production of the Karachaganak field averaged 23146 KBBL/d of liquids (61 KBBL/d net to Eni) and 867186 mmCF/d of natural gas (230 mmCF/d net to Eni).Eni. This field is developed by producing liquids from the deeper layers of the reservoir. The gas is marketed (about 51%50%) at the Russian gas plant inof Orenburg, and the remaining volumes isare utilized for re-injectingre-injection in the higher layers of the reservoir and the production ofas fuel gas. Approximately 91% ofAlmost the entire liquid production areis 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. The Expansion Project is currently under study. The project targets to install, in stages,Within the gas treatment plantsexpansion projects of the Karachaganak field, activities concerned: (i) the Karachaganak Debottlenecking project progressed; (ii) project of the construction of fourth gas re-injection unit was sanctioned and activity started up during the year; and (iii) the Front End Engineering Design of the Karachaganak Expansion Project has been completed. The planned activities include the installation of two additional gas 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.facility.
As of December 31, 2016,2019, Eni’s proved reserves booked for the Karachaganak field amounted to 613448 mmBOE, reporting an increase of 26slightly decreased from 452 mmBOE from 2015 mainly due to lower marker Brent price.in 2018. As of December 31, 2015, Eni’s proved reserves booked2019, the aggregate costs incurred by Eni for the Karachaganak fieldproject capitalized in the financial statements amounted to 587 mmBOE, reporting an increase of 98 mmBOE from 2014 mainly due to lower marker Brent price. As$4.1 billion (€3.7 billion at the EUR/USD exchange rate of December 31, 2014, Eni’s proved reserves booked for2019). Cost incurred in the Karachaganak field amounted to 489 mmBOE, barely unchanged compared to 2013.year were €267 million.
Rest of Asia Eni’s operations in Rest of Asia are conducted mainly in Indonesia, Iraq and United Arab Emirates. In 2016,2019, Eni’s operations in the Rest of Asia accounted for 7%approximately 9% of its total worldwide production of oil and natural gas. ChinaIraq. Eni hasDevelopment activities concerned the execution of an additional development phase of the ERP (Enhanced Redevelopment Plan) at the Zubair field, to achieve a production plateau of 700 KBBL/d. This phase also contemplates utilization of the associated gas for power generation. The production capacity and relevant facilities to treat the targeted production plateau have been present in China since 1984 with activities located inalready installed; the South China Sea. In 2016, Eni’sfield reserves will be progressively put into production amounted to 2 KBOE/d.
Exploration and production activities in China are regulated by Production Sharing Agreements.
In 2016, hydrocarbons were produced fromdrilling additional productive wells over the offshore Blocks 16/19 through 3 platforms connected to an FPSO.next few years.
Indonesia. Eni has been present in Indonesia since 2001. In 2016, Eni’s production mainly composed of gas, amounted to 14 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; in total, Eni holds interests in 1413 blocks. Exploration and production activitiesIn 2019, Eni divested to Neptune a 20% interest in Indonesia are regulated by PSAs.
In 2016 production start-up was achieved at the Bangka project (Eni’s interest 20%) in the East Kalimantan.
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 deep-offshore 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.
Exploration activities yielded positive results with appraisal activities at the Merakes gas discovery in the deep offshore of the East Sepinggan block, (Eni operator with an 85% interest), nearbyoffshore East Kalimantan, which includes the Jangkrik project.
Iraq. Eni has been present in Iraq since 2009. Eni, leading a consortium of partners including international companiesMerakes field and the national oil company Missan Oil, holdsEast Merakes discovery. Eni will retain a 41.6% interests in65% interest and the Zubair oil field.
Development and production activities at the Zubair field are regulated by a technical service contract. This contractual scheme establishes an oil entitlement mechanism and an associated risk profile similar to those applicable to Production Sharing contracts.operatorship.
In 2016, production of2019 Eni was awarded the Zubair field averaged 64 KBBL/d net to Eni. 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 5 existing restructured and modernized plants 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 the Zubair field were completed with start-up of these new facilities.
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.
Myanmar. Eni has been present in Myanmar since 2014. Eni is operator of four Production Sharing Contracts; two onshore blocks RSF-5 and PSC-K (Eni’s interest 90% in both leases) and two offshore blocks MD-02 and MD-04 (Eni’s interest 40% in both leases). The contracts foresee, for the onshore blocks, anWest Ganal exploration period of six years subdivided into three phases and for the offshore blocks a study period of two years, followed by an exploration period of six years, subdivided in 3 phases.
Pakistan. Eni has been present in Pakistan since 2000. In 2016, Eni’s production mainly composed of gas amounted to 30 KBOE/d.
Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore).
Eni’s main permits in the country are Bhit/Bhadrablock (Eni operator with a 40% interest), Latif (Eni’s interest 33.33%) and Zamzama (Eni’s interest 17.75%), which located in 2016 accounted for 79% of Eni’s productionthe deep water Kutei Basin, effective since January 1, 2020.
Development activities concerned the offshore Merakes gas project in Pakistan.the operated East Sepinggan block.
Production optimization throughUnited Arab Emirates. In 2019, Eni awarded: (i) the operatorship of the Block 1 and 2 with a 70% interest, located offshore Abu Dhabi. The exploration commitment for the first phase consists in exploration studies for the Block 1 and the drilling activities of new developmenttwo exploration wells represents the main activity currently performedand one appraisal well in the above listed fields to mitigateBlock 2; (ii) three onshore explorationconcessions in the natural field production decline.Emirate of Sharjah with a 75% interest in the operated concession Area A and C and a 50% interest in the participated concession Area B. In January 2020, exploration activities yielded positive results with the Mahani-1 gas and condensates discovery in the Area B concession; and (iii) the operatorship with a 90% interest in the Block A, located offshore Emirate of Ras al Khaimah.Russia. Eni has been presentDevelopment activities concerned: (i) the Dalma Gas Development project in Russia through three joint ventures with Rosneft for the development of Fedynsky and Central Barents licensesGasha concession (Eni’s interest 33.33%25%) located. The final investment decision was sanctioned. Start-up is expected in 2022; and (ii) the Nasr Full Field Development project in the Russian Barents Sea and Western Chernomorsky licenseUmm Shaif/Nasr concession (Eni’s interest 33.33%10%). The program was completed and production ramp-up achieved in the Black Sea since 2013.
Following the adoption of EU sanctions measures relating to the upstream sector in Russia, Eni started the required authorization before competent Authorities of the Member States of the European Union who granted the Company and the joint ventures between Eni and Rosneft certain authorization for the execution and financing of the exploration activities in Russia, under the terms of contracts entered into force before the enactment of the relevant sanctions. The current sanctions have delayed and will continue to affect the timing of implementation of the projects. For further information on this matter, see “Item 3 – Risk factors”.
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. The license expires in 2032.
In 2016, Eni’s production averaged 9 KBOE/d.
Exploration and production activities in Turkmenistan are regulated by PSAs.
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.
Production optimization represents the main activity currently performed in the area to mitigate the natural field production decline.
Vietnam. Eni has been present in Vietnam since 2012 and is operator of five offshore Production Sharing Contracts, two of which are held with 100% interest (Block 116 and Block 122) and three are in Joint Venture (Block 114 Eni’s interest 50%, Block 120 - Eni’s interest 66.67%, Block 124 - Eni’s interest 60%).year.
Americas In 2016, Eni’s operations in Americas are conducted mainly in Mexico, United States and Venezuela. In 2019, Eni’s operations in the Americas area accounted for 10%approximately 6% of its total worldwide production of oil and natural gas.
EcuadorEcuador. In 2019, Eni has been presentdivested its activities in Ecuador since 1988. Operations are performedthe country. Mexico. In 2019 production start-up was achieved at the operated Area 1 license (Eni’s interest 100%) by means of the drilling of two wells and the installation of a production platform which is linked by a sealine to an onshore treatment unit. The full field development envisages a phased installation of three additional platforms and a FPSO unit, which will increase the production capacity up to 100 KBBL/d in 2021. In February 2020, exploration activities yielded positive results with the Saasken offshore oil discovery in the operated Block 10 (Eni’s interest 100%65%) located in the Oriente Basin, in the Amazon forest. In 2016, Eni’s production averaged 11 KBBL/d. Exploration and production activities in Ecuador are regulated by a service contract that expires in 2033.
Block 10 production is processed by a Central Production Facility and transported to the Pacific Coast through a pipeline network.
In December 2016, development activities of the Villano Phase VI project started up with the drilling of the first of two infilling wells.
Mexico. Eni has been present in Mexico since 2015. Eni is operator of the Block 1 (Eni’s interest 100%) to develop the Amoca, Miztón and Tecoalli fields, located in the Gulf of Mexico shallow waters. The delineation campaign of the fields was submitted to the Mexican Authorities in the first quarter of 2016 and plans the drilling of four wells in order to define a fast track and synergic development plan.In January 2017, the delineation campaign started with the first well..
Trinidad and Tobago. Eni has been present in Trinidad and Tobago since 1970. In 2016, Eni’s production averaged 70 mmCF/d. Eni owns a 17.3% interest in the North Coast Marine Area 1 Block, located offshore North of Trinidad.
Exploration and production activities in Trinidad and Tobago are regulated by PSAs.
Production is provided by the Chaconia, Ixora, Hibiscus, Ponsettia, Bougainvillea and Heliconia gas fields. 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 StatesStates.. Eni has been present in the United States since 1968. Activities are performed in the shallow and deep offshore of the Gulf of Mexico, onshore and offshore in Alaska, and in Texas onshore.In 2016, Eni’s oil&gas production was 91 KBOE/d mainly from the Gulf of Mexico and Alaska fields.
Exploration and production activities in the United States are regulated by concessions.
Eni holds interests in 8441 exploration and production blocks in the Gulf of Mexico, of which 4418 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 in the Gulf of Mexico at: (i) the Heidelberg field (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 (Eni’s interest 8.5%) 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.
To achieve the highest safety standards of operations, Eni became a member of the HWCG Consortium of Gulf of Mexico operators. The HWGC provides resources, coordination and performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline. For further information on this matter, see “Item 3 – Risk factors”.
Eni holds interests in 43 exploration and developmentoperates 151 blocks in Alaska with interests ranging from 30 to 100%; Eni is the operator in 27 of these blocks. working interest.
Eni’s production is provided by Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni’s interest 30%) fields with a 2016 overallDuring 2019 the net production of Eni in the Unites States has significantly increased by 20%, from 50 KBOE/d to 60 KBOE/d, as a result of an intense activity of production optimization.
Venezuela. In 2019, Eni’s production of oil and natural gas averaged 38 KBOE/d and accounted for approximately 24 KBBL/d. In Texas onshore,2% of Eni’s total production. Eni’s production comes from the Alliance Area (Eni’s interest 27.5%).
Venezuela. Eni has been present in Venezuela since 1998. In 2016, Eni’s production averaged 60 KBOE/d.
Activity is concentrated both offshore (Gulf of Venezuela and Gulf of Paria) and onshore in the Orinoco Oil Belt.
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.
Eni’s production comes from the giant Perla gas field (Eni’s interest 50%), in the Gulf of Venezuela, the Corocoro field (Eni’s interest 26%), in the GulfoGulf de Paria, and the JuninJunín 5 oil field (Eni’s interest 40%), located in the Orinoco Oil Belt.
Development Production activities performed in 2016 were: (i)have been negatively affected by the ongoing drilling activities at the Junin 5 oil field. The production level at year-end was approximately 18 KBBL/d at 100%. Possible optimization of development program is currently under evaluation;distressed financial and (ii) the completionpolitical situation of the first development phase at the Perla field. The six wells currentlyCountry. For further information on stream are producing approximately 540 mmCF/d at 100%this matter, see “Item 3 – Risk factors – Political considerations”. The gas will be mainly used by PDVSA for the domestic market, under the Gas Sales Agreement in place until 2036. The Perla project includes two additional development phases to achieve a production plateau of approximately 1,200 mmCF/d.
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
Eni’s operations in Australia and Oceania area are conducted mainly in Australia. In 2016, the area of Australia and Oceania accounted for 1% of Eni’s total worldwide production of oil and natural gas.
Australia. Eni has been present in Australia since 2001. In 2016, Eni’s production of oil and natural gas averaged 23 KBOE/d. Activities are focused on conventional and deep offshore fields.
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.
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.
Capital expenditures See “Item 5 – Liquidity and capital resources – Capital expenditures by segment” Disclosure pursuant to Section 13(r) of the Exchange Act The Iran Threat Reduction and Syria Human Rights Act of 2012 (ITRA) created a new subsection (r) in Section 13 of the Exchange Act which requires a reporting issuer to provide disclosure if the issuer or any of its affiliates engaged in certain enumerated activities relating to Iran, including activities involving the Government of Iran. In accordance with our general business principles and Code of Ethics, Eni seeks to comply with all applicable international trade laws including applicable sanctions and embargoes. The activities referred to below have been conducted outside the U.S. by non-U.S. Eni subsidiaries. For purposes of the disclosure below, amounts have been converted into U.S. dollars at the average or spot exchange rate, as appropriate. AsIn 2017, Eni fully recovered the overdue trade receivable owed by Iranian state- owned companies relating to the cost recovery of December 31, 2016, Eni outstanding trade receivables amountedpast projects due to $278 million towards the National Iranian National Oil Co (NIOC) which were recorded in connection with the settlement agreement recognized in 2015. This amount was curtailed from the amount outstanding at December 31, 2015 ($339 million). The State counterparties expressed their willingness to negotiate a repayment plan of overdue receivables based on arrangements relating the sale of volumesenactment of the Iranian counterpart equity crude and the attribution to Eni of a percentage of the sale proceeds. This agreement has been enactedagreements signed in the last months of 2016 with a reimbursement to Eni of $44 million. Negotiations are underway to identify additional crude volumes to be marketed, some of which have already been awarded to Eni in early 2017, with the aim of fully recovering the overdue amounts. Eni had2016. There were no payablesmore outstanding receivables towards NIOCIran’s national oil companies as of December 31, 2016.2019. In 2019, Eni made payments in the region of $1$0.04 million to the Iranian Social Security Organization in connection to health and social security insurance for which Eni retains at the balance sheet dateDecember 31, 2019 a residual payable amounting to $10approximately $5 million, date, which will be settled upon terminationde-registration of our presence in the country.local branch.
Gas & Power Eni’s Gas & Power segment engages in supply, trading and marketing of gas and electricity, international transport, and LNG supply/marketing and trading. This segment also includes the activities of electricity generation. In 2016,2019, Eni’s worldwide sales of natural gas amounted to 88.93 BCM, including 2.62 BCM of gas sales made directly by Eni’s Exploration & Production segment.73.07 BCM. Sales in Italy amounted to 38.4337.85 BCM, while sales in European markets were 42.4327.07 BCM that included 4.37 BCM of gas sold to certain importers to Italy. In the Gas & Power segment we expect a continuing weak outlook for natural gas salesThe business results of operations in 2019 and prices due to structural headwindsits strategy are described in the industry as we forecast oversupplies“Item 5 – Group results of operations” and strong competition across all“Item 5 – Management’s expectations of our main markets in Europe, including Italy.operations.”
Supply of natural gas In 2016,2019, Eni’s consolidated subsidiaries supplied 82.64 BCMtotal supply of natural gas was 70.65 BCM, down by 2.753.50 BCM, or 3.2%4.7% from 2015.2018. Gas volumes supplied outside Italy (76.64(65.21 BCM from consolidated companies), imported
in Italy or sold outside Italy, represented approximately 93%92% of total supplies, down by 2.023.61 BCM, or 2.6%5.2% compared to the previous year, due to lower volumes purchased in LibiaAlgeria (down 2.38by 5.36 BCM), in Russia (down 2.34by 1.53 BCM), in Indonesia (down by 1.48 BCM), partially offset by higher purchases in France (up by 2.90 BCM), in Libya (up by 1.31 BCM) and in the Netherlands (down 2.13United States (up by 1.20 BCM), partly offset by higher volumes purchased in Algeria (up 6.85 BCM). Supplies in Italy (6.00(5.44 BCM) decreasedincreased by 2.1% from 2015 (down 0.73 BCM or 10.8%) due to the production shutdown in the Val d’Agri district during the period April-August 2016. 2018. In 2016,2019, main gas volumes from equity production derived from: (i) Italian gas fields (4.5 BCM)(3.4 bcm); (ii) certain Eni fields located in the British and Norwegian sections of the North Sea (2.2 BCM)(2.3 bcm); (iii) Libyan fields (1.5 BCM)(1.8 bcm); (iv) Indonesia (0.8 bcm) and (v) the United States (1.4 BCM); and (v) other European areas (0.2 BCM)bcm). Considering also direct sales of the Exploration & Production segment and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied Supplied gas volumes from equity production were approximately 15.02 BCM8.5 bcm representing 17%12% of total volumes available for sale.
The available for sale by Eni’s affiliates amounted to 2.56 bcm (down by 3.8% compared to 2018) and mainly referred to supplied volumes from Oman, Spain, the United States and Nigeria.
The table below sets forth Eni’s purchases of natural gas by source for the periods indicated. | Natural gas supply | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | | | (BCM) | | | (BCM) | | Italy | | | | 6.92 | | | | | 6.73 | | | | | 6.00 | | | | | | 5.44 | | | | | 5.33 | | | | | 5.05 | | | Outside Italy | | | | 75.99 | | | | | 78.66 | | | | | 76.64 | | | | | | 65.21 | | | | | 68.82 | | | | | 73.23 | | | Russia | | | | 26.68 | | | | | 30.33 | | | | | 27.99 | | | | | | 24.71 | | | | | 26.24 | | | | | 28.09 | | | Algeria (including LNG) | | | | 7.51 | | | | | 6.05 | | | | | 12.90 | | | | | | 6.66 | | | | | 12.02 | | | | | 13.18 | | | Libya | | | | 6.66 | | | | | 7.25 | | | | | 4.87 | | | | | | 5.86 | | | | | 4.55 | | | | | 4.76 | | | the Netherlands | | | | 13.46 | | | | | 11.73 | | | | | 9.60 | | | | | | 4.12 | | | | | 3.95 | | | | | 5.20 | | | Norway | | | | 8.43 | | | | | 8.40 | | | | | 8.18 | | | | | | 6.43 | | | | | 6.75 | | | | | 7.48 | | | the United Kingdom | | | | 2.64 | | | | | 2.35 | | | | | 2.08 | | | | | | 1.75 | | | | | 2.21 | | | | | 2.36 | | | Hungary | | | | 0.38 | | | | | 0.21 | | | | | 0.02 | | | | Indonesia (LNG) | | | | | 1.58 | | | | | 3.06 | | | | | 0.74 | | | Qatar (LNG) | | | | 2.98 | | | | | 3.11 | | | | | 3.28 | | | | | | 2.79 | | | | | 2.56 | | | | | 2.36 | | | Other supplies of natural gas | | | | 5.56 | | | | | 7.21 | | | | | 5.81 | | | | | | 7.91 | | | | | 5.52 | | | | | 6.75 | | | Other supplies of LNG | | | | 1.69 | | | | | 2.02 | | | | | 1.91 | | | | | | 3.40 | | | | | 1.96 | | | | | 2.31 | | | Total supplies of subsidiaries | | | | 82.91 | | | | | 85.39 | | | | | 82.64 | | | | | | 70.65 | | | | | 74.15 | | | | | 78.28 | | | Withdrawals from (input to) storage | | | | (0.20) | | | | | | | | | | 1.40 | | | | | | 0.08 | | | | | 0.08 | | | | | 0.31 | | | Network losses, measurement differences and other changes | | | | (0.25) | | | | | (0.34) | | | | | (0.21) | | | | | | (0.22) | | | | | (0.18) | | | | | (0.45) | | | Volumes available for sale of Eni’s subsidiaries | | | | 82.46 | | | | | 85.05 | | | | | 83.83 | | | | | | 70.51 | | | | | 74.05 | | | | | 78.14 | | | Volumes available for sale of Eni’s affiliates | | | | 3.65 | | | | | 2.67 | | | | | 2.48 | | | | | | 2.56 | | | | | 2.66 | | | | | 2.69 | | | E&P volumes | | | | 3.06 | | | | | 3.16 | | | | | 2.62 | | | | Total volumes available for sale | | | | 89.17 | | | | | 90.88 | | | | | 88.93 | | | | | | 73.07 | | | | | 76.71 | | | | | 80.83 | | | | |
Sales of natural gas Eni is selling gas to wholesale and retail markets in Italy and in a number of European countries. The wholesale market includes sales to large accounts (industrials and thermoelectric utilities) and on European spot markets. The retail segment includes sales to residential customers (households and larger accounts like hospitals, schools, office buildings) and small and medium-sized businesses located in urban areas. The Company has grown the combined offer of gas and electricity to retail customers to maximize cross-selling opportunities and cost synergies. In 2016,2019, natural gas sales amounted to 88.9373.07 BCM (including Eni’s own consumption, Eni’s share of sales made by equity-accounted entities and upstream sales in Europe and in the Gulf of Mexico)entities), representing a decrease of 1.953.64 BCM, or 2.1%4.7% from the previous year. Sales in Italy were barely unchanged (38.43(37.85 BCM); lower volumes in the wholesale decreased by 3% from 2018. Lower sales to wholesalers, spot market and residential segment were partly offset by higher spot volumes.sales to thermoelectrical and industrial segments. Sales in the European markets were 38.06amounted to 22.70 BCM, down by 0.6%a decrease of 12.7% or 3.30 BCM from 2015. Direct sales of Exploration & Production segment in Europe and the Gulf of Mexico (2.62 BCM) decreased by 0.54 BCM due to lower volumes marketed in the United Kingdom and the United States, partially offset by higher sales in Norway.2018.
Sales to long-term buyers were down4.37 BCM; up by 5.2%27.8% compared to the previous year duethanks to shorterthe higher availability of Libyan output as well as lower sales tooutput. Sales in the Extra European markets (down(8.15 BCM) decreased by 14.7%) driven by0.11 BCM or 1.3% due to lower LNG volumes marketedsales in the Far East due tomarkets, partly offset by higher volumes sold in the lack of contracts renewal.United States.
The tables below set forth Eni’s sales of natural gas by principal market for the periods indicated. | | | | | Natural gas sales by entities | | | 2014 | | | 2015 | | | 2016 | | | | | (BCM) | | Total sales of subsidiaries | | | | | 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 | | | Total sales of Eni’s affiliates (Eni’s share) | | | | | 4.38 | | | | | | 2.78 | | | | | | 2.97 | | | Italy | | | | | | | | | | | | | | | | | | | | Rest of Europe | | | | | 3.15 | | | | | | 1.75 | | | | | | 1.91 | | | Outside Europe | | | | | 1.23 | | | | | | 1.03 | | | | | | 1.06 | | | Total sales of G&P | | | | | 86.11 | | | | | | 87.72 | | | | | | 86.31 | | | E&P in Europe and in the Gulf of Mexico(a) | | | | | 3.06 | | | | | | 3.16 | | | | | | 2.62 | | | Worldwide gas sales | | | | | 89.17 | | | | | | 90.88 | | | | | | 88.93 | | | |
(a)
E&P sales include volumes marketed by the Exploration & Production segment in Europe (2.60, 2.75 and 2.32 BCM in 2014, 2015 and 2016, respectively) and in the Gulf of Mexico (0.46, 0.41 BCM and 0.30 in 2014, 2015 and 2016, respectively).
| | | | | Natural gas sales by market | | | 2014 | | | 2015 | | | 2016 | | | | | (BCM) | | 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 | | | United Kingdom/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 | | | |
European markets
A review of Eni’s presence in the key European markets is presented below.
| | | | | Natural gas sales by entities | | | 2019 | | | 2018 | | | 2017 | | | | | (BCM) | | Total sales of subsidiaries | | | | | 70.39 | | | | | | 73.70 | | | | | | 77.52 | | | Italy (including own consumption) | | | | | 37.85 | | | | | | 39.03 | | | | | | 37.43 | | | Rest of Europe | | | | | 25.56 | | | | | | 27.58 | | | | | | 36.10 | | | Outside Europe | | | | | 6.98 | | | | | | 7.09 | | | | | | 3.99 | | | Total sales of Eni’s affiliates (Eni’s share) | | | | | 2.68 | | | | | | 3.01 | | | | | | 3.31 | | | Italy | | | | | | | | | | | | | | | | | | | | Rest of Europe | | | | | 1.51 | | | | | | 1.84 | | | | | | 2.13 | | | Outside Europe | | | | | 1.17 | | | | | | 1.17 | | | | | | 1.18 | | | Worldwide gas sales | | | | | 73.07 | | | | | | 76.71 | | | | | | 80.83 | | | |
| | | | | Natural gas sales by market | | | 2019 | | | 2018 | | | 2017 | | | | | (BCM) | | ITALY | | | | | 37.85 | | | | | | 39.03 | | | | | | 37.43 | | | Wholesalers | | | | | 7.79 | | | | | | 9.15 | | | | | | 8.36 | | | Italian gas exchange and spot markets | | | | | 12.13 | | | | | | 12.49 | | | | | | 10.81 | | | Industries | | | | | 4.92 | | | | | | 4.79 | | | | | | 4.42 | | | Medium-sized enterprises and services | | | | | 0.87 | | | | | | 0.79 | | | | | | 0.93 | | | Power generation | | | | | 1.90 | | | | | | 1.50 | | | | | | 2.22 | | | Residential | | | | | 3.99 | | | | | | 4.20 | | | | | | 4.51 | | | Own consumption | | | | | 6.25 | | | | | | 6.11 | | | | | | 6.18 | | | INTERNATIONAL SALES | | | | | 35.22 | | | | | | 37.68 | | | | | | 43.40 | | | Rest of Europe | | | | | 27.07 | | | | | | 29.42 | | | | | | 38.23 | | | Importers in Italy | | | | | 4.37 | | | | | | 3.42 | | | | | | 3.89 | | | European markets | | | | | 22.70 | | | | | | 26.00 | | | | | | 34.34 | | | Iberian Peninsula | | | | | 4.22 | | | | | | 4.65 | | | | | | 5.06 | | | Germany/Austria | | | | | 2.10 | | | | | | 1.83 | | | | | | 6.95 | | | Benelux | | | | | 3.77 | | | | | | 5.29 | | | | | | 5.06 | | | United Kingdom/Northern Europe | | | | | 1.75 | | | | | | 2.22 | | | | | | 2.21 | | | Turkey | | | | | 5.56 | | | | | | 6.53 | | | | | | 8.03 | | | France | | | | | 4.48 | | | | | | 4.95 | | | | | | 6.38 | | | Other | | | | | 0.82 | | | | | | 0.53 | | | | | | 0.65 | | | Extra European markets | | | | | 8.15 | | | | | | 8.26 | | | | | | 5.17 | | | WORLDWIDE GAS SALES | | | | | 73.07 | | | | | | 76.71 | | | | | | 80.83 | | |
Benelux. Eni holds a leadership position in the Benelux countries (Belgium, the Netherlands and Luxembourg) granted by a direct presence, through the Belgium Gas & Power branch, and its significant exposure to spot markets in Western Europe. Furthermore Eni operates in the retail and middle market through its subsidiary. In 2016, sales in Benelux amounted to 7.03 BCM (7.94 BCM in 2015), down by 0.91 BCM, or 11.5%.
France. Eni sells natural gas to industrial clients and wholesalers, 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. In 2016, sales in France amounted to 7.42 BCM (7.11 BCM in 2015), an increase of 0.31 BCM, or 4.4%, from a year ago.
Germany-Austria. Eni operates in Germany-Austria through its direct commercial activities and through its subsidiaries. In 2016, total sales in Germany-Austria amounted to 7.81 BCM, an increase of 1.99 BCM, or 34.2%.
The LNG business Eni LNG business can count currently on a portfolio of contracted long-term supplies mainly from, Qatar, Nigeria, OmanIndonesia and Algeria.Oman. In the plan period, Eni intends to develop its LNG business leveraging on the integration with the E&P segment and the valorization of the equity gas. In 2017, the G&P LNG business will start marketing volumes of gas produced at the E&P large Jangkrik gas complex, off Indonesia. Final markets of that gas include the Chinese marketEurope, China, Pakistan and other areas.Japan. The business’s profitability will be also driven by enhancing the commercial presence in premium markets and continuing integration with trading activities. | | | | | LNG sales | | | 2014 | | | 2015 | | | 2016 | | | | | (BCM) | | 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 | | | - Point Fortin (Trinidad & Tobago) | | | | | 0.6 | | | | | | 0.7 | | | | | | 0.7 | | | - Bonny (Nigeria) | | | | | 2.8 | | | | | | 2.8 | | | | | | 2.6 | | | - Darwin (Australia) | | | | | 0.4 | | | | | | 0.5 | | | | | | 0.5 | | | | | | | | 13.3 | | | | | | 13.5 | | | | | | 12.4 | | | |
| | | | | LNG sales | | | 2019 | | | 2018 | | | 2017 | | | | | (BCM) | | Europe | | | | | 5.5 | | | | | | 4.7 | | | | | | 5.2 | | | Extra European markets | | | | | 4.6 | | | | | | 5.6 | | | | | | 3.1 | | | | | | | | 10.1 | | | | | | 10.3 | | | | | | 8.3 | | |
Electricity sales and power generation Electricity sales As part of its marketing activities in Italy, Eni engages in selling electricity on the Italian market principally on the open market, on the Italian Stock Exchange for electricity and at industrial sites. Supplies of electricity include both own production volumes through gas-fired, combined-cycle facilities and purchases on the open market. This activity has been developed in order to capture further value along the gas value chain leveraging on the Company’s large gas availability. In addition, with the aim of developing and retaining valuable customers in the residential space and small and middle to large industrial users,business located in urban area, the Company has been developingdeveloped a commercial offer that provides the combined supply of gas and power to the retail market in Italy and fuels.in France. In 2016,2019, power sales (37.05(39.49 TWh) were directed to the free market (74%(72%), the Italian Power Exchange (15%(18%), industrial sites (9%) and others (2%(1%). Compared to 2015,2018, electricity sales in the free market were up by 6.2%2.40 TWh or by 9.3%, due to higher volumes sold to wholesalers, and middle market and retail segments, partially offset by lower volumes tradedsold to small and medium size enterprises andthe large clients.customers.
| Power availability | | 2014 | | 2015 | | 2016 | | | Power availability | | | 2019 | | 2018 | | 2017 | | | | (TWh) | | | (TWh) | | Power generation sold | | | | 19.55 | | | | | 20.69 | | | | | 21.78 | | | | | | 21.66 | | | | | 21.62 | | | | | 22.42 | | | Trading of electricity (a) | | | | 14.03 | | | | | 14.19 | | | | | 15.27 | | | | | | 17.83 | | | | | 15.45 | | | | | 12.91 | | | | | | | 33.58 | | | | | 34.88 | | | | | 37.05 | | | | | | 39.49 | | | | | 37.07 | | | | | 35.33 | | | Power sales by market | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Free market (a) | | | | 24.86 | | | | | 25.90 | | | | | 27.49 | | | | | | 28.31 | | | | | 25.91 | | | | | 26.53 | | | Italian Exchange for electricity | | | | 4.71 | | | | | 5.09 | | | | | 5.64 | | | | | | 7.27 | | | | | 7.17 | | | | | 5.21 | | | Industrial plants | | | | 3.17 | | | | | 3.23 | | | | | 3.11 | | | | | | 3.38 | | | | | 3.49 | | | | | 3.01 | | | Other (a) | | | | 0.84 | | | | | 0.66 | | | | | 0.81 | | | | | | 0.53 | | | | | 0.50 | | | | | 0.58 | | | | | | | 33.58 | | | | | 34.88 | | | | | 37.05 | | | | | | 39.49 | | | | | 37.07 | | | | | 35.33 | | | | |
(a)
Include positive and negative imbalances (differences between power introduced in the grid and the one planned). Power generation Eni’s power generation sites are located in Ferrera Erbognone, Ravenna, Mantova, Brindisi, Ferrara and Bolgiano. In 2016,2019, power generation was 21.7821.66 TWh, up by 1.09 TWh, or 5.3% from 2015, mainly due to higher production at Brindisi, Ferrara, Ferrera Erbognone and Ravenna plants following increasing demand.substantially in line with 2018. As of December 31, 2016,2019, installed operational capacity was 4.7 GW, (4.9 GW as ofunchanged compared to December 31, 2015). 2018.
Electricity trading (17.83 TWh) reported an increase of 15.4% thanks to 15.27 TWh, due to higher purchases on the spot market (up 7.6%) reflecting the optimization of inflows and outflows of power. Site | | | Total installed capacity in 20162019 (GW) | | | Technology | | | Fuel | | Brindisi | | | | | 1.3 | | | | CCGT | | | gas | | Ferrera Erbognone | | | | | 1.0 | | | | CCGT | | | gas/syngas | | Livorno (a)
| | | | | - | | | | Power station | | | gas/fuel oil | | Mantova | | | | | 0.80.9 | | | | CCGT | | | gas | | Ravenna | | | | | 1.0 | | | | CCGT | | | gas | | Ferrara(b)(a) | | | | | 0.4 | | | | CCGT | | | gas | | Bolgiano | | | | | 0.1 | | | | Power station | | | gas | | | | | | | 4.7 | | | | | | | | |
(a)
Since March 1, 2016 Livorno was tranferred to R&M segment.
(b)
Eni’s share of capacity. | | | | | | | | Power generation | | | | | | 2014 | | | 2015 | | | 2016 | | Purchases | | | | | | | | | | | | | | | | | | | | | | | Natural gas | | | (mmCM) | | | | | 4,074 | | | | | | 4,270 | | | | | | 4,334 | | | Other fuels | | | (ktoe) | | | | | 338 | | | | | | 313 | | | | | | 360 | | | - of which steam cracking | | | | | | | | 104 | | | | | | 87 | | | | | | 105 | | | Production | | | | | | | | | | | | | | | | | | | | | | | Electricity | | | (TWh) | | | | | 19.55 | | | | | | 20.69 | | | | | | 21.78 | | | Steam | | | (ktonnes) | | | | | 9,010 | | | | | | 9,318 | | | | | | 7,974 | | | Installed generation capacity | | | (GW) | | | | | 4.9 | | | | | | 4.9 | | | | | | 4.7 | | |
| | | | | | | | Power generation | | | | | | 2019 | | | 2018 | | | 2017 | | Purchases | | | | | | | | | | | | | | | | | | | | | | | Natural gas | | | (mmCM) | | | | | 4,410 | | | | | | 4,300 | | | | | | 4,359 | | | Other fuels | | | (ktoe) | | | | | 276 | | | | | | 356 | | | | | | 392 | | | - of which steam cracking | | | | | | | | 91 | | | | | | 94 | | | | | | 104 | | | Production | | | | | | | | | | | | | | | | | | | | | | | Electricity | | | (TWh) | | | | | 21.66 | | | | | | 21.62 | | | | | | 22.42 | | | Steam | | | (ktonnes) | | | | | 7,646 | | | | | | 7,919 | | | | | | 7,551 | | | Installed generation capacity | | | (GW) | | | | | 4.7 | | | | | | 4.7 | | | | | | 4.7 | | |
International transport Eni has transport rights on a large European network of integrated infrastructures for transporting natural gas, which links key consumption markets with the main producing areas (Russia, Algeria,(Algeria, Libya and the North Sea). Eni payshas contracted the transport capacity under ship-or-pay contracts, which are similar to take-or-pay contracts. Eni also retains ownership interests in certain pipeline companies, which run and operate the facility by selling transportation capacity tounder long-term ship-or-pay contracts to both shareholders and third party shippers. The main assets of Eni’s transport activities are provided in the table below. International Transport infrastructure Route | | | Lines | | | Total length | | | Diameter | | | Transport capacity(1) | | | Transit capacity(2) | | | Compression stations | | | | | (units) | | | (km) | | | (inch) | | | (BCM/y) | | | (BCM/y) | | | (No.) | | TTPC (Oued Saf Saf-Cap Bon) | | | 2 lines of km 370 | | | | | 740 | | | | | | 48 | | | | | | 34.3 | | | | | | 33.2 | | | | | | 5 | | | TMPC (Cap Bon-Mazara del Vallo) | | | 5 lines of 155 | | | | | 775 | | | | | | 20/26 | | | | | | 33.5 | | | | | | 33.5 | | | | | | | | | GreenStream (Mellitah-Gela) | | | 1 line of km 520 | | | | | 520 | | | | | | 32 | | | | | | 8.0 | | | | | | 8.0 | | | | | | 1 | | | Blue Stream (Beregovaya-Samsun) | | | 2 lines of km 387 | | | | | 774 | | | | | | 24 | | | | | | 16.0 | | | | | | 16.0 | | | | | | 1 | | |
(1)
Includes both transit capacity and volumes of natural gas destined to local markets and withdrawn at various points along the pipeline.
(2)
The maximum volume of natural gas which is input at various entry points along the pipeline and transported to the next pipeline.
| | | Lines | | | Total length | | | Diameter | | | Transport capacity | | | Compression stations | | | | | (units) | | | (km) | | | (inch) | | | (BCM/y) | | | (No.) | | TTPC (Oued Saf Saf-Cap Bon) | | | 2 lines of km 370 | | | | | 740 | | | | | | 48 | | | | | | 34.3 | | | | | | 5 | | | TMPC (Cap Bon-Mazara del Vallo) | | | 5 lines of 155 | | | | | 775 | | | | | | 20/26 | | | | | | 33.5 | | | | | | | | | GreenStream (Mellitah-Gela) | | | 1 line of km 520 | | | | | 520 | | | | | | 32 | | | | | | 8.0 | | | | | | 1 | | | Blue Stream (Beregovaya-Samsun) | | | 2 lines of km 387 | | | | | 774 | | | | | | 24 | | | | | | 16.0 | | | | | | 1 | | |
International transport activities The TTPC pipeline, 740-kilometer long, is made up of two lines that are each 370-kilometer370-kilometers 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 Mediterranean coast 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-kilometer155-kilometers 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 GreenStream pipeline, jointly-owned with the Libyan National Oil Co, started operations in October 2004 for the import of Libyan gas produced at the Eni operated fields of Bahr Essalam and Wafa. It is 520-kilometer520-kilometers 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 (water depth greater 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. Capital expenditures See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”. Refining & Marketing & Chemicals Refining & Marketing Eni’s Refining & Marketing business engages in the supply and refining of crude oil as well asto produce a large slate of fuels and other refined products and in the marketing of refined productsfuels primarily in Europe.Italy and in selected European markets. In Italy, Eni is the largest refining and marketing operator in terms of capacity and market share. The Company operations are fully integrated through refining, supply, logistics and marketing in order to maximize cost efficiencies and operational effectiveness. The Company also engages in the production of bio-fuels at the Venice and Gela refineries, where certain renewable feedstock are processed (palm oil). 67The business results depend heavily on trends in refining margins, i.e. the spread between the cost of the oil feedstock and the price of the refined products obtained from the crude processing.
In 20162019 refining margins in the Mediterranean area decreasedincreased by approximately 50%16% y-o-y due to a high level of inventories of gasoline and gasoil because of a high utilization rate of refineries as well as availability4.3 $/BBL driven by the higher relative prices of products coming fromcompared to the Middle East. Looking forward, managementcost of the petroleum feedstock. Notwithstanding this trend, the refining business was negatively affected by the appreciation of crudes against the Brent and a less favourable products scenario. Management believes that refining margins will remain under pressure in the mediumshort-to-medium term will remain stable ondue to continuing competition. In the 2016 level; in the longer term, margins will improvemedium-term, spreads between products and crude may find a support as a resultconsequence of the IMO 2020 IMO legislation,regulations, which will lead, among other solutions, to the substitution of bunker fuel oil with cleaner fuels (gasoil, ULSFO and LNG). that could be short in the first period of law application, with benefit for high conversion refineries. In marketing, competition remains tough,the longer term, refinery margins will normalize, as a result of supply-demand re-alignment thanks investments by both refining companies (fuel oil destruction units) as well as ship-owners (scrubbers, retrofitting, new ships/engines). The business results of operations in particular from unbranded2019 and large retailers.its strategy are described in “Item 5 �� Group results of operations” and “Item 5 – Management’s expectations of operations”. Supply In 2016,2019, a total of 23.3523.43 mmtonnes of crude were purchased (compared with 24.8022.62 mmtonnes in 2015)2018), of which 3.434.24 mmtonnes by equity crude oil. The breakdown by geographic area was the following: approximately 43%24% of purchased crude came from Russian Commonwealth, 30% from the Middle East, 12%23% from Russia, 17% from Central Asia, 13% from Italy, 11%13% from North Africa, 1%2% from West Africa, 1%2% from North Sea and 2%6% from other areas. Refining In 2016,2019, Eni refinery capacity (balanced with conversion capacity) was approximately 27.436.6 mmtonnes (equal to 548732 KBBL/d), with a conversion index of 50%56%. Conversion index is a measure of refinery complexity. The higher the index, the wider the range of crude qualities and feedstock that a refinery is able
to process thus enabling refineries to benefit from the cost economies arising from the discount – versus the benchmark – at which certain qualities of crude (particularly the heavy ones) may be supplied. Eni’s 100% owned refineries have a balanced capacity of 19.4 mmtonnes (equal to 388 KBBL/d), with a 49%55% conversion index. In 2016,2019, Eni’s refineries throughputs in Italy and outside Italy were 24.5222.74 mmtonnes. The refinery utilization rate, ratio between throughputs and refinery capacity, is 88%. Refining system in 20162019 | | Ownership (%) | | Balanced refining capacity (Eni’s share) (KBBL/d) | | Utilization rate (Eni’s share) (KBBL/d) | | Conversion index(1) (%) | | Fluid catalytic cracking (FCC)(2) (KBBL/d) | | Residue conversion(2) (KBBL/d) | | Hydro- cracking(2) (KBBL/d) | | Visbreaking/ Thermal Cracking(2) (KBBL/d) | | | Ownership (%) | | Balanced refining capacity (Eni’s share) (KBBL/d) | | Utilization rate (Eni’s share)(1) (%) | | Conversion index(2) (%) | | Wholly-owned refineries | | | | | | | | | 388 | | | | | 90 | | | | | 49 | | | | | 34 | | | | | 16 | | | | | 90 | | | | | 29 | | | | | | | | | | | 388 | | | | | 89 | | | | | 55 | | | Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sannazzaro | | | | 100 | | | | | 200 | | | | | 98 | | | | | 71 | | | | | 34 | | | | | 16 | | | | | 51 | | | | | 29 | | | | | | 100 | | | | | 200 | | | | | 85 | | | | | 74 | | | Taranto | | | | 100 | | | | | 104 | | | | | 73 | | | | | 38 | | | | | | | | | | 0 | | | | | 39 | | | | | 0 | | | | | | 100 | | | | | 104 | | | | | 89 | | | | | 56 | | | Livorno | | | | 100 | | | | | 84 | | | | | 91 | | | | | 11 | | | | | | | 100 | | | | | 84 | | | | | 98 | | | | | 11 | | | Partially owned refineries | | | | | | | | | 160 | | | | | 93 | | | | | 52 | | | | | 143 | | | | | 25 | | | | | 75 | | | | | 27 | | | | | | | | | | | 344 | | | | | 84 | | | | | 57 | | | Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Milazzo | | | | 50 | | | | | 100 | | | | | 90 | | | | | 60 | | | | | 45 | | | | | 25 | | | | | 32 | | | | | | | 50 | | | | | 100 | | | | | 94 | | | | | 60 | | | Germany | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Vohburg/Neustadt (Bayernoil) | | | | 20 | | | | | 41 | | | | | 96 | | | | | 36 | | | | | 49 | | | | | | | 20 | | | | | 41 | | | | | 60 | | | | | 36 | | | Schwedt | | | | 8.33 | | | | | 19 | | | | | 100 | | | | | 42 | | | | | 49 | | | | | | | | | | 43 | | | | | 27 | | | | | | 8.33 | | | | | 19 | | | | | 87 | | | | | 42 | | | UAE | | | | | | | | | | | | | | | | | | | | | | | ADNOC Refining | | | | | 20 | | | | | 184 | | | | | | | | | | 63 | | | Total | | | | | | | | | 548 | | | | | 90 | | | | | 50 | | | | | 177 | | | | | 41 | | | | | 165 | | | | | 56 | | | | | | | | | | | 732 | | | | | 88 | | | | | 56 | | | | |
(1)
Since the participation interest in ADNOC Refining has been acquired effective August 1, 2019, the utilization rate has been calculated only for refineries owned or participated for the full year. (2)
Conversion index: catalytic cracking equivalent capacity/topping capacity (%wt).
(2)
Conversion unit capacities are 100%.
Italy Eni’s refining system in Italy is composed of the wholly-owned refineries of Sannazzaro, Livorno and Taranto, as well as its 50% stake in the Milazzo refinery in Sicily. Eni’s refineries operate to maximize asset value according to market conditions and the integration with marketing activities. The Sannazzaro refinery has a balanced capacity of 200 KBBL/d and a conversion index of 71%74%. Located in the Po Valley, in the center of the Northern 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%. The Taranto refinery has a balanced capacity of 104 KBBL/d and a conversion index of 38%56%. Taranto has a strong market position due to the fact that is the only refinery in Southern Continental Italy, and is upstream integrated with the Val d’Agri fields in Basilicata (Eni 60.77%61%) through a pipeline. The main equipments are a topping-vacuum unit, a hydrocracking, a platforming unit and two desulphurization units. The Livorno refinery, with a balanced refining capacity of 84 KBBL/d and a conversion index of 11%, is dedicated to the production of lubricants and specialties. The refinery is connected by pipeline to a depot in Florence (Calenzano). The refinery has a topping-vacuum unit, a platforming unit, two desulphurization units and a dearomatizationde-aromatization unit (DEA) – for the production of fuels; a propane de-asphalting (PDA), aromatics extraction and dewaxingde-waxing units, for the production of base oils; a blending and filling plant – for the production of finished lubricants.
The Milazzo refinery (Eni 50%) has a balanced capacity of 200 KBBL/d and a conversion index of 60%. Located in Sicily, Milazzo is mainly dedicated to export and to the supply of Italian coastal depots. The main equipments in the refinery are: two primary distillation columns and a vacuum unit, two desulphurization units, a fluid catalytic cracker (FCC), one hydrocracker (HdC), one reforming unit and one LC fining (ebullated bed residue conversion). Outside Italy In Germany, Eni owns an interest of 8.33% stake in the Schwedt refinery (PCK) and an interest of 20% in the Vohburg and Neustadt refineries (Bayernoil). Eni’s refining capacity in Germany is 60 KBBL/d to supply Eni’s distribution network in the country. GreenIn the UAE, Eni and ADNOC signed a Share Purchase Agreement to enable Eni to acquire from ADNOC a 20% equity interest in ADNOC Refining. ADNOC Refining operates two refineries in Ruwais (Ruwais East and Ruwais West) and another in Abu Dhabi (Abu Dhabi Refinery), with a total refining capacity of 922 KBBL/d.
| | | Ownership share (%) | | | Capacity (2016) (ktonnes/y) | | | Capacity (at regime) (ktonnes/y) | | | Throughput (2016) (ktonnes/y) | | Wholly-owned | | | | | | Venezia | | | | | 100 | | | | | | 360 | | | | | | 560 | | | | | | 212 | | | Gela | | | | | 100 | | | | | | | | | | | | 750 | | | | | | | | | Total green refineries | | | | | | | | | | | 360 | | | | | | 1,310 | | | | | | 212 | | | |
Green RefiningBiorefineries
| | | Ownership share (%) | | | Capacity (2019)(a) (ktonnes/y) | | | Capacity (at regime) (ktonnes/y) | | | Throughput (2019) (ktonnes/y) | | Wholly-owned | | | | | | | | | | | | | | | | | | | | | | | | | | Venezia | | | | | 100 | | | | | | 360 | | | | | | 560 | | | | | | 217 | | | Gela | | | | | 100 | | | | | | 300 | | | | | | 750 | | | | | | 94 | | | Total biorefineries | | | | | | | | | | | 660 | | | | | | 1,310 | | | | | | 311 | | |
(a)
Includes the pro-rata of installed capacity of Gela’s biorefinery (720,000 tonnes/y) started in August 2019. Biorefining Eni fully owns the green refinery oftwo biorefineries in Italy, specifically in Venice and the site of Gela, where another green refinery will be realized.Gela. The Venice green refinery entered intobiorefinery started production in June 2014, replacing the old oil-based refinery that was shut down. The refinery, with a production capacity of 360 ktonnes/y. The refinery exploitsy, leverages on the EcofiningTMproprietary EcofiningTM technology to transform vegetable oil in hydrogenated bio-fuels. A second phase of development is underway. At regime,full capacity, the refinery production will satisfy approximately half of Eni bio-fuels needs required for being compliant with the EU environmental normative aimed at reducing the CO2 emission.CO2 emissions. The Gela refinery is located onin the Southern coast of Sicily. The refinery was shut-down in March 2014 and in November 2014, Eni signed a Memorandum of Understanding for the reconversion of the plant into a biorefinery. In 2017 the project obtained the environmental impact assessment and authorization (VIA/AIA) by the Italian Ministry of the Environment and the Ministry of Cultural Heritage. In August 2019, Eni started-up the biorefinery with an installed capacity of 720,000 tonnes/y and equipped with the EcofiningTM technology, developed and licensed by Eni, to convert into biodiesel, vegetable oil and second generation raw materials, such as used cooking oil and animal fat. The plant properties allow the production of biodiesel in compliance with the last regulatory constraints in terms of reduction of GHG emissions throughout the whole production chain, deploying the full capacity in process second-generation feedstock.
into a bio-refinery with the Ministry for Economic Development and Local Authorities. In 2016 Eni’s activities continued in line with the commitments foreseen in the Memorandum of Understanding. In April 2016 Eni began the construction activities at the Green Refinery project. 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 highly 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:
•
the launch of new hydrocarbon exploration and production activities in the Region of Sicily and the offshore area;
•
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;
•
the set-up of a competence center focused on safety issues;
•
a plan for the environmental remediation of plants and areas that will gradually lose their industrial destination.
The table below sets forth Eni’s sales of refined products availability figuresby distribution channel for the periods indicated. | Availability of refined products | | 2014 | | 2015 | | 2016 | | | Availability of refined products | | | | | | | 2019 | | 2018 | | 2017 | | | | (mmtonnes) | | | (mmtonnes) | | ITALY | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Refinery throughputs | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | At wholly-owned refineries | | | | 16.24 | | | | | 18.37 | | | | | 17.37 | | | | | | 17.26 | | | | | 16.78 | | | | | 16.03 | | | Less input on account of third parties | | | | (0.58) | | | | | (0.38) | | | | | (0.27) | | | | | | (1.25) | | | | | (1.03) | | | | | (0.34) | | | At affiliated refineries | | | | 4.26 | | | | | 4.73 | | | | | 4.51 | | | | | | 4.69 | | | | | 4.93 | | | | | 5.46 | | | Refinery throughputs on own account | | | | 19.92 | | | | | 22.72 | | | | | 21.61 | | | | | | 20.70 | | | | | 20.68 | | | | | 21.15 | | | Consumption and losses | | | | (1.33) | | | | | (1.52) | | | | | (1.53) | | | | | | (1.38) | | | | | (1.38) | | | | | (1.36) | | | Products available for sale | | | | 18.59 | | | | | 21.20 | | | | | 20.08 | | | | | | 19.32 | | | | | 19.30 | | | | | 19.79 | | | Purchases of refined products and change in inventories | | | | 7.19 | | | | | 6.22 | | | | | 6.28 | | | | | | 7.27 | | | | | 7.50 | | | | | 6.74 | | | Products transferred to operations outside Italy | | | | (0.72) | | | | | (0.48) | | | | | (0.39) | | | | | | (0.68) | | | | | (0.54) | | | | | (0.46) | | | Consumption for power generation | | | | (0.57) | | | | | (0.41) | | | | | (0.37) | | | | | | (0.35) | | | | | (0.35) | | | | | (0.34) | | | Sales of products | | | | 24.49 | | | | | 26.53 | | | | | 25.60 | | | | | | 25.56 | | | | | 25.91 | | | | | 25.73 | | | Biorefinery throughputs | | | | | 0.31 | | | | | 0.25 | | | | | 0.24 | | | OUTSIDE ITALY | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Refinery throughputs on own account | | | | 5.11 | | | | | 3.69 | | | | | 2.91 | | | | | | 2.04 | | | | | 2.55 | | | | | 2.87 | | | Consumption and losses | | | | (0.21) | | | | | (0.23) | | | | | (0.22) | | | | | | (0.18) | | | | | (0.20) | | | | | (0.22) | | | Products available for sale | | | | 4.90 | | | | | 3.46 | | | | | 2.69 | | | | | | 1.86 | | | | | 2.35 | | | | | 2.65 | | | Purchases of finished products and change in inventories | | | | 4.48 | | | | | 4.77 | | | | | 4.72 | | | | | | 4.17 | | | | | 4.12 | | | | | 4.36 | | | Products transferred from Italian operations | | | | 0.72 | | | | | 0.48 | | | | | 0.40 | | | | | | 0.68 | | | | | 0.54 | | | | | 0.46 | | | Sales of products | | | | 10.10 | | | | | 8.71 | | | | | 7.81 | | | | | | 6.71 | | | | | 7.01 | | | | | 7.47 | | | Refinery throughputs on own account | | | | 25.03 | | | | | 26.41 | | | | | 24.52 | | | | | | 22.74 | | | | | 23.23 | | | | | 24.02 | | | of which: refinery throughputs of equity crude on own account | | | | 5.81 | | | | | 5.04 | | | | | 3.43 | | | | | | 4.24 | | | | | 4.14 | | | | | 3.51 | | | Total sales of refined products | | | | 34.59 | | | | | 35.24 | | | | | 33.41 | | | | | | 32.27 | | | | | 32.92 | | | | | 33.20 | | | Crude oil sales | | | | 0.33 | | | | | 0.27 | | | | | 0.20 | | | | | | 0.44 | | | | | 0.28 | | | | | 0.86 | | | TOTAL SALES | | | | 34.92 | | | | | 35.51 | | | | | 33.61 | | | | | | 32.71 | | | | | 33.20 | | | | | 34.06 | | | | |
In 2016,2019, Eni’s refining throughputs on own account in Europe were 24.5222.74 mmtonnes, downslightly decreased by 7.2 %2.1% from 20152018, due toto: the lower availability of domestic crude oil driven bythroughputs at the shutdownBayernoil refinery, as a result of the Val d’Agri fieldunavailability of the Vohburg facility in the early nine months of the year following the event occurred in September 2018, the adverse climatic events at the Taranto plant during the period of April - August 2016,Milazzo refinery, as well as other planned maintenance turnarounds (Livorno and Milazzo),the participated PCK refinery, affected by the Druzhba pipeline contamination. These negatives were partially offset by higher volumes processed by the Taranto refinery following lower maintenance standstills. In Italy, the refinery throughputs (20.70 mmtonnes) were in line with 2018; the lower volumes processed at Sannazzaro despiterefineries affected by higher maintenance standstills, logistic issues due to adverse climatic events and the incident occurred in December 2016. On a homogeneous basis, when excludingupset at the impact ofMilazzo refinery, as well as the disposal of CRClower throughputs at the Livorno refinery in Czech Republic finalizedto counteract the scenario, were offset by higher volumes processed at the Taranto refinery leveraging on April 30, 2015, refining throughputs reported a decrease of 4.5% compared to the 2015.fewer shutdowns.
Outside Italy, Eni’s refining throughputs on own account were 2.912.04 mmtonnes, down by 0.78 mmtonnesapproximately 510 ktonnes or 21.1% from previous year, mainly20% due to the above-mentioned divestment inabove mentioned downtime of the Czech Republic finalized in the second quarter of 2015. Bayernoil refinery. Total throughputs in wholly-owned refineries were 17.3717.26 mmtonnes, downup by 1 mmtonne,0.48 mmtonnes or 5.4%2.9% compared with 2015, determining a2018. The refinery utilization rate, (ratioratio between throughputs and balanced capacity) of 89.5%refinery capacity, is 88%. Approximately 14.8%18.9% of processed crude was equity, downsupplied by approximately 6 percentage pointsEni’s Exploration & Production segment, increasing by 18.3% from 2015 (20.4%).2018. The volumes of biofuels produced from vegetable oil increased by 22.9% compared to 2018, driven by the start-up of the Gela biorefinery in August 2019, where full production ramp-up is underway, while the Venice biorefinery has been hit by unplanned downtime. 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 oil66
Oil and refined products pipelines. Eni logistic model is organized in three hubs (North, Central and South 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 other Italian operators to optimize its logistic footprint and increase efficiency. Other depots are operated by seven different joint ventures (Sigemi, Petrolig, Petroven, Petra, Seram, Disma, Toscopetrol). Since the beginning of 2017 Petrolig joint venture ends. Eni transports oil and refined products:transported: (i) by sea through spot and long-term contracts of tanker ships; and (ii) inland through a proprietary pipeline and depots network directly operated. In particular, Eni owns and operates an integrated infrastructure consisting of 16 directly managed depots and a network of oil and refined products pipelines extending approximately 1,4621.154 kilometers. Eni logistic model is organized in four hubs (Northern depots, Central depots, Southern depots and Pipeline) and one subsidiary (Petroven), 100% owned since December 2019. They manage the product flows in order to guarantee high safety, asset integrity and technical standards, as well as cost effectiveness and constant products availability along the country. Eni is also part of 5 different logistic joint ventures (Sigemi, Seram, Disma, Seapad, Toscopetrol), together with other Italian operators, that operate other localized depots and pipelines. Secondary distribution to retail and wholesale markets is outsourced to independent tanker carriers.trucks, selected as market leaders. Marketing Eni markets a wide range of refined petroleum products, primarily in Italy, through a widespread operated network of service stations, franchises and other distribution systems. The table below sets forth Eni’s sales of refined products by distribution channel for the periods indicated. | Oil products sales in Italy and outside Italy | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | | | (mmtonnes) | | | (mmtonnes) | | Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Retail | | | | 6.14 | | | | | 5.96 | | | | | 5.93 | | | | | | 5.81 | | | | | 5.91 | | | | | 6.01 | | | Wholesale | | | | 7.57 | | | | | 7.84 | | | | | 8.16 | | | | | | 7.68 | | | | | 7.54 | | | | | 7.64 | | | | | | | 13.71 | | | | | 13.8 | | | | | 14.09 | | | | | | 13.49 | | | | | 13.45 | | | | | 13.65 | | | Petrochemicals | | | | 0.89 | | | | | 1.17 | | | | | 1.02 | | | | | | 0.83 | | | | | 0.96 | | | | | 0.86 | | | Other sales | | | | 9.89 | | | | | 11.56 | | | | | 10.49 | | | | | | 11.24 | | | | | 11.5 | | | | | 11.22 | | | Total | | | | 24.49 | | | | | 26.53 | | | | | 25.6 | | | | | | 25.56 | | | | | 25.91 | | | | | 25.73 | | | Outside Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Retail | | | | 3.07 | | | | | 2.93 | | | | | 2.66 | | | | | | 2.44 | | | | | 2.48 | | | | | 2.53 | | | Wholesale | | | | 5.03 | | | | | 4.25 | | | | | 3.61 | | | | | | 3.11 | | | | | 3.29 | | | | | 3.48 | | | | | | | 8.10 | | | | | 7.18 | | | | | 6.27 | | | | | | 5.55 | | | | | 5.77 | | | | | 6.01 | | | Other sales | | | | 2.00 | | | | | 1.53 | | | | | 1.54 | | | | | | 1.16 | | | | | 1.24 | | | | | 1.46 | | | Total | | | | | 10.1 | | | | | 8.71 | | | | | 7.81 | | | | | | 6.71 | | | | | 7.01 | | | | | 7.47 | | | TOTAL SALES | | | | | 34.59 | | | | | 35.24 | ��� | | | | 33.41 | | | | | | 32.27 | | | | | 32.92 | | | | | 33.20 | | |
In 2016,2019, retail sales volumes of refined products (33.41(32.27 mmtonnes) were down by 1.830.65 mmtonnes or by 5.2%2% from 2015,2018, mainly due to the assets disposaldecrease of sales to oil companies and petrochemical industry in Italy and lower volumes marketed in the Czech Republic and Slovakia finalized in July 2015 as well as in Slovenia and Hungarywholesalers segment in the second halfrest of 2016.Europe. Retail sales in Italy In 2019, retail sales in Italy were 5.81 mmtonnes, with a decrease compared to 2018 (about 100 ktonnes from 2018 or down by 1.7%). Retail sales in the premium segment increased significantly. Average gasoline and gasoil throughput (1,586 kliters) was substantially in line with 2018. Eni’s retail market share of 2019 was 23.7%, slightly down from 2018 (24%). As of December 31, 2019, Eni’s retail network in Italy consisted of 4,184 service stations, lower by 39 units from December 31, 2018 (4,223 service stations), resulting from the negative balance of acquisitions/releases of lease concessions (34 units), closure of low throughput stations (6 units), partly offset by the net increase of 1 motorway concession. Retail sales in the Rest of Europe Retail sales in the Rest of Europe were 2.44 mmtonnes, recording a slight reduction from 2018 (down by 1.6%) mainly due to lower volumes traded in Germany, following the production unavailability at the Bayernoil plant and in France.
Retail sales in Italy
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 of sales in Eni highway segment, partially offset by an increase in owned stations. Average gasoline and gasoil throughput (1.551 kliters) decreased by approximately 20 kliters from 2015. Eni’s retail market share in 2016 was 24.3%, down by 0.2 percentage points from 2015 (24.5%).
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).
Retail sales in the rest of Europe
Eni’s strategy in the rest of Europe is focused on selectively growing its presence, particularly in Germany and Austria leveraging on the synergies ensured by the proximity of these markets to Eni’s production and logistic facilities.
In 2016, retail sales of refined products in the rest of Europe (2.66 mmtonnes), recorded a reduction from 2015 (down by 9.2%). This result reflected mainly the assets disposal 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. On a homogeneous basis, when excluding the impact of the assets disposal in Eastern Europe, sales increased by 1%.
At December 31, 2016,2019, Eni’s retail network in the Rest of Europe consisted of 1,2261,227 units, decreasingincreasing by 2002 units from December 31, 2015, due to the service stations disposal above mentioned.2018, mainly in Germany. Average throughput (2,340(2,356 kliters) increaseddecreased by 6835 kliters compared to 2015 (2,2722018 (2,391 kliters). Other businesses Wholesale Eni is strongly present in wholesale market in Italy, including sales of diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and sales of fuel oil. Major customers are resellers, agricultural users, manufacturing industries, public utilities and transports, as well as final users (transporters, condominiums, farmers, fishers, etc.). Eni provides its customers with its expertise in the area of fuels with a wide range of products that cover all market requirements. Customer care and product distribution isare supported by a widespread commercial and logistical organization presence throughout Italy and is articulated in local marketing offices and a network of agents and concessionaires. In 2016,2019, sales volumes on wholesale markets in Italy (8.16(7.68 mmtonnes) increased by 0.32 mmtonnes or 4.1%1.9% from the previous year,2018, mainly due to higher volumes marketed of jet fuel, gasoil, bitumen and fuel oil partlygasoline offset by lower sales of bunkering.jet fuel and bunkers. Wholesale sales in the Rest of Europe were 3.182.63 mmtonnes, down by 17%6.7% from 20152018 due to lower sold volumes in Germany due to the above-mentioned asset disposals. On a homogeneous basis, sales are barely unchanged from 2015. unavailability of the Bayernoil refinery and France, partly offset by higher volumes in Switzerland, Spain and Austria. Supplies of feedstock to the petrochemical industry (1.02(0.83 mmtonnes) decreased by 12.8%13.5%. Other sales in Italy and outside Italy (12.03(12.40 mmtonnes) decreased by approximately 1.050.34 mmtonnes or 8%down by 2.7%, mainly due to lower sales volumes sold to other oil companies. LPG The marketing of LPG in Italy is supported by the refining production and a logistic network made up of fivefour bottling plants, 1 owned storage site and coastal storage sites located in Livorno, Naples and Ravenna. LPG is used as heating and automotive fuel. In 2016,2019, Eni share of LPG market in Italy was 17.5%16.95%.
Outside Italy, the main market of Eni is Ecuador, with a market share of 38%37.3%. Lubricants Eni operates sixfive (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, grease, 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 2016,2019, Eni’s share of lubricants market in Italy was 21%19.85%, in Europe 3% and on a worldwide base 0,6%1%. Eni operates in more than 80 countries by subsidiaries, licensees and distributors. Oxygenates Eni’s, through its subsidiary Ecofuel (100% Eni’s share), sells approximately 10.9 mmtonnes/y of oxygenates, mainly ethers (approximately 3% of world demand, used as a gasoline octane booster) and methanol (mainly for petrochemical use). About 80%70% of oxygenates are produced in Eni’s plants in Italy (Ravenna), Saudi Arabia (in joint venture with Sabic) and Venezuela (in joint venture with Pequiven) and the remaining 20%30% is purchased.
Chemicals Eni operates in the businesses of olefins and aromatics, basic and intermediate products, polystyrene, elastomers and polyethylene. Its major production siteshubs are located in Italy and Western Europe. These The business results of operations in 2019 and its strategy are predominantly oil-based businesses with a historydescribed in “Item 5 – Group results of lossesoperations” and poor growth prospects. In fact, we face structural headwinds in our legacy basic petrochemicals and plastics businesses due to the commoditized nature“Item 5 – Management’s expectations of our products, low entry barriers, lack of scale, exposure to the volatility in the costs of oil-based feedstock, cyclicality in demand, and strong competitive pressures from operators with lower cost structure especially from the Middle and Far East and other weaknesses. Eni’s profitability in the petrochemical businesses is particularly sensitive to movements in product margins that are mainly affected by changes in oil-based feedstock costs and the speed at which product prices adjust to higher oil prices. See “Item 3 – Risk factors”operations”. In 20162019 sales of chemical products amounted to 3,7594,285 ktonnes, decreased from 20152018 (down by 42653 ktonnes, or 1.1%13.2%) mainly in ethylene, olefins and derivatives. Average sale prices of the intermediates business decreased by 9.9% from 2018, with derivatives and olefins down by 10.6% and 10.2%, respectively. The polymers reported a decrease of 10.8% from 2018. Petrochemical production of 8,068 ktonnes decreased by 1.42 mmtonnes (down by 14.9%) mainly due to the stagnationlower production of demand in Europe. The declines were registered in polyethyleneintermediates business (down by 9.8%18.4%), in particular aromatics and styrene (down by 9.1%) followingolefins; the shutdown of Ragusa and Mantova, 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. Petrochemicalpolymers production of 5,6462,250 ktonnes decreased by 54 ktonnes (down4.4% with elastomers, polyethylene and styrenics down by 0.9%). Higher decreases occurred in polyethylene (down by 8.6%) due to a weak demand7.0%, 3.9% and in styrene (down by 7.2%) due to planned and unplanned Mantova standstills. Derivatives productions increased (up by 10.2%) as well as elastomers (up by 7.1%) due to the recovery in sales volumes from the lower levels registered in 2015. 3.8%, respectively.
The main decreases in production were registered at the RagusaPriolo site (down by 45%23.3%), due to a malfunctioningthe event occurred at the plant, as well as Ravennabeginning of 2019 with the ramp-up finalized between April and July, at the Porto Marghera (down by 21.9%) and Dunkerque (olefins), Ferrara (elastomers) and Mantova(down by 17.1%) sites (styrene) due to planned shutdowns ofunplanned shutdowns. Plants nominal capacity is in line with the plants.2018. The productions of Brindisi plant increased (up by 15.7%) as well as Grangemouth site (up by 20.7%), for the start-up of the new butadiene-based rubber production line. Nominal capacity of plants barely unchanged from the previous year, with an average plant utilization rate, calculated on nominal capacity of 71.4% reporting a slight decreasewas 66.8%, decreasing from 2015 (72.7%2018 (76.2%). following the aforementioned shutdowns.
The table below sets forth Eni’s main chemical products availability for the periods indicated. | | Year ended December 31, | | | Year ended December 31, | | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | | | (ktonnes) | | | (ktonnes) | | Intermediates | | | | 2,972 | | | | | 3,334 | | | | | 3,417 | | | | | | 5,818 | | | | | 7,130 | | | | | 6,595 | | | Polymers | | | | 2,311 | | | | | 2,366 | | | | | 2,229 | | | | | | 2,250 | | | | | 2,353 | | | | | 2,360 | | | Total production | | | | 5,283 | | | | | 5,700 | | | | | 5,646 | | | | | | 8,068 | | | | | 9,483 | | | | | 8,955 | | | Consumption and losses | | | | (2,292) | | | | | (1,908) | | | | | (2,410) | | | | | | (4,307) | | | | | (5,085) | | | | | (4,566) | | | Purchases and change in inventories | | | | 472 | | | | | 9 | | | | | 523 | | | | | | 524 | | | | | 540 | | | | | 257 | | | | | | | 3,463 | | | | | 3,801 | | | | | 3,759 | | | | | | 4,285 | | | | | 4,938 | | | | | 4,646 | | | | |
The table below sets forth Eni’s main petrochemical products revenues for the periods indicated. | | Year ended December 31, | | | Year ended December 31, | | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | | | (€ million) | | | (€ million) | | Intermediates | | | | 2,310 | | | | | 1,899 | | | | | 1,688 | | | | | | 1,791 | | | | | 2,401 | | | | | 1,988 | | | Polymers | | | | 2,800 | | | | | 2,690 | | | | | 2,380 | | | | | | 2,201 | | | | | 2,589 | | | | | 2,730 | | | Other revenues | | | | 174 | | | | | 127 | | | | | 128 | | | | | | 131 | | | | | 133 | | | | | 133 | | | Total revenues | | | | 5,284 | | | | | 4,716 | | | | | 4,196 | | | | | | 4,123 | | | | | 5,123 | | | | | 4,851 | | | | |
Intermediates Intermediates revenues (€1,6881,791 million) decreased by €211€610 million from 20152018 (down by 11.1%25.4%) reflecting both the lower commodity prices scenario that influencesinfluencing average intermediates prices.prices of main products and the lower product availability due to plant standstills. Sales increaseddecreased by 4.6%18.4%, in particular for ethylene business (up(down by 19.3%38.0%). Derivatives sales registered an increased (up, olefins (down by 14.8%21.9%) drivenand derivatives (down by 13.4%) following the combined effect of a higher demand and a higher availability of product. lower product availability. Average unit prices decreased by 11.1%9.9%, within particular olefins (down by 10.2%), aromatics price lowered(down by 7% (benzene),5.4%) and derivatives prices(down by 7.7% and olefins prices by 17.8% driven by the weakness of the market and overcapacity in Europe.10.6%).
Intermediates production (3,417(5,818 ktonnes) registered an increasea decrease of 2.5%18.4% from the last year due to increases2018. Decreases were registered in aromatics (up(down by 2.7%19.6%), olefins (down by 18.9%) and in derivatives (up(down by 10.2%). Olefins barely unchanged (up by 0.8%11.3%). Polymers Polymers revenues (€2,3802,201 million) decreased by €310€ 388 million or 11.5%15.0% from 20152018 due to average unit priceslower volumes sold (down by 5.5%) and sold volumes decrease (down by 6.7%4.6%), driven by continuing weakness of automotive sectored demand and low prices of Asian producers. These negatives were further exacerbated byas well as 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 shutdown. Polyethylene volumes (down by 9.8%) and average prices (down by 3.2%10.8%). The styrenics business registered the decrease of volumes sold (down by 4.3%) recorded a decrease.for lower product availability; decrease of sale prices (down by 14.7%). Polymers production (2,229 ktonnes) decreased by 5.8% from 2015. Styrene productionsPolyethylene volumes decreased (down by 7.2%5.0%) due to oversupply and mounting competitive pressure from cheaper products streams from the planned Mantova standstill withMiddle-East and the USA; decreasing of average prices (down by 7.7%).
In the elastomers business, a decrease of sold volumes (down by 4.9%) was attributable to NBR rubbers (down by 10.3%), thermoplastic rubbers (down by 14.8%) and BR (down by 3.7%); increasing of SBR rubbers (up by 1.7%) and lattices (up by 1.0%). Polymers productions (2,250 ktonnes) decreased from the 2018 due to the lower production of styrolelastomers (down by 6.4%7.0%), polyethylene (down by 3.9%) and compact polystyrenestyrenics (down by 11.2%) partly offset by higher productions of ABS/SAN (up by 9.9%3.8%). Polyethylene productions decreased (down by 8.6%) driven by scheduled standstills of Ragusa, Ferrara and Dunkerque partly offset by higher productions of HDPE (up by 9.4%). Elastomers productions increased (up by 7.1%), especially in BR segment (up by 15.2%), driven by higher volumes sold compared to 2015. Capital expenditures See “Item 5 – Liquidity and capital resources – Capital expenditures by segment”.
Corporate and Other activities These activities include the following businesses: •
the “Other activities” segment comprises results of operations of Eni’s subsidiary Eni Rewind (former Syndial SpA) which runs minor petrochemical activities and reclamation and decommissioning activities pertaining to certain businesses which Eni exited, divested or shut down in past years;years, as well as Eni New Energy SpA which engages in developing the business of renewable energy; and •
the “Corporate and financial companies” segment comprises results of operations of Eni’s headquarters and certain Eni subsidiaries engaged in treasury, finance and other general and business support services. Eni’s headquarters is a department of the parent company Eni SpA and performs Group strategic planning, human resources management, finance, administration, information technology, legal affairs, international affairs and corporate research and development functions. Through Eni’s subsidiaries Eni Finance International SA, Banque Eni SA, Eni International BV, Eni Finance USA Inc and Eni Insurance DAC, Eni carries out cash management activities, administrative services to its foreign subsidiaries, lending, factoring, leasing, financing Eni’s projects around the world and insurance activities, principally on an intercompany basis. EniServizi, Eni Corporate University, AGI and other minor subsidiaries are engaged in providing Group companies with diversified services (mainly services including training, business support, real estate and general purposes services to Group companies). Management does not consider Eni’s activities in these areas to be material to its overall operations. At the end of 2019, the Energy Solutions department of the Group managed by Eni New Energy, installed total capacity from renewables of 167 MW, of which 82 MW in Italy and around 86 MW abroad. By February 2020, the construction of Badamsha in Kazakhstan and Volpiano in Italy had been finalized, taking total capacity to over 190 MW. Including the Falck Renewables plants in the United States, for which a negotiation is underway, total installed capacity is around 250 MW. Following two competitive bids, rights for the construction of a 50 MW photovoltaic plant in the Southern Kazakhstan and permits to build a 48 MW wind farm in Badamsha, were awarded to the subsidiary ArmWind LLP in Kazakhstan.
Seasonality Eni’s results of operations reflect the seasonality in demand for natural gas and certain refined products used in residential space heating, the demand for which is typically highest in the first quarter of the year, which includes the coldest months and lowest in the third quarter, which includes the warmest months. Moreover, year-to-yearyear- to-year comparability of results of operations is affected by weather conditions affecting demand for gas and other refined products in residential space heating. In colder years, thatwhich are characterized by lower temperatures than historical average temperatures, demand for gas and products is typically higher than normal consumption patterns, and vice versa. Research and development Technology researchEni’s commitment and investment in Research and Development are divided into the following technology platforms, which reflect the strategic drivers of development (R&D) and continuous innovation are key factors in successfully implementing Eni’s business strategies and in supporting mid and long-term performances.of R&D projects:
The Company believes that the oil&gas industry will have to face several challenges:
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uncertainty about oil&gas prices and demand;
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limited access to new low-cost hydrocarbon resources, with increasing role of unexplored oil&gas basins;
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need of a more efficient exploitation of conventional fossil sources;
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strong request of stakeholders for aOperational Excellence: reduction of GHG emissions;costs and
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safety times of operations, as a crucial pointdeveloping key technologies for business success.
In order to address the above challenges, Eni will pursue the following technological targets in the next future:
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reducing operational risk and maximizing operational efficiency by development of new tools for prevention and response to blow outs (mechanical barriers and equipment for the capture of subsea oil eruption)access and development of tools for vessel maintenanceassets, ensuring the highest level of sustainability, safety and restoring clogged pipes;minimum environmental impact;
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strengthening technological leadershipCarbon Neutrality: reduce, capture, transform or store CO2, develop products with “energy saving” characteristics, promote natural gas as an energy source in exploration by continuouslythe transition to a low carbon energy mix, integrate renewable energies into the energy system and develop innovative energy technologies;
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Circular Economy: reduce the use of raw materials, including through recycling, transforming waste into value-added products, with a view to sustainable development based on the principles of the circular economy. Research and development is a key element in Eni’s transformation into an integrated energy company in a low-carbon future. The availability and development of proprietary tools;cutting-edge technological skills at the service of innovation and sustainability and the continuous commitment to multiply the areas of application of the energy solutions identified are the common denominator of our activities.
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maximizingResearch and Development becomes, therefore, the recovery factorlever to create value, with the aim of reservoirs aiming at innovative enhanced oil recovery techniques sustainable also in low oil price scenarios;
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focusing on conversion and processing of stranded gas resources andminimizing the time to market that from research leads to the development of proprietary technologies in the sector of renewable energies;
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further development of Eni’s Green Refinery processes with innovative solution for the conversion of conventional refineries into bio-refineries;
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formulations of innovative fuels, lubricants and bitumen that comply with European regulations and new motor specifications;
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development of new technologies for the separation, conversion, transportation and utilization of natural gas;
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commitment to transfer quickly the relevant results achieved by research and development to business units, also to the new appointed energy solution one; and
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development of innovative environmental technologies for in situ monitoring and remediation.
their implementation on an industrial scale.
In 2016,2019, Eni filed 5234 patent applications (33(43 in 2015)2018). In 2016,2019, Eni’s overall expenditure in R&D amounted to €161€194 million which were almost entirely expensed as incurred (€176197 million in 20152018 and €174€185 million in 2014)2017). Exploration & Production • Oxy-Combustion. Proprietary software for seismic signal processing, petroleum system modeling and flow assuranceAs part that confirms and strengthens Eni’s position at the top of the zero-flaring strategy, Eni is assessing through a pilot installation atindustry, both in terms of operating results and with significant savings on the New Oil Centercost of Gela, alicenses and code maintenance.
Drilling automation. Two new tools addressing lost/non productive time and based on big data technology for oxy-combustion, which allows to exploit low calorific tail gas by production of electricity with CO, NOX and hydrocarbons emissions essentially absent. • MAREnergy. Project aiming at the exploitation of renewable energy in the sea (from waves and wind)were developed since 2017 to support upstream activities through the development of hybrid solutions capable of minimizing the typical variability of renewableoperations. The first tool is e.NPT (Eni Non Productive Time) which analyzes and integrates multiple data sources in energy generation.
• CO2 -to-Oil. Project aiming to reduce Eni’s carbon footprint using a technology that captures CO2 to produce a third generation bio-fuel. The emerging technology is based on the cultivation of micro-algae inside bio-reactorsreal time in order to producepredict sticking events. The second tool is a bio-algal oil suitablenew solution enabling a near real time performance analysis to feed Eni’s Green Refineries. The technology pilot plant has being built in Ragusa with start-up scheduled for March 2017.identify Invisible Lost Times.
• Chemical EOR. In 2016, in Egypt three chemical EOR pilots (chemical and low salinity injection) were started in Belayim giant field. First results of the polymer injection in two producing wells confirmed the forecasted improved recovery allowing the booking of additional reserves.
• Drilling Safety Technologies. TechnologiesProject aiming: to reduce by two ordersa further order of magnitude the risk of blowout occurrence compared to the OGP reference. To achieve this goal, new technologies able to improve well integrity both during drilling and well productive life have beenare being developed. In 2016 the first test of a casing valve activated without control line and therefore suitable to be used in subsea wells, was performed; beginning of 2017 a first application in a well will be carried out.
Refining & Marketing
• Eni Green Diesel+.Subsea Hub Technology Solutions A new premium diesel containing 15% of Hydrotreated Vegetable Oil (HVO), produced in Venice bio-refinery: to develop, together with industry partners, technologies to significantly reduce subsea development CAPEX and OPEX by using Eni/UOP’s Ecofining™ process, was launched in January with sales increase by about 20%. In November the winter diesel (Eni Green Diesel + Alpino) was also launched.
• Energy Saving Lubricants. In collaboration with GE a new lubricant oil for gas turbines has been developed. Its use will allow Eni to save 790 MMscf of gasfull subsea architectures, very long step-outs and 44’000 tons of CO2 emissions per year.
Renewable Energy & Environment
• Concentrated Solar Power. Since some years, Eni is engaged in an R&D project for the development of innovative components and engineering solutions for Concentrated Solar Power (CSP) in order to reduce capital investment and operation costs for thermal energy production via solar. In partnership with Massachusetts Institute of Technology it has been developed an innovative, low cost parabolic solar collector, easy to manufacture and assembly.life-of-field robotics. The latter feature will allow the manufacture in the same countries where they will be installed, fostering local employment and economic development. In 2016 a full-scale prototype was built in Politecnico of Milan University.program starts from lessons learned from Eni’s most recent subsea
development projects. The objective is to increase the distance between new subsea production systems and existing floating production facilities, or connect those new subsea assets directly to shore. Cost effective and flexible extra-long subsea architectures prove to efficiently work on a wide range of applications and design basis parameters. Key enabling technologies under development are multicontrol communication, subsea power distribution, subsea boosting and thermal management. MarEnergy (Wave Energy): Eni launched in 2016 an R&D program called MarEnergy, aiming at developing, demonstrating and deploying wave energy renewable technologies in Oil & Gas offshore operations. In the MarEnergy program Eni is both validating innovative renewable marine energy technologies, and developing Wave Energy Converters (WEC), as this type of technology resulted according to an internal assessment as the most interesting for Oil & Gas applications. Since the end of November 2018 Eni has been successfully testing the PB3 wave energy converter developed by Ocean Power Technologies (OPT) in the Adriatic Sea (Italy) nearby a producing gas platform. A second line of activity of the MarEnergy R&D program is the development of an innovative WEC in partnership with Politecnico fo Turin University and spin-off Wave for Energy. On December 6, 2018 a 50 kW subscale prototype of an Inertial Sea Wave Energy Converter (ISWEC) was installed near Ravenna (Italy). Since February 22, 2019 a pilot test with the ISWEC integrated with the Photo Voltaic system already present on the platform has been going on. On April 19, 2019 Eni, Cassa Depositi e Prestiti, Fincantieri and Terna signed a non-binding agreement to develop and build wave power stations on an industrial scale in Italy, especially near the minor islands. Refining & Marketing and Chemicals Methanol based alternative fuels. A new gasoline formulation containing alternative fuels (15% methanol and 5% bioethanol comprising a proper additive package to protect the engine), labeled M15, has been developed and is currently undergoing extensive road tests on five Fiat 500 cars belonging to the car sharing Enjoy fleet in Milan. M15 can provide more than 3% CO2 tailpipe emissions reduction due to the lower H/C ration and higher octane number. i-Sigma Bio Tech lubricants. Eni R&D in collaboration with Versalis and Matrìca developed a new synthetic lubricant base stock of ester type, obtained from renewable sources. This synthetic product is featured with excellent properties in terms of oxidation stability, volatility and wear protection that are suitable for several applications in the industrial and automotive lubrication sectors. Bioester is a key component of a new SAE 10W-30 engine oil for heavy duty services (trucks, buses, and off-road vehicles) designed and tested by Eni to meet some important international technical specifications, and ready for the market under the brand name i-Sigma Bio Tech. Energy Saving Lubricants: In collaboration with BHGE, Eni has developed an innovative low viscosity oil for turbomachinery sector, Eni OTE GT 15, that showed outstanding energy saving characteristics by reducing friction losses up to 15%, decreasing the consumption of natural gas and decreasing CO2 emissions. Guayule. Project aiming at the production of natural latex, dry rubber and resins from Guayule (ongoing experimental cultivation in Basilicata and Sicily) with exploitation of all components with proprietary technologies and their development in the market allowing the use of whole value of the Guayule plant. An important agreement has been signed with one of the most important international player in the field of tire manufacturing for the joint development of a common technology platform for guayule production and applications. Bio-butadiene. A joint venture between Versalis and Genomatica has developed a process to produce 1,3 bio-butadiene from renewable sources via sugars production from biomasses, fermentation and subsequent chemical processes. Renewable Energy & Environment Concentrated Solar Power. The Eni R&D effort towards the definition and application of improved Concentrated Solar Power (CSP) solutions has led to proprietary technology assemblies with advantageous capital investment and operation costs. A long-term partnership with Massachusetts Institute of
Technology and the Politecnico of Milano (that has realized the first proprietary CSP prototype) has allowed the focusing of capabilities for this purpose. The deployment phase is ongoing in the South of Italy, with a pilot plant in Gela (Sicily) and a demo plant of 1MW thermal power. • Organic Photovoltaic. New solutions (active and buffer materials) for flexible solar cells have been developed and applied in an emerging field that relies on organic polymeric photovoltaic solutions. The developed technology solutions allow easy transportation and application wherever power is required and no grid infrastructure is available. Thanks to the light weight and the technical and operational simplicity some photovoltaic modules with inflatable support have been also developed and installed in demonstrative situations.
Energy storage. The storage of the electric energy produced from renewable sources is indeed a key issue for allowing the further development of this field. Accordingly, Eni is testing solutions for Redox Flow Batteries and for integrating these devices “conventional” electrical energy production devices such as gas turbines and diesel generators in demonstrative plants for off-grid applications. Targeting in these cases a relevant CO2 (higher that 75%) emission reduction. Phytoremediation. Field tests showed that selected Plant Growth-Promoting Rhizobacteria able to enhance the plants biomass, increasing the uptake of metallic soil contaminants. The usage of these bacteria has been experimented in field tests for promoting the biodegradation of hydrocarbons in polluted environments (Ravenna, Priolo and Mantova). Hydrocarbon recovery. Eni developed and applied a proprietary technology (e-hyrec®) allowing the remediation of aquifer environments through the recovery and separation of hydrocarbon contaminants. The full commercialization phase begun in the second quarter of 2018. Soil and Groundwater Bioremediation: Eni R&D has developed through laboratory, pilot and field scale tests, technologies and site-specific protocols (e-lamina®) for treating contaminated soils and groundwater utilizing biological, environmental-friendly and cost-effective means. The protocols involve: (i) sampling and site characterization, (ii) evaluation of the bio-degradation potential by micro/meso-cosm test studies, (iii) in situ pilot plant activities, (iv) design and application of full-scale bio-remediation treatments. Waste to Fuel. Eni is evaluatinghas developed a Waste-to-FuelWaste- to-Fuel process able to transform wet domestic waste into bio-oils suitablewith characteristics similar to feed Eni’s biorefineriesthat of a heavy oil of fossil origin, which can be used directly as a renewable component in marine fuels (bunker oil) or treated in the traditional refining processes to obtain second-generation biofuels.produce biofuels for automotive use. The pilot scale development phasetechnology consists of a heat treatment carried out directly on the wet biomass (typically containing 70 -80% by weight of water) which does not require strong dehydration pretreatment, and allows concentrating up to 75% of the technology has been completed. • Monitoring of Pollution and Remediation of Soils. Eni R&D has been active for yearsenergy in the developmentbio-oil from the total energy content of devices and protocols ablethe feedstock. In 2018 a pilot plant treating wet domestic waste up to characterize polluted sites and monitor their remediation. Eni in collaboration with Massachusetts Institute of Technology, Consiglio Nazionale delle Ricerche, University of Piemonte Orientale, University of Rome “Tor Vergata” and Syndial, has developed and validated some original passive biomimetic samplers to determine700 kg/day was started at the available fraction of organic contaminants. The devices consist of low-density polyethylene films. In 2016 the application protocol of those devices was validated as official method of analysis by the Italian institute for the research on water (CNR-IRSA).Gela refinery.
Energy Transition In 2016 Eni launched the “Energy Transition” R&D program with the aim of developing new technologies to promote the widespread use of natural gas, making easier its production and transport, widening its uses and to decarbonizefavoring the decarbonization of the whole value chain. In particular, the research deals with three areas of interest:
a)
Natural gas transportation, transformation and uses, b)
H•2S management, c)
CO2 management. On the forefront of Natural Gas Transportationtransportation and Conversion. Transportation and use of natural gas includingconversion, important results have been obtained for the development of materials suitable to takea process for the Adsorbed Natural Gas (ANG)production of methanol from natural gas. The process is based on an Eni proprietary technology to an industrial scale, and the development of processes for the conversion of natural gasmethane to methanol. The latter seen as an important vector forsyngas, which is cheaper and has a footprint and a weight much lower than the production of low environmental impact liquid fuels and chemical products (olefins and aromatics).existing processes based on steam reformer. • Hydrogen Sulfide. Development of new technologies forIn the separation and usearea of H2S both in fertilizer products and in materials and plastics containing sulfur.
CO• Carbon Dioxide.2 Development of new technologiescapture, innovative highly effective solvents for the separation of H2S and use of CO2 comprising on-board capture of generated CO2 in motor vehiclesfrom natural gas have been identified and use of CO2 for production of plastics, fibers and building materials. Petrochemicals
• Guayule. Project aimingtested at lab scale. Now the production of natural latex, dry rubber and resins from Guayule (ongoing experimental cultivation in Basilicata and Sicily) with exploitation of all components with proprietary technologies and their development in the market allowing the use of whole value of the Guayule plant.
• Bio-butadiene. A joint venture between Versalis and Genomatica has developedresults is under scaling-up to a process to produce 1,3 bio-butadiene from renewable sources via sugars production from biomasses, fermentation and subsequent chemical processes. The Tire Technology Committee has awarded this projectpilot unit with the “Environmental Achievement Award”.cooperation of an external specialized company. New ways for sulphur utilization are under consideration. Innovative sulphur-based products which can be used in agriculture have been obtained and are under testing in a field parcel in Central Italy.
Insurance In order to control the insurance costs incurred by each of Eni’s business units, the Company constantly assesses its risk exposure in both Italian and foreign activities. The Company has established a captive subsidiary, Eni Insurance DAC, in order to efficiently manage transactions with mutual entities and third parties providing insurance policies. Internal insurance risk managers work in close contact with business units in order to assess potential underlying business and other types of risks and possible financial impacts on the Group results of operations and liquidity. This process allows Eni to accept risks in consideration of results of technical and risk mitigation standards and practices, to define the appropriate level of risk retention and, finally, the amount of risk to be transferred to the market.
Eni enters into insurance arrangements through its shareholding in the Oil Insurance Ltd (OIL) and with other insurance partners in order to limit possible economic impacts associated with damages to both third parties and the environment occurring in case of both onshore and offshore accidents. The main part of this insurance portfolio is related to operating risks associated with oil&gas operations which are insured making use of insurance policies provided by the OIL, a mutual insurance and re-insurance company that provides its members with a broad coverage of insurance services tailored to the specific requirements of oil and energy companies. In addition, Eni uses insurance companies who it believes are established in the marketplace. Insured liabilities vary depending on the nature and type of circumstances; however, underlying amounts represent significant shares of the plafond granted by insuring companies. In particular, in the case of oil spills and other environmental damage, current insurance policies cover costs of cleaning-up and remediating polluted sites, damage to third parties and containment of physical damage up to $1.2 billion for offshore events and $1.4 billion for onshore plants (refineries). These are complemented by insurance policies that cover owners, operators and renters of vessels with the following maximum amounts: $1,250 million for the fleet owned by the subsidiary LNG Shipping in the Gas & Power segmenttankers and time charters; $1 billion for FPSOs used by the Exploration & Production segment for developing offshore fields. Management believes that the level of insurance maintained by Eni is generally appropriate for the risks of its businesses. However, considering the limited capacity of the insurance market, we believe that Eni could be exposed to material uninsured losses in case of catastrophic incidents, like the one occurred in the Gulf of Mexico in 2010 which could have a material impact on our results, liquidity prospects, share price and reputation. See “Item 3 – Risk factors – Risk associated with the exploration and production of oil and natural gas”. Environmental matters Environmental regulation Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil&gas operations, products and other activities, including legislation that implements international conventions or protocols. In particular, exploration, drilling and production activities require acquisition of a special permit that restricts the types, quantities and concentration of various substances that can be released into the environment. The particular laws and regulations can also limit or prohibit drilling activities in the certain protected areas or provide special measures to be adopted to protect health and safety at workplace and health of communities that could have been affected by the Company’s activities. These laws and regulations may also restrict emissions and discharges to surface and subsurface water resulting from the operation of natural gas processing plants, petrochemical plants, refineries, pipeline systems and other facilities that Eni owns. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials. Environmental laws and regulations have a substantial impact on Eni’s operations. Some risk of environmental costs and liabilities is inherent in certain operations and products of Eni, and there can be no assurance that material costs and liabilities will not be incurred. See “Item 3 – Risk factors”. We believe that the Company will continue incurringto incur significant amounts of expenses in order to comply with pending regulations in the matter of environmental, health and safety protection and safeguard regulations, particularly in order to achieve any mandatory or voluntary reduction in the emission of GHG in the atmosphere and cope with climate change and water quality of discharges, as well as availability. International and European Union Environmental Laws Framework In 2016, the main environmental efforts of the European Union continued to focus on the air quality, energy transition, circular economy and Climate Change matters.
On November 4, 2016, the Paris Agreement entered into force, exactly 30 days after the date on which the last of at least 55 Parties to the Convention accounting in total for at least an estimated 55% of the total
global greenhouse gas emissions have deposited their instruments of ratification. To date, the 123189 Parties have ratified the Convention. This important step in the common international Climate Change strategy sets out a global action plan to put the world on track to avoid dangerous climate change by limitingkeep a global warming totemperature rise this century well below 2°C. By the ratification of the Convention, the governments agreedC above pre-industrial levels and to pursue efforts to limit the temperature increase even further to 1.5°C, since this would significantly reduce risksC. In 2019, the UN Climate Change Conference (COP 25) had taken place in Madrid under the Presidency of the Government of Chile. The COP 25 had an important role to play in moving forward with the Paris Agreement “rule- book” implementation and it laid the basis for more ambitious emission reduction commitments from Parties at the next conference (COP 26 to be held in Glasgow, UK). Main focus areas discussed during the COP 25 were adaptation to climate impacts, ofthe support to loss and damage suffered by developing nations due to climate change. On October 4, 2016,change, international climate finance and others. Regarding the European Parliament approvedrules for the ratificationinternational carbon market (article 6 of the Paris Agreement), the COP 25 did not reach any agreement. On this topic, negotiations could not go over the impasse due to a divergence between the Parties on a few crucial points and in the end, the issue was delayed until next year’s talks.
In 2020, other than agreeing upon a common framework for international carbon market, the Parties are required to submit new or updated national climate action plans, referred as Nationally Determined Contributions (NDCs) and, in this task, Parties are urged to consider the significant gap between the current emission pathways and the pathways consistent the Paris Agreement mitigation target. During the COP 25, the European Union (EU) released the Green Deal Communication, in which it clearly announces its commitment on the environmental aspects. The document represents a package of measures that should enable European citizens and businesses to benefit from sustainable green transition. Measures accompanied with an initial roadmap of key policies range from ambitiously cutting emissions, to investing in cutting-edge research and innovation, to preserving Europe’s natural environment and achieving a climate neutral economy by 2050. The roadmap includes also a comprehensive plan to increase the EU’s GHG reduction target for 2030 to at least 50% and toward 55% vs 1990, compared to current target of 40%. Once implemented in legislation, the new EU 2030 GHG reduction target will entail a revision of the main targets and provisions enforced by the European Union. The Paris Convention vindicatescurrent EU legislation. In particular, the EU strategy in climate change defined in October 2014, when the European Council agreed on the 2030 climate and energy policy framework. In this strategy the EU stated an ambitious economy-wide domestic target of at least 40% GHG reduction for the period up to 2030 (below 1990 levels) and to a 27% share of renewable energy in final energy consumption. On November 30, 2016, the following step of this strategy was written down, when the EU Commission presented theexisting Clean Energy for All Europeans (so called “Winter“Clean Energy Package”). By this proposal, developed between 2016 and early 2019, among the EU is consolidatingothers commitments, set a binding target of 32% for renewable energy sources in the enabling environment for the transitionEU’s energy mix by 2030 and a binding target of at least 32.5% energy efficiency by 2030, relative to a low carbon economy through a wide range of interacting policies and instruments reflected under the Energy Union Strategy, one of the 10 priorities of the Juncker Commission. ‘business as usual’ scenario.
The Winter Package has three main goals: putting energy efficiency first (setting a binding 30% energy efficiency target), achieving global leadership in renewable energies and providing a fair deal for consumers. The Package includes some legislative proposals such as revision ofrevised Renewable Energy Directive (“RED”) - (Directive 2009/28/CE) and revision ofsets also the Energy Efficiency Directive. For Eni’s strategies and policy on biofuels, a revision of RED has atarget for renewable energy in the transport sector. In particular, importance. In order to foster the de-carbonization and energy diversification the RED revision proposal introduces an obligation on European transportMember States must require fuel suppliers to provide an increasing sharesupply a minimum of 14% of the energy consumed in road and rail transport by 2030 as renewable and low-carbon fuels, including advanced biofuels, renewable transport fuelsenergy, of non-biological origin (e.g. hydrogen), waste-based fuels and renewable electricity. The level of this obligation is progressively increasing from 1.5 percent in 2021 (in energy terms) to 6.8 percent in 2030, includingwhich at least 3.6 percent of3.5% coming from advanced biofuels. It also introduces a cap onIn terms of environmental sustainability, high Indirect Land Use Change-risk feedstocks will be capped at 2019 levels until 2023 and then progressively phased-out up to zero by 2030. A centerpiece of the contribution of first generation biofuels (so called “food-based” biofuels) in transport sector towardsEU’s 2030 energy and climate policy framework is the EU renewable energy target, starting at 7 percent in 2021 and going down progressively to 3.8 percent in 2030 to minimize the Indirect Land-Use Change (ILUC) impacts. An important part of EU Climate Strategy is covered by the Emission Trading System (ETS), which is now in the III phase (2013-2020). The Commission has already brought forward key proposals to implement the EU’sbinding target to reduce greenhouse gasoverall GHG emissions by at least 40% below 1990 levels by 2030. In July 2015, it presented a proposal to reformTo achieve this cost-effectively, the sectors covered by the EU Emission Trading System (ETS) – phase IV (2021-2030) to ensure the energy sector and energy intensive industries deliver the emissions reductions needed. In summer 2016, the Commission brought forward proposals for accelerating the low-carbon transition in other key sectors of the European economy. To achieve the at least 40% EU target, the sectors covered by the ETS(EU ETS) will have to reduce their emissions by 43% compared with 2005, while non-ETS sectors will have to 2005. To this end,reduce theirs by 30%. The ETS is about to enter in its IV phase (2021-2030), in which the overall number of emission allowancesEuropean cap will decline at an annual rate of 2.2% from 2021 onwards,, compared to 1.74% currently.of the previous phase. The carbon leakage sectors will still receive 100% of the free allowances calculated with the sectorial benchmark, for all the IV phase. All the Eni’s activity sectors are included in the new carbon leakage list, excluding the extraction and production of natural gas. Currently around 49%46% of Eni’s direct GHG emissions are included within the Carbon Pricing Scheme by its participation in the EU ETS.
In May 2018, the European institutions adopted the Effort Sharing Regulation (ESR) to ensure further emission reductions in sectors falling outside the scope of the EU ETS for the IV phase. The airESR maintains existing flexibilities (e.g. banking, borrowing and buying and selling between Member States) and provides two new flexibilities, allowing the use of some EU ETS emissions allowances and credits from land use sector to achieve the final target. The Clean Energy Package includes also a new regulation on Governance of Energy Union, which asks all the Member States to draft their own National Energy and Climate Plans (NECPs), in order to plan, in an integrated manner, their climate and energy objectives, policies and measures, aligned with the broad EU targets. During 2019, most of the Member States presented their NECP for 2021-2030 period, to achieve their respective targets.
Under the electricity market reform, the European Commission approved a new limit for power plants eligible to receive subsidies as capacity mechanisms. Subsidies to generation capacity emitting 550gCO2/kWh or more will be phased out, as of 2020 for new infrastructure and as of 2025 for existing plants. The criterion, used in the European Investment Bank’s policy, is technology neutral and in practice preclude from the subsidies the coal power plants and some inefficient gas plants. In the second half of 2019, the European Investment Bank (EIB) also approved the new energy lending policy, according to which, the EIB will no longer consider new financing for unabated, fossil fuel energy projects, including gas, from the end of 2021 onwards. In addition, the bank set a new Emissions Performance Standard of 250 gCO2/kWh as a threshold for its investments in both fossil and renewable energy sources. Air quality remains at the center of the European environmental policies and strategies. On December 18, 2013,In 2019 the European Commission adoptedhas completed a packagefitness check of proposalsthe two EU Ambient Air Quality (AAQ) Directives (Directives 2008/50/EC and 2004/107/EC). These Directives set air quality standards and requirements to improveensure that Member States monitor and/or assess air quality in their territory, in a harmonized and comparable manner. The fitness check of the AAQ Directives was based on the analysis of the experience in all Member States, focusing on the period from 2008 to 2018 and evaluated the relevance, effectiveness, efficiency, coherence and EU added value of the AAQ Directives, in line with Better Regulation requirements. In order to guarantee better quality standards and to shift toward a low carbon economy, in December 2017, the Commission has launched the Clean Mobility Package. This is a decisive step forward in implementing the EU’s commitments under the Paris Agreement for a binding domestic CO2 reduction of at least 40% till 2030. Its aim is to help accelerate the transition to low- and zero emissions vehicles, through a new target for the EU which updatedfleet wide average CO2 emissions of new passenger cars and vans of 30% by 2030 to provide stability and long-term direction. The Mobility Package has a 2025 intermediary target of 15% to ensure that investments kick-start already now. As the air policy objectives for 2020confirmation of Eni’s involvement in sustainable mobility in November Eni and 2030. The package includesFCA have signed a long-awaited revision of the National Emission Ceilings (NEC) Directive, a proposalcontract to addresscarry out research and develop technological applications aimed at reducing CO2 emissions from medium scale combustion plants (MCP) and a proposal for ratification of the recently amended Gothenburg Protocol.in road transport. On December 31, 2016, the new National Emissions Ceilings (NEC) Directive entered into force. The NEC directive, based on a Commission proposal setsforce to guarantee stricter limits on the five main pollutants in Europe: sulfur dioxide (SO2)(SO2), nitrogen oxides (NOx), ammonia (NH3), volatile organic compounds (VOC) and primary particulate matter (PM). The Member States had time until June 30, 2018 to transpose the NEC Directive must be transposed byand had to submit the Member states by 30 June 2018. The new NEC directive repeals and replaces Directive 2001/81/EC. Each EU Member State is required to produce aFirst National Air Pollution Control ProgramProgrammes by 31 MarchApril 1, 2019, setting out the measures it will take to ensure compliance with the 2020 and 2030 reduction commitments. On December 18, 2015, The NEC directive aim is to improve not only human health but also the Directive No. 2015/2193/EUcondition of ecosystems across the EU. In 2019 the Commission Guidance on the limitationmonitoring ecosystem impacts of emissions of certain pollutants intoair pollution was released. Moreover the first data on air from medium combustion plants entered into force. The Medium Combustion Plant
Directive (MCP Directive) regulates pollutant emissions from the combustion of fuels in plants with a rated thermal input equal to or greater than 1 megawatt (MWth) and less than 50 MWth. The MCP Directive is a part of the Clean Air Policy Package adoptedpollution impacts on December 18, 2013 and it regulates emissions of SO2, NOX and dust into the air with the aim of reducing those emissions and the risks to human health and the environment they may cause. The MCP Directive will haveecosystems was supposed to be transposedsubmitted by Member States by December 19, 2017. The MCP1 July 2019. in line with Directive also ensures implementation of the obligations arising from the Gothenburg Protocol under the UNECE Convention on Long-Range Trans-boundary Air Pollution.2016/2284 (National Emission Ceilings).
The Industrial Emission Directive (IED) 2010/75/EU is fundamental for European industries, it provides the framework for granting permits for about 50,000 industrial installations across the EU. It lays down rules on the integrated prevention and control of air, water and soil pollution arising from industrial activities. As part of the IED framework, additional emission limit values are defined by the sector specific and cross-sector Best Available Technology (BAT) Conclusions. In 2016, the Commission has published the Implementing Decision (EU) 2016/902 of May 30, May 2016 establishing best available techniques (BAT) conclusions, under Directive 2010/75/EU, for common wastewater and waste gas treatment/management systems in the chemical sector. CurrentlyIn February 2019, the exchangeBest Available Techniques Reference Document for the Management of views betweenWaste from Extractive Industries was published. In accordance with Directive 2006/21/EC, the reviewed document presents up -dated data and information on the management of waste from extractive industries, including information on BAT, associated monitoring, and developments in them. The new risk-based “BAT” approach considers the diversity of types of extractive waste, sites and operators and covers a wide range of potential risks that must be considered by operators responsible for waste management in the extractive industries.
In August 2017 the Commission Implementing decision 2017/1442 of July 31, 2017 entered in force. The decision establishes the best available techniques (BAT) conclusions, under Directive 2010/75/EU of the European Parliament and of the Technical Working Group onCouncil, for large combustion plants (LCP – combustion installations
with a rated thermal input exceeding 50 MW). Plants with a thermal input lower than 50 MW are, however, discussed in the LCP BAT where technically relevant because smaller units can potentially be added to a plant to build one larger installation exceeding 50 MW. In December 2017, the Large Combustion Plant Best Available Technique reference document (LCP BREF) was published. The update of both documents was expected under the Emission Directive is taking place. By the end of 2017, the adoption of final LCP BREF with revised BAT conclusions is expected. The updated LCP BREFand will have a significant implication on the Eni’s technologies applied in the power plants. A Technical Working Group has been formed to implement a new Best Available Techniques Guidance Document on the upstream hydrocarbon exploration and production sector. Moreover, in November, Commission has published its implementing decision establishing best available techniques (BAT) conclusions, under Directive 2010/75/EU of the European Parliament and of the Council, for the production of large volume organic chemicals (LVOC BAT). New emissions and efficiency standards will help national authorities to lower the environmental impact of the 3,200 installations that produce Large Volume Organic Chemicals (LVOC) and represent 63% of the EU’s entire chemical industry. The Member States must all the permits for LCPs in line with the LCP BAT conclusions by August 2021. In 2017 (at the latest on May 16) all Member States must apply the rules of the new Environmental Impact Assessment Directive 2014/52/EU (EIA). The EIA Directive should simplify the rules for assessing the potential effects of projects on the environment and boarders scope of the EIA covering new issues such as climate change, biodiversity, resource efficiency and risks prevention on both human and environmental aspects. Fluorinated gases (‘F-gases’) play an important role in the accomplishment of the Paris Agreement and in the EU environmental policy. These ozone-depleting substances are regulated by F-gasF- gas Regulation (No. 517/2014) which applies from January 1, 2015. The new regulation strengthens the previous measures and should cut by 2030 the EU’s F-gasF- gas emissions by two-thirdstwo- thirds compared with 2014 levels. This represents a fair and cost-efficient contribution by the F-gas sector to the EU’s objective of cutting its overall GHG emissions by 80-95%80 – 95% of 1990 levels by 2050. Moreover,In 2017, the EU continued to shape the F-gases strategy. In October 2017, the Commission Implementing Decision (EU) 2017/1984 was published in the Official Journal. The decision sets a reference values for the period January 1, 2018 to December 31, 2020 for each producer or importer which has lawfully placed on the market hydrofluorocarbons from January 1, 2015 UE of October 201624, 2017. During the Kigali amendmentreporting year, the EU focused on improving the environmental management principles and rule. In December, the Commission published the decision, amending the user’s guide setting out the steps needed to participate in EMAS (decision 2017/2285). The guidelines offer an additional information and guidance about the Montreal Protocol (on Substancessteps needed to participate in EMAS, which represents the voluntary participation by organizations in a Community eco-management, and audit scheme. In November, Commission Guidelines on Environmental Impact Assessment (EIA) were released (they include three parts: Guidance Document on Screening, Guidance Document on Scoping and Guidance Document on the preparation of the EIA Report). The Commission has updated and revised the 2001 EIA Guidance Documents to reflect both the legislative changes brought by 2014/52/EU and the current state of good practice. In February 2018, the working group of experts has started the revision of the ISO 14067 standard that Depletespecifies principles, requirements and guidelines for the Ozone Layer) was signed in Rwanda. The Amendment adds powerful greenhouse gases hydrofluorocarbons (HFCs) toquantification and communication of the listcarbon footprint of substances controlled under the Protocol to be phased down. HFC phasedown is expected to avoid up to 0.5 degree Celsius of global temperature rise by 2100, while continuing to protect the ozone layer.a product (CFP), based on International Standards on life cycle assessment. In 20152018 the European Commission adoptedParliament and Council approved the directives included in the Circular Economy Package, which includes revised legislative proposalsrevising the EU legislation on waste, aiming to stimulate Europe’s transition towards a circular economyeconomy. The approved directives introduce new waste-management targets regarding reuse, recycling and landfilling, strengthens provisions on waste prevention and extended producer responsibility, and streamlines definitions, reporting obligations and calculation methods for targets. The Member States must transpose the directives in national legislation by 5th July 2020. In January 2018, the first Europe-wide strategy on plastics was adopted. The directive 2019/904/EU was approved on June 2019; it bans some single use plastic products and establishes requirements for some other plastic products (examples: content of recycled plastic, marks on packaging). The directive, which emphasizesalso asks the needadoption of measures to move towards a lifecycle-driven ‘circular’ economy, with a cascading usestrengthen separate collection of resources and residualplastic waste, that is close to zero. The O&G sector will have to put a significant effort to follow the “circular philosophy” by investingmust be transposed in the innovative technological solutions, optimizationnational legislations of the water use, energy efficiency andMember States by 3rd July 2021. According to the green procurement. AUE Green Deal the new integratedcircular economy action plan is attended in March 2020, as part of a broader EU policy for the Arctic Region has been adopted in 2016. The policy defines the 39 actions focusing on strengthening international cooperation, tackling climate change, enhancing environmental protection and promoting sustainable development.industrial strategy.
European Union Health and Safety Laws Framework Legislative Decree No. 81/2008 concerned the protection of health and safety in the workplace and was designed to regulate the work environments, equipment and individual protection devices, physical
agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), dangerous substances (chemical
(chemical agents, carcinogenic substances, etc.), biological agents and explosive atmosphere, the system of signs, video terminals. Eni worked on the implementation of the general framework regulations on health and safety concerning prevention and protection of workers at national and European level to be applied to all kinds of workers and employees. On June 1, 2007, the REACH Regulation of the European Union (EC No. 1907/2006 of December 18, 2006) entered into force. REACH stands for Registration, Evaluation, Authorization and Restriction of Chemicals and was adopted to improve the protection of human health, safety and the environment from the risks that can be posed and caused by chemicals, while enhancing the competitiveness of the EU chemical industry. It also promotes alternative methods for the assessment of hazardous substances in order to reduce the number of tests on animals. REACH places the burden of proof on companies. To comply with the regulation, companies must identify and manage the risks linked to the substances they manufacture and market in the EU. They have to demonstrate to the European Chemicals Agency (ECHA) how the substance can be safely used and they must communicate the risk management measures to the users. If the risks cannot be managed, Authorities can restrict the use of substances in different ways. Over time, the hazardous substances should be substituted with less dangerous ones. The deadline of the REACH registration depends on the tonnage band of a substance and the classification of a substance; next and last deadline is 2018.substance. Eni recognizes the importance of the Regulation EC No. 1907/2006 (REACH), the general principles of which are already an intrinsic part of the Company’s commitment to sustainability and are an integral part of the culture and history of the Company. The compliance with the REACH requirements and the involvement of all the interested parties in the Company are coordinated and supervised by the HSEQ function. In particular, Eni is involved in the registration of substances to ECHA which regards a complex series of information about the characteristics of such substances and their uses and in another fundamental aspect that concerns the exchange of information between producers and importers, as well as the users of chemical substances (“downstream users”). The CLP Regulation (Classification, Labeling and Packaging) entered into force in January 2009 (Regulation EC No. 1272/2008 on the classification, labeling and packaging of substances and mixtures), and the method of classifying and labeling chemicals introduced is based on the United Nations’ Globally Harmonized System. The Regulation will replacewas replaced two previous pieces of legislation, the Dangerous Substances Directive and the Dangerous Preparations Directive. There is a transition period until 2015. The CLP Regulation ensures that the hazards presented by chemicals are clearly communicated to workers and consumers in the European Union through classification and labeling of chemicals. Before placing chemicals on the market, the industry must establish the potential risks to human health and the environment of such substances and mixtures, classifying them in line with the identified hazards. The hazardous chemicals also have to be labeled according to a standardized system so that workers and consumers know about their effects before they handle them. Following the incident at the Macondo well in the Gulf of Mexico, the U.S. Government and other governments have adopted more stringent regulations targeting safety and reliable oil&gas operations in the United States and elsewhere, particularly relating to environmental and health and safety protection controls and oversight of drilling operations, as well as access to new drilling areas. Italian Authorities as well have passed legislation with Law Decree No. 128 on June 29, 2010 that introduces certain restrictions to activities for exploring and producing hydrocarbons that have been confirmed and further geographically limited by the successive Law Decree No. 134 of August 7, 2012 and by the Ministerial Decree of September 4, 2013.
European institutions have also increased their activities in the area of environmental protection in the field of hydrocarbon extraction. On June 12, 2013, the Directive No. 2013/30/EU was issued with the aim of replacing the existing National Legislations and uniform the legislative approach at European level. The main elements of the EU Directive are the following: •
The Directive introduces licensing rules for the effective prevention of and response to a major accident. The licensing authority in Member States will have to make sure that only operators with proven technical and financial capacities are allowed to explore and produce oil&gas in EU waters. Public participation is expected before exploratory drilling starts in previously un-drilled areas.
•
Independent national competent authorities, responsible for the safety of installations, are in charge to verifyof verifying the provisions for safety, environmental protection, and emergency preparedness of rigs and platforms and the operations conducted on them. Enforcement actions and penalties apply in case of non-compliance with the minimum set standards. •
Obligatory emergency planning calls for companies to prepare reports on major hazards, containing an individual risk assessment and risk-control measures, and an emergency response plan before exploration or production begins. These plans have to be submitted to National Authorities. •
Technical solutions presented by the operator need to be verified independently prior to and periodically after the installation is taken into operation.
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Companies are required publish on their websites information about standards of performance of the industry and the activities of the national competent authorities, as well as reports of offshore incidents. •
Companies are required prepare emergency response plans based on their rig or platform risk assessments and keep resources at hand to be able to put them into operation when necessary. These plans are periodically tested by the industry and National Authorities. •
Oil and gas companies are fully liable for environmental damage caused to the protected marine species and natural habitats. For damage to waters, the geographical zone is extended to cover all EU waters including the exclusive economic zone (about 370 km from the coast) and the continental shelf, where the coastal Member States exercise jurisdiction. For water damage, the present EU legal framework for environmental liability is restricted to territorial waters (about 22 km offshore). •
Operators working in the EU are required to demonstrate they apply the same accident-prevention policies overseas as they apply in their EU operations. We believe that Eni operations are currently in compliance with all those regulations in each European country whosewhere they have been enacted. Adoption of stricter regulation both at national and European or international level and the expected evolution in industrial practices would trigger cost increases to comply with new HSE standards. Eni exploration and development plans to produce hydrocarbon reserves and drilling programs could also be affected by changing HSE regulations and industrial practices. Lastly, the Company expects that production royalties and income taxes in the oil&gas industry will likelyprobably increase in future years. Moreover, in order to achieve the highest safety standards of our operations in the Gulf of Mexico, Eni entered into a consortium led by Helix that worked at the containment of the oil spill at the Macondo well. The Helix Fast Response System (HFRS) performs certain activities associated with underwater containment of erupting wells, evacuation of hydrocarbon on the sea surface, storage and transport to the coastline. Worldwide Eni approach was to join international consortiums for main equipment and to develop in-house technologies to improve the intervention capability. Eni Emergency Response Kit consists of: •
Outsourced equipment contracted by Eni Head Quarter; •
Access Agreement to Subsea Capping Equipment consortium; •
Access Agreement to Global Dispersant Stockpile consortium; •
Eni Head Quarter proprietary equipment; •
Rapid Cube; •
Killing System. As toregards major accidents, the Seveso III (Directive No. 2012/18/EU) was adopted on July 4, 2012 and entered into force on August 13, 2012. Italy has transposed it into national legislation through the Legislative Decree No. 105/2015 (June 26, 2015). The main changes in comparison to the previous Seveso Directive are: •
technical updates to take into account the changes in EU chemical classification, mainly regarding the 2008 European CLP Regulation of substances and mixtures; •
expanded public information about risks resulting from Company activities; •
modified rules in participation by the public in land-use planning projects related to Seveso plants; and •
stricter standards for inspections of Seveso establishments. Eni has carried out specific activities aimed at guaranteeing the compliance of its own industrial sites.
HSE activity for the year 20162019 Eni is committed to continuously improving its model for managing health, safety and environment issues across all its businesses in order to minimize risks associated with its own industrial activities, ensure reliability of its industrial operations and comply with all applicable rules and regulations.
In 2016,2019, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. The total number of certifications achieved was 304,306, of which: •
9992 certifications according to the ISO 14001 standard;
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10 registrations according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union); •
1823 certifications according to the ISO 50001 standard (certification for an energy management system);
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10383 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems -– requirements) and 19 according to the new ISO 45001 standard;
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42 according to the ISO 9001 standard (certification of the quality management system). In 20162019 the percentage of Eni industrial installations and operating units with a significant HSE risk covered by certification is 97%95% for the OHSAS 18001/ISO 45001 standard OHSAS 18001 and 95%94% for the ISO 14001 standard. In 2016,2019, total HSE expenses (including cross-cutting issues such as HSE management systems implementation and certification, etc.) amounted to €1,102€1,323 million increasing by 3.3% from 2015.(+5% vs 2018). Environment.Environment. In 2016,2019, Eni incurred total expenditures of €588.65€963 million for the protection of the environment (with a reductionan increase of 5.9%5% with respect to 2015)2018). Environmental expenditures are mainly related to remediation and reclamation activities (€233.9367 million), waste management (€133.8248 million), water management (€62168 million), air protection (€47.254 million) and spill prevention (€37.141 million).
Safety. Eni is committed to safeguarding the safety of its employees, contractors and all people living in the areas where its activities are conducted and its assets located. In 2016,2018, the new legislation didn’t impact significantly procedures already in place for safety in the workplace. The dissemination of safety culture is a primary targetvalue for Eni. In 2016,2019, in order to increase safety’s culture in the workforce, awareness-raising initiatives continued. Road Showscontinued: •
Safety starts @ office: realization of video clips that aim to raise awareness of virtuous and safe behaviors to be held in the office •
Inside Lesson Learned Project: dissemination and sharing of the most significant lessons learned through video in which the correct modus operandi is explained according to Eni Safety Day were organizedGolden Rules; •
Io vivo sicuro: day of sharing between employees and contrasts, dedicated to the creation and testing of a modular training course in the thematic areas of road safety, home safety and leisure time safety •
Workshop on Product Safety: workshop on REACH and CLP Regulations with the aim of sharing performance, target, new projectsdeepening the knowledge of the European Norms on chemical substances, strengthening the awareness of the responsibilities and safety vision between Eni’s top management and employees and contractors. In order to keep developing new awareness raising actions regarding safety at work, in 2016 two new initiatives were launched:
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“Inside Lesson Learned Project” to share lessons learned using video clips made by internal resources and inspired by real events occurred infulfilments of the company;organizational roles.
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“Eni in Safety 2” to increase safety culture with workshops finalized to discuss safe behaviors, responsibility and leadership in safety. The new projects will be roll out in 2017 involving employees and contractors.
In 2013, Eni launched an initiative aimed at issuing work permits in electronic form for standardizing and improving the related risk assessment process. The initiative is progressively involving all the operating sites. In 2015, Eni developed the Company Process Safety Management System for increasing the safety of its operations through still higher technical and management standards. Starting from 2016 and in following years these standards will beare applied progressively in all operating activities. In 2019 Eni participated in a working group of EPSC (European Process Safety Center) on the definition of a set of shared operating rules on process safety which led, also through an internal technical team work attended by representatives and knowledge owners of Process Safety of the various Business Units and Operations representatives, to the definition of Eni’s Process Safety Fundamental.
Results of efforts to achieve a better safety in all activities brought an improvement of EniIn 2019, the Total Recordable Injury Rate for the workforce total recordable injury rate (0.35), decreasedimproved by 21%3% compared to 2015.2018 (0.34 vs 0.35).
Regarding emergency preparedness to oil spill, Eni has joined the Oil Spill Response-Joint Industry Project (OSR-JIP I & II) which was launched in December 2011 by International Association of Oil&Gas Producers (IOGP) and International Petroleum Industry Environmental Conservation Association (IPIECA) and concluded in 2016. The JIP executed the outstanding recommendations from the report produced by the Global Industry Response Group (GIRG)2016 set-up after the Macondo accident. The JIP aimed at: •
providing a forum forwork of the five-year Joint Industry Project is now included in the Oil Spill Group that continues to develop good practice and facilitates industry forums to share knowledge on the science, tools and techniques;
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representing the industry on approaches for oil spill preparedness and response, working closely with other associations on communications with both nationalresponse.
Moreover in the same framework Eni participates at two Global Initiatives jointly led by the IMO and global regulatory groups;
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engaging pro-actively in broader outreachIPIECA: OSPRI (Black Sea, Caspian Sea and communication.
The OSR-JIP carried out specific projects dealing with exercise planning, in situ burning, dispersants advocacy-subsea, efficacy-post spill monitoring, upstream risk assessmentCentral Eurasia) and response capability, etc., publishing 11 Research Reports, 9 Technical ReportsWACAF (West, Central and 24 Good Practice Guidance (two are already available in Italian)Southern Africa).
Costs incurred in 20162019 to support the safety levels of operations and to comply with applicable rules and regulations were €287.8€306 million. HealthHealth.. Eni’s activities for protecting health aim to continuously improve the psychophysical wellbeing of people in the workplace. Eni believes that it achieved a good performance in this area thanks to:
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plant and facility efficiency and reliability; •
promotion and dissemination of knowledge, adoption of best practices and operating management systems based on advanced criteria of protection of health and internal and external environment; •
certification programs of management systems for production sites and operating units; •
identified indicators in order to monitor exposure to chemical and physical agents; •
strong engagement in health protection for workers operating worldwide also with the support of international health providers capable of guaranteeing a prompt and adequate response to any emergency; •
identification of an effective and reliable health providers, in Italy and abroad; •
training programs for medics and paramedics. In order to protect the health and safety of its employees, Eni relies on a network of health care facilities located in its main operating areas. A set of international agreements with the best local and international health providers ensures efficient services and timely responses to emergencies. Eni is engaged to the elaboration of HIA and relative standards to be applied to all new projects of evaluation of working exposure to environment, in Italy and abroad. The main aim of HIA is to avoid any negative impacts and maximize any positive impacts of the project on the host community and it is usually carried out as part of/or in conjunction with the Health, Environmental and a Social Impact Assessment process. Its results are used to develop appropriate mitigation measures and an improvement plan with the host community. In 2016, Eni incurred total expenses of €47.9 million, to protect the health of its employees. Eni expects to continue incurring amounts of expenses for health, which will beInformation about Eni’s strategy and targets in line with 2016 levels in future years.
Managing GHG emissions
2016 was a relevant year for the international climate change debate, mainly due to the entry into force of the Paris Agreement on 4th November. The Paris Agreement and its early entry into force represents for Eni a very positive step toward a low carbon energy transition. As a major international energy company, Eni is actively involved to play a leading role to contrast climate change.
Eni recognizes indeed the scientific evidences presented in the IPCC Fifth Assessment Report and the necessity to limit the rise of the global temperature below 2 °C above pre-industrial levels. In line with this long term target, Eni has developed an integrated climate strategy with the aim of advance in the transition towards a low-carbon energy future while fulfilling the growth of energy demand. Eni’s climate strategy is composed of three main pillars: reducing and offsetting its greenhouse gas (GHG) emissions; developing a low-carbon portfolio; and committing on renewables and low carbon R&D.
Regarding the reduction of greenhouse gas (GHG) emissions, since 2010 years Eni reached important results, such as an absolute reduction of 31%scenario in total direct GHG emissions, together with a 30% reduction in the carbon intensity of the Upstream business. These results were mainly drivenaccordance to standards set by flaring down projects, methane monitoring campaign and energy efficiency efforts.
In order to strengthen this engagement and with a forward looking perspective, in 2015 Eni launched a strategic internal Program on Climate Change aimed at developing a medium and long term roadmap able to drive Eni towards a low carbon future. In line with this Program and the abovementioned strategy, Eni published its targets and established the new “Energy Solutions” business line in order to integrate traditional energy sources with the production of energy from renewable sources.
In particular, by 2025 we have confirmed three main commitments focused on improving our GHG performance: to reduce by -43% vs 2014 the GHG emission intensity of our production, to reach zero routine gas flaring and to abate by 80% the fugitive emissions coming from our Upstream business.
In addition to these operational actions and commitments, Eni actively participates in primary international climate initiatives. In particular, in 2016 Eni contributed to further develop the “Oil and Gas Climate Initiative” (OGCI), a voluntary CEO led initiative launched in 2014 along with other companies in the oil&gas sector (currently, the ten OGCI member companies represent about 25% of global HC production). On November 4, 2016, during a high-level event in London, OGCI CEOs announced an investment of $1 billion over the next ten years to develop and accelerate the deployment of innovative low emissions technologies able to improve the management of GHG emissions and contain climate impacts of the Oil&Gas sector.
In 2016, Eni has continued its efforts in two international Public-Private Initiatives focused on operational efficiency: the “zero routine gas flaring at 2030” program of the World Bank’s “Global Gas Flaring reduction partnership” and the “Clean Air and Climate initiative - Oil & Gas Methane Partnership”, aimed at reducing methane emissions in the oil&gas value chain. About this important topic, in October 2016 was published the first report of the initiative, with details and information on Eni methane LDAR monitoring campaign during the first year of the initiative.
Thanks to its climate strategy and the ambitious targets for the future, in 2016 Eni has been recognized by the CDP as a global leader for its actions and strategies in response to climate change and was included in the prestigious A-list of CDP. Eni was the only oil & gas major achieving this high recognition.
Another acknowledgment of Eni’s climate leadership was the invitation to take part in the works of the Task Force on Climate Relatedclimate-related Financial Disclosures (TCFD) of the Financial Stability Board and other non-financial information about sustainability is provided in the “Non -financial Information report” which has the aimis part of develop voluntary, consistent climate-related financial risk disclosures for use by companies in providing effective information to investors.
Regarding Eni’s own GHG emissions management, with the aim of ensuring a comprehensive, transparent and accurate reporting for GHG emissions, in 2005 Eni introduced its own Protocol for accounting and reporting GHG emissions (GHG Accounting and Reporting Protocol), integrated in 2013 by a procedure on reporting and accounting methodologies on indirect emissions scope 3 types. This procedure was updated in 2015. According to the Eni methodology for accounting and reporting Scope 3 GHG, Eni estimates the indirect GHG emissions generated by several emission categories (e.g. purchased goods and services, use of sold hydrocarbon products, business travel, franchising, etc.) in line with the WBCSD-WRI Protocol “Corporate Value Chain (Scope 3) Accounting and Reporting Standard”.
Eni documents are an essential requirement for emissions certification. Indeed, accurate reporting supports the strategic management of risks and opportunities related to GHG, the definition of objectives and the assessment of progress. Eni GHG Protocol has been updated in 2016 to be in compliance with the National and European Guidelines (Regulation No. 601/2012) and with the best practices reference document (American Petroleum Industry Compendium). For safer and more accurate management of GHG emissions and more effective reporting, Eni provided all its business units with a dedicated database, in order to gather and report GHG emissions according to the Protocol and to ensure completeness, accuracy, transparency and consistency of GHG accounting as required by certification needs. In order to improve the Eni accounting and reporting process, Eni confirmed independent verification of its 2016 equivalent CO2 emissions data (Scope 1, 2 and 3 emissions), as submitted to the CDP, and obtained the verification statement2019 Annual Report published in accordance with ISAE 3410.
In Europe, Eni is subject to the European Union Emission Trading Scheme (EU-ETS) that was establishedItalian law and practice. These reports are not incorporated by Directive No. 2003/87/EC. Effective from January 1, 2005, EU-ETS is the largest carbon marketreference in the world for exchanging emission allowances targeting industrial installations with high carbonthis Form 20-F.
dioxide emissions. The EU-ETS Directive states that any operator, who produces GHG emissions in excess of the amounts allowed on the basis of the national allocation plan, is required to acquire allowances on the market to cover the excess emissions or to pay a penalty.
Currently, Eni participates in the ETS with 41 plants, mostly located in Italy, which collectively represent 49% of all direct GHG emissions generated by Eni’s plants worldwide. Due to stricter allocation rules in the third phase (2013-2020) of the Emissions Trading Scheme, Eni has been receiving a lower amount of free allowances in comparison with the second phase (2008-2012). As a consequence, in the next four-year period (2017-2020), Eni will buy on the market an amount of allowances to cover GHG emissions of its industrial plants. The large majority of the deficit is concentrated in the power sector due to European allocation rules.
For additional information on Eni’s climate strategy and GHG management, please refer to the latest Eni’s Corporate Sustainability Report (“Enifor”) or to the Eni’s CDP climate change questionnaire response, both published on Eni’s website (www.eni.com).
Regulation of Eni’s businesses Overview The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments. Regulation of exploration and production activities Eni’s exploration and production activities are conducted in many countries and are therefore subject to a broad range of legislation and regulations. These cover virtually all aspects of exploration and production activities, including matters such as license acquisition, production rates, royalties, pricing, environmental protection, export, taxes and foreign exchange. The terms and conditions of the leases, licenses and contracts under which these oil&gas interests are held vary from country to country. These leases, licenses and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements usually take the form of licenses or production sharing agreements. See “Regulation of the Italian hydrocarbons industry” and “Environmental matters” for a description of the specific aspects of the Italian regulation and of environmental regulation concerning Eni’s exploration and production activities. Licenses (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a license, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the license holder is entitled to all production minus any royalties that are payable in-kind. A license holder is generally required to pay production taxes or royalties, which may be in cash or in-kind. Concession contracts currently applied mainly in Western countries regulating relationships between States and oil companies with regards to hydrocarbon exploration and production activity. Both exploration and production licenses are generally for a specified period of time (except for production licenses in the United States which remain in effect until production ceases). The term of Eni’s licenses and the extent to which these licenses may be renewed vary by area. In production sharing agreements, entitlementsContractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to production volumes are defined on the basis of contractual agreements drawn up with state oil companieshydrocarbon reserves. The company holding the concessions. Such contractual agreements regulate the recovery of costs incurred for themining concession has an exclusive right on exploration, development and operatingproduction activities, (Cost Oil)sustaining all the operational risks and give entitlementcosts related to the exploration and development activities, and it is entitled to the productions realized. As a compensation for mineral concessions, pays royalties on production (which may be in cash or in-kind) and taxes on oil revenues to the state in accordance with local tax legislation. Proved reserves to which Eni is entitled are determined by applying Eni’s share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. Eni operates under Production Sharing Agreement (PSA) in several foreign jurisdictions mainly in African, Middle Eastern and Far Eastern countries. The mineral right is awarded to the national oil company jointly with the foreign oil company that has an exclusive right to perform exploration, development and production activities and can enter into agreements with other local or international entities. In this type of contract, the national oil company assigns to the international contractor the task of performing exploration and production with the contractor’s equipment (technologies) and financial resources. Exploration risks are borne by the contractor and production is divided into two portions: “Cost Oil” is used to recover costs borne by the contractor and “Profit Oil” is divided between the contractor and the national company according to variable schemes and represents the profit deriving from exploration and production. Further terms and conditions of these contracts may vary from country to country. Pursuant to these contracts, Eni is entitled to a portion of a field’s reserves, the sale of which is intended to cover expenditures incurred by the Company to develop and operate the field. The Company’s share of production volumes exceeding volumes destinedand reserves representing the Profit Oil includes the share of hydrocarbons which corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. Therefore, the Company recognizes at the same time an increase in the taxable profit, through the increase in revenues, and a tax expense. Proved reserves to which Eni is entitled under PSAs are calculated so that the sale of production entitlements should cover costsexpenses incurred by the Group to develop a field (Cost Oil) and recognize the Profit Oil set contractually (Profit Oil). A similar scheme to PSA applies to Service and “buy-back” contracts.
In general, Eni is required to pay income tax on income generated from production activities (whether under a license or PSA). The taxes imposed upon oil&gas production profits and activities may be substantially higher than those imposed on other businesses.
Regulation of the Italian hydrocarbons industry The matters regarding the effects of recent or proposed changes in Italian legislation and regulations or EU directives discussed below and elsewhere herein are forward-looking statements and involve risks and uncertainties that could cause the actual results to differ materially from those in such forward-looking statements. Such risks and uncertainties include the precise manner of the interpretation or implementation of such legal and regulatory changes or proposals, which may be affected by political and other developments. Exploration & Production The Italian hydrocarbons industry is regulated by a combination of constitutional provisions, statutes, governmental decrees and other regulations that have been enacted and modified from time to time, including legislation enacted to implement EU requirements (collectively, the “Hydrocarbons Laws”). Exploration permits and production concessions. Pursuant to the Hydrocarbons Laws, all hydrocarbons existing in their natural condition in strata in Italy or beneath its territorial waters (including its continental shelf) are the property of the State. Exploration activities require an exploration permit, while production activities require an exploiting concession, in each case granted by the Minister of Economic Development. The initial duration of an exploration permit is six years, with the possibility of obtaining two three-year extensions and an additional one-year extension to complete activities underway. Upon each of the three-year extensions, 25% of the area under exploration must be relinquished to the State (only for initial acreages larger than 300 square kilometers). The initial duration of a production concession is 20 years, with the possibility of obtaining a ten-year extension and additional five-year extensions until the field depletes. These provisions are to be coordinated with a new law effective as of February 12, 2019 (Law 12/2019 – ex “D.L. Semplificazioni”), which requires certain Italian administrative bodies to define within eighteen months a plan (PiTESAI) aiming to identify areas that are suitable for carrying out exploration, development and production of hydrocarbons in the national territory, including the territorial seawaters. Until approval of such a plan, (within two years) it is established a moratorium on exploration activities, including the award of new exploration leases. Following the plan approval, exploration permits resume their efficacy in areas that have been identified as suitable; on the contrary, in unsuitable areas, exploration permits are repealed. As far as development and production concessions are concerned, pending the national plan approval ongoing concessions retain their efficacy and administrative procedures underway to grant extension to expired concession remain unaffected; instead no applications to obtain new concession can be filed. Once the above mentioned national plan is adopted, development and production concessions that fall in suitable areas can be granted further extensions and applications for new concessions can be filed; on the contrary development and production concessions current at the approval of the national plan that fall in unsuitable areas are repealed at their expiration and no further extensions can be granted, nor new concession applications can be filed. In case Italian administrative bodies fail to adopt the national plan for suitable areas within thirty months from the law enactment, the general moratorium on exploration activities is revoked and application for new concession permits can be filed. According to the statute, areas that suitable to the activities of exploring and developing hydrocarbons must conform to a number of criteria including morphological characteristics and social, urbanistic and industrial constraints, with particular bias for the hydrogeological balance, current territorial planning and with regard to marine areas for externalities on the ecosystem, reviews of marine routes, fishing and any possible impacts on the coastline. Moreover, the above mentioned law, starting from June 1, 2019, increases by 25 fold the current annual fee for all licensees (exploration permits and production concessions). Finally, it’s worth to mention two further legislative measures recently approved: •
the Fiscal decree no. 124/2019, converted into Law 157/2019which established (art. 38), starting from 2020, the property tax on marine structures (IMPI);
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the Law 8/2020 – “D.L. Milleproroghe” which extends the time required for definition of PiTESAI by further 6 months (until February 2021) and the moratorium for prospecting and research by 6 months (until August 2021). Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. As per Legislative Decree No. 625 of November 25, 1996, subsequent modifications and integrations (the last modification was introduced by Law 160/2019 – Budget Law 2020, art. 1 par. 736 & 737) and Law Decree No. 83 of June 22, 2012, royalties are equal to 10% for gas and oil productions onshore, to 10% for gas and 7% for oil offshore, with fixed amount of exemption. Onlyexemptions only for on shore gas concessions with production lower than 10 Msmc/year and off shore gas concessions with production lower than 30 Msmc. (Only in the Autonomous Region of Sicily, following the Regional Law No. 9 of May 15, 2013, royalties onshore for oil and gas are equal to 20% for oil&gas,20,06%, with no exemptions). Gas & Power NaturalWholesale gas market in Italy
Legislative Decree No. 130 of August 13, 2010 containing measures for increasing competitionIn the last decade, and even more in the naturallast years, a number of new rules have been introduced in order to improve liquidity and efficient functioning of the Italian wholesale gas market, fostering competition and transferring the ensuing benefits to final customers and Law Decree of December 23, 2013 containing measures to promote gas market liquidity
In 2011, Legislative Decree No. 130 of August 13, 2010 titled “New measures to improve competitiveness in the natural gas market and to ensure the transfer of economic benefits to final customers” became effective. This new regulation replaced the previous system of gas antitrust thresholds defined by Legislative Decree No. 164 of May 23, 2000 by introducing a 40% ceiling to the wholesale market share of each Italian gas operator who inputs gas into the Italian backbone network. In the frame of Legislative Decree No. 130/2010 Eni built new storage capacity for about 2.64 BCM; as a consequence the above mentioned cap to its market share in Italy rises from 40% to 55%. In the case of violations of the mandatory threshold, Eni is obliged to execute gas release measures at regulated prices up to 4 BCM over a two-year period following the ascertainment of the breach. Access to the new storage capacity was reserved to industrial customers.
The Law Decree of December 23, 2013, converted into Law on February 21, 2014, establishes that any operator with a wholesale market share higher than 10% is obliged to offer on the natural gas forward market a volume of natural gas corresponding to 5% of the annual imported volumes. The obligation to offer should be combined with a corresponding obligation to bid on the same market;time improving the spread between bid and ask prices has tosystem security of supply. Among such new rules, it could be lower than an amount defined by the Minister of Economic Development, based on a proposal by the AEEGSI. AEEGSI also defines the modalities for the fulfillment of the above mentioned obligation. worth mentioning:
Eni’s management is monitoring these issues with a view of assessing any possible financial or economic impact associated with the enacted measures and their evolution. Management also believes that these regulations will increase competition in the wholesale natural gas market in Italy leading to further margin pressures.
Law Decree No. 1 of January 24, 2012 for new liberalization measures in Italy
Law Decree No. 1 enacted by the Italian Government on January 24, 2012, the so-called Liberalization Decree was converted to Law No. 20 on March 24, 2012. This law aimed to:
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enhance competitiveness in gas tariffs to residential customers and in the distribution of refined products. The AEEGSI, in charge with setting pricing mechanisms for supplies to final users, starting from the second quarter of 2012 updated the indexation mechanism by gradually increasing the weight of spot prices in the indexation of the supply costs of gas that previously used to be oil-linked; and
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reform the storage system introducing market-basedMarket based mechanisms for the allocation of storage capacity,capacities and of regasification capacities: moving away from the traditional “pro-rata”/tariff system,allocation criteria based on tariffs, new auction mechanisms were implemented that enabled market players to express the market-value of storage and withof regasification capacities, while at the aimsame time ensuring the allowed revenues of storage operators and LNG terminal operators by means of specific parallel measures. Thanks to reducethese reforms, much higher levels of capacity bookings have become structural for both types of infrastructures, and more LNG deliveries have been attracted recently to the costcountry, to the benefit of natural gas for industrial customers. In particular:security of supply and of market competition.
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for an amount determined by the Ministry itself, storage capacity is primarily reserved for the offer to industrial sector of an integrated service (international transport of liquefied natural gas, regasification and storage) allowing them to supply natural gas directly from abroad in the form of liquefied natural gas; and
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the remaining amount of storage capacity is assigned via auction procedures devoted to the modulation needs.
Based on the principles described above, the Minister of Economic Development and the AEEGSI establish every year the detailed criteria for the allocation of gas storage capacities. In 2016, 1BCM of bundled storage and regasification capacity was offered to the industrial sector.
NegotiationAn organized market platform (MGAS) for gas trading and gas balancing market,
In compliance with managed by the provisions of Law No. 99 of July 23, 2009, on March 18, 2010, the Ministry of Economic Development published a decree that implements a trading platform for natural gas from May 10, 2010 aimed at increasing competition and flexibility on wholesale markets. Management and organization of this platform (MGAS) are entrusted to an independent operator the Gestore dei Mercati Energetici (GME), an Italian agency. In the MGAS, parties authorised to which also acts as a central counterparty, where different market participants (including TSO) can carry out spot and forward transactions at the “Punto di Scambio Virtuale” (PSV -
–
Virtual Trading Point) may make forward. In addition, since February 2018 voluntary market making activity has been introduced in the spot section of the gas exchange MGAS: such activity is based on the service provided by some liquidity providers, in order to boost liquidity and spot purchases and sales of volumes of natural gas. Intrading activity on the MGAS, GME playssame exchange, initially for the role of central counterpartyday-ahead market but with possible future extension to the transactions concluded by Market Participants.within-day section and to the forward section of the MGAS. In October 2016 the
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A new gas balancing regime, -entered into force in October 2016 as an evolution of the one already in place - has entered into force in the Italian systemand in compliance with the EU regulatory framework. This system is based on the principle that network users have to balance their daily position, also in accordance with the timely information provided by Snam Rete Gasthe TSO about the daily gas consumption. The new gas balancing regime provides for: •
the incentive for shippers to balance their position via penalizing imbalance prices and at the same time it provides the possibility for shippers to modify intra-day thetheir gas nominations;
•
the possibility for shippersflow nominations and to trade on the market with other shippers and/or with the TSO itself (that can access the market under some constraints, in order to address overall system balancing needs that may arise on top of shippers’ activities).
•
the incentive for shippers to balance their position via penalizing imbalance prices.
To foster market liquidity, starting from April 2017 all of the above-mentioned gas trading activities will be concentrated on the MGAS, managed by GME, as one single platform.
Management believes that these measuresnew regulation have already significantly increased and will further increase,continue increasing the level of liquidity and the competition in the Italian spotwholesale natural gas market of gas.in Italy, leading to possible margin pressures.
Natural gas prices in the retail sector in Italy Following the liberalization of the natural gas sector introduced in the year 2000 by Decree No. 164, prices of natural gas in the wholesale market which includes industrial and power generation customers are freely negotiated. However, the AEEGSI holdsARERA retains a power of surveillance on this matter (see below) underas per Law No. 481/1995 (establishing the AEEGSI)ARERA) and Legislative Decree No. 164/2000. Furthermore, the AEEGSIARERA is still
entrusted (as per the Presidential Decree dated October 31, 2002) with the power of regulating natural gas prices to residential customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which sell natural gas to residential customers are currently required to offer to those customers the regulated tariffs set by AEEGSIARERA beside their own price proposals. In 2013, a new tariff regime was fully enacted forby ARERA targeting Italian residential clients who are entitled to be safeguarded in accordance with current regulations. Clients who are eligible for the tariff mechanism set by the AEEGSIARERA are residential clients (including residential buildings consuming less than 200,000 CM/y).clients. With Resolution No. 196 effective from October 1, 2013, the AEEGSIARERA reformulated the pricing mechanism of gas supplies to those customers by providing a full indexation of the raw material cost component of the tariff to spot prices versusat the previousTTF (Title Transfer Facility) hub in Northern Europe, replacing the then current regime that provided a mix between an oil-based indexation and spot prices. The new tariff regime intended to partially offset the negative impact born by wholesalers due to possible indexation mismatches by introducing a pricing component intended to cover the risks and costs of the supplies to wholesalers.compensate wholesalers for losses that they would incur on those risks. Furthermore, it was provided a stability mechanism whereby a wholesaler part of a long-term, take-or-pay gas supply contract maycould opt for beingto be reimbursed offor the possible negative difference between the oil-linked costs of gas supplies and spot prices in the two thermal years following the implementation of the new regime implementation;regime; conversely, in case spot prices would fall below the oil-linked cost of gas supplies in the following two thermal years, the same wholesaler had to refund customers of the difference. Based on this compensation mechanism, which run out after September 2016, Eni totalled about €160 million of reimbursement over three thermal years, startingThose provisions explicated their effects in October 2013 and ending in September2014 – 2016. This tariff regime also reduced the tariff components intended to cover storage and transportation costs. Finally, it also increased the specific pricing component intended to remunerate certain marketing costs incurred by retail operators, including administrative and retention costs, losses incurred due to customer default and a return on capital employed. Furthermore,This new gas tariff indexation aiming at safeguarding the new tariff mechanism indexedhouseholds was initially intended to TTF (Title Transfer Facility) for residential clients will be applicable until the end of thermalremain effective till July 1, 2019 (as provided by Law 124/17). However, this deadline had been already prorogated by one year 2017 - 2018. However, a(as per Law Decree still under discussion at the Italian Parliament, is expected91/2018), and finally has been prorogated to increase competitive pressure with the abrogation of theJanuary 1st 2022. From that point onwards, households in Italy will no longer have access to regulated tariffs for gas supplies. Consumers will have to choose among the different pricing proposals made by gas selling companies. The ARERA has established that gas selling companies comply with certain requirements about the offerings to customers which include at least two pricing indexations (fixed and power effective from July 1, 2018. Referring tovariable), both complemented with contractual conditions regulated by the ARERA. Management believes that this development will increase competition in the Italian retail market for selling gas.
In the electricity market residential customers would choose tariffs on the free market, potentially, lower than the regulated ones. For the gas market, similar competitive impact cannotprices phase out will be excluded following the adoption of the same price regulation regime.effective: from January 1st 2021 for small enterprises (enterprise which employs fewer than 50 persons and whose annual turnover and/or annual balance sheet total does not exceed 10M€) and from January 1st 2022 for households and microenterprises (enterprise which employs fewer than 10 persons and whose annual turnover and/or annual balance sheet total does not exceed 2M€). Similarly other Regulatory Authorities in European countries where Eni is present have issued regulations referring to hub component in the pricing formulas related to retail clients, as well as measures to boost liquidity and competitivenessOther regulatory developments in the gas and electric sector in Italy and Europe
Within the scope of access criteria to the main gas logistic infrastructures, and of the related access costs, the risk factors for the business are linked to the periodic processes by which each European country reviews the definition of economic conditions and access rules for transportation, LNG regasification and storage services. Concerning gas transportation tariffs, in Italy and in some of the main European countries the revision processes aimed at defining the tariff criteria applicable for the next regulatory period (2020-2023) were recently concluded, with overall positive effects; possible new changes may concern the regasification sector, featuring either risks or opportunities for the business. Besides, in the coming years the gas sector regulation could be concerned by modifications, potentially relevant, linked to the adjustments that will be necessary because of the evolution of European policies and regulations in the energy transition context, coherently with the decarbonization targets in the energy sector and, therefore, with the related development of renewable and decarbonized gases and new technologies enabling higher integration between the gas and the power sectors.
With regard to power sector, Italian Capacity Market auctions, taken place in November 2019, allocated capacity with delivery in 2022 and 2023 to the power producers. During the delivery period the operators selected by the auctions will receive a fixed premium and, in return for this payment, they must i) offer power capacity on energy markets (day-ahead Market and intraday Market) and/or balancing market (the so called “MSD”) ii) pay the difference between a market reference price and a pre-determined strike price whenever the reference price exceeds the strike price. Eni has been awarded all the capacity offered in the tenders so it will receive a net benefit for its existing Eni group’s power plants during the delivery period (2022 and 2023) and for a new power plant, that will be built in Ravenna, for a period of fifteen years (starting from 1.1.2023). This benefit is affected by the risk that the tenders could be canceled due to the administrative appeal filed by some power companies against the tender procedure. Besides, in the next years Italian power market design could significantly change due to the implementation of European market model. The main innovations concern: introduction of negative prices, starting of new intraday Market based on continuous trading and gate-closure close to delivery period (h -1 gate closure), fostering the cross-border integration of European energy and balancing market (coupling of intraday market, coupling of balancing reserves markets). Management believes that this development will increase competition, in particular in the Italian balancing market. Refining and marketing of petroleum products Refining. The current regulations introduced with Law No. 9/1991 and No. 239/2004 (Article 1, paragraphs 56, 57 and 58) significantly changed the norms introduced in the 1930’s that required that anyon refining activity be handled under a concession from the state. Today an authorization is requiredin Italy provides that Italian administrative bodies authorize plans filed by refining operators intended to set up new processing and storage plants and for any change in theto upgrade capacity, of mineral processing plants, while all other changes that do not affect capacity can be freely implemented. Another simplification measureThis regime was introducedstreamlined by Law Decree No. 5/2012 that defined mineral oil processing and storage plants as “strategic settlements”installations” that need authorization from the State, in agreement with the relevant Region, and imposeslocal administrations. The Decree introduced a singleunitized process of authorization that must be closedfinalized within 180 days. Management expects nodays, subject to compliance with applicable environmental regulations. the company has not experienced any material delays in obtaining relevant concessions for the upgrading of the Sannazzaro and Taranto refineries as planned in the medium term.underway.
Marketing. Following the enactment of the above mentionedabove-mentioned Law Decree No. 1 on January 24, 2012, certain measures are expected to be introduced in order to increase levels of competition in the retail marketing of fuels. The rules regulating relations between oil companies and managers of service stations have been changed introducing the difference between principal and non-principal of a service station. Starting from June 30, 2012, principals will be allowed to freely supply freely up to 50% of their requirements. In such case, the distributing company will have the option to renegotiate terms and conditions of supplies and brand name use. As for non-principals, the law allows the parties to renegotiate terms and conditions at the expiration of existing contracts and new contractual forms can be introduced in addition to the only one allowed so far, i.e. exclusive supply. The law also provides for an expansion of non-oil sales. Eni expects developments on this issue to further increase pressure on selling marginsFurthermore, the law 205/2017 provides some measures for preventing of tax evasion in the retail marketingsale of fuels andoil products that in the past produced anticompetitive effects on the sector. The law requires the advance payment of Value Added Tax (VAT) on oil products before the extraction from deposits or the sale to reduce opportunities of increasing Eni’s market share in Italy.consumer. Service stations. Legislative Decree No. 32 of February 11, 1998, as amended by Legislative Decree No. 346 of September 8, 1999 and Law Decree No. 383 of October 29, 1999, as converted in Law No. 496 of December 28, 1999, significantly changed Italian regulation of service stations. Legislative Decree No. 32 replaces the system of concessions granted by the Ministry of Industry, regional and local authorities with an authorization granted by city authorities while the Legislative Decree No. 112 of March 31, 1998 still confirms the system of such concessions for the construction and operation of service stations on highways and confers the power to grant to Regions. Decree No. 32 also provides for: (i) the testing of compatibility of existing service stations with local planning and environmental regulations and with those concerning traffic safety to be performed by city authorities; (ii) upon the closure of at least 7,000 service stations, the option to extend by 50% the opening hours (currently 52 hours per week) and a generally increased flexibility in scheduling opening hours; (iii) simplification of regulations concerning the sale of non-oil products and the permission to perform simple maintenance and repair operations at service stations; and (iv) the opening up of the logistics segment by permitting third party-party access to unused storage capacity for petroleum products. WithSubsequently, various regulations have been enacted in Italy with the same goalaim of renewing the Italian distributionimproving network Law No. 57 of March 5, 2001 provides that the Ministry of Productive Activities is to prepare guidelines for the modernization of the network,efficiency, modernizing service stations and the Regions shall follow those guidelines in the preparation of regional plans. The subsequent Ministerial Decree of October 31, 2001 establishes the criteria for the closing down of incompatible stations, the approval of the plan, the renewal of the network, the opening up of new stations and the regulations of the operations of service stations on matters such as automation, working hours and non-oil activities. After the approval of Law No. 133/2008, Article 28 of Law Decree No. 98/2011 converted into Law No. 111/2011, contains new guidelines for improving market efficiency and service quality and increasing competition. Among other things it provides that within July 6, 2012market. Currently, all service stations must beare provided with self-service equipment and that Regions will update their regulations in order to allow the sale of non-oil products in all service stations. has been broadly introduced by local administrative bodies.
Law Decree No. 1/2012 also allowed the installation of fully automated service stations with prepayment, but only outside city areas. Law No. 133 of August 6, 2008, by intervening in competition provisions, removes some national and regional regulations, which might prejudicelimit the liberty of establishment and introduces new provisions particularly concerning the elimination of restrictions concerning distances between service stations, the obligation to undertake non-oil activities and the liberalization of opening hours. The new regulatory framework provided by the legislative decree No 257/2016 – implementing EU Directive 2014/94/UE on alternative fuel infrastructures – has introduced minimum requirements for the construction of infrastructure for the development of alternative fuels to mitigate the environmental impacts of the transport sector. The legislation established, furthermore, an adequate number of charging stations accessible to the public to be created throughout the country by 2020. Finally, Law no. 124/2017 aims to promote the structural reorganization of the fuel distribution network also in order to increase competition and efficiency. The law requires the closure of fuel stations that are incompatible with road safety regulations and environmental streamlining procedures for the decommissioning. Management believes that thosethese measures will favor competition in the Italian retail market and enhance the competitiveness of efficient players. In order to support efficient operators.the achievement of the renewables target in the transport sector established by the EU and national laws, the Ministerial Decree of March 2, 2018, provides the legislative framework to incentivize the production of both biomethane and other advanced biofuels to be used in the transport sector. The Decree provides incentives for plants starting operations between 2018 and 2022 and to plants that are converted to biomethane production. The incentive consists in an allocation of a Certificate (CIC) for every 10 Gcal of biomethane produced. The certificate has a market value since fossil fuel marketers have to sell a minimum percentage of biofuels annually, for which they receive the same Certificates. In order to access to incentives, producers must comply with legal and technical regulations governing the quality and certification of the produced biomethane, verified by the competent Authority (Gestore dei Servizi Energetici, GSE). These measure aims to favor advanced biofuels production through the valorization of waste, notably of agricultural and farm/zoo technical waste. Law no. 128/2019 anticipated the transposition of the EU regulation on End of Waste and the authorization stall has been unlocked. Italian Regions can now authorize the recycling and recovery systems “on a case-by-case basis”, pending the adoption of the regulations on individual processes. The Directive (EU) 2018/2001 on the promotion of the use of energy from renewable sources confirms the use of some wastes as feedstock for the production of biofuels and allows the calculation of recycled carbon fuels for the purposes of the transport target, based on the criteria that will be issued by the European Commission. The directive must be transposed by June 30, 2021. In 2019, the Law no 157/2019 introduced a set of measures to prevent illegal conduct/practices linked to fiscal fraud for the exchange of products in the fuel retail market. These regulatory initiatives will also address for more competition and efficiency of the sector. With several Acts (Law no 157/2019 and Law no 141/2019) and 2020 budget law, new measures for sustainable mobility have been adopted in order to decarbonize the transport sector, through incentive mechanisms for low-emission vehicles. Petroleum product pricesprices.. Petroleum productproducts’ prices were completely deregulated in May 1994 and are now freely established by operators. Oil and gas companies periodically report their recommended prices to the Ministry of Productive Activities;Economic Development; such recommendations are considered by service station operators in establishing retail prices for petroleum products. Compulsory stocksstocks.. According to Legislative Decree of January 31, 2001, No. 22 (“Decree 22/2001”) enacting Directive No. 1993/98/EC (which regulates the obligation of Member States to keep a minimum amount of stocks of crude oil and/or petroleum products) compulsory stocks, must be at least equal to the quantities required by 90 days of consumption of the Italian market (net of oil products obtained by domestically produced oil). In order to satisfy the agreement with the International Energy Agency (Law No. 883/1977), Decree No. 22/2001 increased the level of compulsory stocks to reach at least 90 days of net import, including a 10% deduction for minimum operational requirements. Decree No. 22/2001 states that compulsory stocks are determined each year by a decree of the Minister for Economic Development based on domestic consumption data of the previous year, defining also the amounts to be held by each oil
company on a site-by-site basis. The Legislative Decree No. 249/2012, entered into force on February 10, 2013 to implement the Directive No. 2009/119/EC (imposing an obligation on Member States to maintain
minimum stocks of crude oil and/or petroleum products), sets forth in particular: (a) that a high level of oil security of supply through a reliable mechanism to assure the physical access to oil emergency and specific stocks shall be kept; and (b) the institution of a Central Stockholding Entity under the control of the Ministry for Economic Development that should be in charge of: (i) the purchase, holding, sell and transportation of specific stocks of products; (ii) the stocktaking; (iii) the statistics on emergency, specific and commercial stocks; and, eventually (iv) the storage and transportation service of emergency and commercial stocks in favor of sellers of petroleum products not vertically integrated in the oil chain. As of December 31, 2016,2019, Eni owned 5.25,6 mmtonnes of oil products inventories, of which 3.63,2 mmtonnes as “compulsory stocks”, 1.42,2 mmtonnes related to operating inventories in refineries and deposits (including 0.2 mmtonnes of oil products contained in facilities and pipelines) and 0.2 mmtonnes related to specialty products. Eni’s compulsory stocks were held in term of crude oil (37%(34%), light and medium distillates (37%), refinery feedstock (19%(20%), fuel oil (5%(4%) and other products (2%(5%) were located throughout the Italian territory both in refineries (80%(85%) and in storage sites (20%(15%). Competition Like all Italian companies, Eni is subject to Italian and EU competition rules. EU competition rules are set forth in Articles 101 and 102 of the Lisbon Treaty on the Functioning of the European Union entered into force on December 1, 2009 (“Article 101” and “Article 102”, respectively being the result of the new denomination of former Articles 81 and 82 of the Treaty of Rome as amended by the Treaty of Amsterdam dated October 2, 1997 and entered into force on May 1, 1999) and EU Merger Control Regulation No. 139 of 2004 (EU Regulation 139). Article 101 prohibits collusion among competitors that may affect trade among Member States and that has the object or effect of restricting competition within the EU. Article 102 prohibits any abuse of a dominant position within a substantial part of the EU that may affect trade among Member States. EU Regulation 139 sets certain turnover limits for cross-border transactions, above which enforcement authority rests with the European Commission and below which enforcement is carried out by national competition authorities, such as the Antitrust Authority in the case of Italy. On May 1, 2004, a new regulation of the European Council came into force (No. 1/2003) which substitutes Regulation No. 17/1962 on the implementation of the rules on competition laid down in Articles 101 and 102 of the Treaty. In order to simplify the procedures required of undertakings in case of conducts that potentially fall within the scope of Article 101 and 102 of the Treaty, the new regulation substitutes the obligation to inform the Commission with a self-assessment by the undertakings that such conducts doesdo not infringe the Treaty. In addition, the burden of proving an infringement of Article 101(1) or of Article 102 of the Treaty shall rest on the party or the authority alleging the infringement. The undertaking or association of undertakings claiming the benefit of Article 101(3) of the Treaty shall bear the burden of proving that the conditions of that paragraph are fulfilled. The regulation defines the functions of authorities guaranteeing competition in Member States and the powers of the Commission and of national courts. The Competition Authorities of the Member States shall have the power to apply Articles 101 and 102 of the Treaty in individual cases. For this purpose, acting on their own initiative or on a complaint, they may take the following decisions: •
requiring that an infringement be brought to an end; •
ordering interim measures; •
accepting commitments; and •
imposing fines, periodic penalty payments or any other penalty provided for in their national law. National courts shall have the power to apply Articles 101 and 102 of the Treaty. Where the Commission, acting on a complaint or on its own initiative, finds that there is an infringement of Article 101 or of Article 102 of the Treaty, it may: (i) require the undertakings and associations of undertakings concerned to bring such infringement to an end; (ii) order interim measures; (iii) make commitments offered by undertakings to meet the concerns expressed to them by the Commission binding on the undertakings; and (iv) find that Articles 101 and 102 of the Treaty are not applicable to an agreement for reasons of Community public interest. Eni is also subject to the competition rules established by the Agreement on the European Economic Area (the “EEA Agreement”), which are analogous to the competition rules of the Lisbon Treaty (ex Treaty of Rome) and apply to competition in the European Economic Area (which consists of the EU and Norway, Iceland and Liechtenstein). These competition rules are enforced by the European Commission and the European Free Trade Area Surveillance Authority.
In addition, Eni’s activities are subject to Law No. 287 of October 10, 1990 (the “Italian Antitrust Law”). In accordance with the EU competition rules, the Italian Antitrust Law prohibits collusion among
competitors that restricts competition within Italy and prohibits any abuse of a dominant position within the Italian market or a significant part thereof. However, the Italian Antitrust Authority may exempt for a limited period agreements among companies that otherwise would be prohibited by the Italian Antitrust Law if such agreements have the effect of improving market conditions and ultimately result in a benefit for consumers. Property, plant and equipment Eni has freehold and leasehold interests in real estate in numerous countries throughout the world. The Company enters into operating lease contracts with third parties to hire plant and equipment such as floating production and storage offloading vessels (FPSO), drilling rigs, time charter, service stations and other equipment. Management believes that certain individual petroleum properties are of major significance to Eni as a whole. Management regards an individual petroleum property as material to the Group in case it contains 10% or more of the Company’ worldwide proved oil&gas reserves and management is committed to invest material amounts of expenditures in developing it in the future. See “Exploration & Production” above for a description of Eni’s both material and other properties and reserves and sources of crude oil and natural gas. Organizational structure Eni SpA is the parent company of the Eni Group. As of December 31, 2016,2019, there were 218225 subsidiaries and 103110 associates, joint ventures and joint operations that were accounted for under the equity or cost method or in accordance to Eni’s share of revenues, costs and assets of the joint operations calculated based on Eni’s working interest. Information on Eni’s investments as of December 31, 20162019 is provided in Note 48the notes to the Consolidated Financial Statements. Item 4A. UNRESOLVED STAFF COMMENTS None.
Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS This section is the Company’s analysis of its financial performance and of significant trends that may affect its future performance. It should be read in conjunction with the Key Information presented in Item 3 and the Consolidated Financial Statements and related Notes thereto included in Item 18. The Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards as issued by the IASB. This section contains forward-looking statements, which are subject to risks and uncertainties. For a list of important factors that could cause actual results to differ materially from those expressed in the forward-looking statements, see the cautionary statement concerning forward-looking statements on page ii. Executive summary Key consolidated financial data | | | | | | | | | | | | | | 2014 | | | 2015 | | | 2016 | | | | | | | | (€ million) | | Net sales from operations from continuing operations | | | | | 98,218 | | | | | | 72,286 | | | | | | 55,762 | | | Operating profit (loss) from continuing operations | | | | | 8,965 | | | | | | (3,076) | | | | | | 2,157 | | | Net profit (loss) attributable to Eni from continuing operations | | | | | 1,720 | | | | | | (7,952) | | | | | | (1,051) | | | Net profit (loss) attributable to Eni from discontinued operations | | | | | (417) | | | | | | (826) | | | | | | (413) | | | Net profit (loss) attributable to Eni | | | | | 1,303 | | | | | | (8,778) | | | | | | (1,464) | | | Net cash provided by operating activities - continuing operations | | | | | 14,469 | | | | | | 12,875 | | | | | | 7,673 | | | Capital expenditures - continuing operations | | | | | 11,178 | | | | | | 10,741 | | | | | | 9,180 | | | Investments and purchases of consolidated subsidiaries and businesses | | | | | 408 | | | | | | 228 | | | | | | 1,164 | | | Shareholders’ equity including non-controlling interest at year end | | | | | 65,641 | | | | | | 57,409 | | | | | | 53,086 | | | Net borrowings at year end | | | | | 13,685 | | | | | | 16,871 | | | | | | 14,776 | | | Net profit (loss) attributable to Eni basic and diluted from continuing operations | | | (€ per share) | | | | | 0.48 | | | | | | (2.21) | | | | | | (0.29) | | | Net profit (loss) attributable to Eni basic and diluted from discontinued operations | | | | | (0.12) | | | | | | (0.23) | | | | | | (0.12) | | | Net profit (loss) attributable to Eni basic and diluted | | | | | 0.36 | | | | | | (2.44) | | | | | | (0.41) | | | Dividend per share | | | (€ per share) | | | | | 1.12 | | | | | | 0.80 | | | | | | 0.80 | | | Ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage)(1) | | | | | 0.21 | | | | | | 0.29 | | | | | | 0.28 | | | |
| | | | | | 2019 | | | 2018 | | | 2017 | | | | | | | | (€ million) | | Sales from operations | | | | | 69,881 | | | | | | 75,822 | | | | | | 66,919 | | | Operating profit (loss) | | | | | 6,432 | | | | | | 9,983 | | | | | | 8,012 | | | Net profit (loss) attributable to Eni | | | | | 148 | | | | | | 4,126 | | | | | | 3,374 | | | Net cash provided by operating activities | | | | | 12,392 | | | | | | 13,647 | | | | | | 10,117 | | | Capital expenditures | | | | | 8,376 | | | | | | 9,119 | | | | | | 8,681 | | | Acquisitions | | | | | 3,008 | | | | | | 244 | | | | | | 510 | | | Disposal of assets, consolidated subsidiaries and businesses | | | | | 504 | | | | | | 1,242 | | | | | | 5,455 | | | Shareholders’ equity including non-controlling interest | | | | | 47,900 | | | | | | 51,073 | | | | | | 48,079 | | | Finance debt (including lease liabilities) | | | | | 30,166 | | | | | | 25,865 | | | | | | 24,707 | | | Net borrowings(1) | | | | | 17,125 | | | | | | 8,289 | | | | | | 10,916 | | | Net profit (loss) attributable to Eni basic and diluted | | | (€ per share) | | | | | 0.04 | | | | | | 1.15 | | | | | | 0.94 | | | Dividend per share | | | (€ per share) | | | | | 0.86 | | | | | | 0.83 | | | | | | 0.80 | | | Ratio of finance debt (including lease liabilities) to total shareholders’ equity | | | | | 0.63 | | | | | | 0.51 | | | | | | 0.51 | | | Ratio of net borrowings to total shareholders’ equity (leverage)(1) | | | | | 0.36 | | | | | | 0.16 | | | | | | 0.23 | | |
(1)
For a discussion of the usefulness and a reconciliation of these non-GAAP financial measures with the most directly comparable GAAP financial measures see - “Liquidity– "Liquidity and capital resources -– Financial Conditions”Conditions" below. Reported earnings In 2016,2019, net profit attributable to Eni’s shareholders was €148 million, much lower than in 2018 when net profit of €4,126 million was reported. The reported operating profit of €6,432 million was 36% lower than in 2018, down by €3.6 billion; approximately 80% of the decline is related to the E&P segment. The 2019 results were negatively affected by a challenging operating and trading environment, reflecting a slowdown in the global macroeconomic cycle, a deceleration in international trade triggered by the “trade dispute” between the US and China, as well as by adverse geopolitical developments that fueled uncertainty among market participants and directly affected Eni’s performance in certain areas. All of these factors have curbed demand for energy commodities and global consumption of fuels and plastics, increasing the negative impact of oil and gas overproduction on the segment results of our Exploration&Production business, while rising competition from producers with more efficient cost structures and overcapacity pressured margins in our downstream businesses of refining and chemicals. Against this backdrop, Eni reported a net loss pertaining to continuing operationsdecline in oil and gas realized prices, as well as in products margins in all of €1,051 million, with a significant improvement compared to last year’s loss of €7,952 million. Theits business segments. Prices and margins reductions negatively affected the reported operating profit was €2,157 million compared tofor an operating loss of €3,076 million a year ago.estimated €2.5 billion. The recoverymain negative factor were lower gas prices in oil markets, that has begun inall geographies with the second half of 2016 favorably affectedworst declines recorded by the full-year results of operations and the assets carrying amounts. Better market fundamentals were factored in an upward revision to management’s long-termEuropean benchmark gas spot price assumption for the benchmark Brent to 70$ per barrel (in 2020 real terms)“PSV”, which was adopted indown by 34% and negatively affected the financial projectionsrevenues of the 2017-2020 industrial plan and in assessingE&P segment relating sales volumes of equity gas. Furthermore, the recoverabilityresult of the Group assets carrying amounts asE&P segment was significantly and negatively affected by lower re-selling prices of December 31, 2016. In 2015, management assumedvolumes of gas entitlements of a long-term Brent price of 65$ per barrel. This upward revision triggered the reversal of prior impairment losses for €1,005 million post-tax at oil&gas properties, which helped mitigate impairment lossesLibyan partner due to a lowered outlook for gasdifferent indexation between the procurement costs, which were oil-linked, and the reselling price which was benchmarked to spot prices in Europe and other drivers, as well as other non-recurring charges for an overall negative impact of €831 million.
OnEurope. Due to different trends in the contrary,indexation, this resale activity resulted in a loss to Eni, which also negatively impacted the FY 2015 result was negatively affected by the recognition of material, post-tax charges of €8.5 billion. Those comprised impairment losses of upstream assets (€3.9 billion) and theGroup tax rate.
Prices realized at sales volumes of equity liquids were driven down by a reduction in prices of the main crude oil benchmarks, with the Brent price down by 9% for the year. Margins on sales of refined products, petrochemicals products and LNG also declined remarkably. The Group performance was also negatively affected by a number of incidents at production plants, such as the fire that occurred at the Priolo chemical cracker in January, and unplanned standstills or outages, like in the case of the Goliat oilfield in Norway, the Bayernoil refinery, the Porto Marghera and the Dunkerque crackers. These negative effects were partly offset by higher hydrocarbon production, a favorable product mix due to higher incidence of barrels with higher-than-average profitability, efficiency and optimization measures and steady results reported by the retail businesses, which include the gas & power retail segment as well as the marketing of fuels at both retail and wholesale markets, leveraging on effective marketing actions and continuing product/service innovation. Management estimated that this positive factors improved the operating profit by 5%. Furthermore, the operating profit was negatively affected by the incurrence of approximately €2.2 billion of impairment losses, which were mainly recorded at oil and gas properties and refineries driven by a revised refining margin scenario and downward reserve revisions and lower expected production rates. Net profit for the year was also negatively affected by lower net income from investments (down by €902 million), due to the fact that the 2018 financial statements accounted for the gains on the Vår Energi business combination (€889 million) and a reversal of a prior-year impairment loss of €262 million made at the Angola LNG equity-accounted entity. Finally, net profit was negatively affected by an increased tax rate, which was due to a higher share of taxable income reported by the Exploration & Production segment in countries subject to higher-than-average tax rates, a loss incurred in reselling volumes of gas entitlements of a Libyan partner, while taxable losses were recorded in jurisdictions with a lower-than-average statutory tax rate. The Group tax rate was also impacted by the write-off of deferred tax assets for €1.8of approximately €0.9 billion due to a lowered profitability outlook. Furthermore,projections of lower future taxable profit at Italian subsidiaries. Hydrocarbons production came at 1.74 mmBOE/d and was flat y-o-y. Considering constant prices at PSAs’entitlements and net of portfolio divestments and one-offs, production would have grown by 4% driven by Eni’s successful strategy of reducing the 2015 charges included the impairmenttime-to-market of the Chemical business (€1 billion), the carrying amount of which was aligned to the expected fair value based on a negotiation then ongoing to establish a joint venture with an industrial partner. Subsequently, Eni and the potential buyer failed to close the negotiation. Finally, other extraordinary charges of €1.8 billion were incurred mainlyits reserves as witnessed by new field start-ups in the G&P segment (for more information about extraordinary charges of G&P segment, seeyear and fast ramp-up at core projects like the paragraph “Operating profit by segment”)Zohr gas field in Egypt. The reserve replacement ratio was 117% on all-sources basis; when stripping out asset purchases and divestments the ratio was 92%. Nevertheless, the 2016 underlying performance was negatively affected by a continued slump in commodity prices especially in the first half of the year which determined y-o-y declines in average crude oil prices (down by 16.7%, from 52.5 $/b reported in 2015, to 43.7 $/b in 2016), gas prices (down by 28.2%) and refining margins (down by 49.4%). These declines drove a 23% reduction in the Group consolidated turnover. Other factors negatively affecting the performance were a four and half-month shutdown of the Val d’Agri oil complex in Italy and lower one-off gains in the Gas&Power segment in connection with an ongoing renegotiation process of its long-term gas supply contracts. Management implemented a number of initiatives to withstand the negative trading environment, including tight investment selection, with capex down by 15% (19% y-o-y at constant exchange rates), control of E&P operating expenses (down by 17%), optimizations of plant setup at refineries and chemical plants, savings on energy consumptions and logistic costs and G&A cuts. All these measures improvedAdjusted results
Adjusted operating profit and adjusted net profit are determined by around €1.7 billion. Finally, income taxes declined by €1,186 million due to the above mentioned extraordinary drivers. The tax rate was affected by the high relative incidence on taxable profit of results earned at PSA contracts, which are characterized by higher-than-average rates of taxes. Overall management estimated that the increase in the Group operating results of approximately €5.2 billion (from an operating loss of €3.08 billion in 2015 to a profit of €2.16 billion in 2016) was due to the following factors:
•
a positive €1.7 billion gain associated with efficiency initiatives, cost reductions, lower depreciation and amortization, as well as a decreased exploration expenditure;
•
a positive €8.6 billion effect due to lower asset impairments and lower other extraordinary charges as well as a lower inventory holding valuation allowance;
These positives were partly offset by:
•
a negative €3.3 billion impact due to lower commodity prices and margins;
•
a negative €0.6 billion effect due to the four and a half months shutdown of operations at the Val d’Agri profit centre (see Item 4 – Exploration & Production – Eni’s principal oil&gas properties) and in the Gas & Power segment lower one-off gains related to the renegotiations of gas contracts;
•
a negative €1.2 billion associated with the accounting of Saipem as discontinued operation in 2015. Due to this accounting method, the 2015 result of the continuing operations benefittedexcluding from the elimination upon consolidation of then intercompany purchases of capital goods and other services, mainly oilfield services to the E&P segment. This reflected the fact that in 2015 for accounting purposes Saipem was a fully consolidated subsidiary as Eni still exercised control at the balance sheet date. In 2016 due to the loss of control, Saipem was derecognized from the beginning of the year. Therefore, in 2016 the purchases of capital goods and services from Saipem were accounted as expenses from third parties incurred by the continuing operations.
In FY 2016, the Group net loss pertaining to Eni’s shareholders amounted to €1,464 million. This included a loss in the discontinued operations of €413 million relating to an impairment charge taken to align the book value of Eni’s retained interest in Saipem to its fair value, equal to the market capitalization at the date of loss of control (January 22, 2016) with a charge of €441 million.
The table below sets forth for the reported periods details of certain, identified gains and charges included in net loss. These gains and charges mainly related toresults inventory holding gains or losses and non-core gains and losses asset impairments, reversals(pre and post-tax, respectively) that in our view do not reflect the ordinary results of prior impairment losses, estimate revisions, risk and other provisions, write downs of deferred tax assets, capital gains on investments and other tangible assets.
| | | Year ended December 31, | | Eni Group | | | 2014 | | | 2015 | | | 2016 | | | | | (€ million) | | (Profit) loss on inventory | | | | | 1,460 | | | | | | 1,136 | | | | | | (175) | | | Environmental provisions | | | | | 179 | | | | | | 225 | | | | | | 193 | | | Impairment losses (impairment reversals), net | | | | | 1,272 | | | | | | 6,534 | | | | | | (459) | | | Impairment of exploration projects | | | | | | | | | | | 169 | | | | | | 7 | | | Net gains on disposal of assets | | | | | (24) | | | | | | (407) | | | | | | (10) | | | Risk provisions | | | | | (35) | | | | | | 211 | | | | | | 151 | | | Provision for redundancy incentives | | | | | 4 | | | | | | 30 | | | | | | 47 | | | Fair value gains/losses on commodity derivatives | | | | | (16) | | | | | | 164 | | | | | | (427) | | | Reclassification of currency derivatives and translation effects to management measure of business performance | | | | | 229 | | | | | | (63) | | | | | | (19) | | | Estimate revision of revenues accrued in the gas retail business | | | | | | | | | | | 484 | | | | | | 161 | | | Valuation allowance of disputed receivables | | | | | | | | | | | | | | | | | 410 | | | Write-off of the damaged units of the EST conversion plant at the Sannazzaro refinery | | | | | | | | | | | | | | | | | 193 | | | Provision for removal and clean-up of EST conversion plant | | | | | | | | | | | | | | | | | 24 | | | Compensation gain on part of a third-party insurer relating to the EST plant incident | | | | | | | | | | | | | | | | | (217) | | | Other | | | | | 303 | | | | | | 301 | | | | | | 279 | | | | | | | | | | | | | | | | | | | | | | | Total net charges (gains) in operating profit | | | | | 3,372 | | | | | | 8,784 | | | | | | 158 | | | Capital gains on disposal of investments | | | | | (159) | | | | | | (33) | | | | | | (57) | | | Write downs of investments and financing receivables | | | | | (38) | | | | | | 506 | | | | | | 483 | | | Write down of deferred tax assets/utilization of deferred tax liabilities | | | | | 1,045 | | | | | | 1,740 | | | | | | 170 | | | Gain on a tax dispute relating to the Libyan Tax | | | | | (824) | | | | | Tax effects on the above listed items and other items | | | | | (13) | | | | | | (1,321) | | | | | | (98) | | | Tax effects on (profit) loss on inventory | | | | | (452) | | | | | | (354) | | | | | | 55 | | | | | | | | | | | | | | | | | | | | | | | Net (charges) gains in net profit | | | | | 2,931 | | | | | | 9,322 | | | | | | 711 | | | Net (charges) gains attributable to non-controlling interest | | | | | 452 | | | | | | 53 | | | | | | | | | Net (charges) gains attributable to Eni | | | | | 2,479 | | | | | | 9,269 | | | | | | 711 | | | |
In evaluating the Company’s underlying performance and with the objective of better explaining year-on-year changes, management has considered to separate from the other drivers of the Group performance the impact of the following items:
•
the above listed gains and charges amounting to a post-tax loss of €9,269 million and €711 million in 2015 and in 2016, respectively, which include an inventory holding post-tax loss of €782 million in 2015 and a post-tax profit of €120 million in 2016; and
•
profit on intercompany transactions with the discontinued operations for €514 million in 2015, which are eliminated upon consolidation.
On that basis, management has calculated a Non-GAAP measure of operating profit that would amount to €2,315 million for 2016, down by €2,171 million from 2015. A low commodity price environment accounted for a decline of €3.3 billion, while a four-month and half shutdown of operations at Val d’Agri and lower non-recurring gains in G&P accounted for €0.6 billion. Efficiency gains and a
reduced cost base, mainly in the E&P segment, helped mitigate the negative factors and improved the performance by €1.7 billion. The corresponding Non-GAAP measure of net loss would amount to €340 million, down by €1,143 million from 2015 due to a lower operating performance, declining results from equity-accounted entities reflecting weak commodity prices and a higher Group tax rate mainly driven by the E&P segment.our operations.
Adjusted operating profit (or loss) and adjusted net profit (or loss) provide management with an understanding of the results from our baseunderlying operations by excluding the effects of certain disposals and special charges or gains that do not reflect the ordinary results of our operations. Adjusted measures of profitability are used to evaluate our period-over-period operating performance, as management believes these provide a more comparable measuremeasures as they adjust for disposals and special charges or gains not reflective of the normal trend results ofunderlying trends in our business. These Non-GAAP performance measures may also be useful to an investor in evaluating the underlying operating performance of our business and in comparing it with the performance of other oil&gas players, because the items excluded from the calculation of such measures can vary substantially from company to company depending upon accounting methods, management’s judgement,judgment, book value of assets, capital structure and the method by which assets were acquired, among other factors. In 2019, non-core items included impairment losses, risk and environmental provisions, extraordinary credit losses, net gains on the divestment of certain oil&gas properties, the accounting effect of certain fair-valued commodity derivatives lacking the formal criteria to be classified as hedges or to be eligible for the own use exemption and other non-core charges for a total negative of €2,728 million in net profit and of €2,165 million in operating profit, including an inventory pre-tax gain of €223 million (€157 million post-tax).
The table below sets forth details of the identified non-core gains and losses included in the net results during the period presented. | | | Year ended December 31, | | Eni Group | | | 2019 | | | 2018 | | | 2017 | | | | | (€ million) | | (Profit) loss on inventory | | | | | (223) | | | | | | 96 | | | | | | (219) | | | Environmental provisions | | | | | 338 | | | | | | 325 | | | | | | 208 | | | Impairment losses (impairments reversals), net | | | | | 2,188 | | | | | | 866 | | | | | | (221) | | | Net gains on disposal of assets | | | | | (151) | | | | | | (452) | | | | | | (3,283) | | | Risk provisions | | | | | 3 | | | | | | 380 | | | | | | 448 | | | Provision for redundancy incentives | | | | | 45 | | | | | | 155 | | | | | | 49 | | | Reinstatement of Eni Norge amortization charges(1) | | | | | | | | | | | (375) | | | | | | | | | Fair value gains/losses on commodity derivatives | | | | | (439) | | | | | | (133) | | | | | | 146 | | | Reclassification of currency derivatives and exchange effects to management measure of business performance | | | | | 108 | | | | | | 107 | | | | | | (248) | | | Estimate revision of revenues accrued in the gas retail business | | | | | | | | | | | | | | | | | 64 | | | Valuation allowance of doubtful accounts(2) | | | | | 123 | | | | | | | | | | | | 616 | | | Compensation gain on part of a third-party insurer relating to the EST plant incident | | | | | (88) | | | | | | | | | | | | | | | Other | | | | | 261 | | | | | | 288 | | | | | | 231 | | | Total net non-core items in operating profit | | | | | 2,165 | | | | | | 1,257 | | | | | | (2,209) | | | Finance expenses | | | | | (42) | | | | | | (85) | | | | | | 502 | | | of which: reclassification of currency derivatives and exchange effects to management measure of business performance | | | | | (108) | | | | | | (107) | | | | | | 248 | | | Capital gains on disposal of investments | | | | | (46) | | | | | | (909) | | | | | | (163) | | | Write downs of investments and financing receivables | | | | | 166 | | | | | | 67 | | | | | | 537 | | | Write down of deferred tax assets/utilization of deferred tax liabilities | | | | | 893 | | | | | | 99 | | | | | | | | | Tax effects relating to the US tax reform | | | | | | | | | | | | | | | | | 115 | | | Tax effects on the above listed items and other items | | | | | (474) | | | | | | 55 | | | | | | 160 | | | Tax effects on (profit) loss on inventory | | | | | 66 | | | | | | (27) | | | | | | 63 | | | Net non-core items in net profit | | | | | 2,728 | | | | | | 457 | | | | | | (995) | | | Net (charges) gains attributable to non-controlling interest | | | | | | | | | | | | | | | | | | | | Net non-core items attributable to Eni | | | | | 2,728 | | | | | | 457 | | | | | | (995) | | |
(1)
In 2018, management has evaluated to reinstate correlation between hydrocarbon production and reserve depletion by accruing the underlying UOP-based amortization charges of Eni Norge subsidiary classified in accordance to IFRS 5 due to the business combination with Point Resources. In the GAAP results, assets or disposal group held for sale are not to be depreciated or amortized. (2)
In 2019, this item relates to credit losses recognized in connection with the renegotiation of a petroleum contract. In 2017, this item mainly related the retail G&P business for the estimate made in accordance with the expected loss accounting model net of the estimate made in accordance to the incurred loss accounting for credit losses.
The Group underlying performance – i.e. excluding non-core gains and losses and the inventory holding profit – was an adjusted operating profit of €8,597 million compared to €11,240 million in 2018, down by 24% or by €2.64 billion. The decrease in adjusted operating profit was driven by lower results in the E&P segment (down by €2.21 billion) and in the Refining & Marketing and Chemical segment (down by €0.43 billion), partly offset by the increase in the Gas & Power segment (up by €0.11 billion). The main reasons for the decline were the following: •
Unfavorable trends in prices and margins of the products that we produce and sold, which negatively impacted the performance for about €2.5 billion. This impact also included a loss incurred at the reselling of volumes of gas entitlements of a Libyan partner due to a mismatch between the indexation of the procurement costs vs. the reselling price as discussed above; •
The business combination that involved our former subsidiary Eni Norge which was consummated at the end of 2018 and impacted the comparability of results due to loss of control and de-recognition at that date; •
A flattening yield-curve which increased the present value of the capitalized asset retirement costs in the E&P, thus resulting in higher DD&A charges through profit estimated at €200 million. These negative trends were partly offset by a number of positive drivers, which comprised increased production volumes of hydrocarbons coupled with a better production mix, better results earned at our retail businesses and margin improvements achieved in the wholesale gas&power business which leveraged its portfolio of assets, long-term gas contracts, power plants and logistic capabilities to benefit from market volatility. Management estimated that the Group internal performance increased operating profit by 5%, partly offsetting the negativity of the trading environment and also excluding the positive accounting effect of IFRS 16 which improved the operating profit by an estimated €204 million, considering that the Company opted for not restating the comparative period. Excluding non-core items and the inventory evaluation profit, adjusted net profit for 2019 was €2.876 million, 37% lower than in 2018 when adjusted net profit came at €4.583 million. The result was negatively affected, in addition to a lower operating performance, by an increased Group tax rate which was due to a higher share of taxable income reported by the Exploration & Production segment in countries subject to higher-than-average tax rates, a loss incurred in reselling the gas entitlements of a Libyan partner, while taxable losses were incurred in jurisdictions with a lower-than-average statutory tax rate. The table below provides a reconciliation of those Non-GAAP measures to the most comparable performance measures calculated in accordance with IFRS. | | | Year ended December 31, | | | | | 2014 | | | 2015 | | | 2016 | | | | | (€ million) | | GAAP measure of operating profit of continuing operations | | | | | 8,965 | | | | | | (3,076) | | | | | | 2,157 | | | Identified net charges and inventory holding gains and losses | | | | | 3,372 | | | | | | 8,784 | | | | | | 158 | | | Elimination upon consolidation of intercompany transactions with discontinued operations | | | | | (1,114) | | | | | | (1,222) | | | | | | | | | Non-GAAP measure of operating profit of continuing operations | | | | | 11,223 | | | | | | 4,486 | | | | | | 2,315 | | | GAAP measure of net profit of continuing operations | | | | | 1,720 | | | | | | (7,952) | | | | | | (1,051) | | | Identified net charges and inventory holding gains and losses | | | | | 2,479 | | | | | | 9,269 | | | | | | 711 | | | Elimination upon consolidation of intercompany transactions with discontinued operations | | | | | (476) | | | | | | (514) | | | | | | | | | Non-GAAP measure of net profit of continuing operations | | | | | 3,723 | | | | | | 803 | | | | | | (340) | | | GAAP measure of net cash provided by operating activities from continuing operations | | | | | 14,469 | | | | | | 12,875 | | | | | | 7,673 | | | Elimination upon consolidation of intercompany transactions with discontinued operations | | | | | (925) | | | | | | (720) | | | | | | | | | Non-GAAP measure of net cash provided by operating activities from continuing operations | | | | | 13,544 | | | | | | 12,155 | | | | | | 7,673 | | | |
| | | Year ended December 31, | | | | | 2019 | | | 2018 | | | 2017 | | | | | (€ million) | | GAAP measure of operating profit | | | | | 6,432 | | | | | | 9,983 | | | | | | 8,012 | | | Inventory holding (gains) and losses | | | | | (223) | | | | | | 96 | | | | | | (219) | | | Identified net (gains) losses | | | | | 2,388 | | | | | | 1,161 | | | | | | (1,990) | | | Total net non-core items in operating profit | | | | | 2,165 | | | | | | 1,257 | | | | | | (2,209) | | | Non-GAAP measure of operating profit | | | | | 8,597 | | | | | | 11,240 | | | | | | 5,803 | | | GAAP measure of net profit | | | | | 148 | | | | | | 4,126 | | | | | | 3,374 | | | Inventory holding (gains) and losses, post tax | | | | | (157) | | | | | | 69 | | | | | | (156) | | | Identified net (gains) losses, post tax | | | | | 2,885 | | | | | | 388 | | | | | | (839) | | | Total net non-core items in net profit | | | | | 2,728 | | | | | | 457 | | | | | | (995) | | | Non-GAAP measure of net profit | | | | | 2,876 | | | | | | 4,583 | | | | | | 2,379 | | |
Hydrocarbons production was substantially stable y-o-y in spite of a 19% reduction in capital expenditures. Project re-phasing andIn 2019, the renegotiation of contracts for the supply of plants and equipment drove the capital reduction. The Group replaced 193% of the reserves produced due to progress in development activities, exploration success and the FID taken at the Zohr gas project, off Egypt. The effectiveness of our exploration activity was proven by the finalization of the transactions to dispose of a 40% interest in the Zohr discovery, with a value to Eni of approximately €2 billion, which includes the reimbursement of the cost incurred in 2016 for developing and operating activities. Even discounting the Zohr 40% disposal, our proved reserve replacement ratio would remain significant at 139%.
In 2016, we started several new capital projects, including Goliat in the Barents Sea and Kashagan in Kazakhstan. In 2017, we expect new large field start-ups, including the OCTP oilfield in Ghana, the East Hub project in Angola, started up in February 2017, the Jangkrik gas complex in Indonesia and the Zohr project. In 2017, we forecast a production growth of approximately 5% due to the full ramp-up of fields started in 2016 and new projects coming on stream.
In 2016,Group’s net cash provided by operating activities was €12,392 million, 9% lower than in 2018, despite the trading environment was significantly worse than the previous year. The cash flow was supported by the collection of dividends from continuing operationsEni’s joint ventures, affiliates and other minority interests (€1,346 million), which are integrated within Eni’s strategy and development plans. The main amount was paid by the JV Vår Energi for €1,057 million.
Capital expenditure and acquisitions amounted to €7,673 million. The closing€11.384 million and comprised the purchase of a 20% interest in ADNOC Refining for a cash consideration of €2.9 billion. Capital expenditure were €8,376 million including the Saipem transaction generated approximately €5.2purchase of proved and unproved mineral interests in Algeria and Alaska for €0.4 billion, and were mainly directed to the development of proceedshydrocarbons reserves and wasexploration
oneprojects. We divested some minor assets for a cash-in of the main drivers in the Group’s net borrowings reduction y-o-y; other disposals amounted€504 million. Cash returns to €0.6 billion. These inflows funded part of financial requirements for capital expenditure (€9,180 million),shareholders were €3,424 million and included the payment of Eni’s dividend (thethe final dividend 2018, the interim 2019 dividend for fiscal year 2015an overall amount of €3,018 million and the 2016 interim dividend totaling €2,881 million)execution of a stock repurchase plan for €400 million.
Those inflows and finallyoutflows coupled with the amount cashed out to subscribeinitial recognition of the share capitallease liabilities upon adoption of IFRS 16 effective since January 1, 2019 (see dedicated paragraph below) drove an increase of Saipem (€1,069 million). Management also assessed€4,301 million in the Group net cash provided by operating activities excluding the negative effect of the Val d’Agri shutdown, which amounted to €0.2 billion, the reimbursement in-kind of certain financing receivables due by a joint venture to Eni with trading receivables, which negatively impacted the operating cash flow for €0.3 billion, while changes in working capital due to the sale of the 40% interest in Zohr would have improved cash flow by €0.1 billion. On that basis, net cash provided by operating activities would have funded a large part of 2016 capital expenditure of €9.2 billion, particularly when considering that approximately €0.5 billion of capex incurred in the year will be reimbursed to Eni because of the Zohr transaction in 2017. The Group’s net debt decreased by €2,095 million to €14,776 million. The Group ratio of finance debt to €30,166 million as at December 31, 2019. The ratio of indebtedness calculated based on GAAP measures was 0.63, calculated as ratio of total equity at year-end 2016 was 0.51. However, in assessingfinance debt including the lease liability to total equity. Management evaluates the soundness of the Group balance sheet and its financial structure, management is usingposition by monitoring a non-GAAP measure of indebtedness, net borrowings, which subtractsis calculated by subtracting cash and cash equivalents and other very liquid financial assets from finance debt. This Non-GAAP measuredebt (see Glossary). In 2019, net borrowings before the effect of IFRS 16 increased by €3.2 billion as a result of the above-mentioned cash inflows and outflows. Adding the initial recognition of the lease liabilities at the opening balance for €5,759 million following transition to IFRS 16, including the repayment of lease liabilities for €877 million and the inception of new lease contracts in the year for €766 million, net borrowings at year end climbed to €17.13 billion, compared to €8.29 billion at the end of 2018, an increase of €8,836 million (see the reconciliation table on page 96). The lease liability initially recognized included approximately €2 billion pertaining to our joint operators in Eni-led upstream projects; that amount will be recovered through a partner-billing process. Our ratio of indebtedness is defined “net borrowings” (see Glossary). The– leverage – ratio of net borrowings to total equity is defined “Leverage” (see Glossary) and is commonly used by management in assessingincreased to 0.36 at year-end 2019 from 0.16 at year-end 2018. Excluding the Group financial condition (seeimpact of IFRS 16, leverage would have been 0.24. See paragraph “Financial condition” below). Leverage at year-end 2016 decreased to 0.28 down from 0.29 at the end of 2015 and was below, the 0.30 threshold set by management in spite of a two-year downturn in crude oil prices. In 2017, we are projecting a capital expenditure budget of approximately €7.6 billion, 18% lower than in 2016 at constant exchange rates, while confirming an increase in production by approximately 5% compared to 2016.
We also plan to preserve our liquidity by leveraging on the timely development of capital projects in the Exploration & Production in order to achieve the scheduled time-to-market of our reserves, on cost efficiencies across all businesses and on strengthening profitability at our Gas & Power and Refining & Marketing and Chemical segments. We plan to generate additional funds through our asset disposal program, which will mainly comprise the dilution of our working interests in certain of our exploration discoveries. In March 2017, we signed a preliminary agreement to divest to ExxonMobil a stake of 25% in our exploration asset Area 4 in Mozambique for a cash considerationfull reconciliation of $2.8 billion.
Finally, notwithstanding a weak commodity prices environment, we are planningnet borrowings and leverage to confirm our base dividend of €0.8 per share for fiscal year 2017.the most comparable performance measures calculated in accordance with IFRS.
Trading environment | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Average price of Brent dated crude oil in U.S. dollars(1) | | | | 98.99 | | | | | 52.46 | | | | | 43.69 | | | | | | 64.30 | | | | | 71.04 | | | | | 54.27 | | | Average price of Brent dated crude oil in euro(2) | | | | 74.48 | | | | | 47.26 | | | | | 39.47 | | | | | | 57.44 | | | | | 60.15 | | | | | 48.03 | | | Average EUR/USD exchange rate(3) | | | | 1.329 | | | | | 1.110 | | | | | 1.107 | | | | | | 1.119 | | | | | 1.181 | | | | | 1.130 | | | Standard Eni Refining Margin (SERM)(4) | | | | 3.2 | | | | | 8.3 | | | | | 4.2 | | | | | | 4.3 | | | | | 3.7 | | | | | 5.0 | | | Euribor - three month euro rate %(3) | | | | 0.21 | | | | | (0.02) | | | | | (0.26) | | | | | | Euribor – three month euro rate % (3) | | | | | (0.36) | | | | | (0.32) | | | | | (0.33) | | |
(1)
Price per barrel. Source: Platt’s Oilgram. (2)
Price per barrel. Source: Eni’s calculations based on Platt’s Oilgram data for Brent prices and the EUR/USD exchange rate reported by the European Central Bank (ECB). (3)
Source: ECB. (4)
In $/BBL FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields. When the term margin is used in the following discussion, it refers to the difference between the average selling prices and reflects the trading environment and are,is, to a certain extent, a gauge of industry profitability. Eni’s results of operations and the year-to-year comparability of its financial results are affected by a number of external factors which exist in the industry environment, including changes in oil, natural gas
and refined products prices, industry-wide movements in refining margins and fluctuations in exchange rates and interest rates. Changes in weather conditions from year to year can influence demand for natural gas and some petroleum products, thus affecting results of operations of the natural gas business and, to a lesser extent, of the refining and marketing business. See “Item 3 – Risk factors”. for a description of the main trends which characterized the year 2019. In 2016, the trading environment was characterized by a continued weakness infirst quarter 2020, crude oil prices particularly in first halfhave dropped materially, hitting a multi-year low below 30 $/bbl driven by the spread of the year due to oversupplies. In the second half of the year, market conditions started to improvea pandemic disease and oil prices recovereda seemingly changed policy on part of first-half losses. This was driven by a better balance between global demand and supplies on the backOPEC+ from supporting prices to boost production. The impact of the agreement reached by OPEC Countries at the end of November 2016 to reduce the output of the cartel, joined also by certain non OPEC countries (among which Russia). Despite this recovery, the average price for the Brent crude oil benchmark declined by 17% y-o-y. A weak commodity scenario (mainlythese trends is described in the United States and in Europe) affected gas realizations on equity production, also reflecting time lags in oil-linked price formulas.section “Management expectations of operations” within this item 5. Eni’s refining margins (Standard Eni Refining Margin - SERM) that represents the benchmark for the level of profitability of Eni’s refineries before fixed cash expenses, halved from a year ago (down by 49.4%) to $4.2 per barrel due to structural headwinds in the European refining industry. The Company managed to reduce its breakeven margin and to align it with the current trading environment, exceeding the planned breakeven target of $4.5 per barrel.94
Gas prices in the Company’s Gas & Power segment declined y-o-y driven by continued oversupplies, weak demand growth and the constraints connected minimum off-take obligations provided by long-term gas purchase contracts with take-or-pay clause. In addition to declining spot sale prices, in 2016 also the differential between Italian hub prices and European hub ones (PSV vs. TTF) contracted and negatively affected the G&P segment’s results.The exchange rate of euro against the dollar was 1.107, stable compared to the average exchange rate recorded in 2015.
Critical accounting estimates The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the carrying amounts of assets and liabilities, revenues and expenses reported in the financial statements, as well as amounts included in the notes thereto, including discussion and disclosure of contingent liabilities. Estimates made are based on complex or subjective judgments and past experience or other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas assets, specifically in the determination of proved and proved developed reserves and impairment of fixed assets,assets. Other areas where management’s estimates and judgement is applied include, among others, evaluation and recognition of intangible assets, equity-accounted investments and goodwill, decommissioning and restoration liabilities, business combinations, pensions and other post-retirement benefits, environmental liabilities and recognition of environmental liabilities.lease contracts. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. A summaryreview of significant accounting estimates and judgemental areas is provided in “Item 18 – note 6 – of the Notes onNote 1 to Consolidated Financial Statements”. 2014-2016 Group resultsIFRS 16 adoption
Eni’s 2019 consolidated financial statements and the statements of operations Adoptionprofit and loss, cash flow and financial position commented in this Item 5 have been prepared incorporating the effects of the Successful effort method (SEM)
Effectivenew IFRS 16 “Leases”, effective at the beginning of the year, which defines a lease as a contract that conveys to the lessee the right to control the use of an identified asset for a period of time in exchange for consideration and eliminates the classification of leases as either operating leases or finance leases for the preparation of the lessee’s financial statements. The Group is hiring third-party assets in the connection with operating activities and the execution of capital projects; these assets mainly comprise FPSO vessels, drilling rigs, buildings, service stations and logistic facilities. The standard provides a lessee to recognize a right-of-use asset, that represents a lessee’s right to use an underlying asset (ROU), and a corresponding finance liability, the lease liability (LL) that represents the lessee’s obligation to make the contractual lease payments recorded at their present value. The new accounting standard has determined a significant impact on the Group key performance indicators of its consolidated financial statements, particularly in net borrowings, with a step up effect due to the fact that Eni has adopted the modified retrospective approach by recognizing the cumulative effect of initially applying the new standard as an adjustment to the opening balance at January 1, 2016, management elected2019, without restating the comparative periods. Additional information about adoption of IFRS 16 with regard to changeassumptions and practical expedients used in the criterionfirst application are provided in the notes to recognize exploration expenses adopting the successful-effort-method (SEM)consolidated financial statements under the heading “changes to accounting criteria”. The successful-effort method is largely adopted by oil&gas companies, to which Eni is increasingly comparable given the recent re-focalizationA brief description of the Group activitiesnew accounting for lease contracts under IFRS 16 and the main effects on its core upstream business.the 2019 financial statements are provided below:
- in the profit and loss account, depreciation charges of the ROU asset and interest expense accrued on the LL are recognized within operating expenses and finance expense, respectively. Under the SEM, geologicalprevious accounting standard, operating lease payments were recorded within operating expenses. The following table shows certain profit and geophysical exploration costs areloss items as adjusted to exclude the effect of the application of IFRS 16 and a reconciliation to the reported measure in compliance with IFRS. Profit and loss account 2019 (€ million) | | | before IFRS 16 | | | IFRS 16 effects | | | GAAP results | | Purchases, services and other | | | | | (51,908) | | | | | | 1,034 | | | | | | (50,874) | | | Depreciation, depletion and amortization | | | | | (7,276) | | | | | | (830) | | | | | | (8,106) | | | Operating profit | | | | | 6,228 | | | | | | 204 | | | | | | 6,432 | | | Finance expense and income taxes | | | | | (9,338) | | | | | | (332) | | | | | | (9,670) | | | Net profit | | | | | 283 | | | | | | (128) | | | | | | 155 | | |
- in the statement of cash flows, reimbursement of the principal portion of the LL is recorded as part of financing activities. Interest expense is recorded as part of operating activities, or as part of investing activities depending on whether it is recognized asin the profit and loss account or is being capitalized in relation to the hire of equipment used in connection with capital projects. Consequently, compared with the requirements of the previous accounting standard in force, IAS 17 related to operating leases, the adoption of IFRS 16 determined a significant impact in the statement of cash flows due to: (a) an expense as incurred. Costs directly associated with an exploration well are initially capitalized as an unproved tangibleimprovement in
asset untilnet cash provided by operating activities, which no longer includes the drillingoperating lease payments related to assets hired in connection with operating activities, but only includes the cash payments for the interest portion of the well is completed andLL relating to those assets; (b) an improvement in net cash used in investing activities, which no longer includes capitalized lease payments in connection with assets hired in connection with a capital project, but only includes cash payments for the results have been evaluated. If potentially commercial quantities of hydrocarbons are not found, the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an unproved asset. If it is determined that development will not occur then the costs are expensed. Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons are initially capitalized as an unproved tangible asset. When proved reserves of oil and natural gas are determined and development is approved by management, the relevant expenditure is transferred to proved property.
In accordance to IAS 8 “Accounting policies, Changes in accounting estimates and Errors”, the retrospective applicationinterest portion of the SEM has required adjustmentlease liability relating to those assets; and (c) an increase in the net cash used in financing activities, which includes cash payments for the principal portion of the opening balance of severalLL. The following table shows certain cash flow statement items as of January 1, 2014. Specifically,adjusted to exclude the opening balanceeffect of the carrying amount of property, plant and equipment was increased by €3,524 million, intangible assets by €860 million and retained earnings by €3,001 million. Other adjustments related to deferred tax liabilities and other minor line items.
In the table below, the key line items of the profit and loss and balance sheet are presented with reference to the full years 2014 and 2015 previously reported, and as restated in accordance with the application of SEMIFRS 16 and a reconciliation to the cessationreported measure in compliance with IFRS.
Cash flow statement 2019 (€ million) | | | before IFRS 16 | | | IFRS 16 effects | | | GAAP results | | Net cash provided by operating activities | | | | | 11,726 | | | | | | 666 | | | | | | 12,392 | | | Capital expenditure | | | | | (8,587) | | | | | | 211 | | | | | | (8,376) | | | Cash flow from financing activity | | | | | (4,964) | | | | | | (877) | | | | | | (5,841) | | | Net increase (decrease) in cash and cash equivalent | | | | | (4,861) | | | | | | | | | | | | (4,861) | | | Initial adoption of IFRS 16 | | | | | | | | | | | (5,759) | | | | | | (5,759) | | | New LL for the year | | | | | | | | | | | (766) | | | | | | (766) | | | LL reimbursement in the year | | | | | | | | | | | 877 | | | | | | | | | Change in net borrowings(a) | | | | | (3,188) | | | | | | (5,648) | | | | | | (8,836) | | |
(a)
Net borrowings is a Non-GAAP measure of indebtedness. For a reconciliation of net borrowings to finance debt see page 108 “Financial condition”. The initial adoption of IFRS 16 resulted in a €5.76 billion increase in net borrowings due to the initial recognition of the accountingLL in the opening balance. However, the initial amount of Eni’s Chemical segment asLL is affected by the fact that in the E&P sectors oil&gas projects are carried out based on the contractual scheme of unincorporated joint operations managed by one of the joint operators (the lead operator). This structure entails that the LL relating to lease contracts entered into by the lead operator on behalf of the joint operations is recorded in full in the financial statements of the lead operator, because the lead operator is normally the sole signatory of the lease contract and consequently takes primary responsibility for discharging the lease obligations towards the third-party lessor, notwithstanding the fact that the lead operator is able to recover the share of lease payments attributable to the joint operators through a disposal group held for sale. In 2015,partner billing process. As a result, the Chemical segment was presented as discontinued operations due to an ongoing negotiation atROU of the 2015asset utilized by a joint operation is recorded in its full amount in the balance sheet date designed to establish an industrial joint venture with a third party who had expressed an interest in acquiring a majority stake of Eni’s chemical arm. In 2016 Eni and the potential buyer could not come to an agreement and the accounting of Versalis as discontinued operation ceased with retroactive effects to the date of initial recognition as discontinued operations.lead operator. | | | AS PREVIOUSLY REPORTED | | | AS RESTATED | | | | | (€ million) | | Full year 2014 | | | | | | | | | | | | | | Operating profit (loss) - continuing operations | | | | | 7,585 | | | | | | 8,965 | | | Operating profit (loss) E&P | | | | | 10,766 | | | | | | 10,727 | | | Net profit (loss) attributable to Eni’s shareholders - continuing operations | | | | | 101 | | | | | | 1,720 | | | Total assets | | | | | 146,207 | | | | | | 150,366 | | | Eni’s shareholders equity | | | | | 59,754 | | | | | | 63,186 | | | Net cash flow | | | | | 1,183 | | | | | | 1,183 | | | | | | | | | | | | | | | | | Full year 2015 | | | | | | | | | | | | | | Operating profit (loss) - continuing operations | | | | | (2,781) | | | | | | (3,076) | | | Operating profit (loss) E&P | | | | | (144) | | | | | | (959) | | | Net profit (loss) attributable to Eni’s shareholders - continuing operations | | | | | (7,680) | | | | | | (7,952) | | | Total assets | | | | | 134,792 | | | | | | 139,001 | | | Eni’s shareholders equity | | | | | 51,753 | | | | | | 55,493 | | | Net cash flow | | | | | (1,414) | | | | | | (1,405) | | | |
OverviewGroup results of the profit and loss account for three years ended December 31, 2014, 2015 and 2016operations
The table below sets forth a summary of Eni’s profit and loss account for the periods indicated. All line items included in the table below are derived from the Consolidated Financial Statements prepared in accordance with IFRS. For the disclosure on 2018 Group results compared to 2017, see the Annual Report on Form 20-F 2018, filed to the SEC on April 5, 2019. | | Year ended December 31, | | | Year ended December 31, | | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | | | (€ million) | | | (€ million) | | Net sales from operations | | | | 98,218 | | | | | 72,286 | | | | | 55,762 | | | | Sales from operations | | | | | 69,881 | | | | | 75,822 | | | | | 66,919 | | | Other income and revenues(1) | | | | 1,079 | | | | | 1,252 | | | | | 931 | | | | | | 1,160 | | | | | 1,116 | | | | | 4,058 | | | Total revenues | | | | 99,297 | | | | | 73,538 | | | | | 56,693 | | | | | | 71,041 | | | | | 76,938 | | | | | 70,977 | | | Operating expenses | | | | (80,333) | | | | | (59,967) | | | | | (47,118) | | | | | | (54,302) | | | | | (59,130) | | | | | (55,412) | | | Other operating (expense) income | | | | 145 | | | | | (485) | | | | | 16 | | | | | | 287 | | | | | 129 | | | | | (32) | | | Depreciation, depletion and amortization | | | | (7,676) | | | | | (8,940) | | | | | (7,559) | | | | | | (8,106) | | | | | (6,988) | | | | | (7,483) | | | Impairment losses (impairment reversal), net | | | | (1,270) | | | | | (6,534) | | | | | 475 | | | | Write-off | | | | (1,198) | | | | | (688) | | | | | (350) | | | | Impairment reversals (impairment losses) of tangible and intangible and right of use assets, net | | | | | (2,188) | | | | | (866) | | | | | 225 | | | Write-off of tangible and intangible assets | | | | | (300) | | | | | (100) | | | | | (263) | | | OPERATING PROFIT (LOSS) | | | | 8,965 | | | | | (3,076) | | | | | 2,157 | | | | | | 6,432 | | | | | 9,983 | | | | | 8,012 | | | Finance income (expense) | | | | (1,167) | | | | | (1,306) | | | | | (885) | | | | | | (879) | | | | | (971) | | | | | (1,236) | | | Income (expense) from investments | | | | 476 | | | | | 105 | | | | | (380) | | | | | | 193 | | | | | 1,095 | | | | | 68 | | | PROFIT (LOSS) BEFORE INCOME TAXES | | | | 8,274 | | | | | (4,277) | | | | | 892 | | | | | | 5,746 | | | | | 10,107 | | | | | 6,844 | | | Income taxes | | | | (6,466) | | | | | (3,122) | | | | | (1,936) | | | | | | (5,591) | | | | | (5,970) | | | | | (3,467) | | | Net profit (loss) - continuing operations | | | | 1,808 | | | | | (7,399) | | | | | (1,044) | | | | Net profit (loss) - discontinued operations | | | | (949) | | | | | (1,974) | | | | | (413) | | | | Net profit (loss) | | | | 859 | | | | | (9,373) | | | | | (1,457) | | | | | | 155 | | | | | 4,137 | | | | | 3,377 | | | Attributable to: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni’s shareholders: | | | | 1,303 | | | | | (8,778) | | | | | (1,464) | | | | - continuing operations | | | | 1,720 | | | | | (7,952) | | | | | (1,051) | | | | - discontinued operations | | | | (417) | | | | | (826) | | | | | (413) | | | | Non-controlling interest: | | | | (444) | | | | | (595) | | | | | 7 | | | | - continuing operations | | | | 88 | | | | | 553 | | | | | 7 | | | | - discontinued operations | | | | (532) | | | | | (1,148) | | | | | | | | | | | - Eni’s shareholders | | | | | 148 | | | | | 4,126 | | | | | 3,374 | | | - Non-controlling interest | | | | | 7 | | | | | 11 | | | | | 3 | | |
(1)
Includes, among other things, contract penalties, income from contract cancellations, gains on disposal of mineral rights and other fixed assets, compensation for damages and indemnities and other income. The table below sets forth certain income statement items as a percentage of net sales from operations for the periods indicated. | | | Year ended December 31, | | | | | 2014 | | | 2015 | | | 2016 | | | | | (%) | | Operating expenses | | | | | 81.8 | | | | | | 83.0 | | | | | | 84.5 | | | Depreciation, depletion, amortization, impairments (reversal of assets) net, write-off | | | | | 10.3 | | | | | | 22.4 | | | | | | 13.3 | | | OPERATING PROFIT | | | | | 9.1 | | | | | | �� (4.3) | | | | | | 3.9 | | | |
2016 compared to 2015. See management discussion under paragraph “Executive summary” on page 90 for an overview of the Group’s results from continuing operations.
Net loss attributable to Eni’s shareholders including both continuing operations and discontinued operations amounted to €1,464 million for 2016. The loss of the discontinued operations pertaining to Eni’s shareholders (€413 million) was affected by the recognition of a charge of €441 million due to the
alignment of Eni’s retained interest in Saipem with its market value the date of the loss of control (January 22, 2016). The market value of the retained interest in the former subsidiary was the carrying amount of such interest upon initial recognition for the subsequent accounting under the equity method (€564 million to which a share capital increase of €1,069 million is to be added).
2015 compared to 2014. Net loss attributable to Eni’s shareholders including both continuing operations and discontinued operations amounted to €8,778 million for 2015. The loss of the discontinued operations pertaining to Eni’s shareholders was negatively affected by the recognition of an impairment loss on the disposal group Saipem the net assets of which were aligned to the lower of their carrying amounts and fair value. Eni’s net asset in Saipem were aligned to the share price at the reporting date, recording an impairment charge of €393 million. Partly offsetting, a fair-valued derivative gain of €49 million was recorded for Saipem due to the difference between the transaction price (€8.39 per share) and the market price at the reporting date (€7.49 per share) relating the stake under disposal.
Discontinued operations
The table below sets forth net profit (loss) attributable to discontinued operations for the periods indicated.
| | | Year ended December 31, | | | | | 2014 | | | 2015 | | | 2016 | | | | | (€ million) | | Net profit - discontinued operations | | | | | (949) | | | | | | (1,974) | | | | | | (413) | | | attributable to: | | | | | | | | | | | | | | | | | | | | - Eni | | | | | (417) | | | | | | (826) | | | | | | (413) | | | - non-controlling interest | | | | | (532) | | | | | | (1,148) | | | | | | | | | |
Based on the accounting of IFRS 5 for disposal groups, gains and losses pertaining to the discontinued operations include only those earned from transactions with third parties. Until such time as Saipem was a subsidiary of the Eni Group (i.e. end of the reporting period 2015), gains and losses on intercompany transactions have been eliminated upon consolidation. These comprised mainly revenues earned by Saipem for the supply of capital goods and maintenance services to Eni’s Group companies, which were eliminated upon consolidation, positively affecting results of the continuing operations, while negatively affecting the results of operations of the discontinued operations. This effect did not recur in 2016 due to the derecognition of Saipem effective January 1, 2016. Furthermore, the 2015 loss from discontinued operations included the alignment of Saipem’s net assets to its market capitalization at the balance sheet date leading to a loss of €393 million.
| | | Year ended December 31, | | | | | 2019 | | | 2018 | | | 2017 | | | | | (%) | | Operating expenses | | | | | 77.7 | | | | | | 78.0 | | | | | | 82.8 | | | Depreciation, depletion, amortization,impairment reversals (impairment losses) of tangible and intangible and right of use assets, net | | | | | 15.2 | | | | | | 10.5 | | | | | | 11.2 | | | OPERATING PROFIT | | | | | 9.2 | | | | | | 13.2 | | | | | | 12.0 | | |
Analysis of the line items of the profit and loss account of continuing operations a) Total revenues Eni’s revenues from continuing operations were €56,693 million, €73,538€71,041 million and €99,297€76,938 million for the years ended December 31, 2016, 20152019 and 2014,2018, respectively. Total revenues consist of net sales from operations and other income and revenues. Eni’s netEni sales from operations from continuing operations amounted to €55,762 million, €72,286€69,881 million and €98,218€75,822 million for the yearyears ended December 31, 2016, 20152019 and 2014,2018, respectively, and its other income and revenues totaled €931 million, €1,252€1,160 million and €1,079€1,116 million, respectively, in these periods.
Net salesSales from operations from continuing operations
The table below sets forth, for the periods indicated, the net sales from operations from continuing operations generated by each of Eni’s business segments including intragroup sales, together with consolidated net sales from operations. | | | Year ended December 31, | | | | | 2014 | | | 2015 | | | 2016 | | | | | (€ million) | | 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(1) | | | | | 54 | | | | | | | | | | | | | | | Consolidation adjustment(2) | | | | | (34,181) | | | | | | (25,353) | | | | | | (21,364) | | | NET SALES FROM OPERATIONS | | | | | 98,218 | | | | | | 72,286 | | | | | | 55,762 | | | |
(1)
This item mainly concerned intra-group sales of goods, services and capital assets recorded at period end in the assets of the purchasing business segment.
(2)
Intragroup sales are included in net sales from operations in order to give a more meaningful indication as to the volume of the activities to which sales from operations by segment may be related. The largest intragroup sales are recorded by the Exploration & Production segment. “Item 18 – note 46 – of the Notes on Consolidated Financial Statements” for a breakdown of intragroup sales by segment for the reported years.
| | | Year ended December 31, | | | | | 2019 | | | 2018 | | | 2017 | | | | | (€ million) | | Exploration & Production | | | | | 23,572 | | | | | | 25,744 | | | | | | 19,525 | | | Gas & Power | | | | | 50,015 | | | | | | 55,690 | | | | | | 50,623 | | | Refining & Marketing and Chemicals | | | | | 23,334 | | | | | | 25,216 | | | | | | 22,107 | | | Corporate and other activities | | | | | 1,681 | | | | | | 1,589 | | | | | | 1,462 | | | Consolidation adjustments | | | | | (28,721) | | | | | | (32,417) | | | | | | (26,798) | | | SALES FROM OPERATIONS | | | | | 69,881 | | | | | | 75,822 | | | | | | 66,919 | | |
20162019 compared to 20152018. Eni’s netEni sales from operations (revenues) from continuing operations for 20162019 (€55,76269,881 million) decreased by €16,524€5,941 million from 20152018 (or down 22.9%by 7.8%) primarily reflecting lower realizations on oil, products and natural gas due to significantly lowera slowdown in commodity prices. Changes in sales volumes of products sold were immaterial.
Revenues generated by the Exploration & Production segment (€16,08923,572 million) decreased by €5,347€2,172 million (or down by 24.9%8.4%). This was due to lower average realizations on equity hydrocarbons (down(oil realizations down by 20.1%9.5%; gas realizations down by 5% on average in dollar terms) driven by declininglower prices for the marker Brent (down by 16,7%9.5%) and gas benchmarksprices in Europe,Europe. Furthermore, lower benchmark gas prices negatively affected the revenues earned from reselling the gas volumes entitlements of a Libyan partner in the United States and elsewhere also considering the time lags in oil-linked formulas. The reductionEuropean market. Finally, y-o-y comparability was also negatively affected by the Val d’Agri shutdown, which lasted four and half months. The negative price impact was mainly recordedde-recognition of our former subsidiary Eni Norge at concession contracts, while PSA contracts are insulated from the scenario dueend of 2018, following a business combination with the Norwegian company Point Resources to established the cost recovery mechanism.Vår Energi joint-venture (Eni’s share 69.6%). Revenues generated by the Gas & Power segment (€40,96150,015 million) decreased by €11,135€5,675 million (or down by 21.4%10.2%). The reductiondecrease reflected lower natural gas and power selling prices as well as lower commodity prices in the business of crude oilEurope and refined products trading, which impact was however offset at the operating profit level bydeclining LNG prices due to a corresponding decrease in the supply costs of the commodities. Furthermore, revenues were also negatively affected by a downward revision of revenues accrued on the sale of gasweaker Asian scenario and power to retail customers in Italy (€161 million) dating back to past reporting periods prior to 2015.lower volumes sold. Revenues generated by the Refining & Marketing and Chemical segment (€18,73323,334 million) decreased by €3,906€1,882 million (or down by 17.3%7.5%) mainly reflectingdue to lower average selling prices driven by weaker commodity prices. Theof gasoline and gasoil in the Refining & Marketing business, as well as the decline in average selling prices and lower volumes sold, mainly intermediates, in the Chemical business declined by 10% due to lower price of polymers (down by 6.7% and down by 6.3% the average price of elastomers and styrenics, respectively), reflecting the impact of scenario and competitive pressure. 2015 compared to 2014. Eni’s net sales from operations (revenues) from continuing operations for 2015 (€72,286 million) decreased by €25,932 million from 2014 (or down by 26.4%) primarily reflecting lower realizations on oil, products and natural gas in dollar terms due to significantly lower commodity prices. This negative trend was partially offset by a favorable exchange rate environment and increased sales volumes in the Exploration & Production segment, as well as higher Eni’s refining throughputs.
Revenues generated by the Exploration & Production segment (€21,436 million) decreased by €7,052 million (or down by 24.8%) due to lower oil&gas realizations in dollar terms (down by 44.3% on average) reflecting the lower price for the marker Brent and lower gas prices in Europe and in the United States.
Lowered hydrocarbons realizations in dollars reduced reported revenues by approximately €12 billion. This effect was partly offset by favorable exchange rate differences in translating dollar-denominated revenues into the euro representation currency for €3.3 billion and higher production volumes sold for €1.6 billion. The negative price impact was mainly recorded at concession contracts, while PSA contracts are insulated from the scenario due to the cost recovery mechanism.
Revenues generated by the Gas & Power segment (€52,096 million) decreased by €21,338 million (or down by 29.1%). The reduction reflected lower commodity prices in the business of crude oil and refined products trading, which impact was however offset by a corresponding decrease in the supply costs of the commodities. Furthermore, gas selling prices continued to deteriorate reflecting, in addition to the commodity price environment, weak gas demand and increasing competitive pressure. Revenues were also impacted an estimate revision of revenues accrued on the sale of gas (€346 million) and power (€138 million) to retail customers in Italy dating back to the past reporting periods.
Revenues generated by the Refining & Marketing and Chemicals segment (€22,639 million) decreased by €6,355 million (or down by 21.9%) mainly reflecting lower average sales prices products driven by lower commodity prices.demand and plant incidents and outages.
Other income and revenues 2019 compared to 2018. Eni’s other income and revenues amounted to €1,160 million in 2019 and mainly related to the gain on the divestment of a 20% interest in the Merakes discoveries to Neptune (€145 million) and the share of lease repayments debited to joint operators in Eni-led upstream projects (€368 million). b) Operating expenses The table below sets forth the components of Eni’s operating expenses for the periods indicated. | | Year ended December 31, | | | Year ended December 31, | | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | | | (€ million) | | | (€ million) | | Purchases, services and other | | | | 77,404 | | | | | 56,848 | | | | | 44,124 | | | | | | 50,874 | | | | | 55,622 | | | | | 51,548 | | | Impairment losses (impairment reversals) of trade and other receivables, net | | | | | 432 | | | | | 415 | | | | | 913 | | | Payroll and related costs | | | | 2,929 | | | | | 3,119 | | | | | 2,994 | | | | | | 2,996 | | | | | 3,093 | | | | | 2,951 | | | Operating expenses | | | | 80,333 | | | | | 59,967 | | | | | 47,118 | | | | | | 54,302 | | | | | 59,130 | | | | | 55,412 | | | | |
20162019 compared to 20152018. Operating expenses from continuing operations for 20162019 (€47,11854,302 million) decreased by €12,849€4,828 million y-o-y, down by 21.4%8%, primarily reflecting lower supply costs of raw materials (natural gas under long-term supply contracts, refinery and chemical feedstock and hydrocarbons purchased for resale). Purchases, services and other costs included €360 million relating mainly to environmental provisions ((€436 million in 2015). Payroll and related costs (€2,994 million) decreased by €125 million from 2015, down by 4%,resale due to lower average number of employees outside Italy.
2015 compared to 2014. Operating expenses from continuing operations for 2015 (€59,967 million) decreased by €20,366 million from 2014, down by 25.4%, primarily reflecting lower supply costs of raw materials (natural gas under long-term contracts, refinery feedstock and hydrocarbons purchased for resale) due to underlying trends in the energy scenario partially offset by negative exchange rate effects. Purchases, services and other costs included €436 million relating to environmental and other risk provisions, net of reversal of unused provisions. In addition, an allowance to the provision for doubtful accounts was recognized in 2015 in the retail Gas & Power business to take in account an estimate revision of revenues accrued on the sale of natural gas and electricity (€226 million; €130 million for gas sale and €96 million for electricity) to retail customers in Italy dating back to past reporting periods. Payroll and related costs (€3,119 million) increased by €190 million from 2014, up by 6.5%, due to the appreciation of the U.S. dollar against the euro. These effects were partially offset by lower average number of employees.
prevailing market prices). Purchases, services and other costs included approximately €390 million relating mainly to environmental provisions and the recognition of losses on certain contractual and commercial disputes. Payroll and related costs (€2,996 million) decreased by €97 million from 2018, down by 3.1%, mainly due to the circumstance that in 2018 higher provisions for redundancy incentives were accounted relating to an early retirement program in the Eni gas e luce subsidiary. c) Depreciation, depletion, amortization, impairments (impairments reversal)impairment losses (impairment reversals) net and write-off The table below sets forth a breakdown of depreciation, depletion, amortization, impairments (impairments reversal)impairment losses (impairment reversals) net and write-off for the periods indicated. | | Year ended December 31, | | | Year ended December 31, | | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | | | (€ million) | | | (€ million) | | Exploration & Production | | | | 6,916 | | | | | 8,080 | | | | | 6,772 | | | | | | 7,060 | | | | | 6,152 | | | | | 6,747 | | | Gas & Power | | | | 335 | | | | | 363 | | | | | 354 | | | | | | 447 | | | | | 408 | | | | | 345 | | | Refining & Marketing and Chemicals | | | | 381 | | | | | 454 | | | | | 389 | | | | | | 485 | | | | | 399 | | | | | 360 | | | Corporate and other activities | | | | 70 | | | | | 71 | | | | | 72 | | | | | | 146 | | | | | 59 | | | | | 60 | | | Impact of unrealized intragroup profit elimination(1) | | | | (26) | | | | | (28) | | | | | (28) | | | | | | (32) | | | | | (30) | | | | | (29) | | | Total depreciation, depletion and amortization | | | | 7,676 | | | | | 8,940 | | | | | 7,559 | | | | | | 8,106 | | | | | 6,988 | | | | | 7,483 | | | Impairment losses | | | | 1,334 | | | | | 6,537 | | | | | 1,067 | | | | Reversals of impairment losses | | | | (64) | | | | | (3) | | | | | (1,542) | | | | Write-off | | | | 1,198 | | | | | 688 | | | | | 350 | | | | Total depreciation, depletion, amortization, impairment losses (impairment reversals), net and write off | | | | 10,144 | | | | | 16,162 | | | | | 7,434 | | | | | | Impairment losses of tangible and intangible and right of use assets, net | | | | | 2,544 | | | | | 1,292 | | | | | 862 | | | Impairment of goodwill | | | | | 26 | | | | | | | | | | | | | Impairment reversal of tangible and intangible assets, net | | | | | (382) | | | | | (426) | | | | | (1,087) | | | Write-off of tangible and intangible assets | | | | | 300 | | | | | 100 | | | | | 263 | | | Total depreciation, depletion, amortization, impairment losses (impairment reversals) of tangible and intangible and right of use assets, net and write off of tangible and intangible assets | | | | | 10,594 | | | | | 7,954 | | | | | 7,521 | | |
(1)
This item concerned mainly intra-group sales of goods and capital, recorded at period end in the assestsassets of the purchasing business segment. 20162019 compared to 20152018. In 2016,2019, depreciation, depletion and amortization charges (€7,5598,106 million) decreasedincreased by €1,381€1,118 million from 2015,2018, or 15.4%16%, mainly in the Exploration & Production segment (with a decrease(an increase of €1,308€908 million) reflecting lower capital expendituresmainly due to the depreciation charges of the year (down by 16.2%)right-of-use asset in accordance to IFRS 16, which provided a new accounting framework for operating leases without restating the comparative periods, higher charges recorded in connection with an upward revision of the present value of capitalized assets retirement costs due to lower interest rates, as well as fields started-up and the lower carrying amounts of certain oil&gas properties following the impairment losses booked in 2015 (€5,212 million).new projects ramp-up.
In 2016,2019, the Group recorded reversals of prior impairment losses at oil&gas propertiesproperty, plant and equipment for €1,440 million. These were determined by an upward revision to the long-term pricea total amount of the benchmark Brent to 70 $/barrel, up from the previous 65 $/barrel assumption, which drove the financial projections of the 2017-2020 industrial plan and the recoverability of oil&gas assets carrying amounts in the 2016 financial statements. These reversals were partly offset by€2,188 million, mainly relating to: (i) impairment losses related to gas properties in the upstream business driven by a lowered price outlook in Europe and otherof oil&gas properties due to contractual changes,downward reserves revisionrevisions and a higher country risk (overalllower-than-expected performance at certain fields in Congo, Italy and in the USA, and of certain assets to align the book value to fair value (for an overall amount of €756€1,217 million). Finally, investments made for compliance and stay-in-business purposes were fully impaired at cash generating units previously written-off in; (ii) impairment losses recorded by the Refining & Marketing business, mainly at the Sannazzaro refinery, reflecting a revised margin outlook both at high and Chemicals segment, whichlow-complexity cycles, upward revisions for the forecast emission allowances expenses and higher capital expenses, as well as the write-down of capital expenditure relating to certain Cash Generating Units. These units were confirmedimpaired in previous reporting periods and continued to lack any profitability prospects (for an overall impact of €819 million); (iii) impairment losses of Chemical assets due to a lowered profitability outlook (€104 million), while103 million in the Gas&Power segment recorded €81full year). Write-off charges amounted to €300 million and related to a gas transport infrastructure and LNG carriers. The write-off amounting to €350 million, mainly related to thepreviously capitalized costs of exploratory wells lacking the requisites for continuing capitalizationwhich were expensed through profit because it was determined that they did not encounter commercial quantities of hydrocarbons or due to lack of management commitment. The item also comprised the write-off of the damaged units of the EST conversion plant at the Sannazzaro Refinery due to the accident occurredcommitment in December 2016 (€193 million).
2015 compared to 2014. In 2015, depreciation, depletion and amortization charges (€8,940 million) increased by €1,264 million from 2014, or 16.5%,pursuing further appraisal activity mainly in the Exploration & Production segment (increasing by €1,164 million) reflecting the appreciation of the U.S. dollar against the euroAustralia, Kazakhstan and higher production volumes.
In 2015, impairment charges of €6,534 million related to oil&gas properties (€5,212 million) driven by the projections of lower hydrocarbon prices in the medium to long-term, which affected their recoverable amounts. The most notable impairments refer to certain assets, which were acquired by the Group following business combinations in previous reporting periods (Algeria, Congo and Turkmenistan) and to CGUs which are currently operating in high-cost areas (United States, United Kingdom, Norway and Angola). Furthermore, investments made for compliance and stay-in-business purposes were written off atPakistan.
cash generating units previously written-off in the Refining & Marketing and Chemicals segment, which were confirmed to be lacking any prospects of profitability. Finally, impairment losses were recorded at the Group power plants in the G&P segment due to a weak margins scenario. The amount of write-offs of exploration project was also mainly driven by management’s decision to cease committing funds to certain projects in light of the deteriorated oil price environment.
d) Operating profit (loss) by segment The table below sets forth Eni’s operating profit from continuing operations by business segment for the periods indicated. | | Year ended December 31, | | | Year ended December 31, | | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | | | (€ million) | | | (€ million) | | Exploration & Production | | | | 10,727 | | | | | (959) | | | | | 2,567 | | | | | | 7,417 | | | | | 10,214 | | | | | 7,651 | | | Gas & Power | | | | 64 | | | | | (1,258) | | | | | (391) | | | | | | 699 | | | | | 629 | | | | | 75 | | | Refining & Marketing and Chemicals | | | | (2,811) | | | | | (1,567) | | | | | 723 | | | | | | (854) | | | | | (380) | | | | | 981 | | | Corporate and other activities | | | | (518) | | | | | (497) | | | | | (681) | | | | | | (710) | | | | | (691) | | | | | (668) | | | Impact of unrealized intragroup profit elimination | | | | 1,503 | | | | | 1,205 | | | | | (61) | | | | | | (120) | | | | | 211 | | | | | (27) | | | Operating profit (loss) | | | | 8,965 | | | | | (3,076) | | | | | 2,157 | | | | | | 6,432 | | | | | 9,983 | | | | | 8,012 | | | | |
The table below sets forth operating profit (loss) from continuing operations for each of Eni’s business segments as a percentage of each segment’s netsegment sales from operations from continuing operations (including intragroup sales) for the periods presented. | | Year ended December 31, | | | Year ended December 31, | | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | | | (%) | | | (%) | | Exploration & Production | | | | 37.7 | | | | | (4.5) | | | | | 16.0 | | | | | | 31.5 | | | | | 39.7 | | | | | 39.2 | | | Gas & Power | | | | 0.1 | | | | | (2.4) | | | | | (1.0) | | | | | | 1.4 | | | | | 1.1 | | | | | 0.1 | | | Refining & Marketing and Chemicals | | | | (9.7) | | | | | (6.9) | | | | | 3.9 | | | | | | (3.7) | | | | | (1.5) | | | | | 4.4 | | | Group | | | | 9.1 | | | | | (4.3) | | | | | 3.9 | | | | | | 9.2 | | | | | 13.2 | | | | | 12.0 | | | | |
Exploration & ProductionProduction.. In 2016,2019, the Exploration & Production segment reported an operating profit of €2,567€7,417 million, with an increasea decrease of €3,526€2,797 million fromcompared to the operating lossprofit of €959€10,214 million reported in 2015. This change mainly reflected2018. The decline was driven by lower realized prices on equity hydrocarbons, particularly lower gas prices in Europe, a loss incurred in connection with the reselling of volumes of gas entitlements of a Libyan partner, and higher amortization charges, exploration well write-offs and impairment chargeslosses taken at oil&gas properties, partly offset by production growth and a better volume/mix performance reflecting higher contribution of €5,212 million recorded in 2015 due to a downward revisionbarrels with higher-than-average profitability. The y-o-y comparison of operating profit was affected also by the following items: (i) the circumstance that the prior year result benefitted from the contribution of the oil scenario, whileformer consolidated subsidiary Eni Norge (€1,278 million) which was de-recognized at the end of 2018 following the business combination with Point Resources to establish Vår Energi, an equity-accounted joint venture, fully operational since January 1, 2019; (ii) the adoption of IFRS 16, which was a positive of approximately €220 million, having Eni elected to adopt the modified retrospective approach, without restating the comparative information. A discussion on trends in 2016 net impairment reversals of €684 million were recorded due to a hikeproduction for 2019 is provided in management long-term oil price assumptions.the section “Executive summary”. In 2016,2019, the Company’s liquids and gas realizations decreased on average by 20.1%8.3% in dollar terms, driven by a decline in international oil prices for market benchmarks (Brent crude prices decreased by 16.7%).weak trading environment. Eni’s average oil realizations decreased on average by 15.4%9.5%, in line with the decrease recorded in international oil prices for the Brent market benchmark (down by 9.5% for the year). Eni’s average gas realizations decreased by 28.2% and were negatively impacted by the weak scenario and time lags in oil-linked formulas. In 2015, the Exploration & Production segment reported an operating loss of €959 million, with a decrease of €11,686 million from 2014. The decline was principally due to reduced oil&gas realizations in dollar terms (down 44.3% on average) and increased impairment charges (up by €4,361 million)5%. The negative impactsdecrease in gas realization prices did not take into account the lower prices realized on the reselling of volumes of gas entitlements of a Libyan partner, which were only partially offset by a favorable exchange rate environment, higher production volumes and reduced operating expenses.
In 2015, the Company’s liquids and gas realizations decreased on average by 44.3%marketed in dollar terms, driven by a decline in international oil prices for market benchmarks (Brent crude price decreased by 47%).Europe, because Eni’s average oil realizations decreased on average by 47.8%. Eni’s averagerealized gas realizations decreased by 33.8%.prices are calculated only with reference to equity production.
In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the non-core gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of core business performance across reporting periods. Excluding the below-listedIn 2019, non-core gains and losses included impairment charges of oil&gas assets (€1,217 million), environmental charges (€32 million) and an allowance for doubtful accounts as part of a dispute to recover credits for investments to align the recoverable amount with the expected outcome of an ongoing renegotiation (€123 million) and included the gain on the assets disposal (€145 million) mainly related to the disposal of the 20% interest in the Merakes discoveries to Neptune.
Excluding those items, the E&P segment reported a Non-GAAP operating profit of €2,494€8,640 million, with a decrease of €1,688€2,210 million from 2015, or 40.4%. The decrease was2018, down by 20.4%, driven byby: (i) a weak commoditynegative impact of the trading environment which drove reduced oil&gas realizations in dollar terms (down by 20.1% on average) and(€2.23 billion) mainly due lower prices of equity gas as well as a four-month and half production shutdownloss incurred at the Val d’Agri site. reselling of volumes of gas entitlements of a Libyan partner due to a mismatch between the indexation of the procurement costs vs. the reselling price; (ii) a flattening yield curve which increased the present value of the assets retirement costs capitalized as property, plant and equipment, resulting in higher amortization charges through profit (€200 million); (iii) the effect of the Vår Energi deal consummated at the end of 2018 with the de-recognition of the former subsidiary Eni Norge, effective January 1, 2019. These negativesnegative trends were partly offset by higher production in other areas and lower operating expenses and DD&Aan improved performance driven by continuing efficiency initiativesproduction growth and optimization, as well as lower carrying amountsa better volume/mix performance reflecting higher contribution of oil&gas assetsbarrels with higher-than-average profitability, partly offset by bigger write-off expenses related to unsuccessful exploration wells. Management estimated that the segment internal performance increased operating profit by 7%. Operating profit included the revenues relating to certain gas volumes which were paid by the buyer without lifting the underlying volume due to the impairments recordedtake-or-pay clause provided in 2015. | | | Year ended December 31, | | | | | 2014 | | | 2015 | | | 2016 | | Exploration & Production | | | (€ million) | | GAAP operating profit (loss) | | | | | 10,727 | | | | | | (959) | | | | | | 2,567 | | | Impairment losses (impairment reversals), net | | | | | 853 | | | | | | 5,212 | | | | | | (684) | | | Risk provisions | | | | | (5) | | | | | | 0 | | | | | | 105 | | | Impairment of exploration projects(1) | | | | | | | | | | | 169 | | | | | | 7 | | | Net gains on disposal of assets | | | | | (70) | | | | | | (403) | | | | | | (2) | | | Provision for redundancy incentives | | | | | 24 | | | | | | 15 | | | | | | 24 | | | Fair value gains/losses on commodity derivatives | | | | | (28) | | | | | | 12 | | | | | | 19 | | | Reclassification of currency derivatives and translation effects to management measure of business performance | | | | | 6 | | | | | | (59) | | | | | | (3) | | | Valuation allowance of disputed receivables | | | | | | | | | | | | | | | | | 410 | | | Other | | | | | 172 | | | | | | 195 | | | | | | 51 | | | Total gains and charges | | | | | 952 | | | | | | 5,141 | | | | | | (73) | | | Non-GAAP operating profit (loss) | | | | | 11,679 | | | | | | 4,182 | | | | | | 2,494 | | | |
(1)
a long-term supply agreement. Management has separately disclosedascertained that it is highly likely that the results ofbuyer will not redeem its contractual right to lift the impairment review conducted at certain ongoing exploration projects where management ceased its commitment due to a deteriorated commoditypre-paid volumes in future reporting periods within the contractual terms. Therefore the price environment.paid by the buyer was recognized as revenue.
| | | Year ended December 31, | | | | | 2019 | | | 2018 | | | 2017 | | Exploration & Production | | | (€ million) | | GAAP operating profit (loss) | | | | | 7,417 | | | | | | 10,214 | | | | | | 7,651 | | | Impairment losses (impairment reversals), net | | | | | 1,217 | | | | | | 726 | | | | | | (158) | | | Net gains on disposal of assets | | | | | (145) | | | | | | (442) | | | | | | (3,269) | | | Environmental provisions | | | | | 32 | | | | | | 110 | | | | | | 46 | | | Risk provisions | | | | | (18) | | | | | | 360 | | | | | | 366 | | | Reclassification of currency derivatives and translation effects to management measure of business performance | | | | | 14 | | | | | | (6) | | | | | | (68) | | | Valuation allowance of disputed receivables and others | | | | | | | | | | | 158 | | | | | | 442 | | | Reinstatement of Eni Norge amortization charges | | | | | | | | | | | (375) | | | | | | | | | Other | | | | | 123 | | | | | | 105 | | | | | | 163 | | | Total gains and charges | | | | | 1,223 | | | | | | 636 | | | | | | (2,478) | | | Non-GAAP operating profit (loss) | | | | | 8,640 | | | | | | 10,850 | | | | | | 5,173 | | |
Gas & Power. This segment comprises the wholesale business of gas, power and LNG, and the marketing of energy commodities (mainly gas and power) to retail customers. In 2016,2019, the Gas & Power segment reported an operating lossprofit of €391€699 million, improving by €867an increase of €70 million compared to 2015 when the segment reported an operating lossprofit of €1,258 million. The 2015 result was negatively affected by a downward estimate revision of revenues accrued on the sale of gas and power (€484 million) to retail customers in Italy dating back to past reporting periods and the establishment of a provision for the above mentioned accruals (€226 million). In 2016, accrued revenues were revised lower by €161 million relating reporting periods prior to 2015. Furthermore, commodity derivatives lacking criteria for being accounted as hedges generated approximately €500€629 million of higher gains in 2016. In 2015, the Gas & Power segment reported an operating lossprevious year, mainly due to a better performance of €1,258 million, down by €1,322 million from 2014 when the segment reported an operating profit of €64 million. The change reflected one-off gains associated to certain contracts renegotiation recorded in 2014, as well as the negative outcome of a commercial arbitration in 2015. Furthermore, the 2015 result was affected by an estimate revision of revenues accrued on the sale of gas and power (€484 million) to retail customers in Italy dating back to past reporting periods and the establishment of a provision for the above mentioned accruals (€226 million). Management estimates revenues accrued in the retail sales business utilizing data communicated by market operators that are responsible for verifying actual consumptions with the possibility to review their measurements until the fifth subsequent reporting period.business.
In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the gains and losses presented below in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the below-listed gains and charges, the G&P segment reported a Non-GAAP operating loss of €390 million, with a decline of €264 million from 2015. This negative trend was due to lower margins in the LNG business on sales to premium markets and lower one-off benefits from contracts renegotiations, partly offset by logistics costs optimizations and better performance in trading activities. The retail segment reported lower results due to unusual winter weather conditions.
The items excluded from GAAP operating profit in determining the Non-GAAP measure of profitability mainly include certaineffects associated with commodity fair-valued derivatives and accruals measurements. derivatives. Particularly, we enter into commodity and currency derivatives to reduce our exposure to (i) the commodity risk due to different indexation between the purchase cost and the selling price of gas and power or to lock in a commercial margin once a sale contract has been signed or it is highly probable, and (ii) the underlying exchange rate risk due to the fact that our selling prices are indexed to the euro and our supply costs are denominated in dollars. These derivatives normally hedge the Group net Group exposure to commodities and exchange rates but do not meet the requirements for being accounted for as hedges in accordance to IFRS. Therefore, in explaining year-on-year charges and in evaluating the business performance management believes that is appropriate to identify the fair valueaccounting effects of fair-valued derivatives used to hedge exposure to commodities and exchange rates, which lack the formal criteria to be accounted for as hedges or are not eligible for the own use exemption, including the ineffective portion of cash flow hedges, as well
as the accounting effects of commodity and exchange rates derivatives because theywhich relate to transactions that will close in subsequent reporting periods or we estimate the portion of gains and losses on the settlement of certain commodity derivatives whichwhere underlying physical transaction has yet to be settled with the delivery of the underlying commodity. Furthermore, albeitalthough the Group classifies within net finance expense those gains and losses on currency derivatives, as well as on the alignment of trade receivable and payables denominated in dollars into the accounts of euro subsidiaries at the closing rate, we believe that it is appropriate to consider those gains and losses on currency derivatives and alignmentcurrency differences ofat our dollar-denominated trade payables and receivables as part of the underlying business performance. Finally, management has excluded from GAAP Excluding the below-listed gains and charges, the G&P segment reported a Non-GAAP operating profit the remeasurement of revenues accrued€654 million, with an increase of €111 million from 2018. The Gas & LNG Marketing and Power segment reported a Non-GAAP operating profit of €376 million (€342 million in 2018); the retail business reported an operating profit of €278 million (€201 million in 2018). This improvement was driven by optimizations at the gas and power assets portfolio in Europe which enabled the business because they relate to past reporting periods.capture the upsides associated with a highly-volatile environment. The improved performance of the retail business was driven by effective commercial initiatives, higher extra-commodity revenues, and lower expenses. These positives were partly offset by the weaker results at our LNG business due to a worsening environment in Asia which affected margins and volumes. | | Year ended December 31, | | | Year ended December 31, | | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Gas & Power | | (€ million) | | | Gas & Power | | | (€ million) | | GAAP operating profit (loss) | | | | 64 | | | | | (1,258) | | | | | (391) | | | | | | 699 | | | | | 629 | | | | | 75 | | | (Profit) loss on inventory | | | | (119) | | | | | 132 | | | | | 90 | | | | Impairment losses | | | | 25 | | | | | 152 | | | | | 81 | | | | Risk provisions | | | | (42) | | | | | | | | | | | | | | Allowance for doubtful accruals in the retail G&P | | | | | | | | | 226 | | | | | 17 | | | | Impairment losses (impairment reversals), net | | | | | 37 | | | | | (71) | | | | | (146) | | | Environmental provisions | | | | | | | | | | (1) | | | | | | | | Provision for redundancy incentives | | | | 9 | | | | | 6 | | | | | 4 | | | | | | 4 | | | | | 122 | | | | | 38 | | | Fair value gains/losses on commodity derivatives | | | | (38) | | | | | 90 | | | | | (443) | | | | | | (423) | | | | | (156) | | | | | 157 | | | Reclassification of currency derivatives and translation effects to management measure of business performance | | | | 205 | | | | | (9) | | | | | (19) | | | | | | 92 | | | | | 112 | | | | | (171) | | | Revision of estimate revenues accruals in the retail G&P | | | | | | | | | 484 | | | | | 161 | | | | Estimated revenues accruals in the retail G&P | | | | | | | | | | | | | | | 64 | | | Revision of estimated revenues accruals in the retail G&P (difference between incurred loss vs. expected loss model) | | | | | | | | | | | | | | | 223 | | | Other | | | | 64 | | | | | 51 | | | | | 110 | | | | | | 245 | | | | | (92) | | | | | (26) | | | Total gains and charges | | | | 104 | | | | | 1,132 | | | | | 1 | | | | | | (45) | | | | | (86) | | | | | 139 | | | Non-GAAP operating profit (loss) | | | | 168 | | | | | (126) | | | | | (390) | | | | | | 654 | | | | | 543 | | | | | 214 | | | | | of which: | | | | | | | | | | | | | | | | | | – Gas & LNG Marketing and Power | | | | | 376 | | | | | 342 | | | | | 77 | | | – retail business | | | | | 278 | | | | | 201 | | | | | 137 | | |
Refining & Marketing and ChemicalsChemicals.. In 2016, the Refining & Marketing and Chemicals segment reported an operating profit of €723 million, reversing an operating loss of €1,567 million reported in 2015. The improvement of €2,290 million was mainly due to lower assets impairments because a €1 billion charge was recognized in 2015 at the Chemical business to align its carrying amount with the expected fair value based on a sale transaction then ongoing designed to establish an industrial joint venture. Furthermore, in 2015 an inventory write-down of €877 million (pre-tax) was accounted for in the profit and loss because of the fall in oil commodity prices to align the net realizable value of the inventories to prices current at the balance sheet date. In 2016, following a late-year recovery in price scenario, the write down resulted in a gain on stock. The 2016 operating profit in the Refining & Marketing and Chemicals segment was also negatively affected by the write-off related to the EST conversion plant, at Sannazzaro Refinery, following an event occurred in December 2016, and the provision for removal and clean-up (a total amount of €217 million), partially offset by the recognition of third-party insurance compensation (€122 million) In 2015,2019, the Refining & Marketing and Chemicals segment reported an operating loss of €1,567 million, thereby reducing operating losses by €1,244€854 million, compared to 2014, when this segment reported an operating loss of €2,811 million. The losses€380 million reported in 20142018 driven by a challenging trading environment and significantly higher impairment losses taken at property, plant and equipment. These negatives were partly offset by an increase in 2015 were due to inventory write-down of €1,746 million (pre-tax) in 2014, and of €877 million in 2015, as a consequence of the fall in commodity prices. Both losses included a charge to align the net book value of inventories to their net realizable values ataccounted for under the reporting date, as well as the difference between the currentweighted-average cost method of supplies and the one used for IFRS inventory accounting based on the weighted average cost.
Results in 2015 improved compared to 2014 also for a positive refining scenario. The Eni benchmark for refining margins (Standard Eni Refining Margin – SERM) improved from 3.2 $/BBL to 8.3 $/BBL. Results benefited from initiatives to optimize operations, to reduce costs and to improve energy efficiency.accounting.
The main item excluded from GAAP operating profit in determining the Non-GAAP measure of profitability is the inventory holding gain (or loss). Inventory holding gains or losses represent the difference between the cost of sales of the volumes sold during the period calculated using the cost of supplies incurred during the same period and the cost of sales calculated using the weighted average cost method. Under the weighted average cost method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant impact on reported income thereby affecting comparability. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a weighted average cost method basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a quarterly or monthly basis by dividing the total cost of inventory acquired in the
period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. We regard the inventory holding gain or loss, including any write-down to align the carrying amounts of inventories to their net realizable value at the reporting date, as lacking correlation to the underlying business performance which we track by matching revenues with current costs of supplies. In addition to the inventory holding loss, the non-core items of this segment for the year 2019 also comprised (i) significant impairment losses recorded at the Sannazzaro refinery, reflecting a revised margin outlook both at high and low-complexity cycles and higher projected expenses for emission allowances, as well as the write-down of capital expenditure relating to certain Cash Generating Units in the R&M business impaired in previous reporting periods, which continued lacking profitability prospects (€819 million); (ii) impairment losses of Chemical assets due to a lowered profitability outlook (€103 million); (iii) environmental provisions (€244 million), partly offset by (iv) insurance compensation (€88 million) relating to an incident occurred at the EST plant at the Sannazzaro refinery in previous reporting periods. In reviewing the performance of the Company’s business segments and with a view to better explaining year-on-year changes in the segment performance, management generally excludes the inventory holding gain (or loss) and the other non-core gains and losses presented belowdescribed above in order to assess the underlying industrial trends and obtain a better comparison of base business performance across reporting periods. Excluding the below-listed gains and charges, thethose items, R&M and Chemical segmentbusiness reported a Non-GAAP operating profit of €583€220 million with(€390 million in 2018) while the Chemical business reported a reductionNon-GAAP operating loss of €112€268 million from 2015. (a loss of €10 million in 2018). The segment base performance in 2016refining activity was negatively affected by an unfavorable margin scenario, as the Eni benchmark forlower refining margins the Standard Eni Refining Margin – SERM was down by 49%, from 8.3 $/BBL in 2015mainly due to 4.2 $/BBL in 2016. Other negative drivers were a planned shutdown of the Livorno refinery for extensive maintenancenarrowing price differentials between heavy crudes and the shutdownBrent market benchmark which impaired the profitability of ESTEni’s complex refineries, as well as by lower products spreads, particularly lubricants and by longer and unplanned plant upset and outages. Marketing activities reported an improved performance both in the retail and wholesale segments also leveraging on effective commercial initiatives to support margins and on efficiency actions. The Chemical business reported an adjusted operating loss of €268 million in 2019, a significant decline from 2018 when the segment almost achieved breakeven. The result was affected by the worsening trading environment due to a slowdown in demand at the Sannazzaro refinery due tomain end-markets, particularly the accidentautomotive sector, and by weaker demand of single-use plastics pressured by stricter environmental regulations. Furthermore, in a shrinking global market, downward margins trends were exacerbated by rising competitive pressure from producers with lower feedstock costs (e.g., US producers using ethane-based crackers) and larger cost economies. These drivers determined unprofitable spreads between product prices and feedstock costs mainly for polyethylene and a profitability decline at styrenics and elastomers. The operating performance was also negatively affected by the incident that occurred at the beginningPriolo hub, which was fully operational by the end of December 2016. Moreover, marketing recorded lower results reflecting weaker margins due to stronger competitive pressureJuly, and asset disposals in Slovenia and Hungary. These negative trends were counteracted by continuing efficiencies and plant optimization, which drove a reduction in the refining breakeven margin down to $4.2 per barrel. The Chemical business’ results were affected by an unfavorable trading environment, which hit commodity margins.other unplanned shutdowns. | | | Year ended December 31, | | | | | 2014 | | | 2015 | | | 2016 | | Refining & Marketing and Chemicals | | | (€ million) | | GAAP operating profit (loss) | | | | | (2,811) | | | | | | (1,567) | | | | | | 723 | | | (Profit) loss on inventory | | | | | 1,746 | | | | | | 877 | | | | | | (406) | | | Environmental provisions | | | | | 138 | | | | | | 137 | | | | | | 104 | | | Impairment losses | | | | | 380 | | | | | | 1,150 | | | | | | 104 | | | Net gains on disposal of assets | | | | | 43 | | | | | | (8) | | | | | | (8) | | | Risk provisions | | | | | | | | | | | (5) | | | | | | 28 | | | Provision for redundancy incentives | | | | | (4) | | | | | | 8 | | | | | | 12 | | | Fair value gains/losses on commodity derivatives | | | | | 41 | | | | | | 68 | | | | | | (3) | | | Reclassification of currency derivatives and translation effects to management measure of business performance | | | | | 18 | | | | | | 5 | | | | | | 3 | | | Other | | | | | 37 | | | | | | 30 | | | | | | 26 | | | Total gains and charges | | | | | 2,399 | | | | | | 2,262 | | | | | | (140) | | | Non-GAAP operating profit (loss) | | | | | (412) | | | | | | 695 | | | | | | 583 | | | |
| | | Year ended December 31, | | | | | 2019 | | | 2018 | | | 2017 | | Refining & Marketing and Chemicals | | | (€ million) | | GAAP operating profit (loss) | | | | | (854) | | | | | | (380) | | | | | | 981 | | | (Profit) loss on inventory | | | | | (318) | | | | | | 234 | | | | | | (213) | | | Environmental provisions and other costs | | | | | 244 | | | | | | 243 | | | | | | 136 | | | Impairment losses (impairment reversals), net | | | | | 922 | | | | | | 193 | | | | | | 54 | | | Net gains on disposal of assets | | | | | (5) | | | | | | (9) | | | | | | (13) | | | Provision for redundancy incentives | | | | | 8 | | | | | | 8 | | | | | | (6) | | | Other | | | | | (45) | | | | | | 91 | | | | | | 52 | | | Total gains and charges | | | | | 806 | | | | | | 760 | | | | | | 10 | | | Non-GAAP operating profit (loss) | | | | | (48) | | | | | | 380 | | | | | | 991 | | | – Refining & Marketing | | | | | 220 | | | | | | 390 | | | | | | 531 | | | – Chemicals | | | | | (268) | | | | | | (10) | | | | | | 460 | | |
Corporate and Other activities. These activities are mainly cost centers comprising holdings, financing and treasury headquarters,activities in support of operating subsidiaries, central functions like information technology,
legal counselling, human resources, self-insuranceinsurance activities general and administrative support, as well as the Group environmental clean-up and remediation activities performed by the subsidiary Syndial.EniRewind and the Energy Solutions business engaged in the development of renewable energy. The aggregate Corporate and Other activities reported an operating loss of €681€710 million in 2016 representing2019, an increase of €184€19 million from 2015,2018, or 37%, mainly reflecting the recognition of risk provisions related to environmental issues and other that were partly offset by the implementation of cost efficiency measures. The aggregate Corporate and Other activities reported an operating loss of €497 million in 2015 representing a decrease of €21 million from 2014, or 4.1%, mainly reflecting the recognition of risk provisions related to environmental issues and other that were partly offset by the implementation of cost efficiency measures.2.7%.
e) Net finance expenses The table below sets forth a breakdown of Eni’s net financial expenses for the periods indicated: | | | Year ended December 31, | | | | | 2019 | | | 2018 | | | 2017 | | | | | (€ million) | | Income (expense) on derivative financial instruments | | | | | (14) | | | | | | (307) | | | | | | 837 | | | of which
– Derivatives on exchange rate | | | | | 9 | | | | | | (329) | | | | | | 809 | | | – Derivatives on interest rate | | | | | (23) | | | | | | 22 | | | | | | 28 | | | Exchange differences, net | | | | | 250 | | | | | | 341 | | | | | | (905) | | | Finance expense on short and long-term debt | | | | | (740) | | | | | | (685) | | | | | | (751) | | | Interest expense for lease liabilities | | | | | (378) | | | | | | | | | | | | | | | Interest from banks | | | | | 21 | | | | | | 18 | | | | | | 12 | | | Net income from financial activities held for trading | | | | | 127 | | | | | | 32 | | | | | | (111) | | | Finance expense due to the passage of time (accretion discount) | | | | | (255) | | | | | | (249) | | | | | | (264) | | | Other finance income and expense, net | | | | | 17 | | | | | | (173) | | | | | | (127) | | | | | | | | (972) | | | | | | (1,023) | | | | | | (1,309) | | | Finance expense capitalized | | | | | 93 | | | | | | 52 | | | | | | 73 | | | NET FINANCE EXPENSES | | | | | (879) | | | | | | (971) | | | | | | (1,236) | | |
Net finance expense
| | | Year ended December 31, | | | | | 2014 | | | 2015 | | | 2016 | | | | | (€ million) | | Gain (loss) on derivative financial instruments | | | | | 165 | | | | | | 160 | | | | | | (482) | | | - Options | | | | | 68 | | | | | | 33 | | | | | | 24 | | | - Derivatives on exchange rate | | | | | 51 | | | | | | 96 | | | | | | (494) | | | - Derivatives on interest rate | | | | | 46 | | | | | | 31 | | | | | | (12) | | | Exchange differences, net | | | | | (415) | | | | | | (354) | | | | | | 676 | | | Net income from financial activities held for trading | | | | | 24 | | | | | | 3 | | | | | | (21) | | | Interest income | | | | | 19 | | | | | | 19 | | | | | | 15 | | | Finance expense from banks on short and long-term debt | | | | | (871) | | | | | | (838) | | | | | | (757) | | | Finance expense due to the passage of time | | | | | (293) | | | | | | (291) | | | | | | (312) | | | Other finance income and expense, net | | | | | 41 | | | | | | (171) | | | | | | (110) | | | | | | | | (1,330) | | | | | | (1,472) | | | | | | (991) | | | Finance expense capitalized | | | | | 163 | | | | | | 166 | | | | | | 106 | | | | | | | | (1,167) | | | | | | (1,306) | | | | | | (885) | | | |
2016 compared to 2015. In 2016,2019, net finance expenses were €885€879 million, down by €421a small improvement of €92 million comparedfrom 2018. This reduction was due to 2015 reflecting the recording oflower losses at fair-valued currency gains partly offset by negative fair value adjustments on currency derivatives, (for a net positive effect of €440 million), with the latter lacking the formal criteria to be designated as hedges under IFRS. Furthermore, lower finance expense on debt were recorded due to the reduction in net borrowings and to lower interest rates reflecting accommodative monetary policies adopted by the Central Banks worldwide. These positives wereIFRS, partly offset by impairment losseslower gains on certain financingcurrency translation differences at dollar-denominated payables and receivables grantedaccrued by Italian subsidiaries, as the Group normally pools different exposures to equity-accounted entities which are currently executing industrial projects on Eni’s behalf (€121 million). Furthermore, a discount expense of €129 million was recognized relatingthe currency risk retained by operating subsidiaries and then hedges the Group net exposure to certain receivable in the E&P segment owed by certain NOCs due to agreements to repay the overdue amount in instalments with the proceeds associated with mineral initiatives. On that basis, the discount rate utilized reflected also the mineral risk.
2015 compared to 2014. In 2015,2019 net finance expenses include €378 million relating to the recognition of finance expenses for lease liabilities, as required by IFRS 16. Furthermore, finance expense from banks on short and long-term debt increased by €55 million reflecting the increase in net borrowings.
Other net finance income and expense were €1,306a gain of €17 million, upreverting a loss of €173 million accounted in 2018 driven by €139 million compared to 2014. The higher gains on derivatives on exchange rate (up €45 million) which did not meet the formal criteria to be designated as hedges under IFRS were more than offset by the negative effect of the impairment of operating financing receivables and securities for financing operating activities related to a Nigerian project following the revision of the commodity price scenario. The balance of net expenses was helpeddue by a reductionan equity-accounted entity, which engaged in the liability relatingexecution of an exploration projects that was written-off due to the fair-valued options (€33 million) embedded in the convertible bond relating to Snam shares. The reduction reflected the exercise of the option to convert the bond in Snam shares for approximately 6% of the share capital of the investee, with the remaining portion of the bond corresponding to approximately 2% of the share capital closer to maturity.an unsuccessful outcome.
f) Net income from investments 2016 compared to 2015. In 20162019 the Group reported a net lossprofit from investments of €380€193 million and mainly related to:
(i)i).
resultsdividends of equity-accounted entities (an overall net loss of €326 million), mainly reported€247 million paid by the Exploration & Production segment due to a weaker commodity scenario and the economic difficulties recordedminority investments in certain Countries with a negative impact on the level of inflation and exchange rates. Particularly, the segment incurred a loss of €144 million mainly related to our joint ventures in Venezuela (PetroSucre,entities which bookwere designated at fair value was completely written off, Cardón IV and PetroBicentenario) driven by changed economics due to the local currency devaluation and rising inflation leading to escalating operating costs.
(ii)
a loss of €144 million was recorded on the equity-accounted interest retained in Saipem. This was driven by the recognition of asset impairment charges andthrough other extraordinary expenses accounted for in Saipem’s results due to the impairment review performed by the investee at its CGUs based on its updated industrial plan. That plan, announced in October 2016, factored in a slower recovery in the oil market and in investment plans of the international oil companies;
(iii)
net losses on the divestment of interests (€14 million) mainly relating to the disposal of the residual 2.22% interest in Snam (€32 million), offset by gains on the divestment of interests (€18 million) mainly of the 100% share in Slovenija doo, Eni Hungaria Zrt and other non-core interests;
(iv)
other losses mainly relating to an impairment charge recorded in G&P related to the interest in Unión Fenosa Gas SA (€84 million) due to a reduced profitability outlook and the impairment of receivables in the E&P segment owed by the equity-accounted PetroSucre SAcomprehensive income under IFRS 9 except for dividends resolved but yet to be paid (€65 million).
which are recorded through profit. These losses were partly offset by dividends received from entities accounted for at cost (€143 million) relating tomainly comprised Nigeria LNG Ltd (€76 million)186 million, where Eni has an interest of 10.4%) and Saudi European Petrochemical Co (€45 million).46 million, where Eni has an interest of 10%); 2015 compared to 2014
ii). Net income from
a loss of €88 million recorded at equity-accounted investments, mainly in 2015 was a net gain of €105 millionthe R&M and mainly related to: (i) dividends received from entities accounted for at costChemical segment (€402 million), relating to Nigeria LNG Ltd (€22263 million) and Snam SpA (€72 million); (ii) gains on disposal of investments (€164 million) which related to a gain recorded on the sale of an 8% interest in Galp (€98 million), gains on the divestment of a 6.03% interest in Snam (€46 million), gains on the divestment of refining infrastructures in Eastern Europe (€70 million), as well as the loss (€47 million) related to the divestment of minor assets in the Gas & Power business in Argentina;Corporate and (iii) other net gains includingactivities (€21 million). These share of profits at equity-accounted investments included the alignment to stock price at December 31, 2015contribution of the Snam stock prices pertaining to Eni after the exercise of the conversion right by the bondholders (€49 million calculated on the 2.22% interest owned by Eni at the closing date). Those gains were partly offset by impairment losses registered in the business: (i) E&P relating to Angola LNG Ltd amounting to €469 million, including production and operating costs related to the start-up of liquefaction plant due to the revision of commodity scenario; and (ii) Gas & Power related to the interest on Unión Fenosa Gas SAupstream joint venture Vår Energi (€49 million). These gains are further explained in “Item 18 – note 20 – Investments – of the Notes on Consolidated Financial Statements”.
g) Taxes
2016 compared to 2015. In 2016, income taxes amounted to €1,936 million, down by €1,186 million compared to 2015, or 38%. These lower charges mainly reflected lower write-downs of deferred tax assets in connection with improved projections of future taxable profit against which those assets would be utilized compared to 2015. Particularly, in 2015 deferred taxes were written down by €1,740 million relating to foreign subsidiaries of the E&P segment and Italian subsidiaries due to a deteriorated profitability outlook. By contrast, the write-downs of deferred tax assets in 2016 were offset by write-ups. In addition, considering the expected outcome of ongoing negotiations to settle disputed receivables owed by the Nigerian national oil company, the Company utilized a provision for deferred tax liabilities for €380 million as those receivables were considered tax-deductible.
| | | Year ended December 31, | | | | | 2019 | | | 2018 | | | 2017 | | | | | (€ million) | | Share of gains (losses) from equity-accounted investments | | | | | (88) | | | | | | (68) | | | | | | (267) | | | Dividends | | | | | 247 | | | | | | 231 | | | | | | 205 | | | Net gains (losses) on disposals | | | | | 19 | | | | | | 22 | | | | | | 163 | | | Other income (expense), net | | | | | 15 | | | | | | 910 | | | | | | (33) | | | | | | | | 193 | | | | | | 1,095 | | | | | | 68 | | |
g) Taxes In 2015 and in 2016, the Group reported tax rate was much higher than the Group historical tax rates. This negative trend was negatively affected by the increased share of taxable profit earned in PSA contracts which bear higher-than-average rates of tax. Furthermore, in many jurisdictions where the Group reported pre-tax losses, the Company was not in the position of recognizing deferred tax assets, due to lack of sufficient future taxable profit against which those tax assets would be utilized. Management is estimating that in the four-year plan 2017-2020 the Group tax rate will progressively normalize in line with an expected recovery in the E&P results in concession contracts and an expected recovery in the pre-tax profit of Italian subsidiaries due to the ongoing upgrading plans at our G&P, R&M and Chemical businesses. 2015 compared to 2014. In 2015,2019, income taxes amounted to €3,122€5,591 million, down by €3,344€379 million compared to 2014,2018, or 51.7%, mainly reflecting6.3%. This decrease reflected lower income before taxes currently payablewhich was €4,361 million lower than in 2018.
Tax rate was approximately 97% compared to 59% reported in 2018, reflecting a higher share of taxable incomes reported by subsidiaries in the Exploration & Production segment operating outside Italy duein jurisdictions subject to higher-than-average tax rates, the tax effect related to a decliningloss incurred in connection with the reselling of gas entitlements of a Libyan partner as disclosed in the “executive summary” section, while taxable profit. In spite of the fact thatlosses were incurred in 2015 Eni’s group pre-tax earnings werejurisdictions with a loss, the Group incurred a netlower-than-average statutory tax expense. This negative development was influenced by a higher tax rate in E&P. The main drivers of this were three. First, the segment’s taxable profit was mainly earned in PSA contracts, which, although more resilient in a low-price environment due to the cost recovery mechanism, nonetheless bear higher-than-average rates of tax. Secondly, there was higher incidence of certain non-deductible expenses on the pre-tax profit lowered by the scenario. In addition, the tax rate was impacted by lower recognition of deferred tax assets relating operating losses due to a reduced profitability outlook (€1,058 million).rate. The Group tax rate was also negatively impacted by the write-off of Italian deferred tax assets and other changes of €1,607approximately €900 million in the full year due to projections of lower future taxable profit at Italian subsidiaries and the reduction of the statutorysubsidiaries. In 2020, we expect that a lower crude oil price environment will negatively affect our tax rate from 27.5% to 24%, which was considered as substantially enacted at the reporting date.rate. Liquidity and capital resources Eni’s cash requirements for working capital, dividends to shareholders, capital expenditures, acquisitions and acquisitionsshare repurchases over the past three years were financed primarily by a combination of funds generated from operations, borrowings and divestments of minority interests in certain of our exploration assets and other non-strategic assets.activities. The Group continually monitors the balance between cash flow from operating activities and net expenditures targeting a sound and balanced financing structure.
The following table summarizes the Group cash flows and the principal components of Eni’s change in cash and cash equivalent for the periods indicated. | | | Year ended December 31, | | | | | 2014 | | | 2015 | | | 2016 | | | | | (€ million) | | Net profit - continuing operations | | | | | 1,808 | | | | | | (7,399) | | | | | | (1,044) | | | Adjustments to reconcile net profit to net cash provided by operating activities: | | | | | | | | | | | | | | | | | | | | - amortization and depreciation charges, impairment losses, write-off 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 expenditures - continuing operations | | | | | (11,178) | | | | | | (10,741) | | | | | | (9,180) | | | Capital expenditures - discontinued operations | | | | | (694) | | | | | | (561) | | | | | | | | | Capital expenditures | | | | | (11,872) | | | | | | (11,302) | | | | | | (9,180) | | | Investments and purchases of consolidated subsidiaries and businesses | | | | | (408) | | | | | | (228) | | | | | | (1,164) | | | Disposals of consolidated subsidiaries, businesses, tangible and intagible assets and investments | | | | | 3,684 | | | | | | 2,258 | | | | | | 1,054 | | | Other cash flow related to investing activity (*) (**) | | | | | 21 | | | | | | (1,651) | | | | | | 5,736 | | | Changes in short and long-term finance 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 equivalents related to discontinued operations | | | | | 78 | | | | | | (780) | | | | | | (3) | | | Change in cash and cash equivalents for the year | | | | | 1,183 | | | | | | (1,405) | | | | | | 465 | | | Cash and cash equivalents at the beginning of the year | | | | | 5,431 | | | | | | 6,614 | | | | | | 5,209 | | | Cash and cash equivalents at year end | | | | | 6,614 | | | | | | 5,209 | | | | | | 5,674 | | | |
(*)
For 2016, the item also includes the reimbursement of intercompany financing loans owed to Eni by Saipem for € 5,818 million.
(**)
Net cash used in investing activities included investments in and divestments of certain financial assets (mainly bank deposits) to absorb temporary surpluses of cash or as part of our ordinary management of financing activities. Due to their nature and the circumstance that they are very liquid, these financial assets are netted against finance debt in determining net borrowings. Furthermore, due to the Company’s decision to retain a cash reserve by investing the proceeds of the disposal plan in the purchase of held-for-trading securities, net cash used in investing activities also includes investments and divestments of those securities. Also these held-for-trading financial assets are netted against finance debt in determining the Group net borrowings. For more information on their composition see Note No. 9 to the Consolidated Financial Statements. For the definition of net borrowings, see “Financial Condition” below. Cash flows of such investments were as follows:
| | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Investing activity: | | | | | | | | | | | | | | | | | | | | - securities | | | | | (19) | | | | | | (140) | | | | | | (1,317) | | | - financing receivables | | | | | (519) | | | | | | (343) | | | | | | (272) | | | | | | | | (538) | | | | | | (483) | | | | | | (1,589) | | | Disposal: | | | | | | | | | | | | | | | | | | | | - securities | | | | | 32 | | | | | | 1 | | | | | | | | | - financing receivables | | | | | 92 | | | | | | 182 | | | | | | 6,860 | | | | | | | | 124 | | | | | | 183 | | | | | | 6,860 | | | Net cash flows used in investing activity | | | | | (414) | | | | | | (300) | | | | | | 5,271 | | | |
| | | Year ended December 31, | | | | | 2019 | | | 2018 | | | 2017 | | | | | (€ million) | | Net profit (loss) | | | | | 155 | | | | | | 4,137 | | | | | | 3,377 | | | Adjustments to reconcile net profit to net cash provided by operating activities: | | | | | | | | | | | | | | | | | | | | – amortization and depreciation charges, impairment losses, write-off and other non monetary items | | | | | 10,480 | | | | | | 7,657 | | | | | | 8,720 | | | – net gains on disposal of assets | | | | | (170) | | | | | | (474) | | | | | | (3,446) | | | – dividends, interest, taxes and other changes | | | | | 6,224 | | | | | | 6,168 | | | | | | 3,650 | | | Changes in working capital related to operations | | | | | 366 | | | | | | 1,632 | | | | | | 1,440 | | | Dividends received by equity investments | | | | | 1,346 | | | | | | 275 | | | | | | 291 | | | Taxes paid | | | | | (5,068) | | | | | | (5,226) | | | | | | (3,437) | | | Interests (paid) received | | | | | (941) | | | | | | (522) | | | | | | (478) | | | Net cash provided by operating activities | | | | | 12,392 | | | | | | 13,647 | | | | | | 10,117 | | | Capital expenditures | | | | | (8,376) | | | | | | (9,119) | | | | | | (8,681) | | | Acquisition of investments and businesses | | | | | (3,008) | | | | | | (244) | | | | | | (510) | | | Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments | | | | | 504 | | | | | | 1,242 | | | | | | 5,455 | | | Other cash flow related to investing activities | | | | | (254) | | | | | | 942 | | | | | | (373) | | | Net investment (divestment) of securities and financing receivables not-related to operations (*) | | | | | (279) | | | | | | (357) | | | | | | 341 | | |
The table below sets forth the principal components of Eni’s change in net borrowings (1) for the periods indicated.
| | | Year ended December 31, | | | | | 2014 | | | 2015 | | | 2016 | | | | | (€ million) | | Net cash provided by operating activities | | | | | 14,742 | | | | | | 11,649 | | | | | | 7,673 | | | Capital expenditures | | | | | (11,872) | | | | | | (11,302) | | | | | | (9,180) | | | Acquisitions of investments and businesses | | | | | (408) | | | | | | (228) | | | | | | (1,164) | | | Disposals | | | | | 3,684 | | | | | | 2,258 | | | | | | 1,054 | | | Other cash flow related to capital expenditures, investments and divestments | | | | | 435 | | | | | | (1,351) | | | | | | 465 | | | Net borrowings(1) of acquired companies | | | | | (19) | | | | | | | | | | | | | | | Net borrowings(1) of divested companies | | | | | | | | | | | 83 | | | | | | 5,848 | | | Exchange differences on net borrowings and other changes | | | | | (850) | | | | | | (818) | | | | | | 284 | | | Dividends paid and changes in minority interest and reserves | | | | | (4,434) | | | | | | (3,477) | | | | | | (2,885) | | | Change in net borrowings(1) | | | | | 1,278 | | | | | | (3,186) | | | | | | 2,095 | | | Net borrowings(1) at the beginning of the year | | | | | 14,963 | | | | | | 13,685 | | | | | | 16,871 | | | Net borrowings(1) at year end | | | | | 13,685 | | | | | | 16,871 | | | | | | 14,776 | | | |
| | | Year ended December 31, | | | | | 2019 | | | 2018 | | | 2017 | | | | | (€ million) | | Changes in short and long-term finance debt | | | | | (1,540) | | | | | | 320 | | | | | | (1,712) | | | Repayment of lease liabilities | | | | | (877) | | | | | | | | | | | | | | | Dividends paid and changes in non-controlling interests and reserves | | | | | (3,424) | | | | | | (2,957) | | | | | | (2,883) | | | Effect of changes in consolidation, exchange differences and cash and cash equivalents | | | | | 1 | | | | | | 18 | | | | | | (65) | | | Net increase (decrease) in cash and cash equivalent | | | | | (4,861) | | | | | | 3,492 | | | | | | 1,689 | | | Cash and cash equivalent at the beginning of the year | | | | | 10,855 | | | | | | 7,363 | | | | | | 5,674 | | | Cash and cash equivalent at year end | | | | | 5,994 | | | | | | 10,855 | | | | | | 7,363 | | | |
(*)
From 2019, Eni’s cash flow statement is reporting in a dedicated line-item the net cash outflow (investments minus divestments) in held-for-trading financial assets and current non-operating receivables financing, with the latter being investment of temporary cash surpluses. Those two assets are netted against financial liabilities to determine the Group net borrowings . In previous reporting periods, cash inflows and outflows relating those assets were reported among investing activities or divesting activities relating to securities and financing receivables, respectively. The establishment of a dedicated line-item for these cash flows enables the users of financial statements to promptly reconcile the statutory cash flow statement to the Non-Gaap financial disclosure relating to changes in the Company’s net borrowings, because the difference between the two cash flow statements is the net investment in held-for-trading securities and current non-operating receivables financing which are part of net cash from financing activities in the Non-Gaap cash flow statements. The cash flow statements of comparative periods have been reclassified accordingly. | | | Year ended December 31, | | | | | 2019 | | | 2018 | | | 2017 | | | | | (€ million) | | Net cash provided by operating activities | | | | | 12,392 | | | | | | 13,647 | | | | | | 10,117 | | | Capital expenditures | | | | | (8,376) | | | | | | (9,119) | | | | | | (8,681) | | | Acquisitions of investments and businesses | | | | | (3,008) | | | | | | (244) | | | | | | (510) | | | Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments | | | | | 504 | | | | | | 1,242 | | | | | | 5,455 | | | Other cash flow related to capital expenditures, investments and divestments | | | | | (254) | | | | | | 942 | | | | | | (373) | | | Repayment of lease liabilities | | | | | (877) | | | | | | | | | | | | | | | Net borrowings(1) of acquired companies | | | | | | | | | | | (18) | | | | | | | | | Net borrowings(1) of divested companies | | | | | 13 | | | | | | (499) | | | | | | 261 | | | Exchange differences on net borrowings and other changes | | | | | (158) | | | | | | (367) | | | | | | 474 | | | Dividends paid, share repurchases and changes in minority interest and reserves | | | | | (3,424) | | | | | | (2,957) | | | | | | (2,883) | | | Change in net borrowings(1) before IFRS 16 effects | | | | | (3,188) | | | | | | 2,627 | | | | | | 3,860 | | | IFRS 16 first application effect | | | | | (5,759) | | | | | | | | | | | | | | | Repayment of lease liabilities | | | | | 877 | | | | | | | | | | | | | | | Inception of new leases for the year | | | | | (766) | | | | | | | | | | | | | | | Change in net borrowings after IFRS 16 effects(1) | | | | | (8,836) | | | | | | 2,627 | | | | | | 3,860 | | | Net borrowings(1) at the beginning of the year | | | | | 8,289 | | | | | | 10,916 | | | | | | 14,776 | | | Net borrowings(1) at year end | | | | | 17,125 | | | | | | 8,289 | | | | | | 10,916 | | |
(1)
Net borrowings is a non-GAAP financial measure. For a discussion of the usefulness of net borrowings and its reconciliation with the most directly comparable GAAP financial measures see “Financial Condition” below. Analysis of certain componentsthe line items of Eni’s change in net borrowingsthe profit and loss account In 2016,2019, adjustments to reconcile net profit from continuing operations to net cash provided by operating activities from continuing operations mainly related to non-monetary charges and gains, which primarily regarded depreciation, depletion, amortization and impairment charges and reversals and the write-off of tangible and intangible assets (€7,43410,594 million). Adjustments to net profit also included accrued income taxes (€1,9365,591 million) and interest expense (€6451,027 million), which were more thanpartly offset by amounts actually paid (€2,9415,068 million and €780€1,029 million, respectively). In 2015, adjustments to reconcile net106
Net profit from continuing operations to net cash providedwas negatively impacted by operating activities from continuing operations mainlyextraordinary credit losses related to non-monetary chargesa valuation allowance for doubtful accounts incurred in the E&P business and gains, which primarily regarded depreciation, depletion, amortization, impairment charges (impairment reversals, net) and write-offcertain provisions for an overall amount of tangible and intangible assets (€16,162 million). Adjustments to net profit also included gains on disposals (€577 million) relating mainly to the sale of a number of oil&gas properties in Nigeria, accrued income taxes (€3,122 million) and interest expense (€659 million) more than offset by amounts actually paid (€4,295 million and €692 million, respectively). Cash-outs for income taxes were partly offset by the reimbursement and the disposal to financing institutions of certain tax receivables due to the parent company (approximately €900 million).€336 million. a) Changes in working capital related to operations In 2016,2019, working capital generated an inflow of €2,112€366 million. This was mainly due to a positive balance between trade receivables collected and trade payables paid (a net inflow of €2,781€83 million) which reflected the higher volume of trade receivables due subsequently to the reporting date which were sold to financing institutions compared to the previous reporting period (about €1 billion). This inflow was partly offset by utilizations of the risk provision for €1,043 million, part of which related to the settlement of obligations towards third parties mainly in the G&P segment also in relation to the final award of an arbitration procedure involving a long-term gas buyer. Conversely an advance made to the same buyer in the previous reporting period was utilized. Finally the working capital inflow was partly absorbed by a reimbursement in-kind of a financing receivable due by an equity-accounted entity operating a gas field in Venezuela with trading receivables (€300 million) due by the Venezuelan state-owned oil company (PDVSA). Finally a positive adjustment related the item other current assets and liabilities (up by €647 million) which mainly reflected the impairment of receivables owed by National Oil Companies due to the expected outcome of ongoing negotiations to settle disputed amounts. The G&P segment was the main driver of the cash inflow from working capital in 2016, reflecting also non-recurring trends. We expect that the G&P working capital contribution will normalize going forward.
In 2015, changes in working capital were positive for €4,781 million as a result of: (i) a positive balance between trade receivables collected and trade payables paid (a net inflow of €2,602 million), which was mainly driven by a positive performance in the Gas & Power segment; (ii) decreasing inventories (a positive €1,638 million) as a result of the alignment of the book value of crude oil and products to market prices (this item being an adjustment of the inventory loss recorded in net profit and as such is not a cash item), as well as reduced inventory levels in R&M due to optimizations measures; and (iii) a positive inflow related to other current assets and liabilities (up by €498 million) which mainly reflected a net positive inflow in the Gas & Power segment dueand because we collected advances on future supplies of equity gas to state-owned partners in Egypt in implementation of the agreements designed to provide adequate funding to the collection of pre-paid volumes of gas under take-or-pay contracts andongoing capital projects to develop hydrocarbons reserves in the collection of receivables from supplied long-term customers.Country (€280 million), mainly the Zohr project. These inflows were partly offset by a greater exposurethe outflows in connection with the settlement of an arbitration proceeding which was provisioned in the E&P segment towards joint venture partners.previous reporting period.
b) Investing activities
| | Year ended December 31, | | | Year ended December 31, | | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | | | (€ million) | | | (€ million) | | Exploration & Production | | | | 10,156 | | | | | 9,980 | | | | | 8,254 | | | | | | 6,996 | | | | | 7,901 | | | | | 7,739 | | | Gas & Power | | | | 172 | | | | | 154 | | | | | 120 | | | | | | 230 | | | | | 215 | | | | | 142 | | | Refining & Marketing and Chemicals | | | | 819 | | | | | 628 | | | | | 664 | | | | | | 933 | | | | | 877 | | | | | 729 | | | Corporate and other activities | | | | 113 | | | | | 64 | | | | | 55 | | | | | | 231 | | | | | 143 | | | | | 87 | | | Impact of unrealized intragroup profit elimination | | | | (82) | | | | | (85) | | | | | 87 | | | | | | (14) | | | | | (17) | | | | | (16) | | | Capital expenditures - continuing operations | | | | 11,178 | | | | | 10,741 | | | | | 9,180 | | | | Capital expenditures - discontinued operations | | | | 694 | | | | | 561 | | | | | | | | | Capital expenditures | | | | 11,872 | | | | | 11,302 | | | | | 9,180 | | | | | | 8,376 | | | | | 9,119 | | | | | 8,681 | | | Acquisitions of investments and businesses | | | | 408 | | | | | 228 | | | | | 1,164 | | | | | | 3,008 | | | | | 244 | | | | | 510 | | | | | | | 12,280 | | | | | 11,530 | | | | | 10,344 | | | | | | 11,384 | | | | | 9,363 | | | | | 9,191 | | | Disposals | | | | (3,684) | | | | | (2,258) | | | | | (1,054) | | | | | | Disposals of consolidated subsidiaries, businesses, tangible and intangible assets and investments | | | | | (504) | | | | | (1,242) | | | | | (5,455) | | |
Capital expenditures totaled €9,180€8,376 million and €11,302€9,119 million, respectively in 20162019 and in 2015.2018. For a discussion of capital expenditures by business segment and a description of year-on-year changes see below “Capital expenditures by segment”. Acquisition of investments and businesses totaled €1,164€3,008 million in 20162019 and €228 millionmainly related to the acquisition of a 20% interest in 2015. In 2016, theyADNOC Refining in Abu Dhabi for a cash consideration of €2,896 million. The transaction is part of Eni’s strategy aimed at achieving better geographical diversification of the portfolio and at rebalancing along the hydrocarbons value chain. Other investments comprised the subscription of thea share capital increase of Saipem (€1,069 million)€39 million at the Lotte Versalis Elastomers Co Ltd joint venture engaged in the elastomers production in South Korea and minor contribution to equity-accounted entities.assets. In 2016,2019, disposals amounted to €1,054€504 million and mainly related to: (i)to the divestment of the 12.503%a 20% interest in Saipem SpAthe Merakes discoveries to CDP Equity SpA in January 2016 (€463 million), an interest in Snam due to exerciseNeptune for €207 million, the sale of the conversion right by bondholderswholly-owned subsidiary Agip Oil Ecuador BV (€332189 million) as well as fuel distribution activities in Eastern Europe.and other minor non-strategic assets. In 2015, disposals amounted to €2,258 million and mainly related to: (i) the divestment of an available-for-sale interest in Snam due to exercise of the conversion right by bondholders (€911 million); (ii) an available-for-sale interest in Galp Energia (€658 million) in order to reimburse an out-of-the-money convertible bond which was due in 2015; and (iii) the divestment of non-strategic assets in the Exploration & Production and in the R&M businesses.
In 2016, other cash flow related to investing activities were positive for €465 million and included the reimbursement in-kind of a financing receivable owed by our equity-accounted entity Cardon IV for €300 million. Cardon IV reimbursed Eni with a trade receivable due by the Venezuelan State-owned oil company (PDVSA) on the supplies of gas volume produced at the Perla project. Furthermore, the production restart of the Kashagan field and the achievement of a production milestone in the fourth quarter of 2016 triggered the reimbursement of the first instalment of a receivable of the divestment of an interest of 1.71% of the project to the Kazakh national oil company occurred in 2008, with a cash-in of €152 million.
c)b) Dividends paid, share repurchases and changes in non-controlling interests and reserves
In 2016,2019, dividends paid and changes in non-controlling interests and reserves (€2,8853,424 million) related almost exclusively to cash dividendsdividend paid to Eni shareholders (€2,8813,018 million, of which €1,441€1,542 million relating to the 20162019 interim dividend and €1,440€1,476 million to the final dividend for fiscal year 2015. In 2015, dividends paid2018) and changes in non-controlling interests and reserves (€3,477 million) mainly related to: (i) cash dividends tothe execution of a repurchase program of the Eni shareholders (€3,457 million, of which €1,440 million relating to 2015 interim dividend and €2,017 million to the balance dividendshare for fiscal year 2014); and (ii) the distribution of dividends to non-controlling interests by other consolidated subsidiaries (€21 million).€400 million.
Financial condition Management assesses the Group’s capital structure and capital condition by tracking net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS less: cash, cash equivalents and certain highly liquid investments not related to operations including, among others, non-operating financing receivablesa liquidity reserve made of held-for-trading securities and securitiesfinally other liquid assets not related to operations.operations (financing receivables and securities). The Company is retaining a liquidity reserve, which comprises very liquid investments, mainly sovereign bonds and corporate securities which management has selected based on their creditworthiness. This cash reserve was established by investing part of the proceeds from the disposal plan carried out in the latest years. Those securities amounted to €6,404€6,760 million as of end
of 20162019 and were accounted as mark-to-market financial instruments. Of this amount, securities issued by industrial companies and financial institutions were €5.3 billion. For further information, see “Item 18 – note 9Note 6 – Financial assets held for trading – of the Notes on Consolidated Financial Statements”. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways in which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt and shareholders’ equity is well balanced compared to industry standards and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to other companies.
The tables below set forth the calculations of net borrowings and leverage for the periods indicated and their reconciliation to the most directly comparable GAAP measure. | | | As of December 31, | | | | | 2015 | | | 2016 | | | | | Short-term | | | Long-term | | | Total | | | Short-term | | | Long-term | | | Total | | | | | (€ million) | | Finance debt (short-term and long-term debt) | | | | | 8,396 | | | | | | 19,397 | | | | | | 27,793 | | | | | | 6,675 | | | | | | 20,564 | | | | | | 27,239 | | | Cash and cash equivalents | | | | | (5,209) | | | | | | | | | | | | (5,209) | | | | | | (5,674) | | | | | | | | | | | | (5,674) | | | Securities held for trading and other securities held for non operating purposes | | | | | (5,028) | | | | | | | | | | | | (5,028) | | | | | | (6,404) | | | | | | | | | | | | (6,404) | | | Non operating financing receivables | | | | | (685) | | | | | | | | | | | | (685) | | | | | | (385) | | | | | | | | | | | | (385) | | | Net borrowings | | | | | (2,526) | | | | | | 19,397 | | | | | | 16,871 | | | | | | (5,788) | | | | | | 20,564 | | | | | | 14,776 | | | |
| | | | | | As of December 31, | | | | | | | | 2015 | | | 2016 | | Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS | | | (€ million) | | | | | 57,409 | | | | | | 53,086 | | | Ratio of finance debt to total shareholders’ equity including non-controlling interest | | | | | 0.48 | | | | | | 0.51 | | | Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest | | | | | (0.19) | | | | | | (0.23) | | | Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage) | | | | | 0.29 | | | | | | 0.28 | | | |
| | | As of December 31, | | | | | 2019 | | | 2018 | | | | | Short-term | | | Long-term | | | Total | | | Short-term | | | Long-term | | | Total | | Finance debt (short-term and long-term debt) | | | | | 5,608 | | | | | | 18,910 | | | | | | 24,518 | | | | | | 5,783 | | | | | | 20,082 | | | | | | 25,865 | | | Lease liabilities | | | | | 889 | | | | | | 4,759 | | | | | | 5,648 | | | | | | | | | | | Cash and cash equivalents | | | | | (5,994) | | | | | | | | | | | | (5,994) | | | | | | (10,836) | | | | | | | | | | | | (10,836) | | | Securities held for trading | | | | | (6,760) | | | | | | | | | | | | (6,760) | | | | | | (6,552) | | | | | | | | | | | | (6,552) | | | Non operating financing receivables | | | | | (287) | | | | | | | | | | | | (287) | | | | | | (188) | | | | | | | | | | | | (188) | | | Net borrowings | | | | | (6,544) | | | | | | 23,669 | | | | | | 17,125 | | | | | | (11,793) | | | | | | 20,082 | | | | | | 8,289 | | | |
| | | | | | As of December 31, | | | | | | | | 2019 | | | 2018 | | Shareholders’ equity including non-controlling interest as per Eni’s Consolidated Financial Statements prepared in accordance with IFRS | | | (€ million) | | | | | 47,900 | | | | | | 51,073 | | | Ratio of finance debt including lease liabilities to total shareholders’ equity including non-controlling interest | | | | | 0.63 | | | | | | 0.51 | | | Less: ratio of cash, cash equivalents and certain liquid investments not related to operations to total shareholders’ equity including non-controlling interest | | | | | (0.27) | | | | | | (0.34) | | | Ratio of net borrowing to total shareholders’ equity including non-controlling interest (leverage) | | | | | 0.36 | | | | | | 0.16 | | |
In 2016, net borrowings amounted to €14,776 million, representing a €2,095 million decrease from 2015. This reduction was driven by repayment of debt due to the net cash flows provided by operating activities of continuing operations (€7,673 million) and the closing of the Saipem transaction, which entailed net proceeds of €5.2 billion. These latter comprised the reimbursement of financing receivables due to Eni by the former subsidiary (€5,818 million), the proceeds of the disposal of a 12.503% interest in the entity (€463 million), net of the cash-out to subscribe pro-quota Saipem’share capital increase (€1,069 million). Other divestment for the year amounted to €0.6 billion and mainly related to an interest in Snam due to exercise of the conversion right by bondholders (€332 million) as well as fuel distribution activities in Eastern Europe.
These inflows funded cash outflows relating to capital expenditures totaling €9,180 million and dividend payment to Eni shareholders amounting to €2,881 million, with the surplus used to pay down finance debt.
Furthermore, the change in the Group net borrowing y-o-y was influenced by the reclassification of financial assets held by the Group captive insurance company as non operating assets, which have been netted againstAt December 31, 2019, total finance debt in determining the Group net borrowings (with a positive effect of €0.6 billion). In previous reporting periods, those financial assets were committed to fund the loss provision and as such were part of capital employed. The change in classification reflects new regulatory requirements applicable to the exercise of the insurance activity from January 1, 2016, based on the provisions of EU Solvency II Directive (the so-called Minimum Capital Requirement – MCR – and Solvency Capital Requirement – SCR). The new rules require that insurance companies meet certain capital and solvency ratios as minimum requirements to continue performing the insurance activity. Therefore, it is no longer necessary to commit the financial assets of the insurance company to funding the loss provisions. Accordingly, those assets, which mainly comprise available-for-sale securities and bank deposits, have ceased to be classified as held for operating purposes.
The ratio of finance debt to total equity was 0.51 at 2016 year-end.
The Group Non-GAAP measure of its financial condition “Leverage” was 0.28 at December 31, 2016 reporting a decrease from 0.29 as of the end of 2015. This decline was driven by lower net borrowing, the effects of which were partly offset by a reduction in the Group total equity as explained below.
Total equity decreased by €4,323 million from December 31, 2015. This was due to the net loss (€1,457 million), the derecognition of Saipem non-controlling interest (€1,872 million), as well as dividend distribution of €2,885 million (including the 2015 balance and the 2016 interim dividends paid to Eni’s shareholders amounting to €2,881 million). These effects were partially offset by a positive change in the cash flow hedge reserve (€883 million) and positive foreign currency translation differences (€1,198 million) due to the 3.2% depreciation of the euro against the US dollar at year end (down by 3.2% due to the exchange rate recorded on December 31, 2016 at 1.054 euro, compared to 1 euro = 1.089 US$ at December 31, 2015).
Total debt of €27,239€24,518 million consisted of €6,675€5,608 million of short-term debt (including the portion of long-term debt due within twelve months equal to €3,279€3,156 million) and €20,564€18,910 million of long-term debt. At the same date, lease liabilities were €5,648 million (short-term portion €889 million).
Total finance debt included unsecured bonds for €19,003€18,779 million (including accrued interest and discount on issuance). Bonds maturing in the next 18 months amounted to €3,724€2,611 million (including accrued interest and discount). Bonds issued in 20162019 amounted to €2,984€1,635 million (including accrued interest and discount). Total debt was denominated in the following currencies: euro (90%(69%), U.S. dollar (7%), British pound (2%(30%) and 1% in other currencies. In 2019, net borrowings amounted to €17,125 million, representing a €8,836 million increase from 2018. This increase was driven by the initial recognition of the lease liabilities upon the adoption of IFRS16, which amounted to €5,759 million. The effect of the adoption of IFRS 16 on the Group net borrowings included €1,976 million of lease liabilities pertaining to joint operators in Eni-led upstream unincorporated joint ventures, which will be recovered through a partner-billing process. Excluding the overall impact of the adoption of IFRS 16, net borrowings would have been at €11,477 million, increasing
by €3,188 million compared to December 31, 2018. This increase was mainly driven by the acquisition of a 20% interest in ADNOC Refining for a cash consideration of €2.9 billion, as cash flow from operating activities of €12.39 billion was able to fund the capital expenditure incurred in connection with the program of exploring for and developing hydrocarbons reserves and other capital projects (€8.4 billion), as well as to fund a cash return to shareholders of €3.4 billion consisting of 3 billion of cash dividends and €0.4 billion of stock repurchases. The ratio of finance debt to total equity was 0.63 at 2019 year-end, including the impact of IFRS 16. Total equity decreased by €3,173 million from December 31, 2018. This was due to the profit for the year (€155 million) and positive foreign currency translation differences (€604 million; the exchange rate of the euro against the US dollar recorded on December 31, 2019 at 1.123, compared to 1 euro = 1.146 euro US$ at December 31, 2018) which added to net equity; while the remuneration of Eni’s shareholders (€3,018 million), a negative change in the fair value of the cash flow hedge reserve (-€679 million) as well as the impact of the share buyback (-€400 million) detracted from net equity. The Group Non-GAAP measure of its financial condition “Leverage” was 0.36 at December 31, 2019, due to increased net borrowings driven by the adoption of IFRS 16 and the acquisition of a 20% interest in ADNOC Refining. The impact of the lease liability pertaining to joint operators in Eni-led upstream unincorporated joint ventures weighted on leverage for approximately 4 basis points. Excluding the impact of IFRS 16 altogether, leverage would be 0.24. Capital expenditures by segment Exploration & ProductionProduction.. In 2016,2019, capital expenditures of the Exploration & Production segment amounted to €8,254€6,996 million, mainly related to the development of oil&gas reserves (€7,7705,931 million). Significant expenditures were directed mainly outside Italy, in particular in Egypt, Angola,Nigeria, Kazakhstan, Indonesia, Iraq, GhanaMexico, the United States and Norway. Development expenditures in Italy also comprised the upgrading of certain plants at the Viggiano oil center in Val d’Agri, which did not alter the plant set up. This upgrading addressed certain objections made by jurisdictional Authorities about the proper function of the plants and were duly authorized by the competent department of the Italian Ministry of Economic Development. Due to this upgrading, plant activities were regularly restarted following notification by the public prosecutor that it has definitively repealed the plant seizure. (see – Item 4 – Exploration & production segment – Italy) as well as sidetrack and workover activities in mature fields.Angola. Exploration expenditures (€417586 million) were directed in particular into Egypt, Indonesia, LibyaAngola, Mexico, the United Arab Emirates and Angola.Libya. In 2015, capital expenditures2019, a total amount of the Exploration & Production segment amounted to €9,980€400 million mainly related to the developmentpurchase of oil&gasproved and unproved reserves (€9,341 million). Significant expenditures were directed mainly outside Italy, in particular Angola, Norway, Egypt, Kazakhstan, Congo, IndonesiaAlaska and the United States. Development expenditures in Italy concerned the well drilling program and facility upgrading in Val d’Agri, as well as sidetrack and infilling activities in mature fields. Exploration expenditures amounting to €566 million were directed outside Italy, in particular in Egypt, Libya, Cyprus, Gabon, Congo, the United States, the United Kingdom and Indonesia.Algeria. Gas & PowerPower.. In 2016,2019, capital expenditures in the Gas & Power segment totaled €120€230 million and mainly related to gas marketing initiatives (€176 million) due to improve flexibilitythe capitalization of expenses for the combined-cycle power plants (€41 million)acquisition of retail customers, and to develop the gas marketing activitybusiness of power generation (€69 million). In 2015, capital expenditures in the Gas & Power segment totaled €154 million and mainly related to initiatives to improve flexibility of the combined-cycle power plants (€69 million) and to develop the gas marketing activity (€6942 million).
Refining & Marketing and Chemicals. In 2016,2019, capital expenditures in the Refining & Marketing and Chemicals segment amounted to €664€933 million and regarded mainly: (i) refining activitiesactivity in Italy and outside Italy (€298683 million) aiming fundamentallyfor the rebuilding of the EST conversion plant at plants improving,the Sannazzaro refinery, the upgrading of the Gela refinery into a biorefinery, increasing plants’ integrity, as well as initiatives in the field of health, securityto comply with stricter environmental and environment;safety standards; (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 (€123132 million); (iii) plant upgrading, efficiency and maintenance at petrochemical plantscompliance to stricter environmental and safety standards in the Chemical business (€20093 million). In 2015, capital expenditures in the Refining & Marketing and Chemicals segment amounted to €628 million and regarded mainly: (i) refining activities in Italy and outside Italy (€282 million) aiming fundamentally at plants improving, as well as initiatives in the field of health, security and environment; (ii) upgrading and rebranding of the refined product retail network in Italy (€75 million) and in the Rest of Europe (€51 million); (iii) upgrading and maintenance at petrochemical plants (€177 million).
Recent developments The table below sets forth certain indicators of the trading environment for the periods indicated: | | Three months ended December 31 | | Three months ended March 31, | | January 1 through March 17, | | | Three months ended March 31, | | Three months ended March 31, | | | | 2016 | | 2016 | | 2017 | | | 2019 | | 2020 | | Average price of Brent dated crude oil in U.S. dollars(1) | | | | 49.46 | | | | | 33.89 | | | | | 54.66 | | | | | | 63 | | | | | 51 | | | Average EUR/USD exchange rate(2) | | | | 1.078 | | | | | 1.102 | | | | | 1.063 | | | | | | 1.136 | | | | | 1.100 | | | Standard Eni Refining Margin (SERM)(3) | | | | 4.7 | | | | | 4.2 | | | | | 4.2 | | | | | | 3.4 | | | | | 3.3 | | | | | Gas at the PSV in $/mmBTU | | | | | 7.1 | | | | | 3.7 | | |
(1)
Price per barrel. Source: Platt’s Oilgram. (2)
Source: ECB. (3)
In $/BBL, FOB Mediterranean Brent dated crude oil. Source: Eni calculations. Approximates the margin of Eni’s refining system in consideration of material balances and refineries’ product yields.
In the period January 1 – March 17, 201731, 2020 the Brent crude oil price was 54.66$/approximately 51 $/BBL on average, 61% higherapproximately 20% lower than in the first quarter of 2016 and 10% higher than in the fourth quarter 2016.2019. This trend will positivelynegatively affect reported revenues, profitability and cash flow of our Exploration & Production segment.segment in 2020. See “management expectations of operations” below. Significant transactions On March 9, 2017, Eni and ExxonMobil signed sale and purchase agreement whereby ExxonMobil is going to acquire a 25% indirect interestThe significant transactions that occurred post-closing are described in the Area 4 block, offshore Mozambique. Eni currently holds a 50% indirect interest in the block through a 71.4% stake in Eni East Africa, which is operator of the Area 4 concession with a 70% interest. 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 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.
The Company’s Annual General Shareholders Meeting scheduled on April 13, 2017, has been convened to approve the full year dividend proposal of €0.80 per share of which 0.4 paid as interim dividend in September 2016. Eni expects to pay the balance of the dividend for fiscal year 2016 amounting to €0.40 per share in April 2017. The total cash out is estimated at approximately €1.4 billion.item 4.
Management’s expectations of operations THE COVID-19 IMPACT and CURRENT TRENDS IN THE OIL MARKET The outbreak of a contagious disease known as COVID-19 which has spread rapidly to many countries in the world at the beginning of 2020 and is currently ongoing has triggered a sharp sell-off in energy commodities markets due to a sudden drop in worldwide consumption of oil, gas and other energy products as a result of measures taken worldwide to contain the spread of the disease. In early March 2020, members of the OPEC+ failed to reach an agreement for additional oil production cuts proposed by some participants to counteract the COVID-19 effects. These developments together triggered a collapse in crude oil prices. As of the end of March 2020, the price of the Brent crude benchmark has fallen by more than 50% from the value recorded before the onset of the disease at more than 65 $/bbl in early January 2020; the average Brent price for the first quarter 2020 of approximately 51 $/bbl has fallen by a considerably lower amount over the corresponding period a year ago (down by approximately 20%). Also, the price of natural gas at the Italian spot market “PSV”, which is the main benchmark for sales volumes of equity gas production has fallen in this period, with the average price for the first quarter 2020 at approximately 3.7 $/mmBTU, down by approximately 50% over the year-ago quarter. Should these developments prolong beyond the short term, they could represent a material risk to the outlook of oil&gas companies considering the already weak fundamentals of the sector due to continued oversupply and changing consumers’ attitudes toward hydrocarbons due to rising climate – related issues. Management has estimated the Company’s operating cash flows to vary by approximately €150 million for each one-dollar change in the price of the Brent crude oil benchmark with respect to the price case assumed in Eni’s financial projections for 2020; regarding the price of natural gas at the PSV, it has been estimated a variation of +/-€235 million in the operating cash flow for a +/-1 $/mmBTU change in the price of the PSV compared to our financial assumptions. Future trends in crude oil and natural gas prices will greatly depend on how the current COVID-19 crisis unfolds and on how long it lasts. Under the worst of the assumptions, the spread of the disease could trigger a global recession which could materially hit demand for energy products and prices of energy commodities. This scenario could be further complicated in case the OPEC+ agreement effectively ceases supporting crude oil prices. These trends could have a material and adverse effect on our results of operations, cash flow, liquidity and business prospects, including trends in Eni shares and shareholders’ returns. However, in recent years the Company has taken several steps to improve its balance sheet and the resilience of the business to the volatility of hydrocarbons prices. Due to continued exploration success at competitive discovery costs, the deployment of an efficient model to develop hydrocarbons reserves based on a phased approach, reduction of time-to-market and design-to-cost, as well as continued control of operating expenses, we believe that our portfolio of oil&gas projects can withstand a significant oil price downturn, leveraging on low break-even prices. We retains some levers of financial flexibility in case of a significant contraction in cash flow from operations. The Group has established a liquidity reserve consisting of very liquid sovereign bonds and corporate securities which amounted to €6.8 billion at the balance sheet date and are marked to market, which together with cash on hands of approximately €6 billion will cushion the impact of a price downturn, also of severe proportions. Furthermore, we have as of December 31, 2019, undrawn uncommitted borrowing facilities amounting to €13,299 million and undrawn long-term committed borrowing facilities of €4,667 million. Those facilities bore interest rates reflecting prevailing conditions on the marketplace. The main financial commitment of 2020 include long-term debt maturities of approximately €3.2 billion, short-term debt of €2.45 billion, while our take-or-pay obligations under long-term gas contracts and other similar obligations amount to an estimated €8 billion at our budget scenario. We are continuing to evaluate the effects of the recent trends in the oil market. This assessment includes an update to the oil price scenario and management actions to counteract the changed environment, the effects of which are currently not yet determinable and will be accounted for in future
reporting periods. To date, in response to the sharp decrease in commodities prices and the foreseeable constraints arising from the COVID-19 pandemic, management has revised its capital plans and updated the commodities scenario for the years 2020 and 2021. Management is now assuming for planning purposes a Brent price of 40-45 $/bbl in 2020 and of 50-55 $/bbl for 2021. In 2020, management is planning to reduce capital expenditures by around €2 billion, equal to 25% of the amount originally planned, and opex by around €400 million. In 2021, Eni expects a capital expenditures reduction of around €2.5-3 billion, equal to 30-35% of the capex scheduled for the same year in the business Plan. The projects involved in this capex reduction are related mainly to Upstream activities, particularly production optimization and new projects developments scheduled to start in the short term. In both cases, activities will be restarted as soon as appropriate market conditions return, and related production will be recovered accordingly. As a result of these measures and the current depressed scenario, production in 2020 is expected to be between 1.8 and 1.84 million barrels of oil equivalent per day, which would remain unchanged in the following year. Finally, management has resolved to suspend the share repurchase program. The program will be reconsidered when the Brent price for the referenced year, which is the benchmark for decisions relating to the buyback plan activation, is at least equal to 60$/barrel. Exploration & Production Management intendsIn the next four-year action plan 2020-2023, management will seek to boost the cash generation in the E&P segment leveraging on profitable production, growth, capital discipline, effective project execution and strict control of operating expenses and project execution. working capital.
Exploration activities will continue to be key todriving the Company’s growth prospects in the short and long-term. The Company is leveragingOur strategic guidelines for exploration in the next four years are to retain capital discipline by investing up to a maximum of 1 billion USD per year, to ensure cost-effective replacement of produced reserves and to support cash generation. Our exploration initiatives will be balanced between the following two clusters: •
Exploration projects in proven/mature areas and near-field i.e. in prospects close to producing fields, where we can leverage existing infrastructures to readily develop the discovered resources, attaining fast contribution to cash flows and production levels. This approach has paid off in recent years; for example in 2019 we made three near-field discoveries in Egypt and one in Nigeria which have been already put into production due to proximity to infrastructures. Furthermore, based on itsthis approach, we have resumed exploration in our operated Block 15/06 off Angola, aiming at extending the life-cycle of our existing units of floating production (FPSO) in the area. We discovered several new fields in the area and one of these discoveries, Agogo, has been linked to our FPSO vessels as of lately; •
Selected initiatives in high-risk/high-rewards plays, where we retain a high working interest and the operatorship which will enable us to apply our dual exploration model which envisages bothin case of material discoveries. Our dual exploration model contemplates the rapid developmentacquisition of high interests in exploration leases and, in case of exploration success, the partial divestiture of the discovered resources and the divestmentwith a view of stakes of our exploration discoveries in order to accelerateaccelerating the conversion of our resources into cash. The effectivenesscash or of accomplishing asset swaps. We are targeting a 3.5% average growth rate in hydrocarbons production up to a plateau of approximately 2.2 million boe/d in the 2020-2023 plan period. In 2020, we anticipate our dual exploration model has been provenproduction to be negatively affected by the divestmentexpected triggering of a 40% interestcontractual revisions at our production sharing agreements in Libya. Growth in the 2020-2023 period is expected to be fueled organically by new fields start-ups and the achievement of full-field production at our main producing fields, including the Zohr gas discoveryfield in Egypt, Block 15/06 in Angola and the Area 1 fields off Egypt, with a value to Eni of approximately €2 billion including the reimbursement of the capital expenditure incurred in 2016 to develop the prospect,Mexico, as well as continuing production optimization to counteract fields natural decline. The main start-ups expected in the plan period include the projects that were sanctioned in 2019 or that are planned to be sanctioned shortly, mainly the cluster of oil discoveries in Area 1 offshore Mexico which was started in early production in 2019, the development of the new discoveries in Block 15/06 offshore Angola with the first one, Agogo, already started at the beginning of 2020, a number of projects operated by our JV Vår Energi in Norway (including Balder X and Johan Castberg) the preliminary agreement signed forMerakes gas field in Indonesia, phase two of the divestmentNenè Marine field in Congo, the gas discovery of a 25% interestCoral in Area 4 offshore Mozambique, with an expected cash considerationthe Dalma gas fields offshore the UAE and other developments. We estimate that new field start-ups, production ramp-ups and expansion projects of approximately $2.8 billion.
We expect to increase our hydrocarbons production at an average rate of 3% across the 2017-2020 plan period. This growth target factors in the effects associated with our planned disposals. For 2017, we expect a production growth of approximately 5%. This grow will be fuelled organically by newexisting fields start-ups, full production at the Goliat and Kashagan projects and the ramp-up of the other fields started in 2016, the recovery of the full plateau at the Val d’Agri profit center and continuing production optimization to fight fields natural decline. The main start-ups of 2017 include the Zohr gas field off Egypt expected at year-end, the oil&gas project of Offshore Cape Three Points in Ghana, the East Hub of Block 15/06 off Angola and the Jangkrik gas project in Indonesia. The East Hub project has already achieved first oil in February 2017. In subsequent years, we are planning new project start-ups in Egypt, Angola, Algeria and Norway. New field start-ups, production ramp-ups and continuing production optimization will add approximately 850800 KBOE/d in 2020.of new production by 2023. We believe thathave good visibility as to the ability to achieve those production targets have good visibility because they relatedrelate to already-sanctioned projects, mostly of which are operated.operated, and to incremental development phases at our existing profit centers.
Our production plans includesinclude assumptions relating to production levels in Libya and Nigeria, whichcertain countries that are particularly exposed to risks of disruptions and political instability. In 2016, Libya represented approximately 20% of the Group total hydrocarbons productions for the year and going forward the contribution of Libya to our future production levels albeit slowing down will remain significant. To factor in possible risks of unfavorable geopolitical developments mainly in Libya but also elsewhere in otherthose countries, of Eni presence, which may lead to temporary production losses and disruptions in our operations in connection with, among others, acts of war, sabotage, social unrest, clashes and other form of civil disorder, we have applied a haircut to our future production levels based on management’s appreciation of those risks, past experience and other considerations. We note that production at one of our field in Libya is currently shut down due to the situation of socio-political instability underway in the country. However, thisthe above-mentioned contingency factor does not cover worst-case developments and extreme events, which could determine prolonged production shutdowns. Furthermore, in recent years we have pursued a strategy intended to diversify the geographic reach of our operations aiming at reducing the geopolitical risk in our portfolio. Based on this, we forecast to lessen going forward our dependence on less politically stable areas such as Libya, where we expect to reduce the weight of this country production relative to our portfolio, by increasing the size of more stable areas like UAE, Mexico, Norway and Mozambique. Our production plans and financial projects are incorporating our Brent price scenario of 55 $/BBL in 2017 andbased on a gradual recovery in the subsequent yearsBrent prices post 2020 up to our long-term case of 70 $/BBL in 20202022 and going forwards (on constant monetary term compared to 2020,2022, i.e. from 20202023 onwards crude oil prices will grow in line with a projected inflationary rate). See “Item 4 – Exploration & Production”. Our recoverypricing assumptions are based on forecast of a recovery in oil demand growth in the progressive rebalancingmedium term, against the backdrop of a moderate pace of expansion in the global oil markets, which will be supported by the OPEC agreement reached in November 2016 to cut the cartel output joinedeconomy. We also by non-Opec members and the effects of the curtailment in expenditures made byexpect that international oil companies duringwill retain a disciplined approach to capital spending going forward, while US independent producers have shown recently the downturn. However, thereintention of shifting their focus from growth to shareholders’ returns. There are some risks to this outlook, including effective complianceuncertainties over the strength of OPEC member countriesthe global economy, which will be significantly and negatively affected in the short-term by the spread of a pandemic disease known as COVID-19, the ability of OPEC+ to control global prices in light of the recent failed attempts in early March to implement additional production cuts seemingly triggering a discontinuation of a policy supportive of prices, as well as the role of geopolitical factors and any possible developments in the USA-China trade war and in Brexit. In the first months of 2020, after a good start to the year, crude oil prices have reversed sharply lower with the planned production quotasBrent crude benchmark losing more than 50% from the highs recorded early in January at 65 $/barrel, down to current values below 30 $/barrel. This sudden movement was driven by a fall in global demand for oil and rising risks of oversupplies due to spread of a pandemic disease and to the pace at which unconventional oil producersrecent developments within the OPEC+, as discussed in the US will be able to bring production back to markets, leveraging the short-cycle nature of this business and rising productivity. Oil price assumptions are particularly significant when it comes to assessing the Company’s future production performance considering the entitlement mechanism under Eni’s PSAs and similar contractual schemes. In 2016, the Company estimated that production entitlements in its portfolio of PSAs increased by approximately 20 KBOE/d, or 1,900 BBL/d for each $1 change in oil prices compared to 2015.previous paragraph. We note that in case oil prices differ significantly from our own forecasts, the result of the above mentioned sensitivity of production to oil price changes may be significantly different.expect a weak trading environment throughout 2020.
Due to those risks and uncertainties, management intends to retain a strong focus on capital discipline, project execution and cost control.discipline and on reducing the time-to-market of our reserves as levers to maintain our development projects profitable in a low price scenario. First, our capital budget inprojects will be carefully selected against our pricing assumptions and minimum requirements of internal rates of return. We intend to reduce financial exposure and the E&P segment for the four-year plan 2017-2020 is estimated 13% lower than the previous capital plan 2016-2019 (in each cases net of the capex associated with planned disposals). In spite of an expected reduction in capital spending, our growth targets in 2017-2020 are above our previous planning assumptions relating the period 2016-2019 due to ourexecution risk leveraging on a phased approach in developing our production projects. This approach will enable the Company to reduce financial exposure and to accelerate production start-ups. Secondly, we intended to be more selective on investment options. Thirdly, we plan to seek opportunities for further reductions indeliver our development and operating costs by renegotiating contracts for the supply of upstream plants, equipment and other infrastructures as well as the supply of oilfield services and drilling rates considering the uncertainties surrounding a recovery in expenditures by oil companies. Finally, management will focus on delivering the planned projects on time and on budget. SomeSeveral of our projects are complex due to scale and reach of operations, environmentally-sensitive locations, external conditions, including offshore operations, industry limits and other considerations including the risk factors described in Item 3. These constraints and factors might cause delays and cost overruns. Furthermore, in the past we experienced delays and cost overruns at certain projects, which were caused by
poor execution by our EPC contractors. We plan to mitigate those risks in the future by continuing deployment of our capabilitiesskills and by means of:our model of project execution driven by: (i) the execution in parallel of the main project activities, including discovery appraisal and pre-fid activities; (ii) the in-sourcing of critical engineering and project management activities; (ii) increasing directphases, for example we are exercising strict control and governance onover construction, activities; (iii) deploying our employees and competences to manage hook-up and commissioning; and (iv) entering into framework agreements with major suppliers, using standardized specifications to speed up pre-award process for critical equipment and plants and increasing focus on supply chain programming to optimize order flows. Effective project execution(iii) the design-to-cost method whereby the Company has been boosted in recent years by our changed approach inredirected its exploration activities, which have been redirectedefforts towards mature and low-complexity areas where we can achieve fast time-to-market and cost synergies. Furthermore, phasedsynergies; (iv) continuing progress in our technologies designed to improve drilling performance and the recovery factor; (v) the promotion of the digital transformation of the business to further improve workplace safety and asset integrity.
Phased project development and strict integration between exploration and development have improved the overall project execution and cost efficiency. Finally, all of our projects undergo a thorough HSE assessment leading to the definition of an integrated plan to reduce blow-out and other well and operational risks and costs. Due to those drivers and our estimation that in recent years our discovery costs have been efficient, we believe that the price breakeven of our ongoing projects has decreased over the latest years.years, thus reducing the risk of a volatile scenario.
Finally, we plan to increaseseek opportunities for further reductions in our development and operating costs, for example by reducing the share of operated production in the Company’s portfolio. We expect to operate more than 74% of the plan period production. Project operatorship enables the Company to better scheduledowntime at our facilities and control project execution, expenditures and timely achievement of project milestones and to mitigate the operational risk associated with drilling activities at high pressure-high temperature wells and at deep waters well by deploying our technologies and competences. Eni estimates that these wells will represent approximately 13.5% of the planned wells to be drilled in 2017. In the next four years, our exploration activities will focus on supporting the replacement of produced reserves and on contributing to cash generation. Our exploration investment will be mainly directed to:
i)
Appraisal of the recent discoveries and near-field plays, where in case of success we can leverage on existing infrastructures in order to readily put into production the discovered resources;
ii)
Initiatives in new areas in proximity to end markets, targeting conventional prospects with high interests in order to implement our dual exploration model in case of material discoveries.
other measures.
Gas & Power We expectanticipate a weak outlook in the Gas & Power segment due to structural headwinds in the industry as weindustry. Gas markets across the world are currently affected by oversupplies due to an ongoing reduction in global demand for energy and rising gas supplies driven by increasing volumes of LNG from upstream projects and associated gas in the US. Furthermore, our expectations point to additional volumes of LNG coming on stream in the medium-term based on the final investment decisions of LNG projects made in 2019 for approximately 60 MTPA. Other LNG projects are expected to be sanctioned in 2020. We forecast sluggisha weak demand growth, oversupplies and strong competition across all ofenvironment in our main reference markets, primarily in Europe, including Italy. We project a flat trend in gas demand in EuropeItaly and in Italy overother European countries, due to an ongoing economic downturn also driven by the next four-year plan. Demand growth will be dampened by sluggish economic growth, risingimpact of the COVID-19 and strong competition from renewables and trends for increasing energy efficiency. On the supply side, the growing importance of liquid hubs and large availability of LNG will drive continuing competition and pricing pressure. Going forwardRising LNG supplies will be fueled by the coming on stream of several export terminals in the United States which will monetize the country’s large reserves of shalehave also increased markets liquidity and interconnections, reducing arbitrage opportunities. In our wholesale gas and the start-up of important LNG projects in the Pacific area. Thesebusiness, these trends are expected to be exacerbated by the constraints of the long-term supply contracts with take-or-pay clauses, whereby wholesale operators are forced to compete aggressively on pricing in order to limit the financial exposure dictated by the contracts in case of volumes off-taken below the minimum take. We also expect continuing volatility in the spreads between gas spot prices at hubs in the northern Europe, which are the main indexation parameter of our supply contracts, and prices at the spot market in Italy which is the main market to sell our procured gas. In the LNG business, we expect a muted margin environment. In the retail business of gas and power we forecast a strong competitive environment due to lack of entry barriers and a proliferation of operators able to resell gas and power commodities to retail customers and to compete on pricing.
Against this scenario, the Company priority in its Gas & Power business is to achieve structuralgain stable profitability and retain positive cash generation. Our strategy in the Gas & Power sector will leveragegeneration based on the renegotiations offollowing drivers: (i)
To continuously renegotiate our long-term gas supply contracts in order to align pricing and volume terms to current market conditions and dynamics optimizationas they evolve and to obtain operational flexibilities (volumes, points of logistic costs, the development ofdelivery, etc) (ii)
To effectively manage our portfolio of highly profitable businessesassets (supply and cost efficienciessales contracts, their flexibilities and operational streamlining.optionality and logistics availability) in order to extract value from market volatility; Our take-or-pay, long-term supply contracts include revisions clauses whereby each counterpart has right to renegotiate
(iii)
To grow the economic terms and other conditions periodically, in relation to ongoing changes in the gas scenario. Leveraging on recent renegotiations, 90% of our portfolio of supply contracts is currently indexed to HUB prices and will benefit the 2017 performance. Looking forward, we expect to fully align our supply portfolio to market conditions and dynamics in terms of both pricing and volumes. Our renegotiation efforts will seek to obtain cost indexation that will track our pricing formulas, to align our procurement costs to prices prevailing in the wholesale market, which includes sales to large industrial and
power companies and resellers, and to match our minimum contractual take with the dimension of our addressable market. The renegotiation strategy is subject to the constraints dictated by availability of the contractual windows. Management believes that the outcome of those renegotiations is uncertain in respect of both the amount of the economic benefits that will ultimately be achieved and the timing of recognition in profit. In case Eni and the gas suppliers fail to agree on revised contractual terms, an arbitration procedure could be commenced to solve the commercial dispute. Furthermore, Eni’s suppliers may file a counterclaim to dismiss Eni’s request for a price review or renewed contractual terms. These possible developments increase the risks and uncertainties relating the outcome of those renegotiations. Therefore, future results of the gasLNG marketing activities are subject to increasing volatility and unpredictability. The expected termination of certain long-term gas supply contracts with take-or-pay clause will reduce Eni’s contractual minimum take and will add flexibility to Eni’s portfolio and renegotiation strategy. Furthermore, we plan to almost complete the recovery of our pre-paid gas volumes due to the triggering of the take-or-pay clause in past reporting periods. This asset amounted to €0.3 billion at 2016 year-end. We expect to improve profitability in gas marketing through initiatives intended to reduce logistic costs by reselling unutilized transport capacity to other operators and by possibly benefitting from expected liberalization measures in the European gas system designated to increase the liquidity of spot markets.
The Company intends to grow its presence in market segments where margins can be sustained in the long-term. As part of this plan, we intend to strengthen our role as a global player in LNG trading where we plan to achieve steady profitability, also leveraging on integration with our upstream operations by marketing equity gas. We will seek to preserve margins on sales to large accounts bybusiness leveraging on the Company’s multiple presence across various marketsintegration with the E&P segment with the aim of maximizing the profitability along the entire gas value-chain and expertiseof supporting the achievement of the final investment decisions at large gas upstream projects (for example in delivering innovative and tailor-made offering structuresMozambique). Based on this approach in 2019 we made the final investment decision for the upgrading of the Bonny LNG project in Nigeria. We plan to best suit customers’ needs by providing complex pricing formulas, hedging againstaccelerate the commodity risk and flexibility in volumes collection. In the retail segment,growth of our priority iscontracted supplies of LNG to maximize profitability and cash generation through more effective and efficient operations. We will closely monitor the levelachieve a robust portfolio of working capitalreselling opportunities, and we will be more selective in new customer additions in order to reduceare targeting 16 million tons of contracted volumes of LNG by 2025, of which 70% deriving from our equity production;
(iv)
To boost the portfolio risk and counterparty losses. We intend to increaseprofitability of the weight in our portfoliogas&power retail business, by enhancing the value of customers who are willing to sign supply contracts in the open market rather than opting to use the regulated tariffs established by Italian gas authorities. The Company’s marketing effort will address retail customers in Italy and in the main European markets in order to valorize the existing customer base against the backdrop of escalating competitive pressures. This will be achieved by selectively growing our customer base, by expanding the offer of new products and services brand identity,other than the administrative advantagescommodity and by continuing innovation in marketing processes including the deployment of digitalization in the dual offeracquisition of gas and electricity,new customers, a competitivereduction in the cost to serve and continuing innovation in processes, promotion and customer care and post-sale assistance. We believe that offering a wide rangeeffective management of valuable services withworking capital. Our plans targets the selling of the commodity will underpin the profitabilityexpansion of our retail operations considering that the regulatory modificationscustomer base to the indexation11 million of the raw material cost have substantially flatten the margin on the commodity. Management will also seek to improve profitabilitypoints of delivery by means2023. We make use of cost efficiencies particularly by streamlining business support activities and reducing general and administrative costs. Finally, the Company intends to capture margins improvements by means of trading activities by entering into derivative contracts both in the commodity and the financial trading venues in orderderivatives to capture possible favorable trends in market prices, within the limits set by internal policies and guidelines that define the maximum tolerable level of market risk. As part of this strategy, the Company intends to improve results of operations by effectively managing the flexibilities associated with the Company’s assets (gas supply contracts, transportation rights, storage capacities, unutilized power capacity). This can be achieved through strategies of asset-backed trading by entering into derivative contracts to leverage on commodity price volatility,hedge us against the risks of which might be absorbeddifferent indexation formulas in partour gas procurement costs vs. selling prices in relation to contracted sales or entirelyhighly-probable sales. A number of these derivatives are not accounted as hedges in accordance to IFRS and consequently there recorded through profit and loss and may add a component of volatility to our results of operations. Furthermore, we make use of derivatives to improve margins by leveraging on market volatility and availability of assets to capture arbitrage opportunities (for example the natural hedge grantedwinter vs summer spread, the Italian spot market vs the continental spot markets spread, the spot vs. the Brent indexation spread). Those derivatives are of speculative nature with gains and losses recognized through profit. Our 2019 results were helped by this asset-backed trading leveraging the asset availability. Asset-backed activities may leadhigh market volatility recorded in the year; however it is difficult to gains, as well as losses the amount of which could be significant. For further information on the market risk and how the Company manages it see “Item 11 – Quantitative and Qualitative Disclosuresmake accurate forecast about Market Risk”.future trends in this activity.
Based on the above outlined trends and industrial actions, management expects that we will retain profitable, cash-positive operationsseek to enhance profitability in the Company’s gas marketing business over the plan period. Our profitability outlook factors in the expected benefitsoutcome of ongoing and planned renegotiations of the Company long-term supply
contracts which the Company is seeking to finalize during the plan period, as well as other circumstances subject to risks and uncertainties described in Item 3. These projections could be subject particularly to the risks of further contraction in demand or the total addressable market and the risks related to the outcome of contract renegotiations. For more information see the specific risk paragraph in “Item 3 – Risk factors”.
Refining & Marketing The outlook of the European refining sector is unfavorablechallenging due to structural headwinds in the industry pressured by overcapacity, stagnanthigh global gasoline stocks, impact of energy efficiency on fuel demand, energy efficiencyconsumptions and rising competition from cheaper products streams from the Middle East and other areas.areas, where large expansion projects in new refineries or in the upgrading of existing plants are anticipated. Furthermore, fuel demand in Europe is projected to fall due to an ongoing economic slowdown now exacerbated by spread of the pandemic disease COVID-19. Management expects refining margins in 2017 and going forward to remain around the weak levels registered in 2016 at about 4$ per barrel, where the Company’s refining business is at breakeven. At the end of the plan period it is projected an improvement in refining margins due to the enactment ofon a new regulation regarding the quality of fuel useddowntrend in the bunker segment.next four years and beyond, reflecting progressive reduction in the oil products crack spread. Furthermore, our refineries are exposed to price differentials shrinking between sour crudes vs. the Brent benchmark, which negatively affects the profitability of our complex refineries eroding cost advantage in processing sour crudes, which generally trade at a discount vs the Brent crude quality. Against this backdrop, the Company priority is to retain profitable and cash-positive operations even in a depressed downstream oil environment, by further reducingenvironment. Our priority is to reduce the breakeven margin of Eni refineries. Therefineries in Europe, leveraging the full operability of our refining business has undergone a restructuring process resulting in a reductionsystem, particularly with the restart of the installed capacity by more than 30% versusEST high-conversion unit at the 2012 baseline. This process has comprisedSannazzaro refinery and the conversionrecovery of the Venice refinery into a green refinery for the production of bio-fuels based on a proprietary technology, the shutdown of Gela refinery, which is undergoing a transformation into a green refinery like the Venice site, asset disposals, the shutdown of unprofitable lines and other efficiency initiatives. We believe that additional optimization is needed considering the structural headwinds and volatility of the refining scenario. Our goal is to lower the breakeven margin to 3$ per barrel by 2018. The planned initiativesBayernoil plant. Other measures include the completion of the Gela project and the second phase of Venice upgrading, optimization of plant setuprun also in view of maximizing yields of valuable fuels and continuedimproved efficiency in energy consumption and operating costs. We intend to maximize the returns at our investment in ADNOC Refining, where we acquired a 20%-stake in 2019. We are planning to deploy our technological lead and plant expertise with the object of improving the refinery efficiency and profitability. We are sponsoring a number of capital projects designated to upgrade the refinery capacity to process crudes with high sulfur content, to increase plant efficiency and to valorize refinery by-products. These projects will be funded by the refinery cash flows. Those action are expected to significantly reduce the break-even margin of ADNOC Refining. Also a trading joint venture will start operations to capture a larger share of the value associated with the refinery products. In recent years we have implemented a plan to reduce the share of traditional, cost-dis-advantaged refineries in our portfolio by upgrading the Venice and Gela plants to bio-refineries based on proprietary technologies. The Gela plant was started in the second half of 2019, bringing installed capacity at our bio-refineries to 1 million tons per year, with profitable crack spreads between the cost of the bio feedstock and the bio-productions. We are planning to progressively phase out palm oil as a feedstock and replace it with more environmentally-sustainable feedstock; this process of substitution is expected to be completed by 2023. Finally, we plan to pursue efficiency gains in logistics, to achieve energy managementsavings and capital discipline. to improve plant reliability with the support of the deployment of a digital shift in our operations. In Marketing activities, where we expect a very competitive pressure to continueenvironment due to weak demand trends,lack of entry barrier and of product differentiation, we are planning to achieve a gradual improvement in results of operationsretain steady and robust profitability mainly by focusing on innovation of products and services anticipating customer needs, strengthening our line of premium products, as well as efficiency in the marketing and distribution activities. Retail operations abroad Further value will be focused onextracted by the core markets of Germany, Austria, Switzerland and France, where we intend to exploit synergies with Italian operations, brand awareness, a fair market share and development of non-oil activities to retain steadily profitable operations. We have completed the refocusing program of our portfolio of activities exiting Eastern Europe.
Overall, we expect that under constant 2017 scenario assumptions,initiatives in the next four-year plansegment of sustainable mobility and new fuels (for example the business will generate enough cash to fund its capital expenditure plansrecharging for electric vehicles, hydrogen and to generate a surplus.compressed natural gas) and selling non-fuel products and services.
Chemical The outlook in the chemical business is unfavorablechallenging due to structural headwindsdeclining consumption of commodity plastics driven by an ongoing economic slowdown in Europe, lower growth in China and in other emerging economies and a downturn in the industry pressuredautomotive sector which is one of the main end-markets of the chemicals business. The situation has been made worse by overcapacity, weak macroeconomic growththe spread of the COVID-19 and the related global slowdown. Furthermore, growing public sensitivity towards the preservation of the environment and stricter regulation have negatively affected the consumption of single-use plastics and we believe that this trend will strengthen in the future. As the market contracts, the profitability of our chemicals business is expected to be negatively affected by rising competitioncompetitive pressures from cheaper products streamsstream in the main commoditized segments, like polyethylene, from theproducers in Middle East Far East and in the US.US which can leverage on larger plant scale and lower feedstock costs (as in the case of ethane-feed crackers). In addition,
our petrochemical commodities are exposed to the volatility of the crude oil-based feedstock costs. Like the R&M business, our chemical activity has undergone a deep restructuring process. Over the last few years, we have lowered the cost base and exposure to commodity riskrestructured our business by reducing capacity, divesting or exiting unprofitable lines, plant optimization and other efficiency measures as well as a shift in our product portfolio towards specialties, green chemicals and products with high technology content, which are less exposed to the scenario volatility. Looking forward we believe that further steps are needed to preserve profitable and cash-positive operations, including self-financing the business capital requirements.operations. The industrial plan contemplatesidentified the completionfollowing lines of action intended to improve resiliency to the restructuring process at unprofitable sites, increasedmarket volatility: (i) strengthening the productive footprint by means of improved plant flexibilityintegration and optimization, development of new products and specialtiesreliability as well as by rightsizing our captive ethylene capacity vs internal needs for the start-upproduction of polyethylene; (ii) improving feedstock costs at our steam crackers by introducing a certain joint ventures in East Asiadegree of flexibility towards ethane; (iii) upgrading the product mix by developing differentiated products, leveraging on new applications through internal R&D; (iv) developing the international presence of our chemical business leveraging on proprietary technologies targeting markets with local partnersgrowth opportunities and access to producecompetitive feedstock and market elastomers.outlets; and (v) developing our portfolio of green products and products from recycled plastics and renewable feedstock. Overall, we expect that even under our conservative scenario assumptions the business will generate enough cash to cover its capital expenditures requirements along the plan period. Liquidity and leverage
Capital expenditure plans
Over the next four years, the Company plans to invest €31.6 billion, excluding capex associated with the disposal plan, to support continued organic growth in oil&gas production; approximately 86% of planned capital expenditures is expected to be directed to the Exploration & Production segment. Eni’s capital expenditure program is reflective of a lower oil price environment and of uncertainties aboutConsidering uncertain future trends in the oil markets. Our capital expenditure plan will be more selective thanmarkets and in the pastglobal economy, the risks of a macroeconomic downturn, oversupplies and will focus onprice volatility, which have been exacerbated by the more profitable projectssteep sell-off in portfolio and on project re-phasing and modularization. These optimizations and curtailments, as well as wider portfolio effects are expected to drive an 8% reduction in capital expenditure compared to the previous plan at constant exchange rates and net of capital expenditures associated with our disposal activity, without sacrificing our production growth targets. E&P capital expenditure for the four-year plan is expected to decrease by 13% compared to the previous plan. In 2017 we expect overall capexcommodity prices in the rangeinitial months of €7.6 billion, down by 18% vs 2016 at a constant exchange rates and post portfolio transactions.
Development of oil&gas reserves will attract some €25 billion. Project start-ups and plateau enhancement at existing fields will be geographically diversified and executed mainly in Egypt, with the development of the very important Zohr gas discovery, Mozambique, Italy, Iraq, Kazakhstan, Nigeria, Norway, Libya, Angola and Ghana. Egypt will attract approximately 20% of the Group capital expenditure over the plan period.
Exploration capex will amount to €2.1 billion. Our projects will include appraisal of recent discoveries and near-field activities designed to provide fast production support and contribution to the cash flow, as well as new initiatives targeting conventional prospects with high working interest in order to support Eni’s dual exploration model in case of material discoveries.
We are planning to invest approximately €2.2 billion in R&M which will mainly be directed to the completion of the Gela reconfiguration project, the repair of the EST unit at the Sannazzaro site and various initiatives of plant upgrading, as well as network upgrading. The Chemical business will attract approximately €1 billion for plant upgrading and selected growth initiatives. In G&P we intend to spend approximately €0.5 billion. Finally, we will invest approximately €0.5 billion to develop photovoltaic and other renewable-related power plants in our industrial properties in Italy or in countries where we are conducting E&P operations.
Management expects to pursue strict capital discipline when assessing individual capital projects. Management is assuming a long-term oil price of 70 $/BBL for the Brent benchmark, which is adjusted to take account of expected inflation rates from 2021 onwards. The internal rate of return of each project is compared to the relevant hurdle rate, differentiated by business segment and country of operation. These hurdle rates are calculated taking into account: (i) the weighted average cost of capital (“WACC”) to the Group. In 2016, management assessed that the cost of capital to the Group was marginally lower than in 2015 mainly2020 due to a reduced premium for the sovereign risk incorporated into the yieldsglobal economic slowdown triggered by fears of pandemic disease and a failed attempt on Italian ten-year bonds, partly offset by an increased volatilitypart of the Eni share and an appreciation of the country risk. This latter factorsOPEC + to support crude oil prices, management’s priorities in the perceived level of risk associated with each country of operations in terms of current trends and conditions in the macroeconomic, business, regulatory and socio-political framework, as well as the consensus outlook. In 2016, our average premium for the country risk was higher than in 2015 due to a deteriorated political and financial outlook of certain countries where we are conducting upstream operations. A country risk premium is added to the Group WACC and a premium for the business risk in determining the hurdle rates, which are utilized by management in its final investment decisions.
Liquidity and leverage
Considering the uncertainties about future trends in market fundamentals and price volatility, management’s prioritiesshort-term remain to maximize cash generation from operating activities and to preserve a solid balance sheet. We believe the initiatives implemented by management during the downturnin recent years intended to lowerincrease efficiency in operations, to reduce the cost base, to optimize investmentstime-to-market of reserves and to streamline operationsrestructure the mid and downstream businesses together with recentcontinuing management’s focus on capital discipline and the monetization of part of our exploration successdiscoveries have improved the Company’s fundamentals and strengthened its capital structure. We believe that in 2019 we have made further progress in enhancing the competitive position. Currently we are estimating that on averageposition of the Company and its resiliency to the market volatility through a number of actions and strategic deals aimed at rebalancing the asset portfolio along the hydrocarbons value chain and at increasing the geographic reach of our operations. Those included the expansion of the geographic presence of our Exploration & Production business in areas like the UAE, Mexico and Norway, this latter due to the acquisition of certain exploration and development E&P properties by our joint-venture Vår Energi, the growth achieved in Egypt and the acquisition of a 20% interest in the Ruwais refining complex in UAE. In future years, we will be ablecapitalize on those initiatives and acquisitions to fund its requirements for capital expendituresextract the projected returns, while at the same time we expect to continue pursuing financial discipline and sustainable growth to drive profitable production increases and an improved sales volumes mix with cash flowthe addition of more valuable barrels, reserve replacement and margin expansion at our mid and downstream businesses driven by synergies from integration, the repositioning of the refining and petrochemicals businesses and a growing customer base in the gas retail operations, in a Brent price environment lower than 45 $/BBL on averageas well as to reduce climate-related risks by developing our planned initiatives designed to expand the renewable generation capacity, to promote the circular economy and make our operations less carbon-emitting.
The initiatives planned in the next four-year plan. We have also evaluated our
financial resiliency considering our commitmentfour years are designed to payreach a floor dividendlow price of €0.8 per share equating to approximately €2.9 billion per year. We estimate that in the 2017-2020 planBrent crude oil at which the Company will be able to fund through cash flow from operations both the planned organic capital expenditures and the floordividend. Specifically, based on these actions and on the planned underlying growth in cash generation, we expect net cash provided by operating activities to fund the planned yearly amount of organic capital expenditure and the full dividend at 60around 45 $/BBL in 2017 andfor the Brent crude, at a Brent price lower than 60 $/BBL going forward. These targets are reflectivethe end of the Company’s initiatives in lowering its cost base and in optimizing its capital plan without impairing its ability to pursue its growth objectives.
During the plan period, management expects to execute an asset disposal program in the range of €5-7 billion, which will comprise the dilution of interests in our exploration assets, non-strategic hydrocarbons producing assets and other marginal assets in the mid and downstream businesses. These expected cash inflows will improve the Group’s financial flexibility. These planned disposals exclude the already defined divestment of a 40% interest in the Zohr gas discovery, off Egypt, while they include the disposition of an interest in our exploration asset in Mozambique.period.
During the downturn, in spite of the sharp contraction in the operating cash flow due to lower oil prices, the Company has managed to maintainhold its key ratio of net borrowings to equity – leverage – within thebelow a preset ceiling of 0.3 through a combination of cost cuts, asset disposals, capital expenditure curtailments and working capital optimization.optimizations. At the end of 2016,2019, our leverage stood at 0.28. Management believes that0.24 before the target ceiling leverage is consistent with the Company’s business profile, which features an increasing exposure to the Exploration & Production segment. In 2017, we expect that the Company leverage will improve from 2016. This will be driven by the planned portfolio transactions,impact of IFRS 16 (0.36 including the likely completioneffect of the Zohr divestment, and an expected reduction of 18% in the Group capital expenditure at constant exchange rates versus 2016, post portfolio transactions. This forecast is also basedIFRS 16). The Company intends to retain a strong control on the Company’s projected levelsevolution of Brent prices at which cash flow from operations is expected to fund the planned capital expenditure for the year.leverage going forward. Our cash flow projectionsflows from operating activities are exposed to the volatility of the oil price environment. Currently, based on our portfolio of oil&gas properties, we estimate that, holding all other factors constant, our net profit and cash flow from operations vary by approximately €0.2€0.15 billion for each dollar change in Brent prices on a yearly basis compared to our price forecast. We note thatassumptions for 2020. Currently, oil prices are on a downtrend due to the Brent pricerecent developments occurred until now in 2020 described in the period January 1 to March 17, 2017 was approximately 55 $/BBL on average (it was 34 $/BBL on averageabove paragraph
“Impact of COVID-19 and other current trends in the period January 1 to March 31, 2016)oil market”. We retain some levels of financial flexibility that we may use in case oil prices should take another leg down in the cycle in the remainder of the year. Particularly, approximately 37% of the planned investmentyear or in the four-year plan has been allocated to projects yet to be sanctioned.subsequent years. In addition, we retain cash reserves and committed and uncommitted borrowing facilities. For planning purposes, management assumed a EUR/USD exchange rate in the range of 1.08-1.201.11 – 1.21 U.S. dollars per euro in the 2017-20202020-2023 period. Given the sensitivity of Eni’s results of operations to movements in the euro versus the U.S. dollar exchange rate, trends in the currency market represent a factor of risk and uncertainty, as well as a potential positive driver of the Group results of operations, cash flow and balance sheet in case the U.S. dollar appreciates against the euro.uncertainty. We note that in the period January 1 to March 17, 2017first quarter 2020 the EUR/USD exchange rate was approximately 1.061.1 and appreciated year-on-year. This trend will favorably affectwas substantially unchanged year-on-year (it was 1 EUR=1.135 USD in the reported amountsfirst quarter of operating profit and operating cash flow in our Exploration & Production segment. However, the net impact of the U.S. dollar appreciation on the Group liquidity and net borrowings is uncertain as our capital expenditures are mainly denominated in U.S. dollars.2019). See “Item 3 – Risk factors”. DividendRemuneration policy
Considering the weak oil price environment, in 2015 the Company decided to rebase the annual dividend at €0.80 per share, whichManagement is our floor dividend. This floor dividend has been confirmed for fiscal year 2016.
In 2017, we confirm our plan to pay a cash dividend of €0.80 per share. Going forward, we remain committed to a progressive distributionremuneration policy in line with our plans of underlying earnings and cash flow growth and considering the scenario evolution. This forecast is dependent onDividends will be driven by the results that ultimately will be achieved in implementing our strategy and on management’s estimations ofby our ability to achieve the minimum level oftargeted Brent prices at
which the Company’s net cash flowsprovided from operating activities areis able to fund planned capital expenditures and dividend payments. This projected levelManagement is forecasting to increase the dividend expected for fiscal year 2020 to 0.89 €/ share compared to 0.86 €/share for fiscal year 2019, up by 3.5%. The Company had previously announced and launched a share repurchase program as a flexible tool to return shareholders the cash in excess of cash neutralitythat committed to achieve the targeted range of leverage, provided that Brent crude oil prices do not fall below a preset level. In 2019, we spent €400 million on share repurchases. Considering the current trends in the oil market, management has resolved to suspend the share repurchase plan for 2020. The program will be reconsidered when the Brent price for the referenced year, which is dependent upon achievement of our plans of profitable production growth and upgrading of profitability in mid and downstream businesses.the benchmark for decisions relating to the buyback plan activation, is at least equal to 60$/barrel. In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year. The expectations described above are subject to risks, uncertainties and assumptions associated with the oil&gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. There are a number of factors that could cause actual results and developments to differ materially, including, but not limited to, the impact of COVID-19 on global hydrocarbon demand, the role of OPEC+ at supporting crude oil prices, political instability in Libya and other countries, crude oil and natural gas prices; global demand for oil&gas&gas; trends in natural gas demand in Italy and other markets; developments in electricity generation; price fluctuations; drilling and production results; refining margins and marketing margins; currency exchange rates; general economic conditions; political and economic policies and climatesdesigned to tackle the risks of climate change in countries and regions where Eni operates;operates or on a global scale; regulatory developments; the risk of doing business in developing countries; governmental approvals; global political events and actions, including war, terrorism and sanctions; project delays; material differences from reserves estimates; inability to find and develop reserves; technological development; technical difficulties; market competition; the actions of field partners, including the inability of joint venture partners to fund their share of operating or developments activities; industrial actions by workers; environmental risks, including adverse weather and natural disasters; and other changes to business conditions. Please refer to “Item 3 – Risk factors”. Off-balance sheet arrangements Eni has entered into certain off-balance sheet arrangements, including guarantees, commitments and risks, as described in “Item 18 – note 38Note 27 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”. Eni’s principal contractual obligations, including commitments under take-or-pay or ship-or-pay contracts in the gas business, are described under “Contractual obligations” below. See the Glossary for a definition of take-or-pay or ship-or-pay clauses. Off-balance sheet arrangements comprise those arrangements that may potentially impact Eni’s liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of Eni’s business purposes, Eni is not dependent on these arrangements to maintain its liquidity and capital resources; nor is management aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on the Company’s financial condition, results of operations, liquidity or capital resources.
Eni has provided various forms of guarantees on behalf of unconsolidated subsidiaries and affiliated companies, mainly relating to guarantees for loans, lines of credit and performance under contracts. In addition, Eni has provided guarantees on the behalf of consolidated companies, primarily relating to performance under contracts. These arrangements are described in “Item 18 – note 38Note 27 – Guarantees, commitments and risks – of the Notes on Consolidated Financial Statements”.
Contractual obligations The amounts in the table refer to expected payments, undiscounted, by period under existing contractual obligations commitments. | | Total | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 and thereafter | | | Total | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and thereafter | | Total debt | | | | 29,318 | | | | | 8,492 | | | | | 2,126 | | | | | 4,120 | | | | | 2,914 | | | | | 1,331 | | | | | 10,335 | | | | | | 32,748 | | | | | 8,948 | | | | | 2,338 | | | | | 1,760 | | | | | 3,177 | | | | | 2,209 | | | | | 14,316 | | | Long-term finance debt | | | | 23,653 | | | | | 2,988 | | | | | 2,090 | | | | | 4,044 | | | | | 2,914 | | | | | 1,285 | | | | | 10,332 | | | | | | 21,920 | | | | | 2,908 | | | | | 1,704 | | | | | 1,259 | | | | | 2,743 | | | | | 1,785 | | | | | 11,521 | | | Short-term finance debt | | | | 3,396 | | | | | 3,396 | | | | | | | 2,452 | | | | | 2,452 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Lease liabilities | | | | | 5,622 | | | | | 884 | | | | | 632 | | | | | 487 | | | | | 434 | | | | | 424 | | | | | 2,761 | | | Fair value of derivative instruments | | | | 2,269 | | | | | 2,108 | | | | | 36 | | | | | 76 | | | | | | | | | | 46 | | | | | 3 | | | | | | 2,754 | | | | | 2,704 | | | | | 2 | | | | | 14 | | | | | | | | | | | | | | | 34 | | | Interest on finance debt | | | | 4,007 | | | | | 696 | | | | | 557 | | | | | 486 | | | | | 386 | | | | | 277 | | | | | 1,605 | | | | | | 3,677 | | | | | 594 | | | | | 452 | | | | | 353 | | | | | 342 | | | | | 269 | | | | | 1,667 | | | Interest expense for lease liabilities | | | | | 2,360 | | | | | 341 | | | | | 302 | | | | | 263 | | | | | 233 | | | | | 206 | | | | | 1,015 | | | Guarantees to banks | | | | 84 | | | | | 84 | | | | | | | 926 | | | | | 926 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Non-cancelable operating lease obligations(1) | | | | 2,418 | | | | | 593 | | | | | 353 | | | | | 257 | | | | | 231 | | | | | 199 | | | | | 785 | | | | Decommissioning liabilities(2) | | | | 16,281 | | | | | 253 | | | | | 580 | | | | | 417 | | | | | 400 | | | | | 184 | | | | | 14,447 | | | | Decommissioning liabilities(1) | | | | | 13,474 | | | | | 331 | | | | | 325 | | | | | 163 | | | | | 179 | | | | | 424 | | | | | 12,052 | | | Environmental liabilities | | | | 2,689 | | | | | 281 | | | | | 249 | | | | | 255 | | | | | 202 | | | | | 71 | | | | | 1,631 | | | | | | 2,591 | | | | | 403 | | | | | 368 | | | | | 319 | | | | | 238 | | | | | 198 | | | | | 1,065 | | | Purchase obligations(3) | | | | 120,225 | | | | | 10,891 | | | | | 9,265 | | | | | 9,511 | | | | | 8,839 | | | | | 7,961 | | | | | 73,758 | | | | Natural gas to be purchased in connection with take-or-pay contracts(4) | | | | 110,697 | | | | | 8,429 | | | | | 7,912 | | | | | 8,277 | | | | | 7,916 | | | | | 7,312 | | | | | 70,851 | | | | Natural gas to be transported in connection with ship-or-pay contracts(4) | | | | 6,620 | | | | | 1,569 | | | | | 1,053 | | | | | 943 | | | | | 724 | | | | | 478 | | | | | 1,853 | | | | Other take-or-pay and ship-or-pay obligations | | | | 724 | | | | | 114 | | | | | 105 | | | | | 101 | | | | | 96 | | | | | 80 | | | | | 228 | | | | Purchase obligations(2) | | | | | 126,483 | | | | | 9,938 | | | | | 9,912 | | | | | 9,467 | | | | | 9,530 | | | | | 9,722 | | | | | 77,914 | | | Natural gas to be purchased in connection with take-or-pay contracts (3) | | | | | 120,918 | | | | | 7,117 | | | | | 9,140 | | | | | 8,912 | | | | | 9,100 | | | | | 9,410 | | | | | 77,239 | | | Natural gas to be transported in connection with ship-or-pay contracts (3) | | | | | 3,410 | | | | | 1,070 | | | | | 532 | | | | | 454 | | | | | 412 | | | | | 296 | | | | | 646 | | | Other purchase obligations(5) | | | | 2,184 | | | | | 779 | | | | | 195 | | | | | 190 | | | | | 103 | | | | | 91 | | | | | 826 | | | | | | 2,155 | | | | | 1,751 | | | | | 240 | | | | | 101 | | | | | 18 | | | | | 16 | | | | | 29 | | | Other obligations(6)(4) | | | | 129 | | | | | 9 | | | | | 3 | | | | | 2 | | | | | 2 | | | | | 2 | | | | | 111 | | | | | | 114 | | | | | 7 | | | | | 1 | | | | | | | | | | | | | | | | | | | | 106 | | | of which: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Memorandum of intent relating to Val d’Agri | | | | 129 | | | | | 9 | | | | | 3 | | | | | 2 | | | | | 2 | | | | | 2 | | | | | 111 | | | | – Memorandum of intent relating to Val d’Agri | | | | | 114 | | | | | 7 | | | | | 1 | | | | | | | | | | | | | | | | | | | | 106 | | | TOTAL | | | | 175,151 | | | | | 21,299 | | | | | 13,133 | | | | | 15,048 | | | | | 12,974 | | | | | 10,025 | | | | | 102,672 | | | | | | 182,373 | | | | | 21,488 | | | | | 13,698 | | | | | 12,325 | | | | | 13,699 | | | | | 13,028 | | | | | 108,135 | | | | |
(1)
Operating leases primarily regarded assets for drilling activities, time charter and long-term rentals of vessels, lands, service stations and office buildings. Such leases did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(2)
Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration. (3)(2)
Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. (4)(3)
Such arrangements include non-cancelable, long-term contractual obligations to secure access to supply and transport of natural gas, which include take-or-pay or ship-or-pay clauses whereby the Company obligations consist of offtaking minimum quantities of product or service or paying the corresponding cash amount that entitles the Company to off-take the product in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors and on the basis of the long-term market scenarios used by Eni for planning purposes to minimum take and minimum ship quantities. See “Item 4 – Gas & Power – Natural Gas Purchases” and “Item 3 – Risk Factors – Risks in the G&P business. (5)
Mainly refers to arrangements to purchase capacity entitlements at certain re-gasification facilities in the United States of euro 1,226 milion.
(6)(4)
In addition to these amounts, Eni has certain obligations that are not contractually fixed as to timing and amount, including contributions to defined benefit pension plansprovisions for employee benefits (See Note 3121 to the Consolidated Financial Statements). The table below summarizes Eni’s capital expenditureexpenditures commitments for property, plant and equipment as of December 31, 2016.2019. Capital expenditures are considered to be committed when the project has received the appropriate level of internal management approval. Such costs are included in the amounts shown below. | | Total | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 and subsequent years | | | Total | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and subsequent years | | | | (€ million) | | | (€ million) | | Committed projects | | | | 23,756 | | | | | 6,733 | | | | | 6,679 | | | | | 4,218 | | | | | 2,441 | | | | | 3,685 | | | | | | 16,448 | | | | | 5,570 | | | | | 4,054 | | | | | 2,611 | | | | | 1,544 | | | | | 2,669 | | | | |
Liquidity risk Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets on the marketplace as to be unable to meet short-term finance requirements and to settle obligations. Such a situation would negatively impact Group results as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. At present, the Group believes it has access to sufficient funding and has also both committed and uncommitted borrowing facilities to meet currently foreseeable borrowing
requirements. The Group has also established a cash reserve, which consists of cash on hand and very
liquid financial assets (short-term deposits and held-for-trading securities). This cash reserve according to management plans can alternatively be used to absorb temporary swings in cash flows from operations, to provide financial flexibility to pursue the Group development programs or to fund the Group contractual obligations with respect to the repayment of financing debt at maturity over a 24-month horizon. For a description of how the Company manages the liquidity risk see “Item 18 – note 38Note 27 of the Notes on Consolidated Financial Statements”. As of December 31, 2016, Eni maintained short-term unused borrowing facilities of €12,308 million, of which €41 million committed. Long-term committed borrowing facilities amounted to €6,236 million, of which €700 million were due within 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions. Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which about €16.3 billion were drawn as of December 31, 2016.
Working capital Management believes that, taking into account unutilized credit facilities, Eni’sthe Company’s liquidity reserves, our credit rating and access to capital markets, Eni has sufficient working capital for its foreseeable requirements. Credit risk Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amount due. For a description of how the Company manages the credit risk see “Item 18 – note 38Note 27 of the Notes on Consolidated Financial Statements”. For information about credit losses in 20162019 and the allowance for doubtful accounts see “Item 18 – note 10Note 7 of the Notes on Consolidated Financial Statements”. Market risk In the normal course of its operations, Eni is exposed to market risks deriving from fluctuations in commodity prices and changes in the euro versus other currencies exchange rates, particularly the U.S. dollar, and in interest rates. For a description of how the Company manages the Market risk see “Item 18 – note 38Note 27 of the Notes on Consolidated Financial Statements”. Research and development For a description of Eni’s research and development operations in 2016,2019, see “Item 4 – Research and development”.
Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES Directors and Senior Management The following table lists the Company’s Board of Directors as at March 2017:December 31, 2019: Name | | Position | | Year elected or appointed | | Age | | | Position | | Year elected or appointed | | Age | | Emma Marcegaglia | | Chairman | | | | 2014 | | | | | 51 | | | | Chairman | | | | 2014 | | | | | 54 | | | Claudio Descalzi | | CEO | | | | 2014 | | | | | 62 | | | | CEO | | | | 2014 | | | | | 64 | | | Andrea Gemma | | Director | | | | 2014 | | | | | 43 | | | | Director | | | | 2014 | | | | | 46 | | | Pietro A. Guindani | | Director | | | | 2014 | | | | | 59 | | | | Director | | | | 2014 | | | | | 61 | | | Karina A. Litvack | | Director | | | | 2014 | | | | | 54 | | | | Director | | | | 2014 | | | | | 57 | | | Alessandro Lorenzi | | Director | | | | 2011 | | | | | 68 | | | | Director | | | | 2011 | | | | | 71 | | | Diva Moriani | | Director | | | | 2014 | | | | | 48 | | | | Director | | | | 2014 | | | | | 51 | | | Fabrizio Pagani | | Director | | | | 2014 | | | | | 50 | | | | Director | | | | 2014 | | | | | 52 | | | Alessandro Profumo1 | | Director | | | | 20152 | | | | | 60 | | | | | | Domenico Livio Trombone | | | Director | | | | 2017 | | | | | 59 | | |
In accordance with Article 17.1 of Eni’s By-laws, the Board of Directors is made up of 3 to 9 members. The current Board of Directors was elected by the ordinary Shareholders’ Meeting held on May 8, 20143April 13, 2017 which also established the number of Directors at nine for a term of three financial years. The Board’s term will therefore expire with the Shareholders’ Meeting called to approve the financial statements for the year ending December 31, 2016.2019. The Board of Directors is appointed by means of a slate voting system: slates may be presented by the shareholders representing at least 0.5% of share capital. According to the Eni By-laws, three out of nine Directors are appointed from among the candidates of the non-controlling shareholders. Emma Marcegaglia, Claudio Descalzi, Andrea Gemma1, Diva Moriani, Fabrizio Pagani and Luigi Zingales4Domenico Livio Trombone were the candidates of the Ministry of the Economy and Finance. Pietro A. Guindani, Karina Litvack and Alessandro Lorenzi were the candidates of institutional investors (non-controlling shareholders). The Shareholders’ Meeting appointed Emma Marcegaglia as the Chairman of the Board of Directors and, on May 9, 2014,April 13, 2017, the Board appointed Claudio Descalzi as the Chief Executive Officer of the Company. The provisions designed to ensure gender balance were applied for the first time in the aforementioned elections. Three Directors out of nine, including the Chairman, were drawn from the less represented gender, thereby already reaching the ratio of one-third of the Directors instead of the ratio of one-fifth as provided by the law for the first relevant election of the Board. The ratio of one-third of the Directors belonging to the less represented gender shall also apply to the next two subsequent terms of the Board of Directors.law.
The following provides details on the personal and professional profiles of the Directors. Emma Marcegaglia was born in Mantua in 1965 and has been Chairman of Eni since May 2014. She has been Chairman of the Fondazione Eni Enrico Mattei since November 2014. She is also Chairman and CEO of Marcegaglia Holding SpA and Deputy Chairman and CEO of the subsidiary companies operating in the processing of steel. She is also Chairman and CEO of Marcegaglia Investments Srl, the holding company of the diversified activities of the group. She is President of Businesseurope and of the Luiss Guido Carli University, a member of the Board of Directors of Bracco SpA and Gabetti Property Solutions SpA. From 1994 to 1996 she was National Deputy President of Young Entrepreneurs of Confindustria, from 1997 to 2000 she was President of the European Confederation of the Young Entrepreneurs (YES), from 1996 to 2000 President of Young Italian Entrepreneurs of Confindustria and from 2000 to 2002 she was Vice President of Confindustria for Europe. From May 2004 to May 2008 she (1)
On July 29, 2015, the Board of Directors of Eni co-opted Alessandro Profumo as Director replacing Luigi Zingales, who resigned from the Board on July 2, 2015. The Director Profumo was confirmed by the Shareholders’ Meeting on May 12, 2016.
(2)
Alessandro Profumo was Director of Eni from May 2011 to May 2014.
(3)
On July 29, 2015, the Board of Directors of Eni co-opted Alessandro Profumo as Director replacing Luigi Zingales, who resigned from the Board on July 2, 2015. The Director Profumo was confirmed by the Shareholders’ Meeting on May 12, 2016.
(4)
Luigi Zingales resigned from the Board on July 2, 2015.
was Confindustria Vice President for infrastructures, energy, transport and environment and Italian Representative of the top High Level Group for energy, competitiveness and environment set up by the European Commission. From May 2008 to May 2012 she was President of Confindustria. From July 2013 to July 2018 she was President of Businesseurope. She was a member of the Management Board of Banco Popolare and Director of Finecobank SpA and Italcementi SpA. She also held the position of 1
Temporarily interdicted from the office of Director for facts relating to another issuer with Consob Resolution of June 26, 2019. The “Corte d’Appello” of Rome suspended the provision with effect from November 4, 2019.
Chairman of the Aretè Onlus Foundation. From July 2010 to June 2019 she was President of the University Luiss Guido Carli. She graduated with a degree in business administration fromBusiness Administration at the Bocconi University in Milan and attended a Master’sMaster in Business Administration at New York University. Claudio Descalzi was born in Milan and has been Eni’s CEO since May 2014. He is a member of the General BoardCouncil and of the Advisory Board of Confindustria and Director of Fondazione Teatro alla Scala. He is a member of the National Petroleum Council for 2016/2017.Council. He joined Eni in 1981 as Oil & Gas field petroleum engineer and then became project manager for the development of North Sea, Libya, Nigeria and Congo. In 1990 he was appointed Head of Reservoir and operating activities for Italy. In 1994, he was appointed Managing Director of Eni’s subsidiary in Congo and in 1998 he became Vice President & Managing Director of Naoc, a subsidiary of Eni in Nigeria. From 2000 to 2001 he held the position of Executive Vice President for Africa, Middle East and China. From 2002 to 2005 he was Executive Vice President for Italy, Africa, Middle East, covering also the role of member of the boardBoard of several Eni subsidiaries in the area. In 2005, he was appointed Deputy Chief Operating Officer of Eni’sthe Exploration & Production Division.Division in Eni. From 2006 to 2014 he was President of Assomineraria and from 2008 to 2014 he was Chief Operating Officer of Eni’sin the Exploration & Production Division.Division of Eni. From 2010 to 2014 he held the position of Chairman of Eni UK. In 2012, Claudio Descalzi was the first European in the field of Oil&Gas to receive the prestigious “Charles F. Rand Memorial Gold Medal 2012” award from the Society of Petroleum Engineers and the American Institute of Mining Engineers. He is a Visiting Fellow at The University of Oxford. In December 2015 he was made a member of the “Global Board of Advisors of the Council on Foreign Relations”. In December 2016 he was awarded an Honorary Degree in Environmental and Territorial Engineering by the Faculty of Engineering of the University of Rome, Tor Vergata. He graduated with a degree in physics in 1979 from the University of Milan. Andrea Gemma was born in Rome in 1973 and has been Director of Eni since May 2014. He is Professor of Private Law at The Third University of Rome Law Department, Memberand was visiting professor at European Universities and at Villanova University. He is member of the Strategic Board of the American University of Rome and Appeal Court Lawyer and Partner in the Law and Tax Firm Gemma & Partners. He is a Member of the Studies Centre of the Chamber of Arbitration of Rome. He is Deputy Chairman of Serenissima SGR SpA and Chairman of the Watch Structure in Sorgente SpA. He is a member of the Board of Directors of Banca UBAE SpA and of Global Capital PLC.Appeal Court Lawyer. He is President of Board of Statutory Auditors of PS Reti S.p.A.SpA and Sirti S.p.A. He is a member of the Board of Directors of Cinecittà Centro Commerciale S.r.l.SpA. He is also Official Receiver of Valtur SpA, Liquidator of Novit Assicurazioni SpA and Sequoia Partecipazioni SpA, Corit SpA and of Sigrec SpA (Unicredit Group).SpA. Pietro A. Guindani was born in Milan in 1958 and has been Director of Eni since May 2014. He is currentlySince July 2008 he has been Chairman of the Board of Directors of Vodafone Italia SpA, where between 1995-2008 he was Chief Financial Officer and subsequently Chief Executive Officer. He previously held positions in the Finance Departments of Montedison and Olivetti and started his career in Citibank after graduating in Business at the Bocconi University in Milan. He is currently also a Board member of FINECOBank SpA, Salini-Impregilo SpA and Cefriel S.cons.r.l. and of the Italian Institute of Technology and Cefriel-Polytechnic of Milan. He is Board Member of Civita Foundation, AssonimeConfindustria and Confindustria, Member of the Executive Board of Assotelecomunicazioni, memberConfindustria Digitale; he is President of the Executive Board of Confindustria DigitaleAsstel-Assotelecomunicazioni and Vice President responsible for Universities, Innovation and Human Capital of Assolombarda. From 1982 to 1986 he was Relationship Banker at Citibank N.A. He then became International Finance Director in Montedison SpA (Enimont SpA) until 1992. He was Group Finance, Budget and Reporting Manager at European Vinyls Corporation SA/NV (1992-1993). In 1993 he became Head of Foreign Finance in Olivetti SpA. From 1995 to 2004 he was Chief Financial Officer of Vodafone Italy and of Vodafone South Europe, Middle East & Africa Region. From 2004 to 2008 he was Chief Executive Officer of Vodafone Italy. He was also Director of Société Française du Radiotéléphone – SFR S.A. (2008-2011), Pirelli & C. SpA (2011-2014), Carraro SpA (2009-2012) and, Sorin SpA (2009-2012), Finecobank SpA (2014-2017) and Salini-Impregilo SpA (2012-2018). He graduated with a degree in Business from the Università Luigi Bocconi in Milan. Karina A. Litvack was born in Montreal in 1962 and has been a Director ofin Eni since May 2014. She is currently a member of the Global Advisory Council of Cornerstone Capital Inc., a member of the Advisory Board ofin Bridges Ventures LLC, a member of the CEO Sustainability Advisory Panel of SAP AG, a memberBoard of Business for Social Responsibility, and of Yachad and a member of the Advisory Council for Transparency International UK.UK, a member of the Senior Advisory Panel of Critical Resource and of the Board of Governors of the CFA Institute. She is founder and executive member of the Board of Chapter Zero Limited. From 1986 to 1988 she was a member of the Corporate Finance team of PaineWebber Incorporated. From 1991 to 1993 she was a Project Manager of the New York City Economic Development Corporation. In 1998 she joined F&C Asset Management plc where she held the position of Analyst Ethical Research, Director Ethical Research and Director Head of Governance and Sustainable Investments (2001-2012). She was also a member of the Board of the Extractive Industries
Transparency Initiative (2003-2009) and of the Primary Markets Group of the London Stock Exchange Primary Markets Group (2006-2012). From 2003 to 2014 she was a member of the CEO Sustainability Advisory Panel of Lafarge SA; from January 2008 to December 2010 she was a member of the CEO Sustainability Advisory Panel of Veolia SA; from January to December 2010 she was a member of the CEO Sustainability Advisory Panel of ExxonMobil and Ipieca; from January 2010 to November 2017 she was a member of the CEO Sustainability Advisory Panel in SAP AG. From January 2015 to May 2019 she was a member of the Board of Yachad. She graduated with a degree in Political Economy fromat the University of Toronto and in Finance and International Business from Columbia University Graduate School of Business.
Alessandro Lorenzi was born in Turin in 1948 and has been Director of Eni since May 2011. He is a founding partner of Tokos Srl, a consulting firm for securities investment,Director and Chairman of Società Metropolitana Acque Torino SpA and Directorthe Internal Control Committee of Ersel SIM SpA and of MuttiBanca Albertini SpA. He began his career at SAIAG SpA in the Administration and Control area. In 1975 he joined Fiat Iveco SpA where he held a series of positions: Controller of Fiat V.I. SpA, Head of Administration, Finance and Control, Head of Personnel of Orlandi SpA in Modena (1977-1980) and Project Manager (1981-1982). In 1983 he joined GFT Group where he was Head of Administration, Finance and Control of Cidat SpA, a GFT SpA subsidiary (1983-1984), Central Controller of GFT Group (1984-1988), Head of Finance and Control of GFT Group (1989-1994) and Managing Director of GFT SpA, with ordinary and extraordinary powers over all operating activities (1994-1995). In 1995 he was appointed Chief Executive Officer of SCI SpA, where he oversaw the restructuring process. In 1998 he was appointed Operating Officer and was subsequently Director of Ersel SIM SpA until June 2000. In 2000 he became Executive Officer of Planning and Control at the Ferrero Group and General Manager of Soremartec, the technical research and marketing company of the Ferrero Group. In May 2003 he was appointed CFO of Coin Group and in 2006 he became Chief Corporate Officer at Lavazza SpA, serving as abecoming Board member from 2008 to June 2011. From July 2011 to September 2017 he was Chairman of Società Metropolitana Acque Torino SpA. From June 2016 to April 2019 he was Director of Mutti SpA. Diva Moriani was born in Arezzo in 1968 and has been a Director ofin Eni since May 2014. She is currently Executive Vice Chairman of Intek Group SpA, CEOVice Chairman of KME AG, Vorstand, a German holding company of KME Group, ChairmanDirector of KME S.r.l.,Srl, Member of the Supervisory Board of KME Germany GmbH and Director of Assicurazioni Generali SpA, Moncler SpA, Ergycapital SpA, Dynamo Academy, Dynamo Foundation and Associazione Dynamo. From 2007 to 2012 she was CEO of I2 Capital Partners, a private equity fund sponsored by Intek Group SpA, with an investment strategy focused on “Special Situations”. and from 2014 to 2017 CEO of KME AG. She graduated with a degree in Economics fromat the University of Florence. Fabrizio Pagani was born in Pisa in 1967 and has been a Director ofin Eni since May 2014. He is currently theHead of Economics and Capital Market Strategy of Muzinich & Co. and Board member of Save SpA, Banca Finint SpA. From 2014 to 2018 he has been Head of the Technical SecretariatOffice of the MinistryMinister of Economy and Finance. He was Deputy Director of the International Training Programme for Conflict Management at the High School S. Anna School of Advanced Studies in Pisa from 1995 to 1998, Professor of International Law in the Faculty of Political Science at the University of Pisa from 1993 to 2001, Deputy Chief of the Legislative Office at the Department of European Affairs from 1998 to 1999 and Counsellor for International Affairs in the Ministry of Industry and Foreign Trade from 1999 to 2001. He was Senior Advisor at the OECD from 2002 to 2006, Head of the Office of the State Undersecretary, within the Prime Minister’sMinister Office from 2006 to 2008, a board member of SACE SpA from 2007 to 2008, Political Counsellor of the OECD General Secretary from 2009 to 2011, Director of the G8/G20 Office at the OECD from 2011 to 2013 and Senior Economic Counsellor to the Prime Minister and G20 Sherpa from 2013 to 2014. He was a NATO Fellow and was a visiting scholar at Columbia University, New York. He graduated with a degree in international studies fromInternational Studies at the Scuola Superiore Sant’Anna, School of Advanced Studies, Pisa, and has a Master’s DegreeMaster degree from the European University Institute, Florence. Alessandro ProfumoDomenico Livio Trombone was born in GenoaPotenza in 19571960 and has been Director of Eni since July 2015.April 2017. He is a certified chartered accountant and a certified public auditor. He is partner of Studio Trombone Dottori Commercialisti e Associati. He is currently Chairman of Equita SIM, of Appeal Strategy & Finance S.r.l. and member of the Supervisory Board of Sberbank.Directors of Consorzio Cooperative Costruzioni-CCC, of Focus Investments SpA, of Società Gestione Crediti Delta SpA and of Prelios Credit Servicing SpA. He is, also a Board memberamong the others, Director of TOG “Together To Go”. In February 2012International World Group Srl. Furthermore, he was appointed member of the International Advisory Board of Itau-UniBanco. He began his career in 1977 at the Banco Lariano, becoming Branch Manager in Milan. In 1987 he joined McKinsey, where he was Project Manager in the strategy area for the finance sector. In 1989 he was appointed Head of relations with financial institutions and integrated development and organization projects at Bain, Cuneo e Associati (now Bain & Company). In 1991 he left the field of company consultancy to join RAS, Riunione Adriatica di Sicurtà, where as General Manager he was responsible for the banking and parabanking sectors. He was also in charge of the yield increase of RAS’s bank and of the other companies in the group operating in the field of asset management. In 1994 he joined Credito Italiano as Joint Central Manager and was in charge of Programming and Control, becoming General Manager in 1995. In 1997 he was appointedis Chief Executive Officer of Credito ItalianoAtrikè SpA and subsequentlySole Director of Unicredit, a positionFINCCC SpA and of Focus Investment International Srl. He is also Chairman of the Board of Statutory Auditors of Coop Alleanza 3.0 Sc, Cooperativa Immobiliare Modenese Soc. Coop., H2I SpA and of Tenute del Cerro SpA. He is standing Statutory Auditor, among the others, of: Arca Assicurazioni SpA, Arca Vita SpA, Cooperare SpA, Il Ponte SpA, Unipol Finance Srl, Unipol Investment SpA, UnipolPart I SpA and Unisalute SpA. He is Liquidator in Italcarni Sc and in Open.Co S.c. He is technical consultant in legal proceedings, coadjutor in bankruptcy proceedings, liquidator, trustee in bankruptcy and judicial commissioner. Over the years he held positions in banks, in asset management and insurance companies. More in detail, he was standing Statutory Auditor in Carimonte Holding SpA, Unicredit Servizi Informativi SpA, Immobiliare Nettuno Srl, Gespro SpA and in PLT Energia SpA. From April 2006 to March 2007 he was Director of Aurora Assicurazioni SpA. From October 2007 until September 2010. On an international levelthe merger of the Company in FonSai SpA, he was Chairman of the European Banking Federation and ChairmanBoard of the IMCStatutory Auditors in Washington. In May 2004Unipol Assicurazioni SpA. Until December 2008 he was decorated as CavaliereDirector in Banca Popolare del Merito del Lavoro.Materano SpA and BNT Consulting
SpA. From 2006April 2010 to 2014October 2011 he was Chairman of the Board of Directors in BAC Fiduciaria SpA. From April 2009 to December 2011 he was Chairman of the Board of Statutory Auditors in Arca Impresa Gestioni SGR SpA. From April 2007 until April 2012 he was Chairman of the Board of Statutory Auditors in Cassa di Risparmio di Cento SpA. From April 2010 to May 2016 he was Chief Executive Officer of Carimonte Holding SpA, becoming Chairman until 26 July 2018. From December 2011 to December 2012 he was independent Director in Serenissima SGR SpA. From December 2011 to April 2016 he was Director and Vice Chairman in Gradiente SGR SpA. From April 2007 to April 2016 he was Standing Statutory Auditor of Unipol Gruppo Finanziario SpA. From October 2017 to April 2019 he was Director of Bocconi University in Milan and from 2011Aeroporto Guglielmo Marconi di Bologna SpA. From April 2013 to 2014 he was Director of Eni andJuly 2019 he was Chairman of the Board of Statutory Auditors in Unipol Banca Monte dei Paschi di Siena from 2012 to 2015. He was Chairman of CASL (Comitato per gli Affari Sindacali e del Lavoro dell’ABI) from 2014 to 2015 and in February 2012 he was appointed a member of the “High-level Expert Group” on structural reform of the EU banking sector; he left the Group when he was appointed Chairman of Banca Monte dei Paschi di Siena.SpA. He graduated with a degree in business administrationEconomics from the Università Luigi BocconiUniversity of Milan.Modena. Senior Management The table below sets forth the composition of Eni’s Senior Management as at December 31, 2016.2019. It includes the CEO, as General Manager of Eni SpA, as well as the Chief Officers and the Executives who report directly to the CEO and to the Board, and on its behalf, to the Chairman. Name | | | Management position | | | Year first appointed to current position | | | Total number of years of service at Eni | | | Age | | Claudio Descalzi | | | General Manager of Eni | | | 2014 | | | | | 35 | | | | | | 61 | | | Luca Bertelli | | | Chief Exploration Officer | | | 2014 | | | | | 32 | | | | | | 58 | | | Roberto Casula | | | Chief Development, Operations & Technology Officer | | | 2014 | | | | | 28 | | | | | | 54 | | | Alberto Chiarini | | | Chief Retail Market Gas & Power Officer | | | 2016 | | | | | 27 (1) | | | | | | 53 | | | Claudio Granata | | | Chief Services and Stakeholder Relations Officer | | | 2014 | | | | | 33 | | | | | | 56 | | | Massimo Mantovani | | | Chief Midstream Gas & Power Officer | | | 2016 (2) | | | | | 23 | | | | | | 53 | | | Massimo Mondazzi | | | Chief Financial Officer | | | 2014 (3) | | | | | 24 | | | | | | 53 | | | Giuseppe Ricci | | | Chief Refining & Marketing Officer | | | 2016 (4) | | | | | 31 | | | | | | 58 | | | Antonio Vella | | | Chief Upstream Officer | | | 2014 | | | | | 33 | | | | | | 59 | | | Marco Bollini | | | Legal Affairs Department Senior Executive Vice President | | | 2016 (5) | | | | | 19 | | | | | | 50 | | | Marco Petracchini | | | Internal Audit Department Senior Executive Vice President | | | 2011 (6) | | | | | 17 | | | | | | 52 | | | Roberto Ulissi | | | Corporate Affairs and Governance Department Senior Executive Vice President Board Secretary and Corporate Governance Counsel | | | 2006 (7) | | | | | 10 | | | | | | 54 | | | Marco Bardazzi | | | External Communication Department Executive Vice President | | | 2015 | | | | | 1 | | | | | | 49 | | | Luca Cosentino | | | Energy Solutions Department Executive Vice President | | | 2015 | | | | | 13 | | | | | | 55 | | | Pasquale Salzano | | | Government Affairs Department Executive Vice President | | | 2015 (8) | | | | | 5 | | | | | | 43 | | | Luca Franceschini | | | Integrated Compliance Department Executive Vice President | | | 2016 (9) | | | | | 25 | | | | | | 50 | | | Jadran Trevisan | | | Integrated Risk Management Executive Vice President | | | 2016 (10) | | | | | 16 | | | | | | 55 | | | |
(1)
It includes the period he served at Saipem SpA
(2)
Prior to October 17, 2016, he was Chief Legal and Regulatory Affairs.
(3)
Prior to September 12, 2016, he was Chief Financial and Risk Management Officer.
(4)
Prior to September 12, 2016 he was Executive Vice President Health, Safety, Environment & Quality Department, but he did not report to Chief Executive Officer.
(5)
Prior to October 17, 2016, he was Executive Vice President International and Finance Legal Department, but he did not report to Chief Executive Officer.
(6)
Since 2014 the Senior Executive Vice President of the Internal Audit Department reports hierarchically to the Board of Directors and, on its behalf, to the Chairman, without prejudice to its functional dependence on the Control and Risk Committee and on the Chief Executive Officer (in his capacity as Director in charge of the Internal Control and Risk Management System).
(7)
Since 2014, the Board Secretary has also served as Corporate Governance Counsel. The Board Secretary reports hierarchically and functionally to the Board of Directors and, on its behalf, to the Chairman.
(8)
Prior to February 19, 2015, he was Senior Vice President Government Affairs.
(9)
Prior to September 12, 2016, he was Executive Vice President Legal Compliance and Regulatory Department, but he did not report to Chief Executive Officer.
(10)
Prior to September 12, 2016 he reported to the Chief Financial and Risk Management Officer.
Name | | | Management position | | | Year first appointed to current position | | | Total number of years of service at Eni | | | Age | | Claudio Descalzi | | | CEO and General Manager of Eni | | | 2014 | | | | | 38 | | | | | | 64 | | | Luca Bertelli | | | Chief Exploration Officer | | | 2014 | | | | | 35 | | | | | | 61 | | | Stefano Maione | | | Chief Development, Operations & Technology Officer | | | 2019 | | | | | 28 | | | | | | 56 | | | Claudio Granata | | | Chief Services and Stakeholder Relations Officer | | | 2014 | | | | | 36 | | | | | | 59 | | | Cristian Signoretto | | | Chief Gas & LNG Marketing and Power Officer | | | 2019 | | | | | 12 | | | | | | 45 | | | Massimo Mondazzi | | | Chief Financial Officer | | | 2014 | | | | | 27 | | | | | | 56 | | | Luigino Lusuriello | | | Chief Digital Officer | | | 2018 | | | | | 31 | | | | | | 58 | | | Giuseppe Ricci | | | Chief Refining & Marketing Officer | | | 2016 | | | | | 34 | | | | | | 61 | | | Alessandro Puliti | | | Chief Upstream Officer | | | 2019 | | | | | 29 | | | | | | 56 | | | Stefano Speroni | | | Legal Affairs Senior Executive Vice President | | | 2019 | | | | | 1 | | | | | | 57 | | | Marco Petracchini | | | Internal Audit Senior Executive Vice President | | | 2011 | | | | | 20 | | | | | | 55 | | | Roberto Ulissi | | | Corporate Affairs and Governance Senior Executive Vice President and Board Secretary and Corporate Governance Counsel | | | 2006 | | | | | 13 | | | | | | 57 | | | Marco Bollini | | | Commercial Negotiations Senior Executive Vice President | | | 2019 | | | | | 22 | | | | | | 53 | | | Marco Bardazzi | | | External Communication Executive Vice President | | | 2015 | | | | | 4 | | | | | | 52 | | | Luca Cosentino | | | Energy Solutions Executive Vice President | | | 2015 | | | | | 16 | | | | | | 58 | | | Lapo Pistelli | | | International Affairs Executive Vice President | | | 2017 | | | | | 4 | | | | | | 55 | | | Luca Franceschini | | | Integrated Compliance Executive Vice President | | | 2016 | | | | | 28 | | | | | | 53 | | | Jadran Trevisan | | | Integrated Risk Management Executive Vice President | | | 2016 | | | | | 19 | | | | | | 58 | | |
The Chief Exploration Officer, the Chief Development, Operations & Technology Officer, the Chief Upstream Officer, the Chief Midstream Gas & LNG Marketing and Power Officer, the Chief Refining & Marketing Officer, the Chief Retail Market Gas & Power Officer, the Chief Financial Officer, the Chief Services & Stakeholder Relations Officer, Chief Digital Officer, the Senior Executive Vice President Legal Affairs, Department, the Senior Executive Vice President Internal Audit, Department, the Senior Executive Vice President Corporate Affairs and Governance, Department,the Commercial Negotiations Senior Executive Vice President as well as the Executive Vice President Energy Solutions, Department, the Executive Vice President External Communication, Department, the Executive Vice President GovernmentInternational Affairs, Department, the Executive Vice President Integrated Compliance, Department, the Executive Vice President Integrated Risk
Management, the Chief Executive Officer of Versalis SpA and the Chief Executive Officer of Syndial SpA are members of the Management Committee2, which provides advice and support to the Chief Executive Officer. Other managers may be invited to attend meetings based on the agenda. The Chairman of the Board is invited to attend meetings. The duties of Committee Secretary are performed by the Senior Executive Vice President Corporate Affairs and Governance Department.Governance. The Chief Financial Officer has been appointed as Officer in charge of preparing Company’s financial reports pursuant to Italian law by the Board of Directors, acting upon a proposal of the CEO in agreement with the Chairman, following consultation with the Nomination Committee and with the approval of the Board of Statutory Auditors. The Senior Executive Vice President of the Internal Audit Department is appointed by the Board of Directors, acting upon a proposal of the Chairman in agreement with the Chief Executive Officer (in his capacity as Director in charge of the internal control and risk management system), following consultation with the Board of Statutory Auditors and the Nomination Committee and with the favorable opinion of the Control and Risk Committee. The Board Secretary and Corporate Governance Counsel is appointed by the Board of Directors upon a proposal of the Chairman. Other members of Eni’s senior management are appointed by Eni’s CEO and may be removed without cause. Senior Managers Luca Bertelli was born in Sesto Fiorentino in 1958. He graduated cum laude with a degreehonours in geology in 1983 from the University of Florence. In 1984 he joined Eni’s geophysics division, where he workedworking first as a researcher in the development of 3D seismic prospecting technology and subsequently as a manager of 3D seismic prospecting programs, and specializingprogrammes, specialising in seismic-stratigraphy. In 1994 he was appointed Managermanager of seismic-stratigraphy applications and in 1999 expandedhe increased the technical-managerial scope of his activities becoming Eni’s Managermanager of geological and geophysical services. services in Eni. At the end of 2001, his career took a new international turn with rolesholding positions of increasing managerial complexity over a period of eight years, starting in Norway where he was Technical Director and Deputy Managing Director ofat Norsk Agip.Agip in Norway. In 2003 he was appointed Managing Director of Eni Indonesia and in 2006 he moved to Egypt as General Manager and Managing Director, a roleposition he covered also held at Eni Angola in 2007. In 2009 he returned to Eni’s headquarters as Senior Vice PresidentChairman of Global Exploration. At the beginning of 2010, heHe was appointed Executive Vice President of Exploration and Unconventional.Unconventional at the beginning of 2010. Since July 1, 2014, he has been Eni’s Chief Exploration Officer. Roberto CasulaStefano Maione was born in Cagliari in 1962.Avellino in1963. He graduated withhas a degree in mining engineeringCivil Engineering from the University of Cagliari and joined EniBologna. Stefano Maione was hired by Agip S.p.A. in 19881991 as a reservoir engineer. He spent the first yearsField Engineer, gaining significant experience in dynamic modelling of his professional life working at oilfieldsoil fields and contributing to studies of fields in Italy before movingEgypt and China. In 1994 he transferred to West AfricaAgip Récherches Congo S.A., again as a Field Engineer, where he was appointed Chief Development Engineer. He returneddeveloped his skills and experience in oil fields and eventually reached the position of Head of Field Operations. Returning to headquarters in 1997 as coordinator business development activities for Africa and the Middle East, contributing to a number of new initiatives and portfolio activities. In 2000,early 1999, he became projectoccupied increasingly important roles in technical services, managerfinally becoming District Head of Production for Italy. From 2003 to 2006 he gained significant experience as a Development Project Manager in Egypt, Libya, Iran and in 2001, moved toItaly. In 2007, he was elected as a member of the Middle East as Project Director on a giant gas production project. From 2004 to 2005, he held a numberManagement Committee that runs Mellitah Gas B.V. Libyan Branch, 50% of managerial positions inwhich is controlled by Eni and 50% by the Exploration & Production Division, becoming Chief Executive Officer of Eni Mediterranea Idrocarburi SpA, engaged in oil&gas exploration and production in Sicily. At the end of 2005,National Oil Corporation (NOC). In January 2009, he was appointed Managing Director of Eni’s activitiesEni Iran B.V. and in 2010 returned to Libya whereas Managing Director of Eni North Africa B.V. Returning to headquarters again in January 2012, he remained for two years and concluded the renegotiation of oil contracts and launched an important program of social projects. In October 2007,
he became head of operational and business activities in sub-Saharan Africa aswas appointed Senior Vice President basedof Development Projects and Deputy Chairman of the Development Department. He was put in Nigeria. In December 2011, he was appointedcharge of the Mozambique Programme in 2013 after Eni discovered super-giant gas fields in the country, becoming Executive Vice President Africa and Middle East Region, also coordinating the Mozambique programme for the development of the Mamba and Coral discoveries. From 2014 to May 2016, heit in 2015. He was a member of the Board of Directors of the Eni Foundation. Since July 1, 2014, he has been Eni’sappointed Chief Development, Operations & Technology Officer.
Alberto Chiarini was born in Milan in 1963. After taking a degree in political science and a course of specialization at the Scuola Enrico Mattei, he joined Eni in 1989. He began his career in an international context, in the business/finance area, in positions of growing responsibility in a number of countries (including the United Kingdom, Congo, Libya and Holland) rising to the position of Managing Director of Eni UK. He returned to Italy in 2006 as head of Planning and Control at the Exploration and Production division and was subsequently appointed as Eni’s Executive Vice President Global Procurement and Strategic Sourcing. In 2011 he was appointed Chief Executive of Syndial, the Eni subsidiary that provides integrated services in the field of environmental remediation. On December 6, 2013 he was appointed Chief Financial and Compliance Officer of Saipem SpA with responsibility for Finance, Legal Affairs & Compliance and ICT, overseeing in particular the recapitalisation and refinancing of the company. He was appointed as Chief Retail Market Gas & Power Officer on September 12, 2016.July 1, 2019.
Claudio Granata was born in Rome in 1960. Graduating with a degree in economics, he joined the Eni group in 1983. From 1983 to 1994 he worked as a labour market and social welfare expert with ASAP (the trade union association for Eni Companies). From 1994 to 1999 he continued his experience with Eni Corporate as an expert in industrial relations. In 2000 he was given responsibilitymade responsible for Staff and OrganizationOrganisation within Eni Servizi Amministrativi, a company that was set up to centralizecentralise Eni’s administrative activities. 2
The Committee includes also the CEOs of certain Eni’s subsidiaries.
In 2001 he took over the management of Eni’s territorial divisions, for which he structuredrestructuring the management of the staff by geographical area and in 2003 he took on the role of Business HR for Eni Corporate, ensuring support for Departmentsdepartments in the management and development of Eni Corporate’s managerial resources during a period of profound change (2002-2004), characterizedwhich was characterised by the mergers by incorporation of Snam and AgipPetroli and the redefinitionrestructuring of the organizational structures for the staff.staff organisation. In the same year he was also appointed as Directorhead of personnelHuman Resources and organizationOrganisation of SofidSOFID (Eni’s financial services company). In 2006 he was appointed Human Resources Director of the E&P Division, where he oversaw the Planning, Management, Developmentplanning, management, development and Compensationcompensation processes for the human resources and organization activities. He also collaborated with the top management in the reorganizationreorganisation of macro processes for the Divisiondivision and promoted Change Managementchange management initiatives. From 2006, he has beenHe became a Board Memberboard member of Eni International Resources Ltd in 2006 and from 2012 to 2013, he has been appointed aswas Chairman of the Boardboard of Eni International Resources Ltd.Ltd from 2012 to 2013. From 2012 to March 2015 he has beenwas a board member of Eni UK Ltd. Sinceltd. In 2013 he has beenwas appointed Executive Vice President Sustainable Development, Safety, Environment and Quality at E&P, with responsibilityresponsible for overseeing safety, environment and quality processes to promote integration with operational processes and contribute to improvements in time“time to marketmarket” and efficiency. From 2014 to May 2016, he was a member of the Board of Directors of the Eni Foundation. Since November 2014, heHe has been Chairman of the Boardboard of Eni Corporate University. Since July 1, 2014, heUniversity since November 2014. He has been Eni’s Chief Services & Stakeholder Relations Officer.Officer in Eni since 1 July 2014. Massimo Mantovani Cristian Signorettowas born in Verona in 1974, is married and has three children. After graduating in Mechanical Engineering in 1999 from the Politecnico di Milano, he fulfilled his military service as an Officer in 1963. He graduatedthe Italian Army. In 2000 he was awarded with a degreescholarship as a Ph.D. candidate at the Department of Energy of the Politecnico di Milano, where he was involved in law from the University of Milan and holds a Master’s Degree from the University of London. He is the author of numerous publications and teaches post-graduate courses. After qualifying to practice law in Italy and UK he worked for a few years in private legal practice in Milan and London. In 1993 he joined Eni’s Legal Department, specializing in international negotiations and contracts, specifically international gas/LNG supplies andresearch projects and joint ventures for the commercialization and transport of gas.teaching activities. In 2001 he was appointed legal Director of Eni’s Gas & Power Division. His main task was participating tojoined McKinsey. He obtained a Master in Business Administration from Columbia University, New York, in 2005. After a short experience in Citigroup in New York, he continued his career in McKinsey, mostly dealing with projects in the management forOil&Gas and Banking&Insurance sectors. In 2007 he joined Eni in the Office of the start-up phase ofCEO supporting the liberalization of the gas market in ItalyTop Management for corporate strategy and the unbundling of the national and international network for the transport of gas.group-level projects. In October 2005November 2008 he was appointed Senior Vice President for International Sales with the responsibility to develop gas sales in the European B2B markets outside Italy within the Gas & Power business of Eni. In May 2012 he became Executive Vice President for International Markets and LNG Activities with the responsibility for the overall commercial strategy and sales activities outside Italy, including affiliate companies and LNG marketing. In November 2016 he became Executive Vice President for Portfolio Strategy and Long Term Gas Negotiations in the newly established Midstream business of Legal AffairsEni with the responsibility to oversee the gas supply portfolio management and the relationships with long term gas suppliers. In February 2018 he was appointed Executive Vice President Business Unit Gas. In this role he managed the entire midstream wholesale gas value chain, including supply and trading activities. In parallel he was also appointed EVP Trading & Origination in Eni S.p.A. He has been Chief Legal and Regulatory AffairsTrading & Shipping SpA (the fully owned subsidiary of Eni from 2014 to 2016,SpA in charge of all the department managed all legal and energy regulatory issues of Eni and its unlisted subsidiaries. From 2005 to 2016 he was member oftrading operations within the Eni S.p.A. Watch Structure.group). He wasis a member of the Board of Directors of Snam Retein Union Fenosa Gas S.p.A. from 2005 to 2012(Spain), a JV between Eni and of the Board of the University of Bologna from 2011 to 2012.Naturgy, and in BlueStream (The Netherlands), a JV between Eni and Gazprom. He has been Chief Gas & Lng Marketing and Power Officer in Eni since April 15, 2019. From April 2019 he is Chairman and CEO in charge of Syndial S.p.A. from 2016 to 2017. He is currently ChairmanGas, Lng and Power activities of Eni Trading & Shipping S.p.A. He is also Eni Representative on the Eurogas Governing Board and on its Executive Committee since November 2016. Between 2011 and
2014 he was a member of the anticorruption working group for the B20, coordinator for activities relating to the development of an international regulatory framework for the B20 held in Russia in 2013 and leading expert for the 2014 B20 in Australia. Massimo Mantovani has been Eni’s Chief Midstream Gas & Power Officer since 17 October 2016.SpA.
Massimo Mondazzi was born in Monza in 1963. He graduated with a degree in economicsEconomics and business administrationBusiness Administration from Bocconi University Milan in 1987. He joined Eni in 1992 after acquiring considerable professional experience in industrial companies and also as a management consultant. He worked in the Administration and Control area of the Exploration and Production Division until 2006, becoming head of the Division.Director. From 2006 to 2009 he was Director of Planning and Control for the Eni Group, before returning to E&P as Executive Vice President for the Central Asia, Far East and Pacific Region business areas. In this role he contributed to the consolidation of Eni’s activities in the Exploration and Production division, to the launch of new development projects and to Eni’s entry into new countries. On December 5, 2012 he was appointed Chief Financial Officer of Eni and Officer charged with preparing the company’s financial reports pursuant to Article 154-bis of Legislative Decree No. 58/1998. He is Chairman of Agi SpA since 2013. From 2014 until September 2016, alongside his role as Eni’s Chief Financial Officer, he was also responsible for Eni’s Integrated Risk Management. Luigino Lusuriello was born in Genoa in 1961. He joined Agip SpA’s Engineering Department in 1988 as a designer engineer of onshore and offshore structures. In 1994 he was appointed Operating and Maintenance Technologies Manager at Crema District and then he grows in the Production Area up to the
role of Production Manager of Ortona District. In 2001 he was appointed Ortona District Manager and later Val d’ Agri District Manager. From 2004 he began an international career path, initially as Technical Director in Congo, where, the year after, he was appointed Managing Director. In 2007 he took on the role of Managing Director in ENI UK. He returned to Italy in 2009 to take on the role of Vice President for Regional Management department.of Kazakhstan-Karachaganak activities. From 2011, following the entry of Eni in Iraq, he has been in charge for the development project as Senior Vice President of the Iraq Program. In 2013 he was appointed Executive Vice President Operations. He graduated with 110/110 in Mechanical Engineering from the University of Genoa and completed the course “The Oxford Advanced Management and Leadership Program” at the Said Business School, University of Oxford. He has been Chief Digital officer in Eni since September 18, 2018. Giuseppe Ricciwas born in Casale Monferrato in 1958. He has a degree in chemical engineering. He joined Eni in 1985 initially working in the study and development of new refining processes at the Sannazzaro refinery, before becoming involved in the creation and consolidation of the joint venture with Kuwait Petroleum at the Milazzo refinery. In 2000 he returned to head office as where he was responsible for Refining Processes Development and oversaw the performance optimisation at the refining facilities of Agip Petroli. He left central technologies to take over, in 2004, as director of the Gela Refinery, a particularly challenging assignment both from a managerial perspective and in terms of the refining cycle and the complexity of the plant; in 2006 he was appointed managing director of the refinery. In June 2010 he was made Senior Vice President of the Industrial Sector for Refining & Marketing, with responsibility for the refineries, storage deposits, oil pipelines and plant and facilities in Italy, as well as the management of subsidiary and associated companies in Italy and abroad. As Industrial Director he also held a series of additional responsibilities, such as the chairmanship of Gela and Milazzo. In 2012 he took on the delicate role of Eni’s Executive Vice President Health, Safety Environment and Quality with responsibility for providing the guidelines, coordination and control of safety, industrial health, product safety, the environment and quality. Since 2016 heHe has been President of Confindustria Energia since July 2017 and President of AIDIC (Italian Association Of Chemical Engineering) since 2018. He has a board member of Eniservizi.degree in chemical engineering. He was appointed as Chief Refining & Marketing Officer on September 12, 2016. Antonio VellaAlessandro Puliti was born in 1957.Florence in 1963. He graduated withjoined Agip SpA’s Reservoir Department in 1990 as a degree in engineering from the Turin Polytechnic in 1982Reservoir Geologist and joined the Eni Group in 1983. He began his career as an oil engineer at Agip in Libya, where he was involved in upstream onshorethe study of reservoirs in Africa and offshore operations. From 1988Italy. His international professional career started in 1998, when he moved to 1991,Aberdeen to fill the position of Assistant Operated Asset Manager of Agip UK, where he was project manager for EniChem’s petrochemical plants and refineriesgained operational experience in Italy. In 1991,complex contexts. After returning to Italy in 2002, he was appointed project manager forReservoir and Drilling and Completion Manager in the development of Libyan oil fields and in 1993,Val D’Agri project. In 2003 he movedwas posted to Egypt initially as IEOC’s Development and Operations Manager and subsequently covered increasingly more complex managerial roles, first as General Manager and Managing Director of Petrobel and later as General Manager of IEOC. In 2009 he moved back to Italy to take on the role of Regional Management Russia and North Europe Vice President. In 2010, he moved to Stavanger, where he was responsible for allheld the dual role of Eni’s upstream operations in Egypt.Eni Norge’s Managing Director and Regional Management Russia and North Europe Vice President. In 1999,2012 he returned to the HQ Operations Department, first as Senior Vice President Petroleum Engineering, Production and Maintenance and then as Senior Vice President Drilling and Completion and Deputy Operations. In October 2015 he was appointed District General ManagerReservoir & Development Projects Executive Vice President. He graduated with Honors in Geology from the University of Nigerian Agip Oil Co (NAOC),Milan and earned the MEDEA Master in 2000, became Vice ChairmanEnergy and Managing DirectorEnvironmental Management and Economics from “Scuola Mattei”. He is the author of the Eni companies in Nigeria NAOC, NAE (Nigerian Agip Exploration)several papers on reservoirs and AENR (Agip Energy). In 2002, he became regional Vice President for Australasia, Russia, Azerbaijan and then, in 2005, a Member of the Board of Directors and Managing Director of Eni Algeria. From 2006drilling presented at international conferences. He was Chief Development, Operations & Technology Officer from 2018 to 2009, he was regional Senior Vice President for North Africa and the Middle East (Algeria, Tunisia, Egypt, Libya, Mali, Morocco, Iran, Iraq and Saudi Arabia) for Eni’s Exploration & Production Division. In 2009, he2019. He was appointed Executive Vice President Operations for the Exploration & Production Division. In December 2012, he was appointed Executive Vice President for Central Asia, the Far East and the Pacific Area. Since July 2014, he has been a Board Member of Eni Foundation. SinceChief Upstream Officer on July 1, 2014, he has been Upstream Officer.2019.
Marco Bolliniwas born in Milan in 1966. He graduated with a degree in law from the University of Milan and he is registered to practice law on the special list of the Ordine degli Avvocati (the Italian bar association)Bar Association) of Milan. After graduating, he worked as a lawyer for a few years in a law firm in Milan. He joined Eni in 1997 in the Legal Department of Agip S.p.A.,SpA, mainly following international legal projects until 2001 when he took on the responsibility of International Legal Assistance of Exploration and Production Division. In 2005 he was appointed Legal Director of the Gas &Power Division, further diversifying his business knowledge. In 2007, he is back in the Exploration & Production Division as Legal
Director. In 2008, following the centralization of the Eni’s legal function into one Legal Department, he took on responsibility for the legal assistance to the company’s activities outside Europe. In 2013 he was appointed Executive Vice President International Business Legal Area and, in 2015, he became Executive Vice President International and Finance Legal Affairs of Eni, with a strong exposure to international matters,
with a particular focus on the Upstream business and management of partnerships and M&A transactions. Since 2016, he has beenHe was a Board Member of Eni Foundation. HeFrom 2016 to 2018 he was appointed Senior Executive Vice President Legal Affairs of Eni. He was nominated Senior Executive Vice President Commercial Negotiations on October 17, 2016.January 1, 2019. Stefano Speroni was born in Milano in 1962. Stefano Speroni has accumulated vast experience in over 30 years of professional activity in the field of corporate affairs, mergers and acquisitions, private equity operations and capital markets. He has given professional support to Italian and International listed companies (in a wide range of sectors including aerospace and defence, oil & gas, telecommunications, transport and infrastructure) in strategic corporate affairs, in share trading, joint ventures and commercial agreements. From January 2016 to December 2018, he was a Managing Partner for Corporate M&A in Dentons’ Italian practice. In 2012, he was one of the founders of the Grimaldi Legal Studio, after having previously been managing partner of Dewey Ballantine’s Rome practice which involved managing its Italian activities for around 10 years. He was also a partner in Studio Gianni, Origoni, Grippo Capelli & Partners (2001 – 2003), in the Simmons and Simmons Italian practice (1991 – 2001), and manager of the European Corporate Department and member of the World-wide Remuneration Committee. He is a member of the scientific committee and contributor to SDA Bocconi’s Private Equity Laboratory and was awarded “Best Lawyer of the Year” 2018 by the Best Lawyers international directory. He graduated in Law at Università degli Studi in Milan and is a registered member of the Italian Bar Association in Milan. Since January 1, 2019, he has been Legal Affairs Senior Executive Vice President. Marco Petracchini was born in Rome in 1964. He graduated Cum Laude with a degree in economics from La Sapienza University in Rome in 1989. After graduation, he was hired by Esso Italiana where he held various positions in the IT, Finance and Auditing sectors. He joined Eni in 1999 in the Internal Audit Department, gradually taking on positions of increasing responsibilities: Head of Downstream Audit activities and Head of Support Process Audit activities (in particular IT and Fraud Audit). He is also a Membermember of the Watch Structure of Eni SpA and Secretary of the Control and Risk Committee of Eni SpA. He holds international qualifications as well, in detail: Certified Internal Auditor (CIA), Certified Fraud Examiner (CFE), Certified Risk Management Assurance (CRMA). He is currently a Board Member of AiiA (Italian Internal Auditors Association). He is Eni’s Senior Executive Vice President Internal Audit Department.Audit. Roberto Ulissi was born in Rome in 1962. He’sHe is a lawyer. After a number of years spent as a lawyer at the Bank of Italy, in 1998 he was appointed General Manager at the Ministry of the Economy and Finance head of the Banking and Financial System and Legal Affairs Department. He has beenwas a Board member of Telecom Italia (and Chairman of the Audit Committee), Ferrovie dello Stato, Alitalia, Fincantieri and a government representative on the Governing Council of the Bank of Italy. He is a board member and Vice Chairman of Banor SIM. He haswas also been a member of numerous Italian and European committees representing the Ministry of the Economy including, at a national level, the Commission for the Reform of Corporate Law (Commission “Vietti”) and, at EU level, the Financial Services Policy Group, the Banking Advisory Committee, the European Banking Committee, the European Securities Committee, and the Financial Services Committee. He was also special professor of banking law at the University of Cassino. He is Grande Ufficiale della Repubblica Italiana. Since 2006, he has been Senior Executive Vice President Corporate Affairs and Governance and a Board Member of Eni International BV. He is currently Board Secretary of Eni and, since 2014, Corporate Governance Counsel.Counsel and Company Secretary. Since May 2018, he has been Coordinator of the Corporate Governance Forum of Company Secretaries. Marco Bardazzi was born in Prato in 1967. AHe is a professional journalist by trade, he workedworking in the media businessworld for 28 years before joining Eni in 2015. He has achieved angained extensive experience inon foreign policy and digital communications, particularly related to Europeanin Europe and American realities (he lived and worked in the United States for nine years).America. Between 2009 and 2015 he has beenwas Managing Editor and Digital Editor at “La Stampa”, a leading European newspaper based in Turin, Italy.. He has beenwas a key member of the “La Stampa” team that has worked on itsthe transformation fromof a traditional newspaper founded in 1867 to an integrated digital news organization, thus creating an innovative “concentric circle”circles” multiplatform newsroom. He has also been a co-founderwas one of the co-founders of “Europa” a partnership between La Stampa, Le Monde, El País, The Guardian, Gazeta Wyborcza and Suddeutsche Zeitung. Before joining “La Stampa”, he was U.S. Correspondentcorrespondent for the Italian news agency ANSA between 2000 and 2009, covering every aspect of American life for the Italian media. Among other things, he has covered the 2000 Bush-Gore electoral race for the White House;House in 2000, the first international Al Qaeda trial in Manhattan;Manhattan, the September 11 2001 attack on America;America, the warwars in Afghanistan; the war in Iraq;Afghanistan, and Iraq and the 2004 and 2008 presidential campaigns; hecampaigns. He has visited and reported on the Guantanamo detention camp at the U.S. Navy Guantanamo Bay base Cuba; he hasin Cuba. He won the Saint-Vincent Award for Journalism for a series of reports on the death penalty in the USA. He covered the 2008 financial crisis, and he hasreported extensively reported on the American digital, energy and manufacturing businesses. He teaches a class on “Journalism innovation” in the Master on Journalism program at ALMED-Università Cattolica del Sacro Cuore, Milan. automobile industries.
He holds an Associate of Arts degree in History from American Public University. His latest book is “L’Ultima Notizia” (with Massimo Gaggi, Rizzoli 2010), an essay on digital transformation in the media business. He is an external lecturer in the Masters in Journalism in ALMED-Università Cattolica del Sacro Cuore, Milan. He is a Visiting Fellow at the University of Oxford. In 2017 he was appointed as a Director of Agi SpA and Eni Gas e Luce. Since February 16, 2015, he has been External Communication Department Executive Vice President. Luca Cosentino was born in Venice on August 1,in 1961. He graduated cum laude with a degree in geology in 1985 from the University of Padua and joined Eni in 1986. He spent the first years of his professional life in the Reservoir Department, within the reservoir modeling group. Between 1992 and 1996, he worked in different operational positions in Italy and abroad in the reservoir sector. From 1996 to 2003, he worked as Project Manager with IFP (Institut Français du Petrol, France), in Venezuela and in the
Persian Gulf. In this period, he also taught at the IFP School and published several technical papers, including a book on Integrated Reservoir Studies. Upon his return to Eni in 2003, he was appointed Head of the Reservoir Department and, in 2004, Head of the Reservoir Modeling Department. From 2005 to 2010, he was in Libya, initially as Operation and Asset Manager with Eni North Africa and then as Member of the Management Committee in the operating company Eni Oil, later Mellitah Oil & Gas. From 2010 to 2013, he has been Managing Director of Eni Congo. In 2013, he was appointed Senior Vice President Non Operated Business Performance and Stranded Resources Valorization. Since November 1, 2015, he has been Executive Vice President Energy Solutions Department.Solutions. Pasquale SalzanoLapo Pistelli was born in Pomigliano d’Arco (Naples)Florence in 1973. In 1996, he1964. Having graduated with Honors with a degreehonors in Law from the University “Federico II”1988 in Naples and in 2000 obtained a PhD in international law from the University of Siena. From 1996 to 1999, he collaborated with Prof. Benedetto Conforti at the Chair of International Law at the Political Science faculty “Cesare Alfieri” at the University of Naples andFlorence, he started working at a research center, while serving for two mandates in 2000, qualified as a Lawyer at the Naples Courtlocal administration of Appeals.Florence. He began his career as a diplomat in December 1999 and from January 2000 to July 2001, worked on legal and institutional issues regarding the European Union at the General Directorate for European Integrationwas member of the Italian Ministry of Foreign Affairs. In 2001, in the aftermathParliament from 1996 to 2015 (1996/2004 and 2008/2015), and also member of the Balkan conflict, Pasquale SalzanoEuropean Parliament (2004/2008). As an Italian MP, he was appointed Chief of Staffmember of the international OSCE MissionCommittees on Constitutional Affairs, European Affairs and on International Affairs. As a MEP in Belgrade and the following year was posted by the Italian Government to Pristina to establish and manage the Italian Liaison OfficeBrussels, he worked at the Special RepresentativeEconomic and Monetary Affairs and Foreign Affairs Committees. During this period, he has also been the President of the Secretary-General of the United Nations in Kosovo, which subsequently became the Italian Embassy. From 2005, he was in New York at the Permanent Mission of Italy to the United NationsEU-South Africa Delegation and after about two years, was posted to Rome to the Office of the Diplomatic Adviser to the Prime Minister where, in viewa member of the Italian Presidency ofDelegation to the G8, was appointed by the PrimeOSCE, where he conducted several monitoring missions in transitional democracies.
He served as Deputy Minister as Head of the Sherpa Office for the G8/G20. In 2009, he was selected by the OECD Secretary-General as Director of the Heiligendamm/L’Aquila Process in Paris. From January 2011, he was seconded by the Ministry of Foreign Affairs and International Cooperation of Italy from 2013 to 2015. He resigned from all his institutional and political roles in July 2015, when he entered Eni where he was appointedas Senior Vice President International Institutional Relationsfor Strategic Analysis for Business Development Support. He taught and lectured at the University of Florence, the Overseas Studies Program of Stanford University and many others international academic institutions. He regularly contributed to many European and American think tanks and research centers specialized in the Department of Institutional Relations and Communications and Vice President of Eni-USA’s Representative office. He isinternational relations. Among other things, he’s a Young Global Leadermember of the World Economic Forum, is a MemberCouncil of Chatham house, member of the Boardboard of the European Council on Foreign Relations (ECFR) Italy, the Scientific Committeeand of the Rome-Mediterranean Foundation and the National Assembly of UNICEF Italy. He is aIstituto Affari Internazionali (IAI), member of the Institute for International Affairs (IAI)WE – World of Energy editorial committee and of the EastWest scientific committee. He’s Vice Chairman of OME (Observatoire Mediterranéen de l’Energie) and member of the IRENA’s (International Renewable Energy Agency) Global Commission on the Geopolitics of Energy Transformation. As a journalist, he regularly publishes in various newspapers issues related to European and international affairs and on specialized magazines, such as Limes. He authored several publications: in his last book, Il nuovo sogno arabo – Dopo le rivoluzioni, Feltrinelli 2012, he analyses the origin and challenges of the ‘Arab Spring’ and its impact on the geo-political scenario in North Africa and the Institute for International Political Studies (ISPI). From July 1, 2014 to 2015 heMiddle East. He was Eni’s Senior Vice President Government Affairs. Since February 19, 2015, he has been Eni’sappointed Executive Vice President Governmentof International Affairs Department.on April 14, 2017. Luca Franceschiniwas born in Milan in 1966. He graduated withis a degreegraduate in lawLaw from the University of Milan and is registered to practice law on the special list of the Ordine degli Avvocati (the Italian bar association)Bar Association) in Rome.HeRome. He first joined in Eni in 1991 in the legal department of Agip S.p.A.,SpA, initially involved in disputes and providing legal assistance to the procurement area, before going on to delivering legal support for a range of national and international projects in the Exploration & Production sector. In 2000, in the context of the process for the liberalisation of the natural gas sector, he was involved in the spin-off of the gas storage business and the creation and launch of Sogit SpA, for which he became head of Legal and Corporate Affairs. He made his return to Eni SpaSpA in 2005 as head of Italian Legal Assistance in the Gas & Power division. Following the concentration of all legal functions in Eni’s central Legal Department, he was engaged in providing legal support in the regulatory and antirust areas, gradually extending his responsibilities and becoming, in 2009, head of Legal Assistance for the business and Antitrust issues in Italy, as well as council for legal assistance for the activities of the Refining & Marketing sector. He was also
a member of the boards of directors of both Italgas and Stogit. InFrom 2015 to 2016 he was appointed as Eni’s Executive Vice President for Legal and Regulatory Compliance. He was appointed as Executive Vice President of Integrated Compliance on September 12, 2016. He is also a member of the Watch Structure of Eni SpA. In 2017 he was awarded “Compliance Officer of the Year” by the Top Legal Corporate Counsel Awards and the Inhouse Community Awards. Jadran Trevisan was Born in Milan in 1961. He has a degree in philosophy and a Master’s in business administration from SOGEA, the management school of Confindustria Liguria. After a short period at Gabetti, in 1991 he joined the Fininvest Group, where he was involved in financial communications and was part of the project for the listing of Mediaset for which, in 1995, he became the Investor Relations Manager. In 2000 he joined Eni as head of Investor Relations, where, in addition to participating in a number of significant extraordinary operations (the listing of Snam Rete Gas, the de-listing of Italgas), he oversaw relations with institutional investors. In 2006 he was appointed head of Business Strategy at Eni’s E&P division, where he was involved in the acquisition of significant assets and companies operating in the upstream sector. In 2008 he was appointed CFO of the recently acquired subsidiary Distrigas, where, for
the following three years, he was engaged in consolidating and aligning the company’s business and financial processes with those of Eni and rationalising the company structure. In 2011 he was part of the project for the creation of Eni Trading & Shipping SpA, becoming its Senior Vice President for Operations & Control. From the end of 2012 until July 2015 he was Senior Vice President Credit and in August 2015 he was appointed Senior Vice President for Integrated Risk Management. Since September 12, 2016 he reports directly to the Chief Executive Officer in his role as Executive Vice President Integrated Risk Management. Since March 18, 2019, he is also responsible of identification, evaluation and monitoring Eni industrial and contractual risks processes. Compensation Board members’ emoluments are determined by the Shareholders’ Meeting, while the emoluments of the Chairman and CEO, in relation to the powers entrusted to them, are determined by the Board of Directors, which considers relevant proposals made by the Compensation Committee after consultation with the Board of Statutory Auditors.
Moreover, in accordance with the applicable Italian laws and regulations (Article 123-ter of Legislative Decree No. 58 of February 24, 1998 and Article 84-quater of Consob Decision No. 11971 of May 14, 1999, and subsequent modifications) and in line with the Corporate Governance Code recommendations for Italian listed companies, the Board of Directors approves and submits to the annual Shareholders’ Meeting advisory vote, the first section of the Remuneration Report which describes the Remuneration Policy Guidelines adopted for Directors and other Managers with strategic responsibilities5.
The main elements of the 2017 remuneration policy and of the compensation paid in 2016 to Directors, Statutory Auditors, CEO and General Manager and other Managers with strategic responsibilities, are described below. 2017 Remuneration Policy Guidelines
This chapter contains the Remuneration Guidelines for the new 2017-2020 term, approved by the Board of Directors on February 28, 2017 for the Directors who will be appointed at the Shareholders’ Meeting on April 13, 2017. The new Board of Directors will retain the prerogative to determine, specific remuneration for the exercise of delegated powers and for participating on Board Committees, based on a proposal by the Compensation Committee. The Shareholders’ Meeting will retain the prerogative to approve the Share-based Variable Incentive Plans.
Furthermore, the Remuneration Guidelines below for Directors in office until April 13, 2017 are also briefly outlined. These were already extensively discussed in the Remuneration Report 2016 and reflect the decisions made by the Board of Directors on May 28, 2014 for the 2014-2017 term.
Policies For Directors During The 2017-2020 Term Of Office
The main novelty of the Remuneration Policy in the new term of office is the comprehensive review of the variable incentive scheme for the Chief Executive Officer and General Manager and for all other Senior Managers in order to simplify the incentive scheme’s overall architecture (which will be broken down into two incentive plans instead of three) and further align performance objectives with shareholder expectations. More specifically, the new incentive scheme provides for the introduction of:
•
a Short-Term Monetary Plan with the deferral of a portion of the accrued bonus, which will start from the assignment of the 2017 objectives with the first payment in 2018, to replace the previous Annual Monetary Incentive and Deferred Monetary Incentive plans.
•
a Long-Term Performance Share Plan 2017-2019, with first attribution in 2017, to replace the previous Long-Term Monetary Incentive Plan (subject to approval by the Shareholders’ Meeting on April 13, 2017).
(5)
Those persons who have the power and responsibility, directly or indirectly, for planning, directing and controlling Eni fall under the definition of “Managers with strategic responsibilities”, pursuant to Consob regulations. Eni Managers with strategic responsibilities, other than Directors and Statutory Auditors, are those who sit on the Management Committee and, in any case, those who report directly to the Chief Executive Officer.
For the Chairman and the Non-Executive Directors, adjustments are proposed for the remuneration envisaged for delegated powers and for participating on Board Committees compared with median levels in the reference markets.
Market references and peer group
For the Chief Executive Officer and General Manager, the positioning of the Company’s remuneration is assessed by comparing similar roles only in the international Oil & Gas sector, with regard to upstream activities in particular, and in line with the company’s strategy to increase its focus on the business. More specifically, the comparator group has been expanded to include the main listed companies in the Oil & Gas sector, which are Eni competitors at the international level and possess comparable business characteristics (Anandarko, Apache, BP, Chevron, Conoco Phillips, ExxonMobil, Marathon Oil, Shell, Statoil and Total).
This panel also constitutes the Peer Group used for the relative comparison of Eni performance in the new Long-Term Performance Share Plan.
For the Chairman and the Non-Executive Directors, the positioning of remuneration is assessed by comparing similar roles in the Top Italy Panel, composed of the main companies listed on the FTSE MIB (Assicurazioni Generali, Atlantia, Enel, Intesa Sanpaolo, Leonardo-Finmeccanica, Luxottica, Mediaset, Mediobanca, Poste Italiane, Snam, Terna, TIM, Unicredit).
For Managers with strategic responsibilities, the positioning of remuneration is assessed by comparing roles with the same level of managerial responsibility and complexity in national and international panels of companies in the industrial sector.
General principle of clawback
Clawback mechanisms will be adopted, through a specific regulation proposed by the Compensation Committee and approved by the Board of Directors, allowing the variable remuneration components already paid and/or granted to be reclaimed, or those subject to deferral to be withheld, where their achievement was based on data that was subsequently proven to be manifestly misstated, or allowing the recoupment of all the incentives for the year (or years) in which subsequent checks confirm the fraudulent alteration of the results data used to obtain the right to incentives, and/or the commission of serious and deliberate violations of the law and/or regulations, the Code of Ethics or the Company rules, if relevant to the employment and trust relationship, without prejudice to any other action permitted by law and regulations to protect the interests of the Company. The regulation provides that the activation of recoupment claims (or revocation of incentives awarded but not yet paid) must take place, once the checks have been completed, within three years of payment (or award) in the case of error, and within five years in the case of fraud.
Chairman of the Board of Directors
Remuneration for the delegated powers
Remuneration will be defined in line with the decisions taken by the Shareholders’ Meeting on 13th April 2017 and with the median levels in the reference market, taking the delegated powers into account.
Payments due in the event of termination of office or employment
No specific severance payments are provided for the Chairman, nor do any agreements exist for indemnities in the case of early termination of office.
Non-executive directors
Remuneration for participation on Board Committees
The Policy Guidelines for Non-Executive and/or Independent Directors provide for the adjustment of the additional annual remuneration for participating on Board Committees in line with the median levels in the reference market, taking due account of commitment in terms of meetings and their duration. More specifically, for the 2017-2020 term, the following remuneration is proposed:
•
for the Control and Risk Committee, annual remuneration consists of €70,000 for the Chairman and €50,000 for the other members;
•
for the Compensation Committee and the Sustainability and Scenarios Committee, the annual remuneration consists of €50,000 for the Chairman and €35,000 for the other members;
•
for the Nomination Committee, the annual remuneration consists of €40,000 for the Chairman and €30,000 for the other members.
Payments due in the event of termination of office or employment
No specific severance payments are provided for the Non-Executive Directors, nor do any agreements exist for indemnities in the case of early termination of office.
Chief Executive Officer and General Manager
The Policy Guidelines for the Chief Executive Officer and General Manager take into account the specific delegated powers granted in accordance with the By-laws, the instructions contained in the chapter “Purpose and general principles of the Remuneration Policy” as well as the remuneration levels and best practices in the reference Oil & Gas panel.
Fixed remuneration
Fixed remuneration (FR) will be set by the new Board of Directors based on a proposal of the Compensation Committee in relation to the delegated powers and positions held, taking into account the median levels in the reference market. Fixed remuneration includes the remuneration for Directors established by the Shareholders’ Meeting on April 13, 2017, as well as any compensation that may be due for participating on the Board of Directors of subsidiaries or associated companies.
Variable incentive plans
Short-Term Monetary Plan with deferral
The new Short-Term Monetary Plan with deferral of a portion of the accrued bonus brings together the previous Annual Monetary Incentive and Deferred Monetary Incentive plans.
Compared with the previous Plans, the performance scales have been extended to include achievement of results that are above or far above the target levels.
In this Plan, a portion of the incentive is paid annually and a portion is deferred for a three-year period, as described below.
The Short-Term Monetary Plan with deferral is linked to the achievement of the 2017 objectives approved by the Board of Directors on February 28, 2017. These objectives keep the structure focused on the essential goals consistent with the guidelines outlined in the Strategic Plan and balanced against the interests of the various stakeholders, in terms of economic and financial results (25%), operating results and sustainability of the economic performance (25%), environmental sustainability and human capital (25%), efficiency and financial strength (25%). The value of each objective, at target performance level, is aligned with the budgeted value.
Each objective is measured in accordance with a performance scale of 70 to 150 points (target=100), in relation to the weight assigned to each target (below 70 points, the performance of each target is considered to be zero). For the purposes of the incentive award, the minimum overall performance is 85 points. This Plan provides for remuneration calculated with reference to a minimum (performance=85), target (performance=100) and maximum (performance=150) multiplier, equal respectively to 85%, 100% and 150% to be applied to the target incentive, as determined by results achieved by Eni over the previous year.
Total incentive (TI) is calculated using the following formula:
TI = FR x % ITarget x Multiplier
Where “ITarget” is the incentive percentage at target performance level, which is set at 150% of total fixed remuneration for the Chief Executive Officer.
The Plan conditions state that the total incentive is divided into 2 portions.
1)
a portion paid annually (IYear) equal to 65% of the total incentive.
Iannual = TI x 65%
The levels of the fraction of the incentive payable during the year, depending on the performance levels achieved, are shown in the table below.
| Annual performance | | | <85 | | | 85 | | | 100 | | | 150 | | | | | | | | | threshold | | | target | | | max | | | Annual incentive (% of Fixed Rem) | | | 0% | | | 83% | | | 98% | | | 146% | |
2)
a deferred portion equal to 35% of the total incentive, subject to further performance conditions during a three-year vesting period.
The deferred portion payable at the end of the vesting period is determined by multiplying the initial deferred portion by the payment multiplier. The latter is given by the average of the three annual multipliers, each determined during the three-year period in relation to the performance achieved, based on Eni’s annual objectives. The multiplier of the deferred portion depends on the performance achieved, with reference to a minimum (performance=85), target (performance=100) and maximum (performance=150) incentive level, equal respectively to 85%, 130% and 230% of total fixed remuneration.
The Deferred Incentive (DI) payable at the end of the three-year deferment period is calculated using the following formula:
DI = TI x 35% x Multiplier
The levels of the payable deferred portion, depending on the performance levels achieved throughout the three-year period, are shown in the table below.
| 3-year Average performance | | | <85 | | | 85 threshold | | | 100 target | | | 150 max | | | Deferred incentive (% of Fixed Rem) | | | 0% | | | 38% | | | 68% | | | 181% | |
Long-Term Performance Share Plan
The Chief Executive Officer participates in the Long-Term Performance Share Plan 2017-2019, which also applies to Senior Managers, deemed critical for the business, subject to approval by the Shareholders’ Meeting on April 13, 2017.
The Plan replaces the previous Long-Term Monetary Incentive Plan as a tool to incentivize and promote the loyalty of the most critical management positions for the company, ensuring achievement, in line with international best practices, of the following additional objectives:
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strengthening the culture of business risk management from the perspective of shareholders by adopting shares as an incentive;
•
setting a more challenging minimum incentive threshold, positioned at median level;
•
further aligning performance conditions with the long-term expectations of shareholders, using:
(i)
an assessment of the performance of the Company’s Total Shareholder Return over a three-year period compared with that of the Reference Stock Market Index, compared with the same performance of the main international competitors (Peer Group);
(ii)
further incentivize the capacity to develop industrial assets, measured using the increase in the Net Present Value of hydrocarbon reserves in the medium-long term (in accordance with the assessment method defined by the SEC), measured in relative terms compared with the designated peer group.
The Plan provides for three annual awards starting from 2017, each with a three-year vesting period.
The Plan is subject to performance conditions during the three-year vesting period, in accordance with the following parameters and related weightings:
1.
The difference between the TSR of Eni Shares and the TSR of the FTSE MIB index of Borsa Italiana, corrected by the Eni Correlation Coefficient, compared with the equivalent adjusted TSR measure for each company in the Peer Group, as shown in the following (50% weight):
TSRA - (TSRI x ρ A,I)
Where:
TSRA: TSR of Eni or one of the companies in the Peer Group
TSRI: TSR of the Reference Stock Market Index of the company for which TSRA was calculated
ρ A,I: Correlation Coefficient
2.
Net Present Value of proven reserves (NPV) vs the Peer Group, measured in terms of the annual percentage change, calculating the average annual performance in the three-year period (50% weight).
The reference Peer Group is described in the “Market references and Peer Group” section. (Anadarko, Apache, BP, Chevron, Conoco Phillips, ExxonMobil, Marathon Oil, Shell, Statoil and Total).
For the Chief Executive Officer and General Manager, the Plan conditions provide for the annual award of shares for a value equivalent to 150% (Itarget) of total fixed remuneration, using the following formula.
| No.of Attributed Shares = | | | FR x % Itarget
| | | PriceAttr
| |
Where the price of the award (PriceAttr) is calculated as the average of daily official prices (source Bloomberg) recorded in the 4 months before the date of the Board of Directors meeting that annually approves the plan rules and the award to the Chief Executive Officer and General Manager.
The granting of shares at the end of the three-year vesting period is determined using a final multiplier to be applied to awarded shares (calculated as the weighted average of the multipliers of each parameter) determined over the vesting period in relation to the position reached in the peer group.
Each multiplier may be between 0 and 180%, with a threshold set at the median level, in accordance with the scale shown below.
| Performance Scale - Multiplier | | | Ranking | | | | | | | | | | | | | | | | | | | | | | | 1st | | | 2nd | | | 3rd | | | 4th | | | 5th | | | | 6th | | | | 7th | | | 8th | | | 9th | | | 10th | | | 11° | | | Multiplier | | | | | | | | | | | | | | | | | | | | | | | 180% | | | 160% | | | 140% | | | 120% | | | 100% | | | | 80% | | | | 0% | | | 0% | | | 0% | | | 0% | | | 0% | | | | | | | | | | | | | | | | | | | Median positioning | | | | | | | |
Grantable shares are calculated using the following formula:
No.of Granted Shares = No.of Attributed Shares x Multiplier
The value levels of the Shares granted at the end of the vesting period, net of changes in the share price over the same period, are given below.
| Weighted average 3-year performance | | | <26.6 | | | 26.6 threshold (*) | | | 100 target | | | 180 max | | | Value of Shares (% of Fixed Rem) | | | 0% | | | 40% | | | 150% | | | 270% | |
(*)
Achieved for example if the minimum level (6th place) is reached for the indicator of NPV of proven reserves, in at least two years of the three year vesting period.
For executives in services, 50% of the shares granted at the end of the vesting period are locked up for a period of 1 year after the grant date.
As the Plan is submitted to the Shareholders’ Meeting for approval, it is also described in detail in the information document made available to the public on the Company website.
For both the deferred portion of the short-term incentive and the long-term share incentive, the clauses provided for all Managers in the respective Rules will apply in cases of termination of employment before the end of their term of employment. If their contract is not renewed, the natural expiry of the related vesting period is retained, in accordance with the performance conditions defined by each Plan.
Benefits
For the Chief Executive Officer and General Manager, the Policy Guidelines provide for insurance coverage for the risk of death or permanent disability and, as per provisions contained in the national collective bargaining agreement and the supplementary corporate agreements for Eni senior managers, enrolment in the supplementary pension plan (“FOPDIRE”) as well as in the supplementary health plan (FISDE ), together with a company car for business and personal use.
Pay Mix
The remuneration package for the Chief Executive Officer and General Manager includes a fixed component, a short-term variable component and a long-term variable component, composed of the short-term incentive deferral and the long-term share incentive valued using the international methodologies adopted for remuneration benchmarks.
The pay mix, calculated by considering fixed remuneration as the base, is significantly focused on the variable components, with a dominant weighting attributed to the long-term component.
Payments due in the event of termination of office or employment
For the Chief Executive Officer and General Manager, in line with reference practice and with the provisions of the European Commission Recommendation No. 385 of April 30, 2009, as well as to protect the Company from potential competitive risks, the Policy provides for following payments:
•
An indemnity supplementing the severance award payable upon termination of the employment relationship, due to non-renewal or early termination of the 2017-2020 term of office, including in the event of resignation due to a substantive reduction of delegated powers. Compensation for the CEO position will be defined in line with European Recommendations. For any employment relationship, the provisions set out for Managers with Strategic Responsibilities shall apply. Also with reference to criteria 6.C.1.g of the Italian Corporate Governance Code, thisconcerning compensation is not due in the event of dismissal for “just cause” under Art. 2119 of the Italian Civil Code, or in the event of resignation as Chief Executive Officer prior to the expiry of the term in office, unless triggered by either the above-noted reduction of delegated powers, or in the event of death as governed by Art. 2122 of the Italian Civil Code;
•
Any non-competition agreement to protect the Company’s interests, with specific compensation as a proportion of annual remuneration, as well as in relation to the rules of application, extent and duration of the commitments.
Policies for Directors during the 2014-2017 term of office
The Policy Guidelines for the term of office that expires at the Shareholders’ Meeting on 13th April 2017 are summarized below.
Chairman of the Board of Directors
Remuneration for delegated powers
A fixed remuneration for the delegated powers of €148,000 is provided for the Chairman of the Board of Directors, in addition to remuneration for the position determined by the Shareholders’ Meeting on May 8, 2014, amounting to €90,000, in compliance with the maximum of €238,000 defined by the same Shareholders’ Meeting. These Guidelines do not provide for variable remuneration.
In 2017, these remuneration components will be paid pro-rata with respect to the period in office that ends with the Shareholders’Meeting called to approve the Financial Statements as at December 31, 2016.
Payments due in the event of termination of office or employment
No specific severance payments are envisaged for the Chairman, nor do any agreements exist for indemnities in the case of early termination of office.
Benefits
The Chairman is granted insurance coverage for the risk of death or permanent disability.
Non-executive Directors
Remuneration for participation on Board Committees
Non-executive and/or Independent Directors receive an additional annual remuneration6 for participating on Board Committees, as follows:
•
for the Control and Risk Committee, the remuneration amounts to €60,000 for the Chairman and €40,000 for the other members;
•
for the Compensation Committee, the Sustainability and Scenarios Committee and the Nomination Committee the remunerations amount to €30,000 for the Chairman and €20,000 for the other members.
In 2017, this remuneration will be paid pro-rata with respect to the period in office that ends with the Shareholders’ Meeting of April 13, 2017.
Payments due in the event of termination of office or employment
No specific severance payments are provided for the Non-Executive Directors nor do any agreements exist that provide for indemnities in the case of early termination of office.
Chief Executive Officer and General Manager
For the Chief Executive Officer and General Manager, the Policy Guidelines reflect the resolutions passed by the Board of Directors on May 28, 2014, taking into account the specific delegated powers granted in accordance with the Articles of Association, the instructions contained in the chapter “Principles and general purposes of Eni Remuneration Policy”, as well as the 25% reduction of the
(6)
This remuneration supplements the one established by the Shareholders’ Meeting of May 8, 2014, for the remuneration of Non-executive Directors, amounting to €80,000 annual gross.
maximum payable overall remuneration of the previous mandate, in accordance with the Shareholders’ resolution of May 8, 2014. The remuneration envisaged by the Board in relation to the delegated powers includes both the compensation for Directors determined by the Shareholders’ Meeting on May 8, 2014, as well as any compensation that may be due for participating on the Board of Directors of Eni’s subsidiaries or associated companies.
Fixed remuneration
For the Chief Executive Officer and General Manager total fixed remuneration is set at a gross annual amount equal to €1,350,000, of which €550,000 for the position of Chief Executive Officer and €800,000 for the position of General Manager.
The remuneration envisaged by the Board in relation to the powers delegated includes both the remuneration for Directors determined by the Shareholders’ Meeting on May 8, 2011, as well as any compensation that may be due for participating on the boards of directors of Eni’s subsidiaries or associated companies.
In 2017, these remuneration components will be paid pro-rata with respect to the period in office that ends with the Shareholders’ Meeting of April 13, 2017.
In his capacity as Eni Senior Manager, the General Manager is also entitled to receive an allowance for travel, in Italy and abroad, in line with the applicable provisions provided by the relevant national collective labor agreement for senior managers and complementary Company level agreements.
Annual variable incentives
The annual variable incentive linked to achieving the targets set for 2016 will be paid in 2017.
Deferred Monetary Incentive Plan
In 2017, the Chief Executive Officer and General Manager participates in the last award of the Deferred Monetary Incentive (DMI) Plan 2015-2017, also envisaged for all the Company’s senior managers, associated with Company performance measured in terms of Earnings Before Taxes (EBT).
Long-Term Monetary Incentive Plan
The Long-Term Monetary Incentive Plan 2014-2016 ended in 2016 with the last award. The new Long-Term Performance Share Plan 2017-2019 will be implemented from 2017. This Plan has already been described in the section “Policies for the 2017-2020 term of office” and in the information document made available to the public on the Company website.
Benefits
For the Chief Executive Officer and General Manager the Policy Guidelines provide for insurance and healthcare coverage defined by the national collective bargaining agreement and the supplementary corporate agreements for Eni senior managers, as well as a company car for business and personal use.
Payments due in the event of termination of office or employment
For the Chief Executive Officer and General Manager, in line with sector practices and with the provisions of the European Commission Recommendation No. 385 of April 30, 2009, as well as to protect the Company from potential competitive risks, the Policy provides for following payments:
•
an indemnity supplementing the severance award, with mutual exemption from notice, is payable upon termination of the employment relationship, due to non-renewal or early termination of the 2014-2017 term of office, including in the event of resignations caused by a substantial reduction of delegated powers. This indemnity is equal to two years of total fixed remuneration (€1,350,000), for a total gross amount equal to €2,700,000. It should also be noticed that there is an ongoing analysis of the effective enforceability of the agreed framework, partly with reference to legislative changes following the conclusion of the contract with the Chief Executive Officer and General Manager. Also with reference to the recommendation 6.C.1g) of the Italian
Corporate Governance Code, note that, in relation to the applicable contractual provisions, this compensation is not due in case of dismissal for “just cause” under Article 2119 of the Italian Civil Code or in cases of resignations as Chief Executive Officer before the expiry of the term in office , unless triggered by a reduction of delegated powers, or in the event of death governed by Article 2122 of the Italian Civil Code;
•
non-competition agreement to protect the Company’s interests that can be activated at the sole discretion of the Board of Directors through the exercise of an option right, the validity of which applies only as of the one set of a second term (if appointed), in exchange for a total option fee of €500,000 gross to be paid in three annual installments. If the option is exercised by the Board and the agreement is implemented, a non-compete award will be paid subject to a commitment by the Chief Executive Officer and General Manager not to undertake, for the twelve months following the expiry of the term, any activities of Exploration & Production activities potentially in competition with Eni in key markets in Europe, America, Asia and Africa. This amount will be set by the Board of Directors as the sum of two components: (i) a fixed component of €1,500,000; and (ii) a linearly determined variable component based on the average annual performance of the previous three years (equal to 0 for performance below or equal to the target and to €750,000 for maximum performance), and will be paid at the expiry of the term of the agreement. The variable component is calculated by taking into consideration the annual performance related to the annual Variable Incentive Plan. Any violation of the non-competition agreement will result in the non-payment of the consideration (or its restitution, where the violation is identified by Eni after the payment), and the obligation to pay damages set by mutual agreement in an amount equal to twice the amount of the non-competition agreement, without prejudice to Eni’s right to seek fulfillment in specific form.
2017 policies for MANAGERS WITH STRATEGIC RESPONSIBILITIES
For Managers with Strategic Responsibilities, the Guidelines provide for remuneration plans that are strictly in line with those of the Chief Executive Officer and General Manager, to better guide and align managerial action with the objectives set out in the Company’s Strategic Plan, and with the provisions and protections laid down by the national collective bargaining agreement for senior managers.
In the new 2017-2020 term of office, starting from April 13, 2017, the new Long-Term Share Incentive Plan and Short-Term Variable Incentive Plan with Deferral – intended for the Chief Executive Officer who will be appointed by the Shareholders’ Meeting of April 13, 2017 - will also apply to Managers with Strategic Responsibilities. The Plans applying to the previous term will be implemented until April 13, 2017.
Market references
For Managers with Strategic Responsibilities, the positioning of remuneration is assessed by comparing roles with the same level of managerial responsibility and complexity in national and international panels of companies in the industrial sector.
Fixed remuneration
Fixed remuneration is based on the role and responsibilities assigned, taking into consideration a graduated and a generally median to below-median positioning versus national and international executive markets for comparable roles. It may be updated periodically during the annual salary review for all managers.
Given current market comparators and trends, the 2017 Guidelines provide for a selective approach to salary reviews, while maintaining appropriate levels to ensure competitiveness and motivation.
More specifically, the proposed actions will include measures to adjust fixed/one-off remuneration for those in positions that have seen a significant increase in responsibility or scope, and to reflect needs for retention and excellent performance.
In addition, as Eni officers, Managers with Strategic Responsibilities are entitled to receive the allowances due for travel in Italy and abroad, in line with applicable provisions of the relevant national collective bargaining agreement for senior managers and supplementary Company agreements.
Variable incentive plans
Annual variable incentives
Starting with the assignment of the 2017 objectives and with the first payment in 2018, the annual variable Incentive Plan will be replaced by the new Short-Term Monetary Plan with deferral, already described for the Chief Executive Officer and General Manager.
The targets set for Managers with Strategic Responsibilities are consistent with those assigned to the Chief Executive Officer and General Manager, on the basis of the same perspective of stakeholder interests, as well as with the relevant individual targets, consistent with the responsibilities of the role played and the provisions of the Company’s Strategic Plan. For Managers with Strategic Responsibilities the target incentive levels for the new Short-Term Monetary Plan differ depending on the role’s level of responsibility and complexity and are equal to the sum of those set for the previous Annual Variable Incentive Plan and Deferred Monetary Incentive Plan (up to 100% of fixed remuneration).
The last award for the previous Annual Variable Incentive Plan will be paid in 2017, determined with reference to the performance goals set for Eni, the business area and individual performance in 2016.
Deferred Monetary Incentive Plan
Managers with Strategic Responsibilities participate in the last attribution of the Deferred Monetary Incentive Plan (DMI) 2015-2017, approved by the Board of Directors on March 12, 2015.
Long-term variable incentive plan
Managers with Strategic Responsibilities participate in the Long-Term Performance Share Plan (LTI) 2017-2019, approved by the Board of Directors on February 28, 2017 and submitted for approval by the Shareholders’ Meeting on April 13, 2017.
The Plan is directed at managers who are critical for the business and envisages three annual awards, starting in 2017, with the same performance conditions and characteristics as those described above for the Chief Executive Officer and General Manager.
For Managers with Strategic Responsibilities, the value of the shares to be awarded each year differs depending upon the level of their role and is limited, as in the previous long-term monetary incentive plan, to a maximum of 75% of fixed remuneration.
Benefits
For Managers with Strategic Responsibilities, in line with the policy implemented in 2016 as well as the provisions of the national collective bargaining agreement and supplementary Company-level agreements for Eni managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (FOPDIRE) and health plan (FISDE), as well as insurance coverage for the risk of death or disability, together with a company car for business and personal use, and the possible assignment of housing based on operational and mobility requirements.
Pay Mix
The average target pay mix of the remuneration package for Managers with Strategic Responsibilities, with the application of both new incentive plans (short-term monetary plan with deferral and long-term performance share plan), calculated using the same valuation methods used for the Chief Executive officer and General Manager, highlights the balance between the fixed and variable components and, as regards the latter, the greater weighting of medium-long term variable incentives, in line with market best practice.
Payments due in the event of consensual termination of employment
Managers with Strategic Responsibilities, as well as Eni senior managers, are entitled to the severance benefits for employment termination established by law and applicable national collective bargaining agreement, together with any termination indemnities agreed on an individual basis, in accordance with the criteria established by Eni for cases of early termination, within the limits of the protection envisaged by the applicable national collective bargaining agreement, and consistent with application criterion 6.C.1 lett.g) of the Italian Corporate Governance Code. These criteria take into account the position held, the retirement age and actual age of the manager at the time employment is terminated and the annual remuneration received. For cases of termination that present high competitive risks relating to the criticality of the position held by the Manager, agreements containing non-competition clauses may also be entered into with payments defined in relation to the remuneration received and the scope, duration and effectiveness of the agreement.
COMPENSATION AND OTHER INFORMATION
Implementation of the 2016 remuneration policies
The following is a description of the remuneration decisions taken in 2016 for the Chairman of the Board of Directors, Non-executive Directors, Chief Executive Officer and General Manager, and other Managers with strategic responsibilities, in relation to their time in office.
The implementation of the 2016 Remuneration Policy, as verified by the Compensation Committee at the regular assessment required by the Corporate Governance Code, was found to be consistent with the 2016 Remuneration Policy, approved by the Board of Directors on March 17, 2016. This takes into account the resolutions passed by the Board of Directors on May 9 and May 28, 2014 on the remuneration of Non-executive Directors appointed Board Committees and on the definition of the remuneration of Directors with delegated powers, in accordance with the resolutions passed at the Shareholders’ Meeting in accordance with Law No. 98/2013.
Chairman of the Board of Directors - Emma Marcegaglia
Fixed remuneration
The Chairman was paid the fixed remuneration approved for the office by the Shareholders’ Meeting of May 8, 2014 of €90,000 gross and the remuneration approved by the Board of Directors Meeting of May 28, 2014, in relation to the exercise of delegated powers, amounting to €148,000 gross.
Benefits
The Chairman was granted insurance coverage against the risk of death and permanent disability, in accordance with the resolutions of the Board of Directors Meeting of May 28, 2014.
Non-executive Directors
The Directors were paid fixed remuneration approved by the Shareholders’ Meeting of May 8, 2014 of €80,000 gross. The additional remunerations payable for participation on the Board Committees, as resolved by the Board of Directors Meeting of March 12, 2015, were also paid.
Chief Executive Officer and General Manager - Claudio Descalzi
Claudio Descalzi has held the office of Chief Executive Officer and General Manager since May 9, 2014, and before then he held the office of Chief Operating Officer (COO) of the E&P Division. Therefore, during 2016, Claudio Descalzi received the fixed remuneration and the annual variable incentive related to his current role of Chief Executive Officer and General Manager and the long term variable incentives accrued during his previous role, as detailed below.
Fixed remuneration
The Chief Executive Officer and General Manager was paid the fixed remunerations approved by the Board of Directors Meeting of May 28, 2014, which also include the remunerations approved by the Shareholders’ Meeting for all the Directors, equal to a total gross annual amount of €1,350,000.
Annual variable incentives
In line with the Remuneration Policy 2016, the Chief Executive Officer and General Manager was paid a gross annual variable incentive of €1,755,000 associated with the performance achieved during 2015 (130 points).
Deferred Monetary Incentive Plan
For the Chief Executive Officer and General Manager, the Board of Directors as its meeting of March 17, 2016, as proposed by the Compensation Committee and in accordance with the Remuneration Policy 2016, approved the assignment of the deferred monetary incentive of €864,000 gross, calculated based on the 2015 EBT results approved by the Board of Directors. Furthermore, in 2016 the Deferred Monetary Incentive assigned in 2013 to Claudio Descalzi, as COO of the Exploration & Production Division, vested, resulting in a gross amount paid equaled €659,000.
Long-Term Monetary Incentive Plan
For the Chief Executive Officer and General Manager, the Board of Directors at its meeting of 15th September 2016, as proposed by the Compensation Committee and in accordance with the Remuneration Policy 2016, approved the grant of the 2016 long-term monetary incentive award of 1,350,000 euros gross.
Furthermore, with regard to the Long-Term Monetary Incentive award granted in 2013 to Claudio Descalzi, as COO of the E&P Division, the performance achieved in the reference three-year period did not satisfy the conditions for payment of the incentive.
Benefits
The Chief Executive Officer and General Manager, in line with the resolution of the Board of Directors Meeting on May 28, 2014, was granted insurance coverage for death or permanent disability, and in compliance with the provisions of the national collective bargaining agreement and the supplementary corporate agreements for Eni senior managers, enrolment in the supplementary pension plan (FOPDIRE) as well as supplementary health plan (FISDE), together with a company car for business and personal use.
In 2016 Claudio Descalzi, for his role as Chief Executive Officer and General Manager, received a total of €3,120,000 and, for his previous role as COO of the E&P Division (held until May 8, 2014), €659,000 for the long term variable incentives accrued. Consequently, the total amount received was €3,779,000.
Managers with strategic responsibilities
Fixed remuneration
For the current Managers with Strategic Responsibilities, within the context of the annual salary review process envisaged for all managers, in 2016 selective adjustments were made to fixed remuneration, in cases of promotion to more senior levels, or in line with necessary market-driven adjustments . The total gross value of the fixed remuneration paid in 2016 to Managers with Strategic Responsibilities is shown in the section “Compensation paid in 2016”, under the item “Fixed compensation”.
Annual variable incentive
In March 2016, annual variable incentives were paid to Managers with Strategic Responsibilities in accordance with the Remuneration Policy and based on performance achieved in 2015.
In particular, the incentive is linked to performance against a range of metrics related to business and sustainability objectives (safety, environmental protection, stakeholder relations), as well as relevant individual, consistent with the provisions of the 2015 Eni Performance Plan.
Deferred Monetary Incentive Plan
Managers with Strategic Responsibilities were granted 2016 deferred monetary incentive awards, in accordance with the Remuneration Policy and on the basis of the 2015 EBT results approved by the Board of Directors on March 17, 2016, as proposed by the Compensation Committee. In 2016, the Deferred Monetary Incentive award granted in 2013 also vested.
Long-Term Monetary Incentive Plan
Managers with Strategic Responsibilities were granted their 2016 long-term monetary incentive award, determined in accordance with the Remuneration Policy. With regards to the Long-Term Monetary Incentive awards granted in 2013, the performance achieved in the three-year reference period did not satisfy the conditions for their payment.
Severance indemnity for end-of-office or termination of employment
During 2016, Managers with Strategic Responsibilities who accepted enhanced voluntary termination offers were paid, in addition to amounts due under legal and contractual obligations, additional amounts defined in line with company policy on early retirement incentives.
Benefits
For Managers with Strategic Responsibilities, in line with provisions in the national collective bargaining agreement and the supplementary corporate agreements for Eni managers, the Policy Guidelines provide for enrolment in the supplementary pension plan (“FOPDIRE”) as well as in the supplementary health plan (FISDE), insurance coverage for the risk of death or disability, together with a company car for business and personal use.
COMPENSATION PAID IN 2016
The table below lists the individual remunerations to the Directors, Statutory Auditors, Chief Executive Officer and General Managers and, in aggregate form, to other Managers with strategic responsibilities. The remunerations received from subsidiaries and/or affiliates, except those waived or paid to the Company, are shown separately. All parties who filled these roles during the period are included, even if they only held office for a fraction of the year.
In particular:
•
based on the criteria of competence, the column “Fixed remuneration” reports the fixed remuneration and fixed salary from employment due for the year, gross of the social security contribution and tax expenses to be paid by the employee; it excludes attendance fees, as these are not provided for. Details of the compensation are provided in the notes, and any indemnities or payments with reference to the employment relationship are indicated separately;
•
based on the criteria of competence, the “Remuneration for participation in the Committees” column reports the compensation due to the Directors for participation in the Committees established by the Board. In the notes, compensation for each Committee on which each Director participates is indicated separately;
•
the column “Variable non-equity remuneration” under the item “Bonuses and other incentives” shows the incentives paid during the year due to rights vested following the assessment and approval of the related performance results by the relevant corporate bodies;
•
based on the criteria of competence and taxability, the “Benefits in kind” column reports the value of the fringe benefits awarded;
•
based on the criteria of competence, the “Other remuneration” column reports any other remuneration deriving from other services provided;
•
the “Total” column details the sum of the amounts of all the previous items;
•
the “Fair value of equity remuneration” column reports the relevant fair value for the year related to the existing stock option Plans, estimatedreport prepared in accordance with international accountingto Italian listing standards, which assignis incorporated herein by reference.
See the related cost in the vesting period; and
•
the “Severance indemnity for end of office or termination of employment” column reports the indemnities accrued, even if not yet paid, for the terminations which occurred during the course of the financial year in question, or in relation to the end of the mandate and/or employment.
Remuneration paid to Directors, Statutory Auditors, Chief Executive officer and General Managers and other Managers with strategic responsibilities
(€ thousand)
| | | Note | | | Position | | | Period for which the position was held | | | Expiration of office (*) | | | Fixed remuneration | | | Remuneration for participation in the Committees | | | Variable non-equity remuneration | | | Benefits in kind | | | Other remuneration | | | Total | | | Fair value of equity compensation | | | Severance indemnity for end of office or termination of employment | | | | | | | | | First name and Surname | | | Bonuses and other incentives | | | Profit sharing | | | | | | | | | Board of Directors | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Emma Marcegaglia | | | (1) | | | Chairman | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 238 (a) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 238 | | | | | | | | | | | | Claudio Descalzi | | | (2) | | | Chief Executive Officer and General Manager | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 1,350 (a) | | | | | | | | | | | | 1,755 (b) | | | | | | | | | 15 | | | | | | | | | | | | 3,120 | | | | | | | | | | | | Andrea Gemma | | | (3) | | | Director | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 80 (a) | | | | | | 90 (b) | | | | | | | | | | | | | | | | | | | | | | | | | | | 170 | | | | | | | | | | | | Pietro Angelo Guindani | | | (4) | | | Director | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 80 (a) | | | | | | 50 (b) | | | | | | | | | | | | | | | | | | | | | | | | | | | 130 | | | | | | | | | | | | Karina Litvack | | | (5) | | | Director | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 80 (a) | | | | | | 63 (b) | | | | | | | | | | | | | | | | | | | | | | | | | | | 143 | | | | | | | | | | | | Alessandro Lorenzi | | | (6) | | | Director | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 80 (a) | | | | | | 80 (b) | | | | | | | | | | | | | | | | | | | | | | | | | | | 160 | | | | | | | | | | | | Diva Moriani | | | (7) | | | Director | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 80 (a) | | | | | | 51 (b) | | | | | | | | | | | | | | | | | | | | | | | | | | | 131 | | | | | | | | | | | | Fabrizio Pagani | | | (8) | | | Director | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 80 (a) | | | | | | 50 (b) | | | | | | | | | | | | | | | | | | | | | | | | | | | 130 | | | | | | | | | | | | Alessandro Profumo | | | (9) | | | Director | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 80 (a) | | | | | | 40 (b) | | | | | | | | | | | | | | | | | | | | | | | | | | | 120 | | | | | | | | | | | | | | | | | | | Board of Statutory Auditors | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Matteo Caratozzolo | | | (10) | | | Chairman | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 80 (a) | | | | | | | | | | | | | | | | | | | | | | | | | | | 97 (b) | | | | | | 177 | | | | | | | | | | | | Paola Camagni | | | (11) | | | Statutory auditor | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 70 (a) | | | | | | | | | | | | | | | | | | | | | | | | | | | 80 (b) | | | | | | 150 | | | | | | | | | | | | Alberto Falini | | | (12) | | | Statutory auditor | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 70 (a) | | | | | | | | | | | | | | | | | | | | | | | | | | | 80 (b) | | | | | | 150 | | | | | | | | | | | | Marco Lacchini | | | (13) | | | Statutory auditor | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 70 (a) | | | | | | | | | | | | | | | | | | | | | | | | | | | 12 (b) | | | | | | 82 | | | | | | | | | | | | Marco Seracini | | | (14) | | | Statutory auditor | | | | | 01.01-12.31 | | | | | | 05.2017 | | | | | | 70 (a) | | | | | | | | | | | | | | | | | | | | | | | | | | | 80 (b) | | | | | | 150 | | | | | | | | | | | | | | | | | | | Other Managers with strategic responsibilities (**) | | | (15) | | | Remuneration in the company that prepares the Financial Statements | | | | | 8,595 | | | | | | | | | | | | 9,118 | | | | | | | | | 186 | | | | | | 126 | | | | | | 18,025 | | | | | | | | | 4,603 | | | | | | | | | | | | | Remuneration from subsidiaries and associates | | | | | 458 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 458 | | | | | | | | | | | | | | | Total | | | | | 9,053 (a) | | | | | | | | | | | | 9,118 (b) | | | | | | | | | 186 (c) | | | | | | 126 (d) | | | | | | 18,483 | | | | | | | | | 4,603 (e) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 11,561 | | | | | | 424 | | | | | | 10,873 | | | | | | | | | 201 | | | | | | 475 | | | | | | 23,534 | | | | | | | | | 4,603 | | | | | | | | | | |
Notes
(*)
The term of office expires with the Shareholders’ Meeting approving the Financial Statements for the year ending December 31, 2016.
(**)
Managers who were permanent members of the Company’s Management Committee during the course of the year together with the Chief Executive Officer and Division Chief Operating Officers, or who reported directly to the Chief Executive Officer (twenty-three managers).
(1)
Emma Marcegaglia - Chairman of the board of directors
(a) The amount includes the fixed remuneration of €90 thousand set by the Shareholders’ Meeting on May 8, 2014 and the fixed remuneration for the delegated powers of €148 thousand approved by the Board on May 28, 2014.
(2)
Claudio Descalzi - Chief Executive Officer and General Manager
(a) The amount includes the fixed remuneration of €550 thousand for the position of Chief Executive Officer, which incorporates the remuneration set by the Shareholders’ Meeting on May 8, 2014 for the position of Director, and the fixed remuneration of €800 thousand for the position of Chief Executive Officer; indemnities due for transfers, in Italy and abroad, in line with the provisions of the relevant national collective labour agreement for senior managers and of the Company’s complementary agreements are added to this amount forExhibit 15. a total of €19 thousand.
(b) The amount correspond to the variable annual incentive paid in 2016. To this amount is added the incentives of €659 thousand paid in 2016 for the position of COO of the E&P Division, held until May 8, 2014, related to the deferred monetary incentive assigned in 2013, calculated in relation to the performance targets achieved during the 2013-2015 vesting period.
(3)
Andrea Gemma – Director
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount includes the €40 thousand for participating in the Control and Risk Committee and €20 thousand for the Sustainability and Scenarios Committee and €30 thousand for the Nomination Committee.
(4)
Pietro Angelo Guindani - Director
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount includes the €30 thousand for participating in the Compensation Committee and €20 thousand for the Sustainability and Scenarios Committee.
(5)
Karina Litvack – Director
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount includes the €23 thousand for participating in the Control and Risk Committee, €20 thousand for participating in the Compensation Committee and €20 thousand for the Sustainability and Scenarios Committee.
(6)
Alessandro Lorenzi - Director
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount includes the €60 thousand for participating in the Control and Risk Committee and €20 thousand for the Compensation Committee.
(7)
Diva Moriani – Director
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount includes the €12 thousand for participating in the Control and Risk Committee, €19 thousand for the Compensation Committee and €20 thousand for the Nomination Committee.
(8)
Fabrizio Pagani – Director
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount includes the €30 thousand for participating in the Sustainability and Scenarios Committee and €20 thousand for the Nomination Committee.
(9)
Alessandro Profumo – Director
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount includes the €20 thousand for partecipating in the Sustainability and Scenarios Committee and €20 thousand for the Nomination Committee.
(10)
Matteo Caratozzolo - Chairman of the Board of Statutory Auditors
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of TTPC (€32.1 thousand) and of Eni Adfin (€13.9 thousand)(i).
(11)
Paola Camagni - Statutory Auditor
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Eni East Africa (€18 thousand) and Auditor of Syndial (€12 thousand).
(12)
Alberto Falini - Statutory Auditor
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Eni Timor Leste (€12.9 thousand) and Auditor of TTPC (€21.2 thousand).
(13)
Marco Lacchini - Statutory Auditor
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of SOM (€20.3 thousand) and Auditor of Eni East Africa (€12 thousand).
(14)
Marco Seracini - Statutory Auditor
(a) The amount corresponds to the fixed annual remuneration set by the Shareholders’ Meeting of May 8, 2014.
(b) The amount related to the pro-rata remuneration for the office of Chairman of the Board of Statutory Auditors of Ing. Luigi Conti Vecchi (€18.2 thousand) and Auditor of Eni Adfin (€9.2 thousand).
(15)
Other Managers with strategic responsibilities
(a) The amount of €8,595 thousand for Gross Annual Salary is supplemented by the indemnities owed for the transfers performed, in Italy and abroad, in line with the provisions of the relevant national collective labour agreement for senior managers and with the Company’s additional agreements as well as other indemnities related to the employment contract for a total amount of €851 thousand.
(b) The amount includes the payment of €3,170 thousand relating to the deferred and long-term monetary incentives assigned in 2013 and the pro-rata amounts of the Long-Term Incentive Plans (DMI and LTMI) paid upon consensual employment contract resolution, for the vesting period expired as defined in the respective Plan Regulations.
(c) The amount includes the taxable value of insurance and welfare coverage, complementary pensions, the car for business and personal use.
(d) Amounts due for the positions held by Managers with strategic responsibilities in the Supervisory Body established under the Company’s Model 231 and the Manager responsible for the preparation of the Company’s financial statements.
(e) The amount includes the severance indemnity and early retirement incentives paid in relation to the termination of the employment, to which €1,044 thousand is added for the non-competition clauses payable by 2017 at the expiry of the related validity period, subject to the obligations being fulfilled.
OTHER INFORMATION
Accrued compensation
Total compensation accrued in the year 2016 pertaining to all the Board members amounted to €7.1 million; it amounted to €0.738 million in the case of the Statutory Auditors. Such amounts include, in addition to each item of emolument reported in the table above, amounts accrued in the year for pension benefits, social security contributions and other elements of the remuneration associated with roles performed, which represent a cost for the Company.
For the year ended December 31, 2016, remuneration of persons in key positions in planning, direction and control functions of Eni Group companies, including executive and non-executive Directors, and other Managers with strategic responsibilities (with reference to all those individuals who, during the course of the 2016 period, filled said roles, even if only for a fraction of the year) amounted to €44 million and was accrued in Eni’s Consolidated Financial Statements for the year ended December 31, 2016. The breakdown is as follow:
| | | | | | | | 2016 | | | | | (€ million) | | Fees and salaries | | | 26 | | Post-employment benefits | | | 2 | | Other long-term benefits | | | 12 | | Indemnity upon termination of the office | | | 4 | | | | | 44 | | |
The above amounts include salaries, fees for attending meetings, lump-sum amounts paid in lieu of expense reimbursements, stock-based compensation and other deferred incentive bonuses, health and pension contributions and amounts accrued to the reserve for employee termination indemnities, which is used to pay severance pay, as required by Italian law to employees upon termination of employment. The members of the Board of Directors in their capacity as such are not entitled to receive such severance pay.
As of December 31, 2016,2019, the total amount accrued to the reserve for employee termination indemnities with respect to Chief Executive Officer and General Manager, Chief OperatingExecutive Officers and other Managers with strategic responsibilities (with reference to the employed ones who, during the course of the 20162019 period, filled said roles, even if only for a fraction of the year), was €1,706€1,427 thousand. Name | | | | | | (€ thousand) | | Descalzi Claudio Descalzi | | | Chief Executive Officer | | | 352 | | 371 | | | Senior Managers managers(a) | | | | | 1,056 | 1,353 | | | | | | | | 1,706 | | 1,427 | | |
(a)
No. 18 Managers20 managers. Board practices3 Corporate Governance The Corporate Governance structure of Eni follows the Italian traditional management and control model, whereby corporate management is the responsibility of the Board of Directors, which is the core of the organizational system, while supervisory functions are allocated to the Board of Statutory Auditors. The Company’s accounts are independently audited by an accredited Audit Firm appointed by the Shareholders’ Meeting. Eni complies with the Corporate Governance Code for listed companies (on the Italian Stock Exchange) approved by Italian Corporate Governance Committee (hereinafter “Corporate Governance Code” or “Code”). On, lastly amended on July 9, 2015, the Italian Corporate Governance Committee approved a few amendments to the Corporate Governance Code. At its Meeting held on February 25, 2016, the Board adopted the new recommendations of the Code, acknowledging that Eni’s Corporate Governance model was already broadly compliant with the new recommendations.2018. The names of Eni’s Directors, their positions, the year in which each of them was initially appointed as a Director and their ages are reported in the related table above. 3
The information contained in this chapter is updated to December 31, 2019 and for specific aspects, expressly indicated, up to the date of approval of this Report.
Board of Directors’ duties and responsibilities The Board of Directors has the fullest powers for the ordinary and extraordinary management of the Company in relation to its purpose. In a resolution dated May 9, 2014,April 13, 2017, the Board, while exclusively reserving to itself the most important strategic, operational and organizational powers, in addition to those that cannot be delegated by law, appointed Claudio Descalzi as CEO and General Manager, entrusting him with the fullest powers for the ordinary and extraordinary management of the Company, with the exception of those powers that cannot be delegated under current law and those retained by the Board. In the same resolution, the Board of Directors resolved to attributeconfirm to the Chairman a major role in internal controls and not operational functions. In particular, with reference to Internal Audit, the Board of Directors resolved that, in accordance with the Corporate Governance Code, the Head of the Internal
Audit Department reports to the Board, and on its behalf, to the Chairman, without prejudice to its functional reporting to the Control and Risk Committee and the Chief Executive Officer, as the director in charge of the internal control and risk management system. The Chairman is also involved in the appointment of the primary Eni officers in charge of internal controls and risk management, as well as in approving internal rules governing the Internal Audit process. In addition, the Chairman carries out her statutory functions as legal representative, managing institutional relationships in Italy, together with the Chief Executive Officer. Finally, the Board of Directors entrusted the Board Secretary with the role of Corporate Governance Counsel, who reports hierarchically and functionally to the Board and, on its behalf, to the Chairman. He lends assistance and independent legal advice to the Board and the Directors and periodically presents to the Board of Directors a report on the functioning of Eni’s Corporate Governance system. On May 9, 2014,April 13, 2017, the Board reserved to itself the strategic, operational and organizational powers briefly described below: •
defines the system and rules of Corporate Governance for the Company and the Group; •
establishes the Board’s internal committees, appoints their members and chairmen, determines their duties and compensation, and approves their procedural rules and annual budgets; •
expresses the general criteria for determining the maximum number of offices that a Company Director may hold in other companies; •
delegates and revokes the powers of the CEO and the Chairman, establishing the limits and procedures for exercising those powers and determining the compensation associated with these duties; •
establishes the basic structure of the organizational, administrative and accounting arrangements of the Company (including the internal control and risk management system), of its strategically important subsidiaries and of the Group as a whole. It evaluates the adequacy of these arrangements; •
establishes the guidelines for the internal control and risk management system, so that the main risks facing the Company and its subsidiaries are correctly identified and adequately measured, managed and monitored, determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives. It sets the financial risk limits of the Company. It also examines the main business risks, which are identified taking into account the characteristics of the activities carried out by the Company and its subsidiaries and which are reported by the Chief Executive Officer at least quarterly. Moreover, it evaluates, every six months, the adequacy of the internal control and risk management system with respect to the characteristics of the Company and its risk profile, as well as the system’s effectiveness; •
approves at least annually the Audit Plan drawn up by the Senior Executive Vice President of the Internal Audit Department. It also evaluates the findings contained in the recommendation letter, if any, of the Audit Firm and in its statement on the key issues that arose during the statutory audit; •
defines the strategic guidelines and objectives of the Company and the Group, including sustainability policies. It examines and approves the budgets and strategic, industrial and financial plans of the Group, periodically monitoring their implementation, as well as agreements of a strategic nature for the Company. It examines and approves the plan for the Company’s non-profit activities and approves operations not included in the plan whose cost exceeds €500,000;
•
examines and approves the annual financial report (which includes Eni’s draft Financial Statements and the Consolidated Financial Statements) and the semi-annual and quarterly financial reports required by applicable law. It reviews and approves the Sustainability Reporting when it is not already contained in the financial report; •
receives reports from Directors with delegated powers at Board meetings, or on at least a bi-monthly basis, on the actions taken in exercising their delegated powers; •
receives a report from the Board’s internal committees on at least a semi-annual basis; •
assesses general developments in the operations of the Company and of the Group, paying particular attention to conflicts of interest and comparing the results with budget forecasts;
•
evaluates and approves transactions of the Company and its subsidiaries with related parties provided for in the procedure approved by the Board74, as well as transactions in which the CEO has an interest; •
evaluates and approves any transaction executed by the Company and its subsidiaries that has a significant strategic, economic, financial or asset impact on the Company; •
appoints and removes the Chief Operating Officers, the Officer in charge of preparing financial reports, the Senior Executive Vice President of the Internal Audit Department and the Eni Watch Structure. It ensures the designation of a manager responsible for shareholder relations; •
examines and approves the Remuneration Report and, in particular, the Remuneration Policy for Directors and Managers with strategic responsibilities to be presented to the Shareholders’ Meeting. It also defines the criteria for remunerating the senior executives of the Company and of the Group and takes steps to implement compensation plans based on shares or other financial instruments approved by the Shareholders’ Meeting; •
resolves on the exercise of voting rights and on the appointment of members of corporate bodies of the strategically important subsidiaries; •
formulates the proposals to present to the Shareholders’ Meeting; and •
examines and resolves on other issues that Directors with delegated powers believe should be presented to the Board due to their particular importance or sensitivity. In accordance with Article 23.2 of the By-laws, the Board also resolves on mergers and proportional spin-offs of companies in which Eni’s shareholding is at least 90%; the establishment and closing of branches; and the amendment of the By-laws to comply with the provisions of law. In accordance with the By-laws, the Chairman and the Chief Executive Officer retain representative powers for the Company. Directors’ independence On the basis of statements made by the Directors and other information available to the Company, during its meeting of May 9, 2014April 13, 2017 and, after an investigation by the Nomination Committee, lastly at its meeting of February 17, 2015,27, 2020, the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Zingales8Trombone satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and ZingalesTrombone have been deemed independent by the Board pursuant to the criteria and parameters recommended by the Corporate Governance Code. Chairman Marcegaglia, in compliance with the Corporate Governance Code, could not be deemed independent as she is a significant representative of the Company.5 On July 29, 2015,At the Enilast assessment, the Board of Directors appointed Alessandro Profumoalso evaluated that the commercial relationships between Eni and Vodafone Italy, a company of which Director Guindani is a significant representative, and between Eni and companies of the KME Group, companies subject to replace Luigi Zingales, who resigned on July 2, 2015. The Boardsignificant influence, also indirectly, by Director Moriani, are not significant for the purpose of assessing the independence of these Directors, following an investigation performed by the Nomination Committee, on the basis of declarations made by Profumo and information availablehaving regard to the Company, ascertained that Profumo was independent according to lawnature and the Corporate Governance Code. With reference to the marital relationshipamounts of Profumo with an employee of the Company, the Board resolved that this relationship does not compromise the independence requirements requested by the Corporate Governance Code, on account of Profumo’s ethical and professional integrity and his international reputation and taking into account the fact that his spouse is employed at a foundation, which is independent of Eni SpA9.
On February 25, 2016, and most recently on February 28, 2017,these relationships. The relationships were evaluated on the basis of statements made by the Directors and other information available to the Company, after an investigation byand taking into account that – due to the Nomination Committee,nature of the Board of Directors determined that Chairman Marcegaglia and Directors Gemma, Guindani, Litvack, Lorenzi, Moriani and Profumo satisfy the independence requirements established by law, as referenced in Eni’s By-laws. Furthermore, Directors Gemma, Guindani, Litvack, Lorenzi, Morianicompanies mentioned above – transactions between these
(7)4
The Board of Directors, on November 18, 2010, approved the Management System Guideline (MSG) “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”, which has been applied since January 1, 2011, to ensure transparency and substantial and procedural fairness of transactions with related parties. The Board modified this MSG on January 19, 2012.2012 and, lastly, on April 4, 2017. (8)5
Luigi Zingales resigned fromAlthough the Chairman of the Board of Directors on July 2, 2015.
(9)
On May 26, 2016,is a non-executive Director, the BoardCode treats her as a significant representative of Directors, after an investigation by the Nomination Committee, on the basis of declarations made by Profumo and information available to the Company verified that Profumo - confirmed by the Shareholders’ Meeting on May 12, 2016 - was independent in accordance with law and(Application Criterion 3.C.2 of the Corporate Governance Code, confirming the previous assessments.Code).
companies and Profumo have been deemed independent by the Board pursuantEni were subject to related parties’ transactions regulation and reported to the criteria and parameters recommended by the Corporate Governance Code.Company’s body. The Board confirmed the independence requirements of Director Profumo on the basis of the aforementioned reasons. At the last assessment, the Board of Directors also evaluated that the commercial relationships between Eni and Vodafone Italy, a company of which Director Guindani is a significant representative, are not significant for the purpose of assessingconfirmed the independence of Director Lorenzi, who the next May 5, 2020 will complete the ninth year of office as Director, himself, having regard to the nature and the amounts of these relationships.taking into account that his office as Director will expire on May 13, 2020. The Board of Statutory Auditors ascertained thatalways verified the proper application of criteria and procedures adopted by the Board of Directors correctly applied the assessment criteria and procedures for evaluatingin assessing the independence of its members. The independence criteria may be not be equivalent to the independence criteria set forth in the NYSE listing standards applicable to a U.S. domestic company. Board Committees The Board of Directors has established four internal Committees to provide it with recommendations and advice: (a) the Control and Risk Committee; (b) the CompensationRemuneration Committee; (c) the Nomination Committee; and (d) the Sustainability and Scenarios Committee. Committees under letters (a), (b) and (c) are recommended by the Corporate Governance Code. The composition, duties and operational procedures of these committees are governed by their own rules, which are approved by the Board, in compliance with the criteria outlined in the Corporate Governance Code. The Committees recommended by the Corporate Governance Code are composed of no fewer than three members and, in any case, less than a majority of members of the Board. The composition is described in the following sections pertaining each Committee. All Board Committees report to the Board of Directors, at least once every six months, on activities carried out. In addition, the Chairmen of the Committees report to the Board at each meeting of the Board on the key issues examined by the Committees in their previous meetings. In the exercise of their functions, the Committees have the right to access any information and Company functions necessary to perform their duties. They are also provided with adequate financial resources, in accordance with the terms established by the Board of Directors, and can avail themselves of external advisers. The Chairman of the Board of Statutory Auditors or a Statutory Auditor designated by him, participates in Control and Risk Committee and Remuneration Committee meetings and may participate in other Committees’ meetings. Furthermore, Committees may invite other persons to attend the meetings in relation to individual items on the agenda. The CEO and the Chairman may attend the meetings of the Nomination Committee and of the Sustainability and Scenarios Committee. Furthermore, they may attend Control and Risk Committee meetings, unless matters relating to them are discussed. Finally, they may attend CompensationRemuneration Committee meetings upon the invitation of its Chairman, except when the meetings are examining proposals regarding their remuneration.remuneration6. The Board Secretary and Corporate Governance Counsel coordinates the secretaries of the Board Committees, receiving at this end information on the calendar of the meetings and the items in the Committees’ agendas, the notices of the meetings, as well as their signed minutes. Minutes of all Committee meetings are usually drafted by their respective secretaries. The current members of the Control and Risk Committee, CompensationRemuneration Committee, Nomination Committee and Sustainability and Scenarios Committee were appointed by the Board of Directors on May 9, 2014, except forApril 13, 2017. Remuneration Committee Members: Andrea Gemma (Chairman), Pietro A. Guindani, Alessandro Lorenzi, Diva Moriani. 6
Rules of the Remuneration Committee establish that “no Director Profumo, appointed byand, in particular, no Director with delegated powers may take part in meetings of the Committee during which Board proposals regarding his remuneration are being discussed, unless are deemed proposals on all the members of the Committees established within the Board of Directors as a member of Nomination Committee andDirectors.”
Sustainability and Scenarios Committee on September 17, 2015, and Director Diva Moriani, who was appointed as a member of the Control and Risk Committee on September 15, 2016, replacing Director Karina Litvack10; Director Diva Moriani left the Compensation Committee on December 22, 2016.
Compensation Committee
Members: Pietro A. Guindani (Chairman), Karina Litvack, Alessandro Lorenzi11.
The CompensationRemuneration Committee is made up of non-executive, independent Directors. All the members possess adequate professional requirements and expertise for carrying out the duties assigned to the Committee. In particular,The Committee’s rules require that at his appointment, the Director Guindani was identifiedleast one of its members possess adequate knowledge and experience of financial matters or remuneration policies, as assessed by the Board asat the member with “adequate knowledge and experience in financetime of his or remuneration policies” as recommended by the Corporate Governance Code.her appointment. Established by the Board of Directors for the first time in 1996, in accordance with the By-laws, the Committee provides recommendations and advice to the Board of Directors. More specifically, the Committee: a)
submits to the Board of Directors for its approval the Remuneration Report and in particular the Remuneration Policy for Directors and Managers with strategic responsibilities to be presentedthe Board of Directors for approval, prior to its presentation at the Shareholders’ Meeting called to approve the year’s financial statements, as provided forin accordance with the time limits set by applicable law; b)
periodically evaluates the adequacy, overall consistency and effective implementation of the Policy, formulating proposals, as appropriate, for approval by the Board of Directors; c)
presents proposals for the remuneration of the Chairman of the Board and the Chief Executive Officer, coveringincluding the various formscomponents of compensation and benefits awarded; c) non monetary benefits; d)
presents proposals for the remuneration of members ofBoard Committee members; e)
having examined the Board’s internal committees; d) examines the CEO’s indications and presents proposals for: (i)Chief Executive Officer’s indication, proposes general criteria for the compensation of Managers with strategic responsibilities; (ii)responsibilities, the annual and long-termLong-Term incentive plans, including equity-based plans;ones, sets performance objectives and (iii) establishingassesses performance targets and assessing results for performance plansagainst them, in connection with the determination of the variable portion of the compensationremuneration for Directors with delegated powers and with the implementation of the approved incentive plans; e) f)
monitors the execution of Board resolutions regarding remuneration matters; f) periodically evaluates the adequacy, overall consistency and actual implementation of the adopted policy, as described in letter a) above, formulating proposals on the topic for the Board of Directors; g) performs the tasks required under the Company’s procedures for handling related party transactions; h) through the Chairman of the Committee, informs the Board of Directors on the main issues examineddecisions taken by the Committee thereof duringBoard; g)
reports at the first available meeting of the Board; furthermore,Board of Directors through the Committee Chairman on the most significant issues addressed by the Committee during the meetings. It also reports to the Board on its activities at least once every six months and no later than the deadlinetime limit for the approval of the annual Financial StatementsAnnual Report and the semi-annual financial report, on its activitiesInterim Report at June 30, at the Board Meeting indicatedmeeting designated by the Chairman of the Board of Directors;Directors. Furthermore, in exercising its functions, the Committee may issue opinions as required by Company procedures in relation to operations with related parties, in accordance with specified procedures. The Committee performs its duties pursuant to an annual plan. In carrying out its duties, the Committee may access the information and i)Company functions necessary to perform its duties and can avail itself of external advisors who are not in positions that might compromise their independence of judgement, within the terms and budget limits established by the Board of Directors. The Committee reports on the procedures it adopts in performing its functions to the Shareholders’ Meeting called to approve the financial statements through its Chairman or another Committee member designated by the Chairman, on its operational procedures toin accordance with the Shareholders’ Meeting called to approverecommendations in the Financial Statements.Corporate Governance Code and with the goal of establishing and appropriate channel for dialogue with shareholders and investors. During 2016,2019, the CompensationRemuneration Committee met a total of nineten times, with an average attendance of 94,4%100% of its members and an average duration of 32 hours and 1310 minutes. All the Committee meetings were attended by atAt least one member of the Board of Statutory Auditors participated in each meeting, whit constant participation of the Chairman of the Board of Statutory Auditors. At the invitation of the Chairman of the Committee, Company executives and external advisors also took part in specific meetings, to provide information and clarifications requested by the Committee. Earlier in the year, the Committee focused its activities in particular on the following topics: (i) i.
the periodic assessmentevaluation of the Remuneration Policy implemented in 2015, also2018 in order to prepare the proposed policy guidelines for 2019, providing for keeping the structure and criteria of remuneration of the Directors and Executives with strategic responsibilities defined in 2017 for the entire term, as regards in particular the simplified variable incentive system, as discussed in greater detail in the 2017 Remuneration Report; ii.
the review of the Company’s 2018 results for the purpose of definingimplementing the proposed Policy Guidelines for 2016; (ii) review of 2015 corporate performance linked to the implementation of annualShort- and long-termLong-Term variable incentive plans, in accordance withusing a “variationpredetermined gap analysis methodology”method approved by the Committee in order to neutralize the positive or negative impact of exogenous factors to allow an unbiasedand enable the objective assessment of the performance levels achieved; (iii)
iii.
the definition of the 20162019 performance targets relatedrelevant to the variable incentive plans, with plans; iv.
the introduction of a new metric in the Annual Incentive Plan, enhancing exploration resources as a fundamental asset in order to preserve the sustainabilityfinalization of the Company’s future results; (iv) definition of the proposalsproposal for the implementation of the Deferred Monetary Incentive Planannual variable incentive system for the Chief Executive Officer and General Manager as well other senior executives; (v)Manager; v.
the review of the 20162019 Eni Remuneration report; (vi) ) reviewReport; vi.
the examination of the outcome of the first cycleengagement activities held with leading institutional investors and proxy advisors in view of engagement conducted with main institutional investors,the general meeting, in order to maximize shareholder consensus on the 20162019 Remuneration Policy,Policy; the Chairman of the Committee also took part in the aforementioned meetings, bearing witness to the importance given by the Committee to dialogue with shareholders; vii.
risk assessment and scenario analysis, examination of the composition of shareholders, including the retail segment, as well as examination of voting recommendations issued by leading proxy advisors and of related voting projections, producedwhich were performed with the support of an international consultant.a leading consulting firm; (10)viii.
On July 28, 2016, Eni’s Boardthe start of Directors approved the replacementa further extensive dialogue with a broad range of Director Karina Litvack with another Director - identified by the Board itself in Director Diva Moriani on September 15, 2016 -investors in the Controlrun-up to the annual meeting, with a view to promoting participation and Risk Committee (CRC) in light ofsupport for the ongoing investigations related to alleged conspiracy against the Company, reported also by the press. The board has taken this decision only to safeguard the Company from the risks of possible conflicts of interest until the closing of the investigation, remaining the presumption that Director Litvack has not been involved in the facts under investigations.Eni Remuneration Policy.
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Director Diva Moriani left the Compensation Committee on December 22, 2016
In the second parthalf of the year, the Committee primarily analyzedexamined the 2019 Shareholders’ Meeting vote results, with regard to the Eni Remuneration Report, compared to the results of the 2016 Shareholder’s Meeting season, regarding the Eni Remuneration Report, the mainmajor Italian and European listed companies as well as companies inand of the peer group of reference. Among other mainEni’s Peer Group. As regards further relevant activities carried out, the Committee also: (i) finalisedCommittee: i
finalized the proposal concerning(2019 grant) for the fulfilment (2016 award)implementation of the 2017-2019 Long Term Share Incentive PlanPlane for the Chief Executive Officer and General Manager and other criticalfor key management personnel; (ii) initiated ii
finalized the examinationproposal on the exercise of the 2017 Remuneration Policy Guidelines, developing in particular, overoption to activate the course of a number of meetings, a proposal for the revision of the variable incentive system applicable tonon-compete agreement entered into with the Chief Executive Officer and General Manager, as well as Managers with Strategic Responsibilities, withset out in the goal2019 Remuneration Report; iii
started to examine the proposal for the Long-Term Share Incentive Plan 2020-2022 for key management personnel; iv
examined the updating of further strengtheningremuneration benchmark studies and started to review the alignment betweenproposals for Remuneration Policy Guidelines for the action of management and shareholder interests; (iii) approved2020-2023 term; v
examined the annualgeneral criteria for defining the 2020 engagement plan prepared by the competent company functionsconducting a preliminary analysis and was informedsegmentation of the findingsinstitutional investors that attended the 2019 Shareholders’ Meeting; vi
monitored developments in the legislative framework and market standards concerning the reporting of remuneration-related information, with a specific focus on changes introduced with Legislative Decree no. 49/2019, transposing the SRD II, including a binding vote of the Shareholders’ Meeting on the Remuneration policy described in the first cycle of meetings held with the main proxy advisors, in implementationsection of the engagement plan for 2017.Remuneration Report, and an advisory vote on the second section, concerning remuneration paid during the reporting period. The composition and appointment,Committee scheduled four meetings for the first four months of 2020, three of which had already been held as well as the duties and operating procedures, of the Committee are governed by the rules approved by the Boarddate of Directors on July 30, 2014, and most recently amended on September 15, 2016, available to the public on the Company’s website.approval of this Report. Control and Risk Committee Members: Alessandro Lorenzi (Chairman), Andrea Gemma, Karina Litvack and Diva Moriani12.Moriani.
The Control and Risk Committee is entrusted with supporting, on the basis of an appropriate control process, the Board of Directors in evaluating and making decisions concerning the internal control and risk management system and in approving the periodical financial reports. It is entirely made up of non-executive and independent Directors137 who possess the necessary expertise consistent with the duties they are required to perform148. In particular, at their appointment, the Directors Lorenzi, Litvack and Moriani were identified by the Board as members with “adequate experience in the area of accounting and finance or risk management”, as recommended by the Corporate Governance Code. The Committee advises the Board of Directors and specifically issues its prior opinion: a) and drafts recommendations concerning the guidelines for the internal control and risk management system so that the main risks faced by the Company and its subsidiaries can be correctly identified and appropriately measured, managed and monitored and also supports the Board in determining the degree of compatibility of such risks with the management of the Company in a manner consistent with its stated strategic objectives; b) on the assessment, performed by the Board of Directors, on the main company risks, identified taking into account the characteristics of the activities carried out by the company or its subsidiaries; c) on the evaluation, performed at least every six months, of the adequacy of the internal control and risk management system, taking account of the characteristics of the Company and its risk profile, as well as its effectiveness. To this end, at least once every six months it reports to the Board of Directors, on the occasion of the approval of the annual and semi-annual financial reports, on its activities and on the adequacy of the internal control and risk management system at the meeting of the Board of Directors indicated by the Chairman of the Board of Directors; d) on the approval, at least once a year, of the Audit Plan prepared by the Senior Executive Vice President of the Internal Audit Department; e) on the description, in the annual Corporate Governance Report, of the main features of the internal control and risk management system, and how the different subjects involved therein are coordinated, providing its evaluation of the overall adequacy of the system itself; and f) on the evaluation of the findings reported by the Audit Firm in any recommendations letter it may issue and in the latter’s report on the main issues arising during the audit. The Committee furthermore: a) issues opinions to the Board of Directors on specific aspects concerning the identification of the main risks faced by the Company; b) examines and issues an opinion (12)
On September 15, 2016, Eni’s Board of Directors appointed Diva Moriani as member of the Control and Risk Committee in place of Director Karina Litvack, following the replacement approved by the Board of Directors on July 28, 2016.
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In accordance with the rules of the Control and Risk Committee, the Committee is made up of three to four non-executive Directors, all of whom are independent. Alternatively, the Committee may be made up of non-executive Directors, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. In any case, the number of members shall be fewer than the number representing a majority on the Board.
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The Governance system put in place by Eni establishes that at least two members of the Committee – and not just one as recommend by the Corporate Governance Code for listed companies – must possess adequate experience in financial and accounting matters or in risk management, as assessed by the Board of Directors at the time of their appointment.
on the adoption and amendment of the rules on the transparency and the substantive and procedural fairness of transactions with related parties and those in which a Director or Statutory Auditor holds a personal interest or an interest on behalf of a third party, while performing additional duties assigned it by the Board of Directors, including examining and issuing an evaluation on specific types of transactions, except for those relating to compensation; and c) gives an opinion on the fundamental guidelines of the Regulatory System, the regulatory instruments to be approved by the Board of Directors, their amendment or update and, upon request by the CEO, on specific aspects in relation to the instruments implementing the fundamental guidelines. In addition, the Committee, in assisting the Board of Directors: a) evaluates, together with the Officer in charge of preparing financial reports and after having consulted the Audit Firm and the Board of Statutory Auditors, the proper application of accounting standards and their consistency in preparing the Consolidated Financial Statements, prior to their approval by the Board of Directors; b) examines and evaluates Reports prepared by the CFO /OfficerCFO/Officer in charge of preparing financial reports through which it shall give its opinion to the Board of Directors on the appropriateness of the powers and resources assigned to the Officer himself and on the proper application of accounting and administrative procedures, enabling the Board to exercise its legally mandated supervision tasks; c) at the request of the Board, it supports, with adequate preliminary activities, the Board of Directors’ assessments and resolutions on the management of risks arising from detrimental facts of which the Board may have become aware and d) monitors the independence, adequacy, efficiency and effectiveness of the Internal Audit Department and 7
In accordance with the rules of the Control and Risk Committee, the Committee is made up of three to four non-executive Directors, all of whom are independent. Alternatively, the Committee may be made up of non-executive Directors, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. In any case, the number of members shall be fewer than the number representing a majority on the Board. 8
The Governance system put in place by Eni establishes that at least two members of the Committee – and not just one as recommend by the Corporate Governance Code for listed companies – must possess adequate experience in financial and accounting matters or in risk management, as assessed by the Board of Directors at the time of their appointment.
oversees its activities with respect to the duties of the Board of Directors in this area, and on its behalf, of the Chairman, ensuring that they are performed with the necessary independence and required level of objectivity, competence and professional diligence, in accordance with the Code of Ethics of Eni SpA and international standards. A favorable opinion of the Committee is required for the approval to the Board on proposals by the Chairman in agreement with the CEO concerning the appointment, the removal and, consistent with the Company’s policies, the structure of the fixed and variable compensation of the Senior Executive Vice President of the Internal Audit Department, as well as on the adequacy of the resources provided to the latter to perform his duties. The Committee also: a) evaluates, on the occasion of his appointment, whether the Senior Executive Vice President of the Internal Audit Department meets the integrity, professionalism, competence and experience requirements and, on an annual basis, assesses their fulfilment; b) examines the results of the audit activities performed by the Internal Audit Department; c) examines the periodic reports prepared by the Senior Executive Vice President of the Internal Audit Department as to whether it contains adequate information on the activities carried out, on the manner in which risk management is conducted and on compliance with risk containment plans, as well as assesses the appropriateness of the internal control and risk management system. It also examines the reports prepared promptly by the Senior Executive Vice President of the Internal Audit Department on events of particular importance; and d) examines the information received from the Senior Executive Vice President of the Internal Audit Department and promptly reports its assessment to the Board of Directors in the case of: (i) significant deficiencies in the system for preventing irregularities and fraudulent acts, and irregularities or fraudulent acts committed by management personnel or by employees that perform important roles in the design or operation of the internal control and risk management system; and (ii) circumstances that may affect the maintenance of the independence of the Internal Audit Department and of auditing activities. The Committee may also ask the Internal Audit Department to perform audits on specific operational areas, providing simultaneous notice to the Chairman of the Board of Statutory Auditors. The Committee also examines and assesses: a) communications and information received from the Board of Statutory Auditors and its members regarding the internal control and risk management system, including those concerning the findings of enquiries conducted by the Internal Audit Department in connection with reports received (whistleblowing), including anonymous reports; b) half yearly reports issued by Eni’s Watch Structure, including in its capacity as Guarantor of the Code of Ethics, as well as the timely updates provided by the Structure, after the updates have been given to the Chairman of the Board and to the CEO, about any particular material or significant situation detected in the performance of its duty; c) information on the internal control and risk management system, including that provided in the course of periodic meetings with the competent Company structures; and d) enquiries and reviews concerning the internal control and risk management system carried out by third parties.
Furthermore, the Committee oversees the activities of the Legal Affairs Department in case of judicial inquiries and proceedings, carried out in Italy and/or abroad, in relation to which the CEO and/or the Chairman of the Company and/or a member of the Board of Directors and/or an Executive reporting directly to the CEO, even if no longer in office, have received a notice of investigation for crimes against the Public Administration and/or corporate crimes and/or environmental crimes, related to their mandate and their scope of responsibility. The composition and appointment, as well as duties and operational procedures of the Committee, are governed by rules approved by the Board of Directors lastly on July 30, 2014 and amended on April 7, 2016,May 9, 2017 available to the public at the Company’s website. Nomination Committee Members: Diva Moriani (Chairman), Andrea Gemma, (Chairman), Diva Moriani, Fabrizio Pagani and Alessandro Profumo.Domenico Livio Trombone. The Nomination Committee is made up of non-executive Directors, a majority of whom are independent.
The Committee provides recommendations and advice to the Board of Directors with recommendations and advice. In particular,Directors. More specifically, the Committee: a)
assists the Board of Directors in formulating any criteria for the appointment of those persons indicated in the following letter b) below, and of the members of the other boards and bodies of Eni’s subsidiaries and associated companies; b)
provides evaluations to the Board of Directors on the appointment of executives and members of the boards and bodies of the Company and of its subsidiaries, proposed by the Chief Executive Officer and/or the Chairman of the Board of Directors, whose appointment fallfalls under the Boards’Board’s responsibility and oversees the associated succession plans. Where possible and appropriate, in relationand with due regard to the shareholding structure, the Committee proposes the CEO succession plan to the Board of Directors the succession plan for the Chief Executive Officer; Directors; c)
acting upon a proposal of the Chief Executive Officer, examines and evaluates criteria governing the succession planplanning for the Company’s key management personnel; managers with strategic responsibilities; d)
proposes candidates to serve as Directors onto the Board of Directors in the event one or more positions need to be filled during the course of the financial year (Article 2386, first paragraph, of the Italian Civil Code), ensuring compliance with the requirements onregarding the minimum number of independent Directors and of the percentage reserved for the less represented gender; e)
proposes to the Board of Directors candidates for the position of Director to be submitted to the Shareholders’ Meeting of the Company, taking account of any recommendationrecommendations received from shareholders, in the event it is not possible to draw the required number of Directors from the slates presented by shareholders; f)
oversees the annual self-assessment program on the performance of the Board of Directors and its Committees, in compliance with the Corporate Governance Code, and deals with the preliminary activity for appointing an external consultant for such self assessment.self-assessment. On the basis of the results of the self-assessment, the Committee provides its opinions to the Board of Directors regarding the size and composition of the Board or its Committees, as well as, the skills and managerial and professional qualifications it feels should be represented within the same Board and Committees so that the Board itself can give its opinion to the shareholders prior to the appointment of the new Board; g)
proposes to the Board of Directors the slate of candidates for the position of Director to be submitted to the Shareholders’ Meeting if the Board decides to opt for the process envisaged in Article 17.3, first sentence,period, of the By-laws; h)
in compliance with the Corporate Governance Code, proposes to the Board of Directors guidelines regarding the maximum number of positions of Director or statutory auditorStatutory Auditor that a Company Director may hold and performs the preliminary activity for the associated periodic checks and evaluations to be submittedfor submission to the Board; i)
periodically verifies that the Directors satisfy the independence and integrity requirements, and ascertains the absence of circumstances that would render them incompatible or ineligible; j)
provides its opinion to the Board of Directors on any activities carried out by the Directors in competition with the Company; and k)
through the Chairman of the Committee, informs the Board of Directors on the main issues examined by the Committee thereof during the first available meeting of the Board; furthermore, the Committee reports to the Board of Directors, at least once every six months and no later than the deadline for the approval of the annual financial statements and of the semi-annual financial report, on the activity carried out as well as on the adequacy of the appointment system, at the Board Meetingmeeting indicated by the Chairman of the Board of Directors. The preliminary examination of corporate affairs or governance issues is carried out jointly with the Senior Executive Vice President Corporate Affairs and Governance who, in this case, participates in the Committee meetings. The composition, appointment, duties and operational procedures of the Nomination Committee are governed by rules approved by the Board of Directors lastly on July 30, 2014, and amended on April 7, 2016,May 9, 2017, available to the public at the Company’s website. Sustainability and Scenarios Committee Members: Pietro A. Guindani (Chairman), Karina Litvack, Fabrizio Pagani and Domenico Trombone.
Sustainability and Scenarios Committee
Members: Fabrizio Pagani (Chairman), Andrea Gemma, Pietro A. Guindani, Karina Litvack and Alessandro Profumo.
The Sustainability and Scenarios Committee is made up of non-executive Directors, a majority of whom are independent. The Sustainability and Scenarios Committee provides recommendations and advice to the Board of Directors on scenarios and sustainability, i.e. the processes, projects and activities aimed at ensuring the Company’s commitment to sustainable development along the value chain, particularly with regard to: the health, well-being and safety of people and communities; respect and the protection of rights, particularly of the human rights; local development; access to energy, energy sustainability and climate change; the environment and efficient use of resources; integrity and transparency; and innovation. Board of Statutory Auditors The current Board of Statutory Auditors was appointed by the Ordinary Shareholders’ Meeting of May 8, 2014April 13, 2017 for a term of three financial years. The Board’s term will therefore expire with the Shareholders’ Meeting called to approve the Financial Statements for the year ending December 31, 2016.2019. Name | | | Position | | | Year first appointed to Board of Statutory Auditors | | Matteo CaratozzoloRosalba Casiraghi | | | Chairman | | | 20142017 | | Enrico Maria Bignami | | | Auditor | | | 2017 | | Paola Camagni | | | Auditor | | | 2014 | | Alberto FaliniAndrea Parolini | | | Auditor | | | 2014 | | Marco Lacchini | | | Auditor | | | 20142017 | | Marco Seracini | | | Auditor | | | 2014 | | Stefania Bettoni | | | Alternate | | | 2014 | | Mauro LonardoClaudia Mezzabotta | | | Alternate | | | 20142017 | | |
Paola Camagni, Alberto Falini,Andrea Parolini, Marco Seracini and Stefania Bettoni (Alternate) were candidates listed in the slate presented by the Ministry of the Economy and Finance; Matteo CaratozzoloRosalba Casiraghi (Chairman), Marco LacchiniEnrico Maria Bignami and Mauro LonardoClaudia Mezzabotta (Alternate) were candidates listed in the slate presented by non-controlling shareholders (institutional investors).shareholders. The Auditors are appointed by means of a slate voting system: the lists are presented by shareholders representing at least 0.5% of the share capital. Two standing Statutory Auditors and one Alternate Auditor are selected from among the candidates of the non-controlling shareholders. The Chairman of the Board of Statutory Auditors is appointed by the Shareholders’ Meeting from among the Auditors chosen by the non-controlling shareholders. In accordance with the provisions designed to ensure gender balance, which were applied for the first time in the elections of the Board of Directors and the Board oftwo Statutory Auditors at the Shareholders’ Meeting held on May 8, 2014, one Statutory Auditor and one Alternate Statutory Auditor were drawn from the less represented gender. For the next two elections, one third of the statutory auditors will be drawn from the less represented gender. The Auditors must satisfy the independence, professional and integrity requirements established by Italian regulations. Article 28 of the By-laws specifies that the professionalism requirements may be fulfilled by having at least three years’ experience in: (i) professional or teaching activities pertaining to commercial law, business economics and corporate finance, or (ii) experience in executive positions in the fields of engineering and geology. U.S. Regulations for Audit Committees require that at least one member of the Board of Statutory Auditors be a financial expert and have adequate knowledge of the functions of the Audit Committee and experience in the analysis and application of generally accepted accounting standards, the preparation and auditing of Financial Statements and internal control processes. In addition, the Board of Statutory Auditors, acting as the Internal Control and Financial Auditing Committee pursuant to Legislative Decree no. 39/2010 (Consolidate Law on Statutory Audits of annual accounts and consolidated accounts), must satisfy the requirement imposed by Art. 19 of that law, providing that “the members of the internal control and financial auditing committee, as a body, are competent in the sector in which the company being audited operates”. Pursuant to the Consolidated Law on Financial Intermediation, the Board of Statutory Auditors monitors: (i) compliance with the law and the Company’s By-laws; (ii) observance of the principles of sound administration; (iii) the appropriateness of the Company’s organizational structure for matters
within the scope of the Board’s Authority, the adequacy of the internal control system and the
administrative and accounting system and the reliability of the latter in accurately representing the Company’s transactions; (iv) the procedures for implementing the Corporate Governance rules provided for in the Corporate Governance Code, which the Company has adopted; and (v) the adequacy of the instructions imparted by the Company to its subsidiaries, in order to guarantee full compliance with legal reporting requirements. In addition, pursuant to Article 19 of Legislative Decree No. 39/2010, (in force as of December 31, 2016) in its role as the “internal control and financial auditing committee” the Board of Statutory AuditorsAuditors: a) informs the Board of Directors of the conclusion of the statutory audit and transmits to the Board the “additional report” of the audit firm adding proper evaluation if deemed necessary; b) oversees the following: (a) the financial reporting process; (b)process and presents recommendations to ensure its integrity; c) controls the efficacyeffectiveness of internal quality control system and Risk Management, the effectiveness of internal audit, (where applicable)with reference to the financial reporting process, without violating its independence; d) oversees the statutory audit of annual accounts and risk management systems; (c) the auditingconsolidated accounts, also considering results of quality control of the annualaudit activity performed by the public authority responsible for regulating the Italian financial statementsmarkets; e) verifies and Consolidated Financial Statements; and (d)monitors the independence of the external auditor oraudit Firm with particular reference to non-audit services; f) is responsible of the Auditprocedure to select the audit Firm, in particular with regardmaking a recommendation to the provisionShareholders’ Meeting for the appointment of non-audit services to the entity subject to financial auditing.audit Firm. The responsibilities assigned under the Legislative Decree No. 39/2010 to the “internal control and financial auditing committee” are consistent and substantively in line with the duties already assigned to the Board of Statutory Auditors of Eni, with specific consideration of its role as Audit Committee pursuant to the “U.S. Sarbanes-Oxley Act” (discussed in greater detail below). As already set forth in the Consolidated Law on Financial Intermediation and currently regulated by Article 13 of Legislative Decree No. 39/2010, the Board of Statutory Auditors submits a reasoned opinion to the Shareholders’ Meeting on the selection of the external auditors and the determination of the associated fees.
As from 2017 the above tasks provided for by the Legislative Decree. no. 39/2010, have been updated by Legislative Decree no. 135/ 2016, to comply with European Directive no 56/2014.
In accordance with law, the Board of Statutory Auditors presents the results of its supervisory activity in a report to the Shareholders Meeting. This report is made available in its entirety to the public within the time limits applicable to the Financial Statements. On March 22, 2005, the Board of Directors, electing the exemption granted by the U.S. Securities and Exchange Commission applicable to foreign issuers listed on the regulated U.S. markets, designated the Board of Statutory Auditors as the body that, as of June 1, 2005, would perform, to the extent permitted under Italian regulations, the functions attributed to the Audit Committee of foreign issuers by the Sarbanes-Oxley Act and U.S. SEC rules. On June 15, 2005, and lastly on May 28, 2014, the Board of Statutory Auditors approved the internal rules, later updated, concerning its performance of the duties assigned to it under that U.S. legislation, the text of which is available on Eni’s website15.website. The key functions performed by the Board of Statutory Auditors acting as an audit committee as provided for by U.S. SEC rules are as follows:include: •
evaluating the offers submitted by external Auditors for their engagement and providing a reasoned recommendation to the Shareholders’ Meeting concerning the engagement or removal of the external Auditor; •
overseeing the work of the external Auditor engaged to audit the accounts or perform other audit, review or certification services; •
examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and c) other material written communication between the external auditor and management; •
making recommendations to the Board of Directors on the resolution of disagreements between management and the auditor regarding financial reporting;reporting. In addition the Board of statutory auditor: •
approvingapproves the procedures for: a) the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters; and b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters;
•
approving the procedures for the pre-approval of specifically identified admissible non-audit services and examining the disclosures on the execution of the authorized services;
•
evaluating requests to use the external auditor firm engaged to perform audit services for admissible non-audit services and providing its opinion to the Board of Directors;
•
examining the periodical reports from the external auditor relating to: a) all critical accounting policies and practices to be used; b) all alternative treatments of financial information within
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These internal rules will be subject to revision and possible updating to take into account the aforementioned regulatory changes.
generally accepted accounting principles that have been discussed with management officials of the Company, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor; and c) other material written communication between the external auditor and management;
•
examiningexamines reports from the CEO and the CFO concerningconcerning: i) any significant deficiency in the design or operation of internal controls which are reasonably likely to adversely affect the
Company’s ability to record, process, summarize and report financial information and any material weakness in internal controls; and
•
examining reports from the CEO and the CFO concerning ii) any fraud that involves management or other employees who have a significant role in the Company’s internal controls.
The Board of Statutory Auditors, in the performance of its duties, is supported by Company’s departments, in particular the Internal Audit Department and the Administrative and Financial Statement Department. Eni Watch Structure and Model 231 In accordance with the Italian regulations concerning the “administrative liability of legal entities deriving from criminal offences”, contained in Legislative Decree No. 231 of June 8, 2001 (henceforth, “Legislative Decree No. 231/2001”), legal entities, including corporations, may be held liable – and consequently fined or subject to prohibitions – in relation to certain crimes attempted or committed in Italy or abroad in the interest or for the benefit of the Company by individuals in high-ranking positions and/or persons managed or supervised by an individual in a high ranking position. The companies may, in any case, adopt organizational, management and control models designed to prevent these crimes. With respect to this issue, Eni Board of Directors – in its Meetings of December 15, 2003 and January 28, 2004 – approved an organizational, management and control model pursuant to Legislative Decree No. 231 of 2001 (Model 231) and created the Watch Structure. Moreover, as a result of changes in the Italian legislation governing the matter and of the Company’s organizational structures, on March 14, 2008, the Board of Directors updated Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of the Eni Code of Conduct of 1998 – which represents a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all business activities are conducted in compliance with laws, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all stakeholders with which Eni relates on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. Since its first adoption, Model 231 has been updated very frequently, in most cases in response to new provisions of law coming into force as well as to organizational changes in the company’s structure. Most recently, the Board of Directors, in its meeting of October 27, 2016, ratifiedSeptember 19, 2019 approved the updating of Model 231231. During 2019, in accordance with Eni Watch Structure, Eni has conducted a project to incorporate a number of legislative changes inrevise and transform the environmental crimes provided for by Law no. 68/2015 (“eco-crimes”). The synergies between theexisting Code of Ethics, – an integral part and essential general principlewhose very “procedural” nature was justified by the different internal regulatory context existing at the time of its first adoption, into a modern charter of values.
The Board of Directors, in its meeting of March 18, 2020, approved the new version of Eni’s Code of Ethics; the new Code sets out the fundamental principles of Eni’s Model 231 – and Model 231 are highlighted by the assignment, to the Eni Watch Structure,which is one of the functionpillars of Guarantor of the Code of Ethics. Eni “regulatory system” and inspires it. At present, the Watch Structure of Eni is composed of three external members, including the Chairman, and four internal members. The internal members are Company executives in charge of Legal Affairs, labor law matters and disputes, Internal Audit and Integrated Compliance. External members are independent professionals, experts in law and/or economic matters. Also in order to grant the Watch Structure the greatest extent of autonomy and independence, the set of rules adopted by the Watch Structure provide for specific quorum to convene and to pass resolutions so to ensure that all resolutions are effectively adopted with the favourable vote of the majority of the external members. Audit Firm The auditing of the Company’s accounts is entrusted, in accordance with the law, to an independent Audit Firm appointed by the Shareholders’ Meeting on the basis of a reasoned recommendation of the Board of Statutory Auditors. In addition to the obligations set forth in national auditing regulations, Eni’s listing on the New York Stock Exchange requires that the Audit Firm issueissues a report on the Annual Report on Form 20-F, in compliance with the auditing principles generally accepted in the United States. Moreover, the Audit Firm is required to issue an opinion on the efficacy of the internal control system applied to financial reporting.
For the most part, the subsidiaries’ financial statements are subject to auditing by Eni’s Audit Firm. Moreover, Eni’s Audit Firm, for the purpose of issuing an opinion on the Consolidated Financial Statements, assumes responsibility for the auditing activities performed by other audit firms with respect to subsidiaries’ financial statements, which, taken together, account for an immaterial share of consolidated assets and revenues. Acting on the Board of Statutory Auditors’ reasoned proposal, the Shareholders’ Meeting of April 29, 2010 appointed Ernst & YoungMay 10, 2018 approved the engagement of PricewaterhouseCoopers SpA to perform the external statutory audit of the accounts of Eni SpA and the audit of the internal control system over financial reporting, pursuant to US law, for the financial years 2010-2018.period 2019 – 2027. Court of Auditors (Corte dei conti) The financial management of Eni is subject to the control of the Court of Auditors in order to preserve the integrity of the public finances. This task ishas been carried out by the Magistrate of the Court of Auditors, Adolfo Teobaldo De Girolamo, appointed by the Presidential Council of the Court of Auditors on December 22, 2014. 2014, until February 28, 2019. As from March 1, 2019 the task is performed by the Magistrate of the Court of Auditors Manuela Arrigucci, on the basis of the resolution approved on December 18-19, 2018 by the Presidential Council of the Court of Auditors. The Magistrate of the Court of Auditors attends the meetings of the Board of Directors, the Board of Statutory Auditors and the Control and Risk Committee. Employees As of December 31, 2016,2019, Eni had a total of 33,53632,053 employees, with an increase of 352 employees, up by 1.1% compared to December 31, 2018, which mainly reflects an increase of 486 employees working in Italy and a decrease of 660 employees, or down by 1.9% from December 31, 2015, which mainly reflects a decrease of 690134 employees working outside Italy.abroad. The increase of personnel headcount in Italy is mainly due to the execution of the turn-over plan for guaranteeing a structure consistent with the objectives of starting up new businesses, rebalancing the business portfolio and enhancing the opportunities offered by new technologies. Outside Italy the reduction of personnel headcount is mainly due to some strategic operations including the transfer to third parties of Exploration & Production activities in Ecuador. Employees at year end | | | | | | | | 2014 (1) | | | 2015 (1) | | | 2016 | | | | | (number) | | Exploration & Production | | | | | 12,777 | | | | | | 12,821 | | | | | | 12,494 | | | Gas & Power | | | | | 4,561 | | | | | | 4,484 | | | | | | 4,261 | | | Refining & Marketing and Chemicals | | | | | 11,884 | | | | | | 10,995 | | | | | | 10,858 | | | Corporate and Other activities | | | | | 5,624 | | | | | | 5,896 | | | | | | 5,922 | | | | | | | | 34,846 | | | | | | 34,196 | | | | | | 33,536 | | | |
(1)
Excluding the operating segment E&C divested in January 2016.
| | | 2019 | | | 2018 | | | 2017 | | | | | (number) | | Exploration & Production | | | | | 11,502 | | | | | | 11,645 | | | | | | 11,970 | | | Gas & Power | | | | | 3,015 | | | | | | 3,040 | | | | | | 4,313 | | | Refining & Marketing and Chemicals | | | | | 11,291 | | | | | | 11,136 | | | | | | 10,916 | | | Corporate and Other activities | | | | | 6,245 | | | | | | 5,880 | | | | | | 5,735 | | | | | | | | 32,053 | | | | | | 31,701 | | | | | | 32,934 | | | |
The table below sets forth Eni’s employees as of December 31, 2014, 20152017, 2018 and 20162019 in Italy and outside Italy: | | | | | | | | | | | | | | 2014 (1) | | | 2015 (1) | | | 2016 | | | | | | | | (number) | | 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 | | | 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 | | | | | | | | 1,074 | | | | | | 1,061 | | | | | | 1,036 | | | |
(1)
Excluding the operating segment E&C divested in January 2016.
| | | | | | | | | | | | | | | | | | | | | | 2019 | | | 2018 | | | 2017 | | | | | | | | (number) | | Exploration & Production | | | Italy | | | | | 4,556 | | | | | | 4,531 | | | | | | 4,510 | | | | | | Outside Italy | | | | | 6,946 | | | | | | 7,114 | | | | | | 7,460 | | | | | | | | | | | 11,502 | | | | | | 11,645 | | | | | | 11,970 | | | Gas & Power | | | Italy | | | | | 2,040 | | | | | | 2,089 | | | | | | 2,282 | | | | | | Outside Italy | | | | | 975 | | | | | | 951 | | | | | | 2,031 | | | | | | | | | | | 3,015 | | | | | | 3,040 | | | | | | 4,313 | | | Refining & Marketing and Chemicals | | | Italy | | | | | 8,901 | | | | | | 8,740 | | | | | | 8,580 | | | | | | Outside Italy | | | | | 2,390 | | | | | | 2,396 | | | | | | 2,336 | | | | | | | | | | | 11,291 | | | | | | 11,136 | | | | | | 10,916 | | | Corporate and other activities | | | Italy | | | | | 5,991 | | | | | | 5,642 | | | | | | 5,501 | | | | | | Outside Italy | | | | | 254 | | | | | | 238 | | | | | | 234 | | | | | | | | | | | 6,245 | | | | | | 5,880 | | | | | | 5,735 | | | Total | | | Italy | | | | | 21,488 | | | | | | 21,002 | | | | | | 20,873 | | | | | | Outside Italy | | | | | 10,565 | | | | | | 10,699 | | | | | | 12,061 | | | | | | | | | | | 32,053 | | | | | | 31,701 | | | | | | 32,934 | | | of which senior managers | | | | | | | | 1,031 | | | | | | 1,016 | | | | | | 1,012 | | |
We seek to maintain constructive relationship with labor unions. Share ownership As of February 28, 2017,2020, the cumulative number of shares owned by Eni’s Directors, Statutory Auditors and Senior Managers was 303,091269,178 less than 0.1% of Eni’s share capital outstanding as of the same date. Eni issues only ordinary shares, each bearing one-vote right; therefore shares held by those persons have no different voting rights. The breakdown of share ownership for each of those persons is provided below. Furthermore, on March 19, 2020, the CEO of Eni purchased on the open market 29,300 shares. Name | | | Position | | | Number of shares owned | | Board of Directors | | | | | | | | | | | Emma Marcegaglia | | | Chairman | | | | | 87,44787,010(1) | | | Claudio Descalzi | | | CEO | | | | | 39,45568,755(2) | | | Board of
| | | | | | | | | | | Statutory Auditors | | | | | 5,000 (2)none | | | Senior Managers | | | | | 171,189142,713(3) | | | |
(1)
Of which No. 1,034597 shares held under Asset Management, No. 7,143 shares held under Asset Management jointly with a third person, and No. 45,000 shares held as naked ownerin bare ownership jointly with a third person. (2)
Shares held under Asset Management.Updated as of March 19, 2020.
(3)
Of which No. 14,3906,890 shares owned by spouseswives not legally separated and by underage children.
Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS Major Shareholders The Ministry of Economy and Finance controls Eni as a result of the shares directly owned and those indirectly owned through Cassa Depositi e Prestiti SpA (CDP), in which the Ministry of Economy and Finance holds a 82.77% stake. As of February 28, 2017,2020, the total amount of Eni’s voting securities owned, by these shareholders was: Title of class | | | Number of shares owned | | | Percent of class | | Ministry of Economy and Finance | | | | | 157,552,137 | | | | | | 4.34 | | | Cassa Depositi e Prestiti SpA | | | | | 936,179,478 | | | | | | 25.76 | | | |
The following table shows the percentage of Eni’s share capital owned, either directly or indirectly, by persons that as of February 28, 2017 have notified that their holding either exceeds the threshold of 3% since March 18, 20161 pursuant to Article 120 of the Legislative Decree No. 58/1998 (as amended by article 1 of Legislative Decree No. 25 of February 15, 2016) and to the Consob Regulation No. 11971/1999 (as amended by Consob Resolution No. 19614was:
Title of class | | | Number of shares owned | | | Percent of class | | Ministry of Economy and Finance | | | | | 157,552,137 | | | | | | 4.34 | | | Cassa Depositi e Prestiti SpA | | | | | 936,179,478 | | | | | | 25.76 | | |
As of May 26, 2016) orFebruary 28, 2020, the previous thresholdpercentage of 2% (in effect until March 17, 2016)Eni’s treasury shares was equal to 1.70% of the share capital12. Title of class | | | Percent of class | | People’s Bank of China | | | | | 2.102 | | | |
Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012, modifiedIn relation to the Italian legislation governing the special powers of the Italian State to comply with European rules. Seesee “Item 10 – Additional information – Limitations on changes in control of the Company (Special Powers of the Italian State)”.
As of February 28, 2017,March 10, 2020, there were 36,611,56933,623,608 ADRs outstanding, each representing two Eni ordinary shares, corresponding to approximately 2.0%1.9% of Eni’s share capital. See “Item 9 – The offer and the listing”. Related partyparties transactions In the ordinary course of its business, Eni enters into transactions concerning the exchange of goods, provision of services and financing with non-consolidated subsidiaries andassociates, joint ventures, joint operations or other affiliates, as well as other companies owned or controlled by the Italian Government. All such transactions are conducted on an arm’s length basis and in the interest of Eni Group companies. Amounts and types of trade and financial transactions with related parties and their impact on consolidated earnings and cash flow, and on the Group’s assets and financial condition are reported in “Item 18 – note 47Note 36 of the Notes on Consolidated Financial Statements”. (1)
The Legislative Decree No. 25/2016, in force since March 18, 2016, modified theMajor holdings pursuant to Article 120 of the Legislative Decree No. 58/1998 increasing this holding threshold from 2%are updated also on the basis of communication made by intermediaries pursuant to 3%. See “Item 10 – Additional information – Shareholder ownership thresholds”.Article 83-novies of the Legislative Decree No. 58/1998 in order to exercise the corporate rights.
(2)
In its meeting of 27 February 2020, Eni’s Board of Directors resolved to submit to the Shareholder’s Meeting, to be held on 13 May 2020, the proposal of cancellation of the treasury shares acquired in 2019.
Item 8. FINANCIAL INFORMATION Consolidated Statements and other financial information See “Item 18 – Financial Statements”. Legal proceedings Eni is a party to a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions disclosed in Note 20 to the Consolidated Financial Statements and that in some instances a negative outcome is not probable or it is not possible to make a reliable estimates of contingency losses, Eni believes that the foregoingthese legal proceedings will likely not have a material adverse effect on Eni’s Consolidated Financial Statements. For a description of legal proceedings in which Eni is involved and which may affect Eni’s financial position and results of operations see “Item 18 – note 38Note 27 of the Notes on Consolidated Financial Statements”. Dividends Eni’s futureManagement is committed to a progressive shareholders’ remuneration policy in line with our plans of underlying earnings and cash flow growth and considering the scenario evolution. For the year 2020 management is planning to distribute a full-year dividend of €0.89 per share, up by approximately 3.5% vs. 2019. The Company’s dividend policy as well asgoing forward and the sustainability of the dividends that the Company is planning to distribute over the next four years will depend upon a number of factors including achievement of the Company’s industrial targets, future levels of profitability and cash flow provided by operating activities, a sound balance sheet structure, capital expenditures and development plans, in light of the “Risk factors” set out in Item 3 and the oil price scenarioand exchange rate assumptions adopted by management and other planning and scenario assumptions described in “Item 5 – Management’s expectations of operations”. The parent company’s net profit and, therefore, the amounts of earnings available for the payment of dividends will also depend on the level of dividends received from Eni’s subsidiaries.
In 2017, we confirm our commitment to pay a full cash dividend of €0.80 per share and, later on, to a progressive distribution policy in line with the achievement of our plans of underlying earnings and cash flow growth and the scenario evolution. For further information on the Company’s dividend policy see “Item 5 – Management’s Expectations of Operation.”
In future years, management expects to continue paying interim dividends for each fiscal year, with the balance for the full-year dividend paid in the following year. For further information on the Company’s dividend policy see “Item 5 – Management’s expectations of operations.” The expectations described above are subject to risks, uncertainties and assumptions associated with the oil&gas industry, and economic, monetary and political developments in Italy and globally that are difficult to predict. For further details see “Item 3 – Risk factors” and the other planning assumptions and initiatives described in “Item 5 – Management’s expectations of operations”. At the General Shareholders’ Meeting scheduled on AprilMay 13, 2017,2020, management intends to propose the distribution of a dividend of €0.80€0.86 per share for fiscal year 2016,2019, of which €0.40€0.43 already paid as interim dividend in September 2016.2019. Total cash outlay for the 2016 balance2019 final dividend is expected at approximately €1.4€1.5 billion to be paid in 2020 (whereas €1.4€1.5 billion were distributed in September 2016)2019) if the General Shareholders’ Meeting approves the annual dividend. Significant changes See “Item 5 – Recent developments”developments and Management’s expectations of operations” for a discussion of significant eventssubsequent business developments and transactions occurred after 2016 year endthe closing date up to the latest practicable date.
Item 9. THE OFFER AND THE LISTING Offer and listing details The principal trading market for the ordinary shares of Eni SpA (Eni), without indication of par value (the “Shares”), is the Mercato Telematico Azionario (Electronic Share Market or “MTA”). MTA, which is the principal trading market for shares in Italy, is a regulated market organized and managed by Borsa Italiana SpA (Borsa Italiana). Eni’s American Depositary Receipts (ADRs), each representing two Shares, are listed on the New York Stock Exchange.
The table below sets forth the reported high and low reference prices of Shares on MTA and of ADRs on the New York Stock Exchange, respectively. See “Item 3 – Key information – Exchange rates” regarding applicable exchange rates during the periods indicated below.
| | | MTA | | | New York Stock Exchange | | | | | High | | | Low | | | High | | | Low | | | | | (Euro per share) | | | (U.S.$ per ADR) | | Year ended December 31, | | | | | | 2012 | | | | | 18.700 | | | | | | 15.250 | | | | | | 49.440 | | | | | | 36.850 | | | 2013 | | | | | 19.480 | | | | | | 15.290 | | | | | | 52.120 | | | | | | 40.390 | | | 2014 | | | | | 20.410 | | | | | | 13.290 | | | | | | 55.300 | | | | | | 32.810 | | | 2015 | | | | | 17.430 | | | | | | 13.140 | | | | | | 39.290 | | | | | | 29.280 | | | 2016 | | | | | 15.470 | | | | | | 10.930 | | | | | | 33.330 | | | | | | 25.000 | | | 2015 | | | | | | First quarter | | | | | 16.680 | | | | | | 13.370 | | | | | | 37.690 | | | | | | 31.960 | | | Second quarter | | | | | 17.430 | | | | | | 15.720 | | | | | | 39.290 | | | | | | 34.940 | | | Third quarter | | | | | 16.210 | | | | | | 13.140 | | | | | | 35.610 | | | | | | 30.300 | | | Fourth quarter | | | | | 15.730 | | | | | | 13.240 | | | | | | 36.020 | | | | | | 29.280 | | | 2016 | | | | | | First quarter | | | | | 13.800 | | | | | | 10.930 | | | | | | 31.050 | | | | | | 25.000 | | | Second quarter | | | | | 14.580 | | | | | | 12.320 | | | | | | 33.330 | | | | | | 28.170 | | | Third quarter | | | | | 14.900 | | | | | | 12.310 | | | | | | 33.250 | | | | | | 27.650 | | | Fourth quarter | | | | | 15.470 | | | | | | 12.260 | | | | | | 32.240 | | | | | | 26.260 | | | Month of | | | | | | September 2016 | | | | | 14.030 | | | | | | 12.310 | | | | | | 31.600 | | | | | | 27.650 | | | October 2016 | | | | | 13.770 | | | | | | 12.890 | | | | | | 30.170 | | | | | | 28.940 | | | November 2016 | | | | | 13.140 | | | | | | 12.260 | | | | | | 28.740 | | | | | | 26.260 | | | December 2016 | | | | | 15.470 | | | | | | 13.540 | | | | | | 32.240 | | | | | | 28.650 | | | January 2017 | | | | | 15.720 | | | | | | 14.210 | | | | | | 33.260 | | | | | | 30.880 | | | February 2017 | | | | | 14.580 | | | | | | 14.120 | | | | | | 31.260 | | | | | | 30.070 | | | March 2017 (through March 17, 2017) | | | | | 15.270 | | | | | | 14.470 | | | | | | 32.250 | | | | | | 30.780 | | | |
Since January 18, 2012, the Bank of New York MellonJune 27, 2017, Citibank N.A. (the “Depositary”) functions as the company’s depositary bank issuing ADRs pursuant to a deposit agreement (the “Deposit Agreement”) among Eni, the Depositary and the beneficial owners (“Beneficial Owners”) and registered holders from time to time of the ADRs issued hereunder. As of February 28, 2017,March 10, 2020, there were 36,611,56933,623,608 ADRs outstanding, representing 71,233,13867,247,216 ordinary shares or approximately 2%1.9% of all Eni’s shares outstanding, held by 10592 holders of record (including the Depository Trust Company) in the United States, 10491 of which are U.S. residents. Since certain of such ADRs are held by nominees, the number of holders may not be representative of the number of Beneficial Owners in the United States or elsewhere. Theelsewhere.The Shares are included in the FTSE MIB Index (the “FTSE MIB”), the primary benchmark index for the Italian Stock Exchange. Capturing approximately 80% of the domestic market capitalization, the FTSE MIB measures the performance of 40 highly liquid, leading companies across leading industries listed on
MTA and the Investment Vehicles Market (MIV) and seeks to replicate the broad sector weights of the Italian Stock Exchange. The constituents of the FTSE MIB are selected based on market capitalization of free float shares and liquidity. The FTSE MIB is market cap-weighted after adjusting constituents for free float and foreign ownership limits. Since June 1, 2009, the FTSE MIB is the principal indicator used to track the performance of the Italian Stock Exchange and is the basis for future and option contracts traded on the Italian Derivatives Market (IDEM) managed by Borsa Italiana. The Shares are the first largesta component of the FTSE MIB, with a weighting of approximately 14%9,4%, as established by FTSE Russel after the quarterly rebalancing for FTSE MIB effective December 19, 2016.23, 2019. Beginning from October 6, 2014, aA two-day rolling cash settlement applies to all trades of equity securities on Borsa Italiana. Besides Shares traded on MTA, futures and options contracts on the Shares are traded on IDEM and securitized derivatives based on the Shares are traded on the Italian Securitized Derivatives Marketmultilateral trading facility of securitised derivatives financial instruments, organised and managed by Borsa Italiana (SeDeX). IDEM facilitates the trading of futures and options contracts on index and shares issued by companies that meet certain required capitalization and liquidity thresholds. SeDeX is the Borsa Italiana electronic regulated marketmultilateral trading facility where it is possible to trade securitized derivatives (for instance, covered warrants and certificates).
Borsa Italiana disseminates daily market data and news for each listed security, including volume traded and high and low prices. At the end of each trading day an “official price”, calculated as the weighted average price of the total volume of each security traded in the market during the session without taking into account the contracts concluded with cross trades, and block trades, and a “reference price”, calculated as the closing auction price, are reported by Borsa Italiana. For the purposes of the automatic control of the regularity of trading on MTA, the following price variation limits shall apply to contracts concluded on shares making up the FTSE MIB, effective February 13, 2017:3, 2020: (i) ± 5.0% (or such other amount established by Borsa Italiana in the “Guide to the Parameters” for trading on the regulated markets organized and managed by Borsa Italiana) with respect to the static price (the static price shall bebeing the previous day’s reference price, in the opening auction or the price at which contracts are concluded in the auction phase after each auction phase; if no auction price is determined, the static price is equal to the price of the first contract concluded in the continuous trading phase); and (ii) ± 3.5% (or such other amount established by Borsa Italiana in the “Guide to the Parameters”) with respect to the dynamic price (the price of the last contract concluded during the continuous trading phase). Where the price of a contract that is being concluded exceeds one of the price variation limits referred to above, trading in that security will be automatically suspended and a volatility auction phase begun for a certain period of time. Markets Consob is the public authority responsible for regulating and supervising the Italian securities markets to, inter alia, ensure the transparency and regularity of the dealings and protect the investing public. Borsa Italiana, which is part of London Stock Exchange Group, following the merger effective October 1, 2007, is a joint stock company authorized by Consob to operate, inter alia, regulated markets in Italy; it is responsible for the organization and management of the Italian Stock Exchange. One of the fundamental characteristics of the financial market organization in Italy is the separation of responsibility for supervision (Consob and the Bank of Italy) from that of market management (Borsa Italiana). Main responsibilities of Borsa Italiana are the admission, exclusion and suspension of financial instruments and intermediaries to and from trading and the surveillance of the markets.
According to Consob regulations, Borsa Italiana has issued rules governing the organization and management of the Italian Regulated Markets it is responsible for, which, inter alia, are MTA (shares,(for example, shares, convertible bonds, pre-emptive rights, warrants and Funds)warrants), ETFplus (Exchange(for example, Exchange Traded Funds, Exchange Traded Commodities, Exchange Traded Notes, Structured ETFs and open-ended funds market)Actively managed ETFs), IDEM (index, stock(futures and other derivatives market), SeDeX (covered warrants and certificates)options contracts whose underlying assets are financial instruments, interest rates, foreign currencies, goods or related indexes), MOT (bond market) and MIV (market for investment vehicles), as well as the admission to listing on and trading on these markets. According to EUthe regulatory framework introduced by Markets in Financial Instruments Directive (No. 2004/39/EC) (MiFID)No. 2014/65/EU as amended (“MiFID II”), as implemented in Italy, and Regulation (EU) No. 600/2014 (“MiFIR”), applicable from January 3, 2018, and Consob regulations, orders can be routed not only to Regulated Markets but also to either Multilateral Trading Facilities (MTFs) or Systematic Internalisers. A MTF is a multilateral system, operated by an investment firm or a market operator, which brings together multiple third-party buying and selling interests in financial instruments – in the system and in accordance with non-discretionary rules – in a way that results in a contract. A Systematic Internaliser is an investment firm or a bank which, on an organized, frequent systematic and substantial basis, deals on own account bywhen executing client orders outside a Regulated Market, an MTF or an Organized Trading Facility (“OTF”) without operating a MTF. Outside Regulated Markets, block trading is also permitted for orders that meet certain minimum size requirements and must be notified to Consob and Borsa Italiana.
multilateral system. Following the transposition in Italy of Directive No. 2014/65/EU (“MiFID II”), which is due to be implemented by 3 January 2018, Organized Trading Facilities (“OTFs”) will beII and the application of MiFIR, OTFs are now included among the “trading venues” that are subject to regulation. An OTF is a multilateral system which is not a Regulated Market or an MTF and in which multiple third-party buying and selling interests in bonds, structured finance products, emission allowances or derivatives are able to interact in the system in a way that results in a contract. The implementation of the MiFID II and entry into force of the Regulation (EU) No. 600/2014 (“MiFIR”) will entail some additional changes to the regulatory framework currently applicable to Regulated Markets, MTFs and Systematic Internalisers. According to Legislative Decree No. 58 of February 24, 1998, as amended from time to time (“Decree No. 58”, the Consolidated Law on Financial Intermediation), the provision of investment services and activities to the public on a professional basis is, inter alia, reserved to investment firms, EU investment companies, Italian banks, EU banks and investment firmscompanies of non-EU countries authorized to operate in Italy (“authorized persons”). The Bank of Italy and Consob shall exercise supervisory powers over authorized persons. They shall each supervise the observance of regulatory and legislative provisions according to their respective responsibilities. In particular, in connection with the pursuance of the safeguarding of faith in the financial system, the protection of investors, the stability and correct operation of the financial system, the competitiveness of the financial system and the observance of financial provisions, the Bank of Italy shall be responsible for risk containment, asset stability and the sound and prudent management of intermediaries whilst Consob shall be responsible for the transparency and correctness of conduct. Besides, for the purposes of the application of certain provisions of MiFIR the Bank of Italy and Consob are the Italian competent authorities: Consob is competent, inter alia, as far as the protection of the investors, the orderly functioning and soundness of the financial markets or of the commodity markets are concerned whereas the Bank of Italy is competent as far as the stability of the whole or part of the financial system is concerned. The Bank of Italy and Consob also regulate the operation of the clearing and settlement service for transactions involving financial instruments as well as the performance of central securities depository services, in line with the European framework – in particular, the Regulation (EU) No. 648/2012, as amended from time to time, (“EMIR”) and the Regulation (EU) No. 909/2014, as amended from time to time, (“Central Securities Depositories Regulation”). The regulations and measures of general application adopted by Consob and the Bank of Italy are available on the website of Consob (www.consob.it) or Bank of Italy (www.bancaditalia.it). The regulations adopted by Borsa Italiana are available on its website (www.borsaitaliana.it).
Item 10. ADDITIONAL INFORMATION Memorandum and Articles of Association Company register “Eni SpA” is the company resulting from the privatization of Ente Nazionale Idrocarburi, a public agency, established by Law No. 136 of February 10, 1953 and it is registered in the Rome Companies Register, with identification number (and tax number) 00484960588, and VAT number 00905811006. The Company’s registered office is in Rome, Italy, and the Company has two branch offices in San Donato Milanese (Milan). The full text of Eni’s By-laws is attached as an exhibit to this Annual Report (last amended on November 20, 2014).Report. On February 27, 2020 the Board approved an amendment to the By-laws regarding gender quotas in the composition of corporate bodies pursuant to Law no. 160 of 2019. See “Exhibit 1”. Company objects and purpose In accordance with Article 4 of Eni’s By-laws, the Company purpose includes the direct and/or indirect exercise, through equity holdings in companies or other entities of: activities in the field of hydrocarbons and natural gases, in compliance with the terms of concessions provided for by law; activities in the field of chemicals, nuclear fuels, geothermal energy, renewable energy sources and energy in general, in the design and construction of industrial plants, in the mining industry, in the metallurgy industry, in the textile machinery industry, in the water sector, including water diversion, potabilization, purification, distribution and reuse; in the environmental protection sector and in the treatment and disposal of waste, as well as any other economic activity that is instrumental, ancillary or complementary to the aforementioned activities. The Company performs and manages the technical and financial coordination of subsidiaries and associated companies and provides financial assistance to them. Moreover, the Company may acquire equity holdings and interests in other companies or enterprises with corporate purposes that are similar, related or complementary to its own or those of companies in which it has equity holdings, either in Italy or abroad, and it may provide secured and/or unsecured guarantees for its own and others’ obligations, including, in particular, sureties.
Directors’ issues Eni’s Board of Directors is invested with the fullest powers for the ordinary and extraordinary management of the Company and, in particular, the Board has the power to perform all acts it deems advisable for the implementation and achievement of the corporate purpose, with the sole exception of acts that the law or Eni’s By-laws reserve to the Shareholders’ Meeting. If the Shareholders’ Meeting has not appointed a Chairman of the Board, the Board shall elect one from among its members. The Board of Directors appoints a Chief Executive Officer and delegates to him all necessary powers for the management of the Company, with the exception of those powers that cannot be delegated in accordance with current legislation and those retained exclusively by the Board of Directors on matters regarding major strategic, operational and organizational decisions. According to Eni’s By-laws, the Board of Directors may delegate powers to the Chairman to identify and promote integrated projects and international agreements of strategic importance. The Board of Directors may at any time revoke the powers delegated, proceeding, in the case of revocation of the powers delegated to the Chief Executive Officer, to appoint another Chief Executive Officer at the same time. The Board of Directors, acting upon a proposal of the Chairman and in agreement with the Chief Executive Officer, may confer powers for individual acts or categories of acts on other members of the Board of Directors. In accordance with Eni’s By-laws, for a Board meeting to be valid, a majority of serving Directors must be present. Resolutions shall be approved by a majority of the votes of the Directors present; in the event of a tie, the person who chairs the meeting shall have a casting vote. For further information on Directors’ duties and responsibilities and, in particular, the role of the Chairman see “Item 6 – Board of Directors’ duties and responsibilities”.
Interests in Company’s transactions As provided by the Italian Civil Code, when a Director retains a personal interest or an interest on behalf of third parties in Company transactions, he shall disclose it to the Board of Directors and to the Board of Statutory Auditors, specifying the nature, terms, origin and extent of such interest. Based on this provision and in compliance with the Consob (“Commissione Nazionale per le Società e la Borsa” is the public authority responsible for regulating the Italian financial markets) regulation on transactions with related parties (the “Consob Regulation”), the Board of Directors – on November 18, 2010 – unanimously approved the Management System Guidelines “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties”1 (“MSG”), which has been in effect from January 1, 20112 to ensure the transparency and substantial and procedural fairness of transactions with related parties and with parties that are of interest to Eni’s Directors and Statutory Auditors, carried out by Eni itself or its subsidiaries. This MSG and the subsequent amendments received the preliminary favorable opinion, expressed unanimously, of the Control and Risk Committee, composed entirely of independent Directors as per the requirements set out in the Corporate Governance Code, which Eni has adopted, and in accordance with the Consob Regulation. The MSG sets out monitoring and evaluation requirements for the preliminary phase and for carrying out a transaction with a party in which a Director or Statutory Auditor has an interest. In this regard, both in the preliminary and deliberation phase, a thorough, documented examination of the reasons for the transaction, highlighting the Company’s interest in carrying it out and the soundness and fairness of the underlying terms, is required. Directors involved in matters subject to Board resolution normally shall not participate in the relevant discussion and decision and shall leave the room during these procedures. If the person involved is the Chief Executive Officer and the transaction falls under his duties, he shall in any case abstain from taking part in the transaction and (1)
The Board of Directors modified this Management System Guideline on January 19, 2012.
(2)
This MSG replaced the previous regulation issued by the Board of Directors on the matter on February 12, 2009. The new provisions regarding information to be provided to the public, under both the Consob Regulation and the MSG, have been applied since December 1, 2010.
shall entrust the matter to the Board of Directors (as provided by Article 2391 of the Italian Civil Code). In any case, if the transaction is under the responsibility of the Board of Directors of Eni, a non-binding opinion from the Control and Risk Committee is required. Moreover, to ensure compliance with the procedures envisaged by the above mentioned MSG, Directors and Statutory Auditors issue a declaration, every six months and/or when there is any change, in which they explainstate their potential interests related to Eni and its subsidiaries, and insubsidiaries. In any case they inform the CEO (orDirectors and the Chairman,Statutory Auditors report in good time the case the CEO holds an interest) about individualsingle transactions that Eni intends to carry out in which they have an interest;interest. Directors report the CEOinterest to the Chief Executive officer (or Chairman)the Chairman, in the case of interests of the Chief Executive Officer), who will then informin turn notify the other Directors and the Board of Statutory Auditors. Statutory Auditors report the interest to the other Statutory Auditors and the Chairman of the Eni SpA Board of Directors. Compensation Directors’ compensation shall be determined by the Shareholders’ Meeting, as required by Italian law, while the compensation of Directors assigned particular dutieswith delegated powers in accordance with the By-laws (such as the Board Chairman and the CEO), or that participate in Board Committees, shall be determined by the Board of Directors, upon the proposal of the CompensationRemuneration Committee, after consultation withexamining the opinion of the Board of Statutory Auditors (for more details about the compensation policy in 2016,2019, see “Item 6 – Compensation”)the Remuneration Report 2020 incorporated herein by reference). Borrowing powers The power to borrow is included in the Company purpose. Moreover, in accordance with Article 11 of the By-laws, the Company may issue bonds, including convertibles bonds and warrants, in compliance with the law. Retirement and shareholdings There are no provisions in the By-laws relating to either retirement based on age-limit requirements and the number of shares required for a Director to qualify. Company’s shares In accordance with Article 5 of the By-laws, the Company’s share capital amounts to €4,005,358,876.003, fully paid, and is represented by 3,634,185,330 ordinary registered shares without indication of par value. As required by the Italian law on the dematerialization of financial instruments, (1)
The Board of Directors modified this Management System Guideline on January 19, 2012 and lastly on April 4, 2017. (2)
This MSG replaced the previous regulation issued by the Board of Directors on the matter on February 12, 2009. The provisions regarding information to be provided to the public, under both the Consob Regulation and the MSG, have been applied since December 1, 2010. (3)
In its meeting of 27 February 2020, Eni’s Board of Directors resolved to submit to the Shareholders’ Meeting, convened on May 13, 2020, the proposal of cancellation of treasury shares acquired in 2019.
Eni’s shares (the “Shares”) must be held with “Monte Titoli SpA” (the Italian Central Securities Depository) and their beneficial owners may exercise their rights through special deposit accounts opened with intermediaries, such as banks, brokers and securities dealers. Shares are indivisible and each share is entitled to one vote. Shareholders are allowed to vote at ordinary and extraordinary Shareholders’ Meeting, including by proxy or by mail or, if envisaged in the notice calling the Meeting, by electronic means. Moreover, in accordance with Article 9 of the By-laws, the Shareholders’ Meeting may resolve to increase the Company share capital by issuing shares, including shares of different classes, to be granted for no consideration to Eni employees, pursuant to Article 2349 of the Italian Civil Code. This power has not been exercised. In 1995, Eni established a sponsored American Depositary Receipts program directed at U.S. investors. Each Eni ADR is equal to two Eni ordinary shares; Eni ADRs are listed on the NYSE. Dividend rights Shareholders have the right to participate in profits and any other rights as provided by the law and subject to any applicable legal limitations. Specifically, the ordinary Shareholders’ Meeting called to approve the annual Financial Statements may allocate the net income resulting after allotment to the legal reserve to the payment of a final dividend per share. In addition, during the course of the financial year, the Board of Directors may distribute, as allowed by the By-laws, interim dividends to the shareholders. Entitlement to dividends not collected within five years of the day on which they become payable shall lapse in favor of the Company and such dividends shall be allocated to reserves.
Voting rights The general provisions on share “voting rights” are described at the paragraph “Shareholders’ Meeting” below. In relation to the appointment of the Board of Directors (Eni’s Board is not a “staggered board”) and the Board of Statutory Auditors (see “Item 6”), Eni’s By-laws provide for a slate voting system. In particular, pursuant to Article 17 of the By-laws and in accordance with applicable law, slates may be presented both by shareholders, either severally or jointly, representing at least 1% of the share capital, or any other threshold established by Consob in its regulation (lastly, on January 25, 2017,30, 2020, Consob confirmed a threshold of 0.5% for Eni, given its market capitalization), or by the Board of Directors. Each shareholder may, severally or jointly, submit and vote on a single slate only. There are no provisions in Eni’s By-laws relating to: rights to share in Company profits; redemption provisions; sinking fund provisions; liability to further capital calls by the Company. Liquidation rights In the event the Company is wound up, the Shareholders’ Meeting shall decide the manner of its liquidation and appoint one or more liquidators, establishing their powers and remuneration. In accordance with Italian law, shareholders would be entitled to the distribution of the remaining liquidated assets of the Company in proportion to their shareholdings, only after payment of all the Company’s liabilities and satisfaction of all other creditors. Change in shareholders’ rights A shareholders’ resolution is required to make changes in shareholders’ rights. Italian law gives shareholders the right to withdraw in the event of an amendment of the provisions of the By-laws relating to, among other matters, voting and dividend rights, approved by resolution of the Shareholders’ Meeting with the attendance and decision making quorum established by law for extraordinary meetings. Shareholders’ Meeting The Shareholders’ Meeting resolves on the issues set forth by applicable law and Eni’s By-laws, in “ordinary” or “extraordinary” form. The ordinary and the extraordinary Shareholders’ Meetings are normally held after a single call, with the majorities required by law in this case. The Board of Directors may, if deemed necessary, establish that both the ordinary and the extraordinary Shareholders’ Meetings shall be held after more than one call; their resolutions at first, second or third call must be passed with the majorities required by law in each case.
Shareholders’ Meetings shall normally be held at the Company’s registered office, unless otherwise decided by the Board of Directors, provided however they are held in Italy. The Shareholders’ Meeting shall be called by way of a notice published on the Company website, as well as in accordance with the procedures specified in Consob regulations, by the statutory deadlines and in accordance with applicable law. The notice calling the meeting, the content of which is defined by the law and Eni’s By-laws, contains all the information for attending and voting at the meeting, including information on proxy voting and voting by mail (the information is also available on the Company’s website) and, if envisaged, it may include instructions for participating in the Shareholders’ Meeting by means of telecommunication systems, as well as exercising the right to vote by electronic means. The Board of Directors shall make a report on each of the items on the agenda available to the public at the Company’s registered office, on the Company’s website and by other means envisaged by Consob regulations by the same date of the publication of the notice calling the Shareholders’ Meeting for each of the items on the agenda. Specific legal provisions may require other terms of publication of the Board of Directors report (i.e. in case of extraordinary transactions). An ordinary Shareholders’ Meeting shall be called at least once a year, within 180 days of the end of the Company’s financial year (on December 31), to approve the financial statements, since the Company is required to draw up Consolidated Financial Statements. The right to attend and cast a vote at the Shareholders’ Meeting shall be certified by a statement submitted by an authorized intermediary on the basis of its accounting records to the Company on behalf of the person entitled to vote. The statement shall be issued by the intermediary on the basis of the balances on the accounts recorded at the end of the seventh trading day prior to the date of the
Shareholders’ Meeting. Credit and debit records entered on the authorized intermediaries’ accounts after this deadline shall not be considered for the purpose of determining entitlement to exercise voting rights at the Shareholders’ Meeting. The statement, issued by the authorized intermediary, must reach the Company by the end of the third trading day prior to the date of the Shareholders’ Meeting, or by any other deadline established by Consob regulations issued in agreement with the Bank of Italy. Shareholders shall nevertheless be entitled to attend the Meeting and cast a vote if the statements are received by the Company after the deadlines indicated above, provided they are received before the start of proceedings of the given call. For the purposes of these provisions, reference is made to the date of first call, provided that the dates of any subsequent calls are indicated in the notice calling the Meeting; otherwise, the date of each call is deemed the reference date. Those persons who are entitled to vote may appoint a party to represent themselves at the Shareholders’ Meeting by means of a written proxy or in electronic form in the manner set forth by current law. Electronic notification of the proxy may be made through a special section of the Company website as indicated in the notice calling the Meeting. In order to simplify proxy voting by shareholders who are employees of the Company or of its subsidiaries and belong to shareholders’ associations that meet applicable statutory requirements, locations for communications and collection of proxies shall be made available in accordance with the terms and conditions agreed from time to time with the legal representatives of said associations. The right to vote may also be exercised by mail in accordance with the applicable laws and regulations. If provided for in the notice calling the meeting, those persons entitled to vote may participate in the Shareholders’ Meeting by means of telecommunication systems and exercise their right to vote by electronic means in accordance with the provisions of the law, applicable regulations and the Shareholders’ Meeting Rules. The Company may designate a person for each Shareholders’ Meeting to whom the shareholders may confer a proxy with voting instructions on all or some of the items on the agenda, as provided for by applicable laws and regulations, by the end of the second trading day preceding the date set for the Shareholders’ Meeting including for calls subsequent to the first. Such proxy shall not be valid for items in respect of which no voting instructions have been provided. The Chairman of the meeting shall verify the validity of proxies and, in general, entitlement to participate in the Meeting. The Shareholders’ Meetings are governed by the Shareholders’ Meeting Rules as approved by resolution of the ordinary Shareholders’ Meeting on December 4, 1998, in order to guarantee an efficient conduct of meetings and the right of each shareholder to express his or her opinion on the items on the agenda.
During Shareholders’ Meetings, the Board of Directors provides broad disclosure on items examined and shareholders can request information on issues in the agenda. Information is provided taking into account applicable rules on inside information. Stock ownership limitation and voting rights restrictions There are no limitations imposed by Italian law or by Eni’s By-laws on the rights of non-residents in Italy or foreign persons to hold shares or vote other than the limitations described below (which are equally applicable to both residents and non-residents of Italy). In accordance with Article 6 of the By-laws, and in application of the special rules pursuant to Article 334 of Decree Law No. 332 of May 31, 1994, ratified with amendments by Law No. 474 of July 30, 1994 (Law No. 474/1994), no shareholder may hold, in any capacity, directly or indirectly, more than 3% of the Company’s share capital. Any voting rights and any other non-financial rights attached to shares held in excess of the maximum limit indicated above may not be exercised and the voting rights of each shareholder to whom such limit applies shall be reduced in proportion, unless otherwise jointly specified in advance by the parties involved. (3)
This provision has been modified by the Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012. For more details see the paragraph “Limitation on changes in control of the Company (Special Powers of the Italian State)” below.
Pursuant to Article 32 of the By-laws and the above mentioned provision of law, shareholdings owned by the Ministry of the Economy and Finance, public entities or organizations controlled by them are exempt from this ban. Finally, this special rule provides that the clause regarding shareholding limits will lose effect if the limit is exceeded as a result of a take-over bid, provided that, as a result of the takeover, the bidder will own a shareholding of at least 75% of the share capital with the right to vote on resolutions concerning the appointment or dismissal of Directors. Limitation on changes in control of the Company (Special Powers of the Italian State) Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012 (Law No. 56/2012), lastly amended by Decree Law No. 105 of September 21, 2019 ratified with amendments by Law No. 133 of November 18, 2019, modified Italian legislation governing the special powers of the Italian State to comply with European rules45. The new special powers no longer apply to specific State-controlled companies, identified by name, but to companies that hold strategic assets vital to the interests of the Italian State as defined by the ministerial regulations which implement the relevant law. The current legislation governing the special powers briefly include: a) veto power (or the power of imposing conditions or requirements) over certain transactions involving strategic assets that could result in a situation, not regulated by Italian or EU laws, that threatens serious injury to interests regarding networks and systems security, as well as continuity of supply; and b) power of attaching conditions or opposing the acquisition by an entity outside of the EU of shareholdings that determine the control of a company that holds, directly or indirectly, strategic assets, when such an acquisition may result in a threat of serious injury to the above mentioned essential interests of the Italian State. The shareholding of third parties who have entered into a shareholders’ agreement with the buyer is taken into account in the calculation of above mentioned relevant shareholdings. With particular reference to the power referred to in letter b), the legislation establishes notification obligations for the buyer entity outside of the EU to the Italian Presidency of the Council of Ministers as well as procedural terms. Until such notification and thereafter, up to the expiration of the term for the possible exercise of power, the voting rights and any other non-financial right related to the significant shareholding may not be exercised. In the case of non-fulfillment of imposed conditions, throughout the relevant period, the voting rights and any other non-financial right related to the significant shareholding may not be exercised. The resolutions adopted with the decisive vote of such shareholding, or otherwise the resolutions or acts adopted in breach or default of the imposed conditions are void. In addition, unless the fact constitutes a crime, failure to comply with imposed conditions entail for the purchaser a fine. In case of opposition, the buyer may not exercise the voting rights and any other non-financial right related to the significant shareholding, which must be sold within a year. In case of non-compliance, at the request of the Government, the Court will order the sale of the significant shareholding. Shareholders’ Meeting resolutions adopted with the decisive vote of such participation shall be void. (4)
This provision has been modified by the Decree Law No. 21 of March 15, 2012, ratified with amendments by Law No. 56 of May 11, 2012. For more details see the paragraph “Limitation on changes in control of the Company (Special Powers of the Italian State)” below. (5)
The prior provisions (Article 2 of Decree Law No. 332/1994, ratified by Law No. 474/1994 and its implementing decrees), as well as the provisions of the By-laws which were inconsistent with the new rules, lapsed at the issuance of Decree of the President of the Italian Republic No. 85 of March 25, 2014, in force since June 7, 2014.
The legislation provides for a general rule that the acquisition, for any reason, by an entity outside of the EU of stock of company that holds strategic assets be allowed on condition of reciprocity, in compliance with international agreements signed by Italy or the EU. These powers are exercised exclusively on the basis of objective and non-discriminatory criteria. Decree Law No. 148 of October 16, 2017, ratified with amendments by Law No. 172 of December 4, 2017, extended the special powers of the Italian State to high-technology industries. Decree Law No. 105 of September 21, 2019 ratified with amendments by Law No. 133 of November 18, 2019 replaced high-technology industries with sectors provided under Article 4, paragraph 1 of EU Regulation 452/2019. Furthermore, with regard to investments in companies with strategic assets by a non-EU investor, the decree defined the assessment criteria to determine whether a foreign investment could affect security or public order. Albeit with some amendments, the provisions regarding the stock ownership limitations and voting rights restrictions pursuant to Article 3 of Law No. 474/1994 are still in force. In order to “promote privatization and the spread of investment in shares” of companies in which the Italian State has a significant shareholding, Article 1, paragraphs 381 to 384 of Law No. 266 of 2005 (2006 Financial Law) introduced the power to add provisions to the By-laws of privatized companies primarily (4)
The prior provisions (Article 2 of Decree Law No. 332/1994, ratified by Law No. 474/1994 and its implementing decrees), as well as the provisions of the By-laws which were inconsistent with the new rules, lapsed at the issuance of Decree of the President of the Italian Republic No. 85 of March 25, 2014, in force since June 7, 2014.
controlled by the Italian State, like Eni, which allow shares or participating financial instruments to be issued that grant the special meeting of its holders the right to request that new shares, even at par value, or new financial instruments be issued to them with the right to vote in ordinary and extraordinary Shareholders’ Meetings. Making this amendment to the By-laws would lead to the shareholding limit referred to in Article 6.1 of the By-laws being removed. At the present time, however, Eni’s By-laws do not contain any of such provisions. Shareholder ownership thresholds There are no By-law provisions governing the disclosure of the ownership threshold because the matter is regulated by Italian law. Pursuant to the Consolidated Law on Finance56 and the Consob Regulation67, any direct or indirect holding in the voting shares of an Italian listed company in excess of 3%78 (until March 17, 2016, the threshold was 2%), 5%, 10%, 15%, 20%, 25%, 30%, 50%, 66.6% and 90% must be notified to the investee company and to Consob. The same disclosure requirements refer to holdings that drop below one of the specified thresholds. Such disclosures shall be made – using the forms contained in Annex 4A to the above Regulation – without delay and, in any case, within four days of the transaction, starting from the day on which the subject gains knowledge of the transaction that can lead to the obligation, regardless of the date of execution, or from the date on which the subject obliged to make the disclosure gains knowledge of the event that leads to changes in the share capital as contemplated in the Consob Regulation. For the purpose of the above disclosure obligations, the Consob Regulation establishes investment calculation criteria89. The obligation to notify also applies to any direct or indirect holding owned through ADRs. Specific disclosure requirements (with partially different thresholds) are connected to investments in financial instruments and for aggregate investments910. Under the above mentioned Decree Law No. 148/2017, in the case of the purchase of a stake in quoted issuers equal or above the thresholds of 10%, 20% and 25% of the relevant share capital in listed companies, the investor shall state the objectives it intends to pursue in the following six months. The declaration shall state under the responsibility of the declarant: a) the means of financing the acquisition; b) whether acting alone or in concert; c) whether it intends to stop or continue its purchases, and whether it intends to acquire control of the issuer or anyway have an influence on the management of the company and, in such cases, the strategy it intends to adopt and the transactions to be carried out; d) its intentions as to any agreements and shareholders’ agreements to which it is party; e) whether it intends to propose the (6)
Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122. (7)
Article 117 of Consob Decision No. 11971/1999 and subsequent amendments. (8)
If the company is not a SME (small or medium enterprise). Moreover, Consob may, by means of measures justified by the need to protect investors, as well as corporate control market and capital market efficiency and transparency, envisage – for a limited period of time – lower thresholds by its decree for companies with an elevated current market value and particularly extensive shareholding structure. (9)
Article 118 of Consob Decision No. 11971/1999 and subsequent amendments. (10)
Article 119 of Consob Decision No. 11971/1999 and subsequent amendments.
integration or revocation of the issuer’s administrative or control bodies. Consob can identify, with its own regulation, the cases where the aforementioned declaration is not due, taking into account the characteristics of the entity making the declaration or of the company whose shares have been purchased. The declaration shall be transmitted to the company whose shares have been purchased and to Consob and shall be subject to public disclosure in accordance with the terms and conditions established by Consob Regulation. Voting rights attached to listed shares which have not been notified pursuant to the above mentioned disclosure requirements may not be exercised. Any resolution or act adopted in violation of such limitation, with the contribution of those undisclosed shares, could be voided if challenged in court, under the Italian Civil Code. According to the Italian Civil Code (Article 2359-bis)2359-bis), a subsidiary may acquire shares of the parent company only within the limits of distributable profits and available reserves as resulting from the last approved balance sheet. Only fully-paid shares can be purchased. The purchase must be approved by the Shareholders’ Meeting and, in any case, the nominal value of shares purchased may not exceed one-fifth of the capital of the parent company – if the latter is a listed company – taking into account for this purpose the shares held by the same parent company or its subsidiaries. The Consolidated Law on Finance provides rules governing cross-holdings. In particular, except for the cases contemplated by the above mentioned Article 2359-bis2359-bis of the Italian Civil Code, in case of a reciprocal participation exceeding the limit of 3% (until March 17, 2016, the threshold was 2%) of the shares, the company that exceeds the limit successively cannot exercise its right to vote relative to the shares held in excess of such threshold and must sell such shares within the following 12 months. In the event of failure to dispose of the shares by such time limit, the voting rights shall be suspended with respect to the entire shareholding. Where it is not possible to ascertain which of the two companies was the last to exceed the limit, the suspension of voting rights and the disposal requirement shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code. (5)
Legislative Decree No. 58 of February 24, 1998, with specific reference to Articles 120-122.
(6)
Article 117 of Consob Decision No. 11971/1999 and subsequent amendments.
(7)
The Legislative Decree No. 25/2016, in force since March 18, 2016, modified the Article 120 of the Legislative Decree No. 58/1998, increasing this holding threshold from 2% to 3%. Moreover, Consob may, by means of measures justified by the need to protect investors, as well as corporate control market and capital market efficiency and transparency, envisage – for a limited period of time – lower thresholds by its decree for companies with an elevated current market value and, particularly, extensive shareholding structure.
(8)
Article 118 of Consob Decision No. 11971/1999 and subsequent amendments.
(9)
Article 119 of Consob Decision No. 11971/1999 and subsequent amendments.
The above mentioned limit is increased to 5% (or to 10% if the issuer is a small or medium enterprise as per Article 1, letter w-quater.1w-quater.1 of the Consolidated Law on Finance) if the threshold is exceeded by both companies subsequent to an agreement authorized in advance by the ordinary shareholders’ meetings of the companies concerned. If a person holds an interest exceeding the aforementioned threshold of a listed company, such listed company or any person controlling such listed company may not acquire an interest exceeding such a limit in a listed company controlled by the former. In the event of non-compliance, the voting rights attached to the shares in excess of the limit specified shall be suspended. Where it is not possible to ascertain which of the two persons was the last to exceed the limit, the suspension shall apply to both unless they have agreed otherwise. In the event of non-compliance, any resolution or act adopted with the contribution of the relevant shares may be challenged under the Italian Civil Code. The limitations described above are not applicable in the case of a takeover bid or exchange tender offer to acquire at least 60% of the ordinary shares of a listed company. Under the Consolidated Law on Finance, any agreement, in any form, regarding the exercise of voting rights in a listed company or in its parent company, must be, within five days of stipulation: (i) notified to Consob; (ii) published in abstract form, in the Italian daily press; (iii) filed with the Register of Companies in which the listed company is registered; and (iv) notified to the company with listed shares. In the event of non-compliance with these requirements, the agreements shall be null and void and the voting rights attached to the relevant shares may not be exercised and any resolution or act adopted with the contribution of such shares may be challenged under the Italian Civil Code. The same provisions also apply to agreements, in any form, that: (a) create obligations of consultation prior to the exercise of voting rights in a listed company and in its controlling companies; (b) set limits on the transfer of the related shares or of other financial instruments that entitle holders to buy or subscribe them; (c) provide for the purchase of the shares or of the above mentioned financial instruments; (d) have as their object or effect the exercise, jointly or otherwise, of dominant influence on such companies; and (d-bis)(d-bis) which aim to encourage or frustrate a takeover bid or an exchange tender offer, including commitments relating to non-participation in a takeover bid.
Finally, in accordance withpursuant to Law No. 287 of October 10, 1990, any merger or acquisition of (legal or factual) sole or joint control over a company or any change of control over a company thatis subject to the prior authorization by the Italian Antitrust Authority11 if the companies involved exceed given turnover thresholds. If the said merger, acquisition or change of control would create or strengthen a dominant position in the domesticItalian market in a manner that eliminates or significantly reduces competition, is prohibited and mergers and acquisitionthe Italian Antitrust Authority can either prohibit the transaction or make it subject to remedies preventing a restriction of specified dimension mustcompetition. Moreover, if the transaction or the companies involved exceed other thresholds set by European or other countries’ legislations (e.g. other turnover thresholds or thresholds referred to transaction’s value or market shares of the parties), the transaction can also be subject to the prior authorization by competition authorities of the Italian Antitrust Authority10. However, if the merging parties or the acquiring party and the company to be acquired operate in more than one EU Member State and/or outside Europe and exceed certain thresholds (e.g. turnover, asset value or market share thresholds), the antitrust approval for the merger and/or acquisition can fall under the jurisdiction of the European Commission or the EU Members States and/or other Competition Authorities outside Europe.jurisdictions. Changes in share capital Eni’s By-laws do not provide for more stringent conditions than are required by law. Share capital increases are resolved by a shareholders’ resolution at an extraordinary Shareholders’ Meeting. Under Italian law, shareholders have a pre-emptive right to subscribe newly issued shares and corporate bonds convertible into shares in proportion to their respective shareholdings. If the Company’s interest so requires, the pre-emptive right may be waived or limited by the shareholders’ resolution authorizing the share capital increase. The shareholders’ pre-emptive right is also waived if the shareholders’ resolution authorizing the share capital increase provides for the subscription of new issues of shares in the form of contributions in-kind. Material contracts None. (10)
Autorità garante per la concorrenza e il mercato (AGCM - www.agcm.it).
Exchange controls There areUnder current Italian exchange control regulations, no limits exist on the amount of payments that Eni may remit to residents of the United States. Laws and regulations concerning foreign exchange controls in Italy. Residents and non-residents in Italy may carry out any investments, divestments and other transactionsdo require, however, that entail aan accredited intermediary must handle all payments or transfer of assetsfunds made by an Italian resident to or from Italy, subject only to the reporting, record-keeping and disclosure requirements described below. In particular, residents of Italy may hold foreign currency and foreign securities of any kind, within and outside Italy, while non-residents may invest in Italian securities without restriction and may export from Italy cash, instruments of credit or payment and securities, whether in foreign currency or euro, representing interest, dividends, other asset distributions and the proceeds of dispositions.
Updated reporting and record-keeping requirements are contained in the Italian legislation which implements an EU directive regarding the free movement of capital. Such legislation requires that transfers into or out of Italy of cash or securities in excess of €12,500 be reported in writing to the relevant authority (Ministry of Economy and Finance) by residents or non-residents that effect such transfers directly, or by banks, securities dealers or Poste Italiane SpA (Italian Mail) that effect such transactions on their behalf. In addition, banks, securities dealers or Poste Italiane SpA effecting such transactions on behalf of residents or non-residents of Italy are required to maintain records of such transactions for five years. These records may be inspected at any time by Italian Tax and Judicial Authorities.
Non-compliance with these reporting and record-keeping requirements may result in administrative fines or, in the case of false reporting and in certain cases of incomplete reporting, criminal penalties.a non-resident.
Taxation The information set forth below is only a summary; Italian, the United States and other tax laws may change from time to time. Holders of shares and ADRs should consult with their professional advisors as to the tax consequences of their ownership and disposition of the shares and ADRs, including, in particular, the effect of tax laws of any other jurisdiction. Italian taxation The following is a summary of the material Italian tax consequences of the ownership and disposition of shares or ADRs as at the date hereof and does not purport to be a complete analysis of all potential tax effects relevant to the ownership or disposition of shares or ADRs. Income tax Dividends regarding income of financial year 2019 to be paid in 2020, received by Italian resident individuals, holding the shares or ADRs in relation to interest exceeding 2% of the voting rights or 5% of the share capital (“substantial interest”)connection with entrepreneurial activity, are included in the taxable income subject to personal income tax to the extent of 49.72%58.14% of their amount. Article 1, paragraph 64 of Law No. 208 of December 28, 2015 (“Italian Budget Law for the 2016”) provides that the percentages of the dividends relevant for the taxable income will be changed by a Decree of the Minister of Economy and Finance, in proportion to the IRES rate reduction to 24% as provided by Article 1, paragraph 61 of the aforementioned Italian Budget Law for the 2016.PersonalPersonal income tax applies at progressive rates ranging from 23% to 43% plus local surtaxes. Dividends received by Italian resident individuals holding the shares or ADRs otherwise than in relation to non-substantial interest not related to the conduct of a businessconnection with entrepreneurial activity, are subject to a substitute tax of 26% withheld at the source by the dividend paying agent. This being the case, the dividend is not to be included in the individual’s tax return. If the non-substantial interest is related to the conduct of a business, dividends are included in the taxable business income for 49.72% of their amount. Article 1, paragraph 64 of the Italian Budget Law for the 2016 provides that the percentages of the dividends and capital gains relevant for the taxable income will be changed by a Decree of the Minister of Economy and Finance, in proportion to the IRES rate reduction to 24% as provided by Article 1, paragraph 61 of the aforementioned Italian Budget Law for the 2016. The change of tax rate does not apply to the entities referred to into Article 5 of Presidential Decree 22 December 1986 No. 917. Despite the above statement, dividends are included in the taxable income at 40% to the extent they relate to undistributed profit of 2007 and previous years.
Dividends received by Italian investment funds, foreign open-ended investment funds authorized to market their securities in Italy pursuant to the Law Decree June 6, 1956, No. 476, converted into Law July 25, 1956, No. 786, and società di investimento a capitale variabile (SICAV) (“SICAV”) are not subject to substitute (11)
Autorità garante per la concorrenza e il mercato (AGCM – www.agcm.it)
substitute tax but are included in the aggregate income of the investment fund or SICAV. The investment fund or SICAV will not be subject to tax on the dividends. A withholding tax of 26% may apply on income of the investment fund or SICAV derived by unitholders or shareholders through distribution and/or upon redemption or disposal of the units and shares. Dividends received by real estate funds to which the provisions of Law Decree No. 351 of September 25, 2001, as subsequently amended, apply, are not subject to any substitute tax nor to any other income tax in the hands of the fund. The income of the real estate fund is subject to tax, in the hands of the unitholder, depending on status and percentage of participation, or, when earned by the fund, through distribution and/or upon redemption or disposal of the units. Dividends received by a pension fund (subject to the regime provided for by Article 17 of the Italian Legislative Decree No. 252 of December 5, 2005) and deposited with an authorized intermediary, will not be subject to substitute tax, but must be included in the result of the relevant portfolio accrued at the end of the tax period, to be subject to a 20% substitute tax (12.5% as regards income from government bonds).tax. Dividends paid to non-Italian residents are subject to the same substitute tax levied at source by the dividend paying agent at the rate of 26%, provided that the interest is not connected to an Italian permanent establishment. Dividends are subject to a 1.375%1,20% substitute tax introduced by the Financial Bill for 2008 where the conditions in Article 27, paragraph 3-ter,3-ter, Presidential Decree No. 600 of 1973 are met, i.e. dividends are paid to companies and entities subject to a corporate income tax in a European Union Member State or in Norway. Because corporate tax rate has been decreased to 24%, from the 1st of January 2017, the above mentioned dividends on 2017 income are subject to a 1,2% withholding tax.European Economic Area. The substitute tax may also be reduced under the Tax Treaty in force between Italy and the country of residence of the Beneficial Owner of the dividend. Italy has executed income Tax Treaties with approximately 90 foreign countries, including all EU Member States, Argentina, Australia, Brazil, Canada, Japan, New Zealand, Norway, Switzerland, the United States and some countries in Africa, the Middle East and the Far East. Generally speaking, it should be noted that Tax Treaties are not applicable where the holder is a tax-exempt entity or, with few exceptions, a partnership or a trust. In order to obtain the Treaty benefit of a reduced substitute tax rate at the same time of payment, the Beneficial Owner must file an application to the dividend paying agent chosen by the Depositary stating the existence of the conditions for the applicability of the Treaty benefit, together with a certification issued by the foreign tax authorities stating that the shareholder is a resident of that country for Treaty purposes. Under the Tax Treaty between the United States and Italy (the “Italy U.S. Tax Treaty”), dividends derived and beneficially owned by a U.S. resident who holds less than 25% of the Company’s shares are subject to an Italian withholding or substitute tax at a reduced rate of 15%, provided that the interest is not effectively connected with a permanent establishment in Italy through which the U.S. resident carries on a business or a fixed establishment in Italy through which such U.S. resident performs independent personal services (for further details please refer to the relevant provisions set forth in the Italy U.S. Tax Treaty). In the absence of such conditions, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. Based on the certification procedure required by the Italian Tax Authorities, to benefit from the direct application of the 15% substitute tax the U.S. shareholder must provide the dividend paying agent with a certificate obtained from the U.S. Internal Revenue Service (the IRS)“IRS”) with respect to each dividend payment. The request for this certificate must include a statement, signed under penalty of perjury, attesting that the shareholder is a U.S. resident individual or corporation, and does not maintain a permanent establishment in Italy, and must set forth other required information. The normal time for processing requests for certification by the IRS is normally about six to eight weeks. Where the Beneficial Owner has not provided the above mentioned documentation, the dividend paying agent will deduct from the gross amount of the dividend the substitute tax at the statutory rate of 26%. The U.S. recipient will then be entitled to claim from the Italian Tax Authorities the difference (treaty refund) between the domestic rate and the Treaty one by filing specific forms (certificate) with the Italian Tax Authorities.
As reflected in the Deposit Agreement, if any tax or other governmental charge shall become payable by or on behalf of the Custodian or the Depositary with respect to an ADR, any Deposited Securities represented by the American Depositary Shares (ADSs)(“ADSs”), such tax or other governmental charge shall be paid by the Holder hereof to the Depositary. The Depositary may refuse to effect any registration, registration of transfer, split-up or combination hereof or any withdrawal of such Deposited Securities
until such payment is made. The Depositary may also deduct from any distributions on or in respect of Deposited Securities, or may sell by public or private sale for the account of the Holder hereof any part or all of such Deposited Securities (after attempting by reasonable means to notify the Holder hereof prior to such sale), and may apply such deduction or the proceeds of any such sale in payment of such tax or other governmental charge, the Holder hereof remaining liable for any deficiency, and shall reduce the number of ADSs to reflect any such sales of shares. Pursuant to the Deposit Agreement, the Depositary and the Custodian may make and maintain arrangements to enable persons that are considered United States residents for purposes of applicable law to receive any tax rebates (pursuant to an applicable Treaty or otherwise) or other tax related benefits relating to distributions on the ADSs to which such persons are entitled. Notwithstanding any other terms of the Deposit Agreement or the ADR, absent the gross negligence or bad faith of, respectively, the Depositary and the Company, the Depositary and the Company assume no obligation, and shall not be subject to any liability, for the failure of any Holder or Beneficial Owner, or its agent or agents, to receive any tax benefit under applicable law or Tax Treaties. The Depositary shall not be liable for any acts or omissions of any other party in connection with any attempts to obtain any such benefit, and Holders and Beneficial Owners hereby agree that each of them shall be conclusively bound by any deadline established by the Depositary in connection therewith. Capital gains tax This paragraph concerns and applies to capital gains out of the scope of a business activity carried out in Italy. Profits gained by Italian resident individuals, upon the sale of a substantial interestnot in connection with entrepreneurial activity, in financial year 2019, are included in the taxable base subject to personal incomesubstitute tax for 49.72% of their amount. Article 1, paragraph 64 of the Italian Budget Law for the 2016 provides that the percentages of the capital gains relevant for the taxable income will be changed by a Decree of the Minister of Economy and Finance, in proportion to the IRES rate reduction to 24% as provided by Article 1, paragraph 61, of the aforementioned Italian Budget Law for the 2016. Gains realized upon the sale of non-substantial interest is subject to a substitute tax at a 26% rate.. For gains deriving from the sale of non-substantial interest, two different systems may be applied at the option of the shareholder as an alternative to the filing of the tax return: •
the so-called “administered savings” tax regime (risparmio amministrato), based on which intermediaries acting as shares depositaries shall apply a substitute tax (26%) on each gain, on a cash basis. If the sale of shares generated a loss, said loss may be carried forward up to the fourth following year; and •
the so-called “portfolio management” tax regime (risparmio gestito) which is applicable when the shares form part of a portfolio managed by an Italian asset management company. The accrued net profit of the portfolio is subject to a 26% substitute tax to be applied by the portfolio. Gains realized by non-residents from non-substantial interest in listed companies are deemed not to be realized in Italy and consequently are not subject to the capital gains tax. On the contrary, gains realized by non-residents from substantial interests even in listed companies are deemed to be realized in Italy and consequently are subject to the capital gains tax. However, double taxation treaties may eliminate the capital gains tax. Under the income tax convention between the United States and Italy, a U.S. resident will not be subject to the capital gains tax unless the shares or ADRs form part of the business property of a permanent establishment of the holder in Italy or pertain to a fixed establishment available to a shareholder in Italy for the purposes of performing independent personal services. U.S. residents who sell shares may be required to produce appropriate documentation establishing that the above mentioned conditions of non taxability pursuant to the convention have been satisfied. Financial Transactions Tax Italian Law No. 228 of December 24, 2012 has introduced a Financial Transactions Tax which applies to the transfer of shares, ADR and other financial instruments issued by companies resident in Italy. The tax rate applicable is 0.10% for ADR negotiated in regulated markets (like the NYSE).
Non-Italian intermediaries, involved in the transactions of Eni ADR, must withhold and pay the Financial Transactions Tax. For this purpose, non-Italian intermediaries can appoint an Italian Tax Representative, according to the Italian tax law. Inheritance and gift tax Pursuant to Law Decree No. 262 of October 3, 2006, converted with amendments by Law No. 286 of November 24, 2006, effective from November 29, 2006, and Law No. 296 of December 27, 2006, the transfers of any valuable assets (including shares) as a result of death or donation (or other transfers for no consideration) and the creation of liens on such assets for a specific purpose are taxed as follows: (a)
4 per cent: if the transfer is made to spouses and direct descendants or ancestors; in this case, the transfer is subject to tax on the value exceeding €1,000,000 (per beneficiary);
(b)
6 per cent: if the transfer if made to brothers and sisters; in this case, the transfer is subject to the tax on the value exceeding €100,000 (per beneficiary); (c)
6 per cent: if the transfer is made to relatives up to the fourth degree, to persons related by direct affinity, as well as to persons related by collateral affinity up to the third degree; and (d)
8 per cent: in all other cases. If the transfer is made in favor of persons with severe disabilities, the tax applies on the value exceeding €1,500,000. Moreover, an anti-avoidance rule is provided for by Law No. 383 of October 18, 2001 for any gift of assets (including shares) which, if sold for consideration, would give rise to capital gains subject to a substitute tax (imposta sostitutiva) provided for by Decree No. 461 of November 21, 1997. In particular, if the donee sells the shares for consideration within five years from the receipt thereof as a gift, the donee is required to pay a relevant substitute tax on capital gains as if the gift had never taken place. United States taxation The following is a summary of certain U.S. federal income tax consequences to U.S. Holders (as defined below) of the ownership and disposition of Shares or ADSs. This summary is addressed to U.S. Holders that hold Shares or ADSs as capital assets, and does not purport to addressdiscuss all material tax consequences of the ownership of Shares or ADSs.ADSs, including tax consequences arising under the Medicare contribution tax on net investment income. The summary does not address special classes of investors, such as tax-exempt entities, dealers in securities, traders in securities that elect to mark-to-market, certain insurance companies, broker-dealers, investors liable for alternative minimum tax, investors that actually or constructively own 10% or more of the combined voting power of Eni SpA’s Shares,voting stock or of the total value of Eni SpA’s stock, a person that purchases or sells Shares or ADSs as part of a wash sale for U.S. federal income tax purposes, investors that hold Shares or ADSs as part of a straddle or a hedging or conversion transaction and investors whose “functional currency” is not the U.S. dollar. This summary is based on the tax laws of the United States (including the Internal Revenue Code of 1986, as amended, (the “Code”), its legislative history, existing and proposed regulations thereunder, published rulings and court decisions) as in effect on the date hereof, and which are subject to change (or changes in interpretation), possibly with retroactive effect. The summary is based in part on representations of the Depositary and assumes that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms. U.S. Holders should consult their own tax advisors to determine the U.S. federal, state and local and foreign tax consequences to them of the ownership and disposition of Shares or ADSs. If an entity or arrangement that is treated as a partnership for U.S. federal income tax purposes holds the Shares or ADSs, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding the Shares or ADSs should consult its tax advisor with regard to the U.S. federal income tax treatment of an investment in the Shares or ADSs. As used in this section, the term “U.S. Holder” means a beneficial owner of Shares or ADSs that is: (i) a citizen or resident of the United States; (ii) a domestic corporation; (iii) an estate the income of which is subject to the U.S. federal income tax without regard to its source; or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust. The discussion does not address any aspects of U.S. taxation other than U.S. federal income taxation. In particular, U.S. Holders are urged to confirm their eligibility for benefits under the income tax convention between the United States and Italy U.S. Tax Treaty with their advisors and to discuss with their advisors any
possible consequences of their failure to qualify for such benefits. In general, and taking into account the earlier assumptions, for U.S. federal income tax purposes, U.S. Holders who own ADRs evidencing ADSs will be treated as owners of the underlying Shares. Exchanges of Shares for ADRs and ADRs for Shares generally will not be subject to U.S. federal income tax. DividendsDistributions
Subject to the passive foreign investment company (PFIC),(“PFIC”) rules discussed below, distributions paid on the shares will generally be treated as dividends for U.S. federal income tax purposes to the extent paid out of Eni SpA’s current or accumulated earnings and profits as determined for U.S. federal income tax purposes, but will not be eligible for the dividends-received deduction generally allowed to U.S. corporations. To the extent that a distribution exceeds Eni SpA’s earnings and profits, it will be treated, first, as a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in the Shares or ADSs, and thereafter as capital gain. A U.S. Holder will be subject to U.S. federal taxation, on the date of actual
or constructive receipt by the U.S. Holder (in the case of Shares) or by the Depositary (in the case of ADSs) with respect to the gross amount of any dividends, including any Italian tax withheld therefrom, without regard to whether any portion of such tax may be refunded to the U.S. Holder by the Italian Tax Authorities. For non-corporate U.S. Holders, dividends paid that constitute qualified dividend income will be taxable at the preferential rates applicable to long-term capital gains provided that such person holds the Shares or ADSs for more than 60 days during the 121 day period beginning 60 days before the ex-dividend date and meet other holding period requirements. Dividends paid by Eni SpA that are received with respect to the GroupADSs will generally be qualified dividend income if the ADSs are readily tradable on an established securities market in the United States. Eni SpA’s ADSs are listed on the New York Stock Exchange and Eni SpA therefore expects that dividends with respect to the ADSs will be qualified dividend income. Dividends paid by Eni SpA with respect to the Shares or ADSs will generally be qualified as dividend income. income provided that, in the year that you receive the dividend, Eni SpA is eligible for the benefits of the Italy U.S. Tax Treaty. Eni SpA believes that it is currently eligible for the benefits of the Italy U.S. Tax Treaty and Eni SpA therefore expects that dividends on the Shares and ADSs will be qualified dividend income, but there can be no assurance that Eni SpA will continue to be eligible for the benefits of the Italy U.S. Tax Treaty. The amount of the dividend distribution that must be included in the income of a U.S. Holder will be the U.S. dollar value of the euro payments made, determined at the spot EUR/USD rate on the date the dividend distribution is includible in such person’s income, regardless of whether the payment is in fact converted into U.S. dollars. Generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the U.S. Holder includes the dividend payment in income to the date he or she converts the payment into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes. Subject to certain conditions and limitations, Italian tax withheld from dividends will be treated as a foreign income tax eligible for credit against the U.S. Holder’s U.S. federal income tax liability. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the preferential rates. To the extent a reduction or refund of the tax withheld is available to a U.S. Holder under Italian law or under the income tax convention between the United States and Italy, the amount of tax withheld that could have been reduced or that is refundable will not be eligible for credit against his or her U.S. federal income tax liability. See “Italian taxation – Income tax” above, for the procedures for obtaining a tax refund. For foreign tax credit purposes, dividends paid on the sharesADSs or Shares will generally be income from sources outside the United States and will, depending on your circumstances,generally be either “passive” or “general” income for purposes of computing the foreign tax credit allowable to you. However, if (a) Eni SpA is 50% or more owned, by vote or value, by United States persons and (b) at least 10% of Eni SpA’s earnings and profits are attributable to sources within the United States, then for foreign tax credit purposes, a portion of Eni SpA’s dividends would be treated as derived from sources within the United States. With respect to any dividend paid for any taxable year, the United States source ratio of Eni SpA’s dividends for foreign tax credit purposes would be equal to the portion of Eni SpA’s earnings and profits from sources within the United States for such taxable year, divided by the total amount of our earnings and profits for such taxable year. Eni SpA does not expect to be 50% or more owned, by vote or value, by United States persons, and therefore does not expect that any portion of Eni SpA’s dividends will be treated as derived from sources within the United States. Sale or exchange of sharesShares Subject to the PFIC rules discussed below, a U.S. Holder generally will recognize gain or loss for U.S. federal income tax purposes on the sale or exchange of Shares or ADSs equal to the difference between the U.S. Holder’s adjusted basis in the Shares or ADSs (determined in U.S. dollars), as the case may be, and the amount realized on the sale or exchange (or if the amount realized is denominated in a foreign currency its U.S. dollar equivalent, determined atequivalent). The amount realized will generally be reduced by any Italian Financial Transaction Tax paid in respect of such transfer, and a U.S. Holder will not be entitled to claim a foreign tax credit in respect of the spot rate onpayment of the date of disposition).Italian Financial Transaction Tax. Generally, such gain or loss will be treated as capital gain or loss if the Shares or ADSs are held as capital assets and will be a long-term capital gain or loss if the Shares or ADSs have been held for more than one year on the date of such sale or exchange. Long-term capital gain of a non corporate U.S. Holder is generally taxed at preferential rates. In addition, any such gain or loss realized by a U.S. Holder generally will be treated as U.S. source income or loss for U.S. foreign tax credit purposes.
PFIC rules Eni SpA believes that Shares and ADSs should not currently be treated as stock of a PFIC for U.S. federal income tax purposes butand Eni SpA does not expect to become a PFIC in the foreseeable future. However, this conclusion is a factual determination that is made annually and thus may be subject to change. If Eni SpA were to be treated as a PFIC, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, gain realized on the sale or other disposition of your Shares or ADSs would in general not be treated as capital gain. Instead, if classified asunless a U.S. Holder
one elects to be taxed annually on a mark-to-market basis with respect to the Shares or ADSs, the U.S. Holder would be treated as having realized such gains and certain “excess distributions” ratably over the holding period for the Shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain or distribution was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, a U.S. Holder’s Shares or ADSs will be treated as stock in a PFIC if Eni SpA were a PFIC at any time during the period the Shares or ADSs were held. Dividends received from Eni SpA will not be eligible for the preferential tax rates applicable to qualified dividend income if Eni SpA is treated as a PFIC with respect to the U.S. Holders either in the taxable year of the distribution or the preceding taxable year, but instead will be taxable at rates applicable to ordinary income.
Documents on display Eni’s Annual Report and Accounts and any other document concerning the Company are also available online on the Company website at: http:https://www.eni.com/en_IT/documentation/documentation.page?type=bil-rap.en-IT/publications.html. The Company is subject to the information requirements of the U.S. Security Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, Eni files its Annual Report on Form 20-F and other related documents with the U.S. SEC. It’s possible to read and copy documents that have been filed with the U.S. via commercial document retrieval services, and from the SEC at the U.S. SEC’s public reference room located at 100 F Street NE, Washington, DC 20549, USA.website (www.sec.gov). You may also call the U.S. SEC at +1 800-SEC-0330 or log on to www.sec.gov.158
It is also possible to read and copy documents referred to in this Annual Report on Form 20-F at the New York Stock Exchange, 20 Broad Street, 17th floor, New York, USA.Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market risk is the possibility that the exposure to fluctuations in commodity prices, currency exchange rates, interest rates or commodity pricesother market benchmarks will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. Eni’s financial performance is particularly sensitive to changes in the price of crude oil and movements in the EUR/USD exchange rate. Overall, a rise in the price of crude oil has a positive effect on Eni’s results from operations and liquidity due to increased revenues from oil&gas production. Conversely, a decline in crude oil prices reduces Eni’s results from operations and liquidity. The impact of changes in crude oil prices on the Company’s downstream gas and refining and marketing businesses and petrochemical operationsbusinesses depends upon the speed at which the prices of finished products adjust to reflect changes in crude oil prices. In addition, the Group’s activities are, to various degrees, sensitive to fluctuations in the EUR/USD exchange rate as commodities are generally priced internationally in U.S. dollars or linked to dollar denominated products as in the case of gas prices.products. Overall, an appreciation of the euro against the dollar reduces the Group’s results from operations and liquidity, and vice versa. As part of its financing and cash management activities, the Company uses derivative instruments to manage its exposure to changes in interest rates and foreign exchange rates. These instruments are principally interest rate and currency swaps. The Company also enters into commodity derivatives as part of its ordinary commercial, optimization and risk management activities, as well as exceptionally to hedge the exposure to variability in future cash flows due to movements in commodity prices, in view of pursuing acquisitions of oil&gas reserves as part of the Company’s ordinary asset portfolio management or other strategic initiatives. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of undertaking finance, treasury and risk management operations based on the Company’s departments of operational finance: the parent company’s (Eni SpA) finance department and
its subsidiaries Eni Finance International, Eni Finance USA and Banque Eni, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping, that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni SpA, Eni Finance International and Eni Finance InternationalUSA manage the Group subsidiaries’ financing requirements in andItaly, outside Italy and in the United States, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies are managed by the parent company. The commodity risk of each business unit (Eni’s business lines or subsidiaries) is pooled and managed by the parent company Midstream business department, with Eni Trading & Shipping executing the negotiation of commodity derivatives. During 2013, the above mentioned centralized model for the execution of financial derivatives has been ring fenced in light of the relevant new financial regulations which became effective (EMIR/Dodd Frank)Frank act). Eni’s activities are in compliance with regulatory requirements for execution of financial derivatives on European and non-European Regulated Markets, on Multilateral Trading Facilities, on Organized Trading Facilities or bilaterally with OTC counterparties. In addition to the reinforcement of the centralized execution model, as required by the new financial regulation, in 2013 the EMIR concepts of “risk reducing” and “non-risk reducing” derivatives were introduced. ActivitiesCompany’s activities in financial derivatives were thus classified in order to clearly: a) isolate ex ante non-risk reducing activities; b) define a priori the types of OTC derivative contracts included in the hedging portfolios and the eligibility criteria, and stating that the transactions in contracts included in the hedging portfolios are limited to covering risks directly related to commercial or treasury financing activities; and c) provide for a sufficiently disaggregate view of the hedging portfolios in terms of for example asset class, product and time horizon, in order to establish the direct link between the portfolio of hedging transactions and the risks that this portfolio seeks to hedge. A derivative can be qualified a risk reducing instrument when, by itself or in combination with other derivative contracts (so-called macro or portfolio hedging) it: (i)
directly or through closely correlated instruments (so-called proxy hedging) covers the risks arising from potential changes in the value direct or caused by fluctuation of interest rates, inflation rates, foreign exchange rates or credit risk, of different assets under Eni control or that Eni will have under its controls in the normal course of business;business driven by fluctuation of interest rates, inflation rates, foreign exchange rates or credit risk; or (ii)
qualifies as a hedging contract pursuant to IFRS.
Use of financial derivatives (in euro or currencies different from euro) is allowed with the following risk reducing purposes: •
Back to back:back: includes market risk-free instruments that are negotiated in accordance to an execution criteria and normally settled with an intermediation fee. They normally comply with hedge accounting requirements or own use exemption. These are transaction-based activities characterized by a substantial absence of market risk. A hedging instrument can be considered back to back when the financial derivative is structured as to match as much as possible asset class, size and maturity of the hedged position. As a result, the combination of the hedged item, normally a single asset/contract or an order received by mean of an internal derivative, and the hedging instrument, i.e. the financial derivative, is substantially market risk free or is exposed only to a basic risk related to the ineffective portion of the hedging item. In addition, the hedging item may entailcounterpartyentail counterparty risk and operational risk. These derivatives are normally accounted for as hedges for financial statement purposes. •
Flow hedging: flow hedging seeks to optimize Group hedging requirements by pooling different positions retained by the business units and then by entering derivative instruments to hedge net exposures, in accordance to a portfolio basis. A central department processes a continuous flow of orders from the Group various business units and then acts as a single broker on financial markets. Flow hedging is characterized by the lack of direct control by the central broker entity on the received orders, which are normally related to assets managed by the business units. The central broker entity can normally rely on a continuous flow of hedging orders that can be predictable to a large extent, on the basis of the regular hedging programs made by the Group’s business units. The central entity is therefore in the position to net opposite orders, by retaining the level of risk necessary to cover timing, volume and asset class mismatch among orders. The benefits are the maximization of integration across the whole of the Group assets portfolio and the related netting potential, avoiding unnecessary derivatives, thus reducing costs and aggregated notional amounts of hedging programs. Flow hedging is managed on a portfolio basis and is dynamic by nature, since resulting net position is normally adjusted in order to take into account new orders received and maximum allowed exposure, related to timing, volume and asset classes mismatch. Those derivatives are accounted to profit and loss as the hedging of net exposures does not qualify as hedges under IFRS.
•
Asset-backed hedging: is a portfolio-based activity performed to protect assets extrinsic value which is the fair value that a third party would potentially pay to buy the flexibility associated to assets available to the Group. It is normally characterized by a maximum level of market risk related to the size of managed assets and the volatility of underlying commodities. The more flexible is anthe asset, the higher is its extrinsic value that can be normally quantified as an option premium, linked to the price of an underlying commodity, volatility, time, interest rate. In order toTo protect the value of asset flexibility, a business unit may transfer to a central entity part or the whole of an asset flexibility or a portfolio of flexibilities and the central entity will hedge such flexibility on financial markets so to lock its value by monetizing it via derivatives. Hedging strategies adopted for asset-backed hedging are normally portfolio based, very dynamic and entail large use of proxies. Depending on the optimization model such strategies are continuously adjusting relevant hedging ratios buying and selling same financial products several times, since the underlying asset flexibility to be hedged is changing depending on price level, price volatility, time to delivery, etc. These derivatives may lead to gains as well as losses which in each case may be significant and are accounted through profit and loss as they lack the hedge requirements provided by IFRS. However, we believe that the risks associated with those derivatives are mitigated by the natural hedge granted by the asset availability. •
Portfolio management: is a portfolio based activity performed on a combination of underlying positions, such as physical assets (production plants, transmission infrastructures, storages, etc.), commercial assets (spot and forward short/medium/long term supply and sale contracts with physical delivery) and related financial derivatives. Normally, the target of a portfolio management activity is to optimize managed assets’ base by running quantitative models which, given production/consumption forecasts, prices scenarios and logistic flexibility/constraints, determine the optimal configuration in termterms of volume, price and flexibility for physical and commercial assets in the portfolio. Financial derivatives are then used in the portfolio management activity in order to manage the overall risk level associated to such optimal configuration within a set tolerance or to balance the combined risk-reward profile of the
portfolio in line with company’s targets. Market risk associated to portfolio management is proportional to assets size and maturity and volatility/correlation of underlying markets. Financial derivatives are normally used to hedge the resulting net position, but they might hedge also single physical/commercial assets included in the portfolio. The activity is dynamic by nature, since optimization models are run periodically, even on a daily and infra-daily timescale, in order to rebalance optimal configuration in view of actual or forecast changes in volumes, prices and flexibility. As a consequence, financial Derivativesderivatives are also managed dynamically, with a continuous adjustment that might lead to buy and sell the same financial product several times.times in a given time frame. These derivatives may lead to gains, as well as losses which in each case may be significant and are accounted through profit as they lack the hedge requirements provided by IFRS.
Pursuant to internal policy, all derivatives transactions concerning interest rates and foreign currencies are executed for risk reducing purposes, as described above. Only commodity derivatives can also be executed in the context of non-risk reducing operations and be consequently classified as Proprietary Trading, which is an ancillary activity not related to industrial assets that makes use of financial derivatives which are entered into with the objective to obtain an uncertain profit, if favorable market expectations occur. Eni monitors on a daily basis that every activity involving derivatives is correctly classified according to the risk reducing taxonomy (i.e. back to back, flow hedging, asset-backed hedging or portfolio management), is directly or indirectly related to the hedged industrial assets and effectively optimizes the risk profile to which Eni is, or could be, exposed. When some derivatives fail to prove their risk reducing purpose, they are reclassified as Proprietary Trading. Provided that Proprietary Trading is segregated ex ante from other activities, its resulting market risk exposure is subject to specific limits expressed in terms of Stop Loss, VaR and notional.notional amounts. The aggregated notional amounts of non risknon-risk reducing derivatives at Group level are constantly benchmarked with the thresholds required by relevant international financial regulations. Please refer to “Item 18 – note 38Note 27 of the Notes on Consolidated Financial Statements” for a qualitative and quantitative discussion of the Company’s exposure to market risks. Please also refer to “Item 18 – notes 15, 23, 28, 33 and 34 of the Notes on Consolidated Financial Statements” for details of the different derivatives owned by the Company in these markets.
Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES Item 12A. Debt securities Not applicable. Item 12B. Warrants and rights Not applicable. Item 12C. Other securities Not applicable. Item 12D. American Depositary Shares In the United States, Eni’s securities are traded in the form of American Depositary Shares (ADSs) which are listed on the NYSE. ADSs are evidenced by American Depositary Receipts (ADRs), and each ADR represents two Eni ordinary shares. Since January 18, 2012, Eni’s ADRs are issued, cancelled and exchanged at the office of Bank of New York Mellon, as depositary (the “Depositary”) under Pursuant to the Deposit Agreement dated June 27, 2017 (the “Deposit Agreement”) between Eni, the DepositaryCitibank N.A. and the holders of ADRs.and beneficial owners ADSs, Citibank N.A. serves as the Depositary for Eni’s ADR Program, and Citibank N.A. Milan Branch serves as Custodian. Computershare is the transfer agent for the Eni SpA ADR program. Société Générale Securities Services SpA and UniCredit SpA are the custodians (the “Custodian”) on behalf of the holders of Eni’s ADRs, and their principal offices are located in Milan, Italy.
Fees and charges paidpayable by ADR holders The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs forPursuant to the purpose of withdrawal or from intermediaries acting on their behalf. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable propertyDeposit Agreement, ADR holders may be required to pay various fees to the fees.Depositary, and the Depositary may refuse to provide any service for which a fee is assessed until the applicable fee has been paid.
The table below sets forth allfollowing ADS fees and charges that a holderare payable under the terms of Eni’s ADRs may have to pay, either directly or indirectly, to Bank of New York Mellon, as Depositary.the Deposit Agreement: Type of serviceService | | | Amount of fees or charges(1) Rate | | | Depositary actionsBy Whom Paid | | (a)(1)
DepositingIssuance of ADSs (e.g., an issuance upon a deposit of Shares, upon a change in the ADS(s)-to-Share(s) ratio, or substituting the underlying sharesfor any other reason), excluding issuances as a result of distributions described in paragraph (4) below.
| | | $5.00Up to U.S. $5.00 per 100 ADSs (or less) for each 100 ADSs
(or portion of 100 ADSs)fraction thereof) issued. | | | Each person to whom ADRs are issued against deposits of shares, including deposits and issuances in respect of:
•
Share distributions, stock split, rights, merger.
•
Exchange of securities or any other transaction or event or other distribution affecting the ADSs or the Deposited Securities.
Person receiving ADSs. | | (b)(2)
SellingCancellation of ADSs (e.g., a cancellation of ADSs for delivery of deposited Shares, upon a change in the ADS(s)-to-Share(s) ratio, or exercising rightsfor any other reason).
| | | $5.00Up to U.S. $5.00 per 100 ADSs (or less) for each 100 ADSs
(or portion of 100 ADSs)fraction thereof) cancelled. | | | Distribution or sale of securities, the feePerson whose ADSs are being in an amount equal to the fee for the execution and delivery of ADSs which would have been charged as a result of the deposit of such securities.cancelled. | | (c)(3)
Withdrawing an underlying securityDistribution of cash dividends or other cash distributions (e.g., upon a sale of rights and other entitlements).
| | | $5.00Up to U.S. $5.00 per 100 ADSs (or less) for each 100 ADSs
(or portion of 100 ADSs)fraction thereof) held. | | | Acceptance of ADRs surrendered for withdrawal of deposited securities.Person to whom the distribution is made. | | (d)(4)
Transferring, splittingDistribution of ADSs pursuant to (i) stock dividends or grouping receiptsother free stock distributions, or (ii) an exercise of rights to purchase additional ADSs.
| | | Registration or transfer feesUp to U.S. $5.00 per 100 ADSs (or fraction thereof) held. | | | Transfers, combining or grouping of depositary receipts.Person to whom the distribution is made. | | (e)(5)
ExpensesDistribution of the depositarysecurities other than ADSs or rights to purchase additional ADSs (e.g., spin-off shares).
| | | Varied chargesUp to U.S. $5.00 per 100 ADSs (or fraction thereof) held. | | | Expenses incurred on behalf of holders in connection with:
•
The Depositary’s or its custodian’s compliance with applicable law, rule or regulation.
•
Stock transfer or other taxes and other governmental charges.
•
Cable, telex, facsimile transmission/delivery.
•
Expenses ofPerson to whom the Depositary in connection with the conversion of foreign currency into U.S. dollars (which are paid out of such foreign currency).
•
Any other charge payable by Depositary or its agents.
distribution is made. | | (f)(6)
Distribution of cashADS Services.
| | | $0.02Up to U.S. $5.00 per 100 ADSs (or less) per ADSfraction thereof) held on the applicable record date(s) established by the Depositary. | | | Any cash distribution to ADS registered holders.Person holding ADSs on the applicable record date(s) established by the Depositary. | | (g)
Depositary services
| | | $0.02 (or less) per ADS
per calendar year | | | Depositary services. | | |
(1)
All feesDirect and charges are paid by ADR holders to Bank of New York Mellon as Depositary and Transfer agent.
Fees andindirect payments made by the Depositary to the issuer
The Depositary has agreed to reimburse certain company expenses related to the ADR Program and incurred in connection with the program and the listing of Eni’s ADSs on the NYSE. These expenses are mainly related to legal and accounting fees incurred in connection with the preparation of regulatory filings and other documentation related to ongoing U.S. SEC compliance, NYSE listing fees, listing and custodian bank fees, advertising, certain investor relationship programs or special investor relations activities. For the year 2016, as agreed in the Deposit Agreement with the previous depositary bank, JPMorgan Chase Bank of New York, and subsequent amendments,2019, the Depositary will reimburse to Eni up to US$2,200,000$1,800,000 in connection with the above mentioned expenditures.
Expenses waived or paid directly to third parties by the Depositary
The Depositary reimbursedhas also agreed to waive certain standard fees associated with the company, or paid amounts onadministration of the company’s behalf to third parties, or waived its fees and expenses, of US$189,419.31 for the year ended December 31, 2016. Category of expense reimbursed, waived or paid directly to third parties | | | Amount reimbursed,
waived or paid directly to
third parties for the year
ended December 31, 2016 | | | | | (US$) | | BNY Mellon products and services | | | | | 120,000.00 | | | BNY Mellon related to servicing registered shareholders | | | | | 650.90 | | | BNY Mellon paid to third-party vendors(1)
| | | | | 68,768.41 | | | Total | | | | | 189,419.31 | | | |
(1)
Includes payments for AGM and related ADR Program services.
PART II Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES None. Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS None. Item 15. CONTROLS AND PROCEDURES Disclosure controls and procedures In designing and evaluating the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and the Company’s management necessarily was required to apply its judgment in evaluating the cost benefit relationship of possible controls and procedures. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. It should be noted that the Company has investments in certain non-consolidated entities. As the Company does not control or manage these entities, its disclosure controls and procedures with respect to such entities are necessarily more limited than those it maintains with respect to its consolidated subsidiaries. The Company’s management, with the participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Rule 13a-14(c) under the Exchange Act as of the end of the period covered by this Annual Report on Form 20-F. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these disclosure controls and procedures are effective. Management’s Annual Report on Internal Control over Financial Reporting The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rules 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of an internal control system may change over time. The Internal Control Committee assists the Board of Directors in setting out the main principles for the internal control system so as to appropriately identify and adequately evaluate, manage, and monitor the main risks related to the Company and its subsidiaries, by laying down the compatibility criteria between said risks and sound corporate management. In addition, this Committee assesses, at least annually, the adequacy, effectiveness, and actual operations of the internal control system.
The Company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of its internal control over financial reporting based on the Internal Control —– Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (CoSO) in 2013. Based on the results of this evaluation, the Group’s management concluded that its internal control over financial reporting was effective as of December 31, 2016.2019.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2016,2019, has been audited by Reconta Ernst & YoungPricewaterhouseCoopers SpA, an independent registered public accounting firm, as stated in its report that is included on page F-2 of this Annual Report on Form 20-F. Changes in Internal Control over Financial Reporting There have not been changes in the Company’s Internal Control over Financial Reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Item 16. [RESERVED] Item 16A. Board of Statutory Auditors financial expert Eni’s Board of Statutory Auditors has determined that the five members of Eni’s Board of Statutory Auditors are “audit committee financial expert”: Matteo Caratozzolo,Rosalba Casiraghi, who is the Chairman of the Board, Enrico Maria Bignami, Paola Camagni, Alberto Falini, Marco LacchiniAndrea Parolini and Marco Seracini. All members are independent. Item 16B. Code of Ethics Eni adopted a Code of Ethics that applies to all Eni’s employees, including Eni’s Chief Executive Officer, ChiefChiefs, Officers, principal Financial Officer and Chief Accounting Officer.Officers, Directors and Statutory Auditors. Eni published its Code of Ethics on Eni’s website. It is accessible at www.eni.com, under the section Corporate Governance. A copy of this Code of Ethics is included as an exhibit to this Annual Report on Form 20-F. Eni’s Code of Ethics contains ethical guidelines, describes corporate values and requires standards of business conduct and moral integrity. The ethical guidelines are designed to deter wrongdoing and to promote honest and ethical conduct, compliance with applicable laws and regulations and internal reporting of violations of the guidelines. The code affirms the principles of accounting transparency and internal control and endorses human rights and the issue of the sustainability of the business model. Item 16C. Principal accountant fees and services Reconta Ernst & YoungPwC SpA has served as Eni principal independent public auditor for fiscal years 2016 and 2015year 2019 for which audited Consolidated Financial Statements appear in this Annual Report on Form 20-F.
EY SpA has served as Eni principal independent public auditor for fiscal year 2018. The following table shows total fees paid by Eni, its consolidated and non-consolidated subsidiaries and Eni’s share of fees incurred by joint ventures for services providedrendered to Eni by Eni to its public auditors Reconta Ernst & YoungPwC SpA and its member firms of PwC Network for the year ended December 31, 2019. The amount shown for the year ended December 31, 2018 have been paid to EY SpA and its respective member firms forwhich has served as Eni principal independent public auditor since the years ended December 31, 2016 and 2015, respectively:fiscal year 2018. | | Year ended December 31, | | | Year ended December 31, | | | | 2015 | | 2016 | | | 2019 | | 2018 | | | | (€ thousand) | | | (€ thousand) | | Audit fees | | | | 33,752 | | | | | 21,433 | | | | | | 15,748 | | | | | 25,445 | | | Audit-related fees | | | | 1,138 | | | | | 1,874 | | | | Audit -related fees | | | | | 1,045 | | | | | 1,628 | | | Tax fees | | | | 3 | | | | | | | | | | | | | | | | | | | All other fees | | | | | | | | | | | | | | | | | | | | | | | Total | | | | 34,893 | | | | | 23,307 | | | | | | 16,793 | | | | | 27,073 | | | | |
Audit fees include professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements, including the audit on the Company’s internal control over financial reporting. Audit-related fees include assurance and related services by the principal accountant that are reasonably related to the performance of the audit or review of the registrant’s financial statements and are not reported as Audit fees in this Item. The fees disclosed in this category mainly include audits of pension and benefit plans, merger and acquisition due diligence, audit, and consultancy services rendered in connection with acquisition deals, certification services not provided for by law and regulations and consultations concerning financial accounting and reporting standards. Tax fees include professional services rendered by the principal accountant for tax compliance, tax advice, and tax planning. The fees disclosed in this category mainly include fees billed for the assistance with compliance and reporting of income and value-added taxes, assistance with assessment of new or changing tax regimes, tax consultancy in connection with merger and acquisition deals, services rendered in connection with tax refunds, assistance rendered on occasion of tax inspections and in connection with tax claims and recourses and assistance with assessing relevant rules, regulations and facts going into Eni correspondence with tax authorities. All other fees include products and services provided by the principal accountant, other than the services reported in Audit fees, Audit-related fees and Tax fees of this Item and consists primarily of fees billed for consultancy services related to IT and secretarial services that are permissible under applicable rules and regulations. Pre-approval policies and procedures of the Internal Control Committee The Board of Statutory Auditors has adopted a pre-approval policy for audit and non-audit services that set forth the procedures and the conditions pursuant to which services proposed to be performed by the principal auditors may be pre-approved. Such policy is applied to entities within the Eni Group which are either controlled or jointly controlled (directly or indirectly) by Eni SpA.SpA as well as to jointly controlled entities that are material to the Eni Group. According to this policy, permissible services within the other audit services category are pre-approved by the Board of Statutory Auditors. The Board of Statutory Auditors approval is required on a case-by-case basis for those requests regarding: (i) audit-related services; and (ii) non-audit services to be performed by the external auditors which are permissible under applicable rules and regulations. In such cases, the Company’s Internal Audit Department is charged with performing an initial assessment of each request to be submitted to the Board of Statutory Auditors for approval. The Internal Audit Department periodically reports to Eni’s Board of Statutory Auditors on the status of both pre-approved services and services approved on a case-by-case basis rendered by the external auditors. During 2016,2019, no audit-related fees, tax fees or other non-audit fees were approved by the Board of Statutory Auditors pursuant to the de minimis exception to the pre-approval requirement provided by paragraph (c)(7)(i) (c)(C) of Rule 2-01 of Regulation S-X.
Item 16D. Exemptions from the Listing Standards for Audit Committees Making use of the exemption provided by Rule 10A-3(c)(3) for non-U.S. private issuers, Eni has identified the Board of Statutory Auditors as the body that, starting from June 1, 2005, performs the functions required by the U.S. SEC rules and the Sarbanes-Oxley Act to be carried out by the audit committees of non-U.S. companies listed on the NYSE (see “Item 6 – Board of Statutory Auditors” above). Item 16E. Purchases of equity securities by the issuer and affiliated purchasers The issuer and its affiliated purchasers have not executed any purchaseEni Board of equity securitiesDirectors, in execution of the issuer sinceauthorization granted by the endEni Shareholders’ Meeting of 2014May 14, 2019 and in accordance with the terms announced to the market on that date, has approved measures to begin the 2019 share buy-back programme, in the maximum amount of €400,000,000 and up to a maximum of 67,000,000 shares. The purchases started in the first week of June 2019 and asended in the month of the date of the 20-F filing for the year ended December 31, 2016.2019. Period | | | Total number of shares purchased | | | Average price paid per share | | | Total number of shares purchased as part of publicly announced plans or programs | | | Total purchase cost | | | Approximate € value of Shares that may yet be purchased under the plans or programs | | | | | | | | | | | € per share | | | | | | | | | (million €) | | | (million €) | | Start of the program June 5 – June 30, 2019 | | | | | 3,690,860 | | | | | | 14.21 | | | | | | 3,690,860 | | | | | | 52 | | | | | | 348 | | | 1 July – 31 July 2019 | | | | | 5,660,592 | | | | | | 14.48 | | | | | | 5,660,592 | | | | | | 82 | | | | | | 266 | | | 1 August – 31 August 2019 | | | | | 3,339,795 | | | | | | 13.49 | | | | | | 3,339,795 | | | | | | 45 | | | | | | 221 | | | 1 September – 30 September 2019 | | | | | 3,543,252 | | | | | | 13.96 | | | | | | 3,543,252 | | | | | | 49 | | | | | | 171 | | | 1 October – 31 October 2019 | | | | | 5,914,499 | | | | | | 13.77 | | | | | | 5,914,499 | | | | | | 81 | | | | | | 90 | | | 1 November – 30 November 2019 | | | | | 4,584,298 | | | | | | 14.03 | | | | | | 4,584,298 | | | | | | 64 | | | | | | 25 | | | 1 December – 31 December 2019 | | | | | 1,857,186 | | | | | | 13.65 | | | | | | 1,857,186 | | | | | | 25 | | | | | | 0 | | | Total as of December 31, 2019 | | | | | 28,590,482 | | | | | | 13.99 | | | | | | 28,590,482 | | | | | | 400 | | | | | | | | |
Item 16F. Change in Registrant’s Certifying Accountant Not applicable.Due to the audit firm rotation rules in Italy, EY, as the Company’s independent public accounting firm, stepped down at the meeting of the Company’s shareholders on May 14, 2019. EY was hired for a period of nine years and served as our independent auditor for the fiscal years ended December 31, 2010 through 2018.
EY report on the Company’s financial statements for each of the past nine years did not contain an adverse opinion or disclaimer of opinion, nor was it qualified or modified as to uncertainty, audit scope or accounting principle. In connection with the audit of the Company’s financial statements in the fiscal years ended December 31, 2018 and 2017, there were no disagreements with EY on any matters of accounting principles or practices, financial statement disclosure, or auditing scope and procedures which, if not resolved to the satisfaction of EY, would have caused EY to make reference to the matter of such disagreements in their reports. Eni has provided a copy of this disclosure to EY and requested that EY furnish us with a letter addressed to the SEC stating whether or not it agrees with the above statements. A copy of EY’s letter is filed as an exhibit to this Form 20-F. The Statutory Board of Auditors selected PricewaterhouseCoopers SpA to be appointed as the Company’s new independent registered public accounting firm for the nine-year period from 2019 to 2027, which was approved by Eni’s shareholders on May 14, 2019.
Item 16G. Significant differences in Corporate Governance practices as per Section 303A.11 of the New York Stock Exchange Listed Company Manual Corporate Governance.Governance. Eni’s Governance structure follows the traditional model as defined by the Italian Civil Code which provides for two main separate corporate bodies, the Board of Directors and the Board of Statutory Auditors to whom management and monitoring duties are respectively entrusted. This model differs from the U.S. one-tier model in which the Board of Directors is the sole corporate body responsible for management, with an Audit Committee established within the Board performing monitoring activities. The following offers a description of the most significant differences between corporate governance practices adopted by U.S. domestic companies under the NYSE standards and those followed by Eni, including with reference to Corporate Governance Code for Italian listed companies, which Eni has adopted (hereinafter the Corporate Governance Code). Independent Directors NYSE standards.standards. In accordance with NYSE standards, the majority of the members on the Boards of Directors of U.S. companies must be independent. A Director qualifies as independent when the Board affirmatively determines that such Director does not have a material relationship with the listed company (and its subsidiaries), either directly, or indirectly. In particular, a Director may not be deemed independent if he or she or an immediate family member has a certain specific relationship with the issuer, its auditors or companies that have material business relationships with the issuer (e.g. he or she is an employee of the issuer or a partner of the Auditor). In addition, a Director cannot be considered independent in the three-year “cooling-off” period following the termination of any relationship that compromised a Director’s independence. Eni standards.standards. In Italy, the Consolidated Law on Financial Intermediation states that at least one of the Directors or two, if the Board is composed of more than seven members, must meet the independence requirements for Statutory Auditors of listed companies. In particular, a Director may not be deemed independent if he/she or an immediate family member has a relationship with the issuer, with its Directors or with the companies in the same group of the issuer that could influence the independence of their judgment.
judgment. Eni’s By-laws require that at least one Director – if the Board has no more than five members – or at least three Directors – if the Board is composed of more than five members – must satisfy the independence requirements. The Corporate Governance Code provides for additional independence requirements, recommending that the Board of Directors includes an adequate number of independent non-executive Directors. In particular, for issuers belonging to FTSE-MIB index of the Italian Stock Market, like Eni, the Corporate Governance Code recommends that at least one-third of the members of the Board of Directors shall be independent Directors. In any event, independent Directors shall not be fewer than two. Independence is defined as not being currently or recently involved in any direct or indirect relationship with the issuer or other parties associated with the issuer and that may influence his/her independent judgment. After the appointment of a Director who qualifies as independent and subsequently, upon the occurrence of circumstances affecting the independence requirements and in any case at least once a year, the Board of Directors assesses the independence of the Director. The Board of Statutory Auditors verifies the correct application of the criteria and procedures adopted by the Board of Directors to evaluate the independence of its members. The Board of Directors shall disclose the result of its evaluations, after the appointment, through a press release to the market and, subsequently, in the Annual Corporate Governance Report. In accordance with Eni’s By-laws, if a Director, who qualifies as independent, does not or no longer satisfies the independence requirements established by law, the Board declares the Director disqualified and provides for their substitution. Directors shall notify the Company if they should no longer satisfy the independence and integrity requirements or if cause for ineligibility or incompatibility should arise.
Meetings of non-executive Directors NYSE standards.standards. Non-executive Directors, including those who are not independent, must meet on a regular basis without the executive Directors. In addition, if the group of non-executive Directors includes Directors who are not independent, independent Directors should meet separately at least once a year. Eni standards.standards. Pursuant to Corporate Governance Code, independent Directors shall meet at least once a year without the other Directors. During 2016,2019, Eni’s independent Directors had numerous opportunities to meet, formally and informally, to hold discussions and exchange opinions.
Audit Committee NYSE standards. Listed U.S. companies must have an Audit Committee that satisfies the requirements of Rule 10A-3 under the Securities Exchange Act of 1934 and that complies with the provisions of the Sarbanes-Oxley Act and of Section 303A.07 of the NYSE Listed Company Manual. Eni standards.standards. At its Meeting of March 22, 2005, the Board of Directors, as permitted by the rules of the U.S. Securities and Exchange Commission applicable to foreign issuers listed on regulated U.S. markets, assigned to the Board of Statutory Auditors, effective from June 1, 2005 and within the limits set by Italian law, the functions specified and the responsibilities assigned to the Audit Committee of such foreign issuers by the Sarbanes-Oxley Act and the U.S. SEC rules (see “Item 6 – Board of Statutory Auditors” earlier). Under Section 303A.07 of the NYSE Listed Company Manual, audit committees of U.S. companies have additional functions and duties which are not mandatory for non-U.S. private issuers and which are therefore not included in the list of functions reported in “Item 6 – Board of Statutory Auditors”. Nominating/Corporate Governance Committee NYSE standards.standards. U.S. listed companies must have a Nominating/Corporate Governance Committee (or equivalent body) composed entirely of independent Directors whose functions include, but are not limited to, selecting qualified candidates for the office of Director for submission to the Shareholders’ Meeting, as well as developing and recommending corporate governance guidelines to the Board of Directors. This provision is not binding for non-U.S. private issuers. Eni standards.standards. Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a nomination committee the majority of whose members shall be independent Directors. The Nomination Committee of Eni is made up of three to four Directors, a majority of whom shall be independent in accordance with the recommendations of the Corporate Governance Code1.Code. On (1)
The Committee is currently made up of four Directors, three of whom are independent.
May 9, 2014, April 13, 2017, the Board of Directors of Eni established the Nomination Committee, chaired by Andrea GemmaDiva Moriani (independent Director) and composed of Diva MorianiAndrea Gemma (independent Director), Fabrizio Pagani (non-executive Director) and Luigi ZingalesDomenico Livio Trombone (independent Director). On September 17, 2015, the Board appointed Director Alessandro Profumo (independent Director) as a member of the Committee, replacing Luigi Zingales who resigned from the Board on July 2, 2015. Further details on this Committee are reported in the Item 6.
CompensationRemuneration Committee
NYSE standards.standards. U.S. listed companies must have a CompensationRemuneration Committee composed entirely of independent Directors who must satisfy the independence requirements provided for its members. The CompensationRemuneration Committee must have a written charter that addresses the Committee’s purpose and responsibilities within the limit set forth by the listing rules. The CompensationRemuneration Committee may, in its sole discretion, retain or obtain the advice of a compensation consultant, independent legal counsel or other adviser and shall be directly responsible for the appointment, compensation and oversight of the work of any compensation consultant, independent legal counsel or other adviser retained by it. These provisions are not binding for non-U.S. private issuers. Eni standards.Pursuant to the Corporate Governance Code, the Board of Directors shall establish among its members a CompensationRemuneration Committee made up of three to four non-executive Directors, all of whom shall be independent or, alternatively, a majority of whom shall be independent. In the latter case, the Chairman of the Committee shall be chosen from among the independent Directors. At least one of the Committee’s members shall have an adequate understanding of and experience in financial matters or compensation policies. First established by the Board of Directors in 1996, the CompensationRemuneration Committee is currently chaired by Director Pietro A. Guindani.Andrea Gemma. The other members include directors Karina A. LitvackPietro Guindani, Alessandro Lorenzi and Alessandro Lorenzi2Diva Moriani. The composition and functions of the Remuneration Committee are outlined in the committee charter (“Rules”) available on the Company’s website (https://www.eni.com/docs/en_IT/enicom/company/governance/rules-of-the-remuneration-committee.pdf). Further details on this Committee are reported in the Item 6. Code of Business Conduct and Ethics NYSE standards. The NYSE listing standards require each U.S. listed company to adopt a Code of Business Conduct and Ethics for its Directors, Officers and employees, and to promptly disclose any waivers of the code for Directors or Executive Officers.
Eni standards.standards. At its Meetings of December 15, 2003 and January 28, 2004, the Board of Directors of Eni approved an organizational, management and control model pursuant to Italian Legislative Decree No. 231No.231 of 2001 (hereinafter “Model 231”) and established the associated Eni Watch Structure. Moreover, after subsequent approvals of the updates to Model 231 in response to changes in the Italian legislation governing the matter and in the Company organizational structures, on March 14, 2008, the Board of Directors approved the overall revision of Model 231 and adopted Eni’s Code of Ethics – replacing the previous version of Eni’s Code of Conduct of 1998. Most recently, the Board of Directors, in its meeting held on October 27, 2016, ratifiedSeptember 19, 2019, approved the updating of Model 231, to incorporate a numberas defined by the CEO with the support of legislative changes provided for by law No. 68/2015 (“eco-crime”). The CEO is supported in this activity by the “Technical Committee 231”, consisting of members from the Company’s Legal Affairs, Integrated Compliance Department, Human Resources and Organization and Internal Audit units. The Board of Directors, in its meeting of March 18, 2020, approved the new version of Eni’s Code of Ethics,Ethics; the new Code sets out the fundamental principles of Eni’s Model 231 which is an integral partone of Model 231,the pillars of Eni “regulatory system” and inspires it. Eni’s Code of Ethics sets out a clear definition of the value system that Eni recognizes, accepts and upholds and the responsibilities that Eni assumes internally and externally in order to ensure that all its business activities are conducted in compliance with the law, in a context of fair competition, with honesty, integrity, correctness and in good faith, respecting the legitimate interests of all the stakeholders with whom Eni interacts on an ongoing basis. These include shareholders, employees, suppliers, customers, commercial and financial partners, and the local communities and institutions of the countries where Eni operates. All Eni personnel, without exception or distinction, starting with Directors, senior management and members of the Company’s bodies, as also required under U.S. SEC rules and the Sarbanes-Oxley Act, are committed to observing and enforcing the principles set out in the Code of Ethics in the performance of their functions and duties. The synergies between the Code of Ethics and Model 231 are underscored by the designation of the Eni Watch Structure, established under Model 231, as the Guarantor of the Code of Ethics. The Guarantor of the Code of Ethics acts to ensure the protection and promotion of the above principles. Every six months, it presents a report on the implementation of the Code to the Control and Risk Committee, to the Board of Statutory Auditors and to the Chairman and (2)
Director Diva Moriani left the Compensation Committee on December 22, 2016.
the CEO, who in turn reports on this to the Board of Directors. At present, the Watch Structure of Eni SpA is composed of three external members, including the Chairman, and four internal members. The internal members are Company executives in charge of Legal Affairs, labor law matters and disputes, Internal Audit and Integrated Compliance. External members are independent professionals, experts in law and/or economic matters. Also in order to grant the Watch Structure the greatest extent of autonomy and independence, the set of rules adopted by the Watch Structure provide for specific quorum to convene and to pass resolutions so to ensure that all resolutions are effectively adopted with the favorable vote of the majority of the external members.
Item 16H. Mine safety disclosure Not applicable since Eni does not engage in mining operations.
PART III Item 17. FINANCIAL STATEMENTS Not applicable. Item 18. FINANCIAL STATEMENTS Index to Financial Statements: Item 19. EXHIBITS 1. By-laws of Eni SpA
8. List of subsidiaries
11. Code of Ethics
Certifications:
12.1. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
12.2. Certification pursuant to Rule 13a-14(a) of the Securities Exchange Act
13.1. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
13.2. Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act (such certificate is not deemed filed for purpose of Section 18 of the Exchange Act and not incorporated by reference with any filing under the Securities Act)
15.a(i) Report of DeGolyer and MacNaughton
15.a(ii) Report of Ryder Scott Co
15.a(iii) Gaffney, Cline & Associates
Report of Independent Registered Public Accounting FirmREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Eni S.p.A.SpA OPINIONS ON THE FINANCIAL STATEMENTS AND INTERNAL CONTROL OVER FINANCIAL REPORTING We have audited the accompanying consolidated balance sheetssheet of Eni S.p.A.SpA and its subsidiaries (the “Company”) as of December 31, 2016 and 2015,2019, and the related consolidated profit and loss account and consolidated statements of comprehensive income, changes in shareholders'shareholders’ equity and cash flows for eachthe year then ended, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States)Treadway Commission (COSO). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Eni S.p.A. atthe Company as of December 31, 20162019, and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the periodyear then ended December 31, 2016, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. As discussed Also in Note 5 to the consolidated financial statements,our opinion, the Company has elected to change its method of accounting for the oil & gas exploration and production activities to the “Successful Efforts Method”. The Company applied this changemaintained, in accounting principle retrospectively to all prior periods presented.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Eni S.p.A.’smaterial respects, effective internal control over financial reporting as of December 31, 2016,2019, based on criteria established in Internal Control-IntegratedControl — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations ofCOSO.
Change in Accounting Principle As discussed in Note 3 to the Treadway Commission (2013 framework), and our report dated March 22, 2017 expressed an unqualified opinion thereon.consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019. /s/ Ernst & Young S.p.A.Basis for Opinions
Rome, Italy
March 22, 2017
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Eni S.p.A,
We have audited Eni S.p.A.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Eni S.p.A.’sThe Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting.Reporting appearing under Item 15. Our responsibility is to express an opinionopinions on the company’sCompany’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audit.audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our auditaudits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, andrisk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit providesaudits provide a reasonable basis for our opinion.opinions. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1)(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the
assets of the company; (2)(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3)(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. InCritical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion Eni S.p.A. maintained,on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. The Impact of Estimates of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net As described in all material respects, effective internal controlNotes 1, 11 and 14 to the consolidated financial statements, the Company’s proved oil and natural gas reserves are used in determining depreciation, amortization, and depletion charges and impairment charges. The Company’s consolidated net carrying amount for Exploration and Production (E&P) property, plant and equipment was €55,467 million at December 31, 2019, and the Company’s depreciation, depletion and amortization (DD&A) expense for E&P wells, plant and machinery was €6,435 million for the year ended December 31, 2019. Additionally, the Company incurred impairment losses before taxes associated with the E&P segment of €1,217 million for the year ended December 31, 2019. Oil and natural gas exploration, appraisal and development activities are accounted for using the principles of the successful efforts method of accounting. Under this method, proved exploration rights and acquired proved mineral interests are amortized over financial reportingproved reserves, and proved exploration and appraisal costs and development expenditures are depreciated over proved developed reserves. The accuracy of reserve estimates depends on a number of factors, assumptions and variables, including: (i) the quality of available geological, technical and economic data and their interpretation and judgement; (ii) projections regarding future rates of production and operating costs as well as the timing and amounts of development expenditures; (iii) changes in the prevailing tax rules, other government regulations and contractual conditions; (iv) results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and (v) changes in oil and natural gas prices which could affect expected future cash flows and the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of December 31, 2016, basedthe date when these estimates are made. The principal considerations for our determination that performing procedures relating to the impact of estimates of proved oil and natural gas reserves on proved oil and gas properties, net is a critical audit matter are there was significant judgement by management, including the use of specialists, when developing the expected future cash flows and estimates of proved oil and natural gas reserves. This, in turn, led to a high degree of auditor judgement, subjectivity, and effort in performing procedures and evaluating the significant assumptions used in developing those estimates, including production profiles, crude oil and natural gas prices (including price differentials), capital expenditures, operating expenses and abandonment costs. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the COSO criteria.consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves, the calculation of DD&A expense and the impairment assessment of proved oil and natural gas properties. These procedures also included, among others, evaluating the methods and significant assumptions used by management in developing these estimates, including production profiles, crude oil and natural gas prices (including price differentials), capital expenditures, operating expenses and
abandonment costs. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of these estimates of proved oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications and objectivity were understood, as well as their methods and assumptions. The procedures performed also included tests of the data used by management and the specialists and an evaluation of their findings. Evaluating the significant assumptions relating to the estimates of proved oil and natural gas reserves also involved obtaining evidence to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the past and current performance of the Company, and whether they were consistent with evidence in other areas of the audit. Legal Proceedings Concerning Administrative Corporate Responsibility and Other Proceedings As described in Notes 1 and 27 to the consolidated financial statements, the Company recognizes provisions as liabilities in the consolidated financial statements when (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and (iii) the amount of the obligation can be reliably estimated. Contingent liabilities are: (i) possible obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose amounts cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Eni is a party in a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business, including proceedings related to Block OPL 245 — Nigeria, Congo and Criminal Proceeding no. 12333/2017. No provisions have been made for these legal proceedings as Eni believes that negative outcomes are not probable or because the amount of the provision cannot be estimated reliably. The Company does not recognize contingent liabilities in the financial statements but discloses them within the footnotes to the consolidated financial statements. The principal considerations for our determination that performing procedures relating to legal proceedings concerning administrative corporate responsibility and other proceedings is a critical audit matter are the significant judgement exercised by management when assessing the likelihood of a loss being incurred for the proceedings relating to Block OPL 245 — Nigeria, Congo and Criminal Proceeding no. 12333/2017 can be made, which in turn led to a high degree of auditor judgement, subjectivity, and effort in evaluating management’s assessment of the loss contingencies associated with the legal contingencies. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s evaluation of legal claims and contingencies, including controls over determining whether a loss is probable for the proceedings relating to Block OPL 245 — Nigeria, Congo and Criminal Proceeding no. 12333/2017, as well as the sufficiency of financial statement disclosures. These procedures also included, among others, obtaining and evaluating the letters of audit inquiry with external legal counsel, evaluating the reasonableness of management’s assessment regarding whether an unfavorable outcome is reasonably possible or probable, and evaluating the sufficiency of the Company’s legal contingency disclosures. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of management’s assumptions noted above. PricewaterhouseCoopers SpA (signed) Rome, Italy April 2, 2020 We alsohave served as the Company’s auditor since 2019.
Report of Independent Registered Public Accounting Firm To the Shareholders and the Board of Directors of Eni S.p.A. Opinion on the Financial Statements We have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), theaccompanying consolidated balance sheets of Eni S.p.A. (the Company) as of December 31, 2016 and 2015, and2018, the related consolidated profit and loss accountaccounts and consolidated statements of comprehensive income, changes in shareholders’ equity, and cash flows for each of the threetwo years in the period ended December 31, 20162018, and the related notes (collectively referred to as the “consolidated financial statements”). In our report dated March 22, 2017 expressedopinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an unqualified opinion thereon.on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ Ernst & YoungEY S.p.A. We served as the Company’s auditor from 2010 to 2018. Rome, Italy April 5, 2019 March 22, 2017Note that the report set out above is included for the purposes of Eni S.p.A.’s Annual Report on Form 20-F for 2019 only and does not form part of Eni S.p.A.’s Annual Report for 2018.
CONSOLIDATED BALANCE SHEET (euro€ million) January 1, 2015(a) | | | | | | | | | December 31, 2015(a) | | | December 31, 2016 | | Total amount | | | of which with related parties | | | | | | Note | | | Total amount | | | of which with related parties | | | Total amount | | | of which with related parties | | | | | | | | | | | | | | ASSETS | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6,614 | | | | | | | | | | Cash and cash equivalents | | | (8) | | | | | 5,209 | | | | | | | | | | | | 5,674 | | | | | | | | | | | 5,024 | | | | | | | | | | Financial assets held for trading | | | (9) | | | | | 5,028 | | | | | | | | | | | | 6,166 | | | | | | 257 | | | | | | | | | | Financial assets available for sale | | | (10) | | | | | 282 | | | | | | | | | | | | 238 | | | | | | 28,601 | | | | | | 1,973 | | | | Trade and other receivables | | | (11) | | | | | 21,640 | | | | | | 1,985 | | | | | | 17,593 | | | | | | 1,100 | | | | | 7,555 | | | | | | | | | | Inventories | | | (12) | | | | | 4,579 | | | | | | | | | | | | 4,637 | | | | | | 762 | | | | | | | | | | Current tax assets | | | (13) | | | | | 360 | | | | | | | | | | | | 383 | | | | | | 1,209 | | | | | | | | | | Other current tax assets | | | (14) | | | | | 630 | | | | | | | | | | | | 689 | | | | | | 4,385 | | | | | | 43 | | | | Other current assets | | | (15) (34) | | | | | 3,642 | | | | | | 50 | | | | | | 2,591 | | | | | | 57 | | | | | 54,407 | | | | | | | | | | | | | | | | | | 41,370 | | | | | | | | | | | | 37,971 | | | | | | | | | | | | | | | | Non-current assets | | | | | | | | | 75,991 | | | | | | | | | | Property, plant and equipment | | | (16) | | | | | 68,005 | | | | | | | | | | | | 70,793 | | | | | | 1,581 | | | | | | | | | | Inventory – compulsory stock | | | (17) | | | | | 909 | | | | | | | | | | | | 1,184 | | | | | | 4,420 | | | | | | | | | | Intangible assets | | | (18) | | | | | 3,034 | | | | | | | | | | | | 3,269 | | | | | | 3,172 | | | | | | | | | | Equity-accounted investments | | | (20) | | | | | 2,853 | | | | | | | | | | | | 4,040 | | | | | | 2,015 | | | | | | | | | | Other investments | | | (20) | | | | | 660 | | | | | | | | | | | | 276 | | | | | | 1,042 | | | | | | 259 | | | | Other financial assets | | | (21) | | | | | 1,026 | | | | | | 396 | | | | | | 1,860 | | | | | | 1,349 | | | | | 4,509 | | | | | | | | | | Deferred tax assets | | | (22) | | | | | 3,853 | | | | | | | | | | | | 3,790 | | | | | | 2,773 | | | | | | 12 | | | | Other non-current assets | | | (23) (34) | | | | | 1,758 | | | | | | 10 | | | | | | 1,348 | | | | | | 13 | | | | | 95,503 | | | | | | | | | | | | | | | | | | 82,098 | | | | | | | | | | | | 86,560 | | | | | | 456 | | | | | | | | | | Discontinued operations and assets held for sale | | | (35) | | | | | 15,533 | | | | | | 308 | | | | | | 14 | | | | | | 150,366 | | | | | | | | | | TOTAL ASSETS | | | | | | | | 139,001 | | | | | | | | | | | | 124,545 | | | | | | | | | | | | | | | | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | | | | | | | | | | | | Current liabilities | | | | | | | | | 2,716 | | | | | | 181 | | | | Short-term debt | | | (24) | | | | | 5,720 | | | | | | 208 | | | | | | 3,396 | | | | | | 191 | | | | | 3,859 | | | | | | | | | | Current portion of long-term debt | | | (29) | | | | | 2,676 | | | | | | | | | | | | 3,279 | | | | | | 23,703 | | | | | | 1,954 | | | | Trade and other payables | | | (25) | | | | | 14,942 | | | | | | 1,544 | | | | | | 16,703 | | | | | | 2,289 | | | | | 534 | | | | | | | | | | Income tax payable | | | (26) | | | | | 431 | | | | | | | | | | | | 426 | | | | | | 1,873 | | | | | | | | | | Other tax payable | | | (27) | | | | | 1,454 | | | | | | | | | | | | 1,293 | | | | | | 4,489 | | | | | | 58 | | | | Other current liabilities | | | (28) (34) | | | | | 4,712 | | | | | | 96 | | | | | | 2,599 | | | | | | 88 | | | | | 37,174 | | | | | | | | | | | | | | | | | | 29,935 | | | | | | | | | | | | 27,696 | | | | | | | | | | | | | | | | Non-current liabilities | | | | | | | | | 19,316 | | | | | | | | | | Long-term debt | | | (29) | | | | | 19,397 | | | | | | | | | | | | 20,564 | | | | | | 15,882 | | | | | | | | | | Provisions for contingencies | | | (30) | | | | | 15,375 | | | | | | | | | | | | 13,896 | | | | | | 1,313 | | | | | | | | | | Provisions for employee benefits | | | (31) | | | | | 1,123 | | ��� | | | | | | | | | | 868 | | | | | | 8,590 | | | | | | | | | | Deferred tax liabilities | | | (32) | | | | | 7,425 | | | | | | | | | | | | 6,667 | | | | | | 2,285 | | | | | | 20 | | | | Other non-current liabilities | | | (33) (34) | | | | | 1,852 | | | | | | 23 | | | | | | 1,768 | | | | | | 23 | | | | | 47,386 | | | | | | | | | | | | | | | | | | 45,172 | | | | | | | | | | | | 43,763 | | | | | | 165 | | | | | | | | | | Discontinued operations and liabilities directly associated with assets held for sale | | | (35) | | | | | 6,485 | | | | | | 207 | | | | | | | 84,725 | | | | | | | | | | TOTAL LIABILITIES | | | | | | | | 81,592 | | | | | | | | | | | | 71,459 | | | | | | | | | | | | | | | | SHAREHOLDERS’ EQUITY | | | (36) | | | | | | | | 2,455 | | | | | | | | | | Non-controlling interest | | | | | | | | 1,916 | | | | | | | | | | | | 49 | | | | | | | | | | | | | | | | Eni shareholders’ equity | | | | | | | | | 4,005 | | | | | | | | | | Share capital | | | | | | | | 4,005 | | | | | | | | | | | | 4,005 | | | | | | (284) | | | | | | | | | | Reserve related to cash flow hedging derivatives net of tax effect | | | | | | | | (474) | | | | | | | | | | | | 189 | | | | | | 60,763 | | | | | | | | | | Other reserves | | | | | | | | 62,761 | | | | | | | | | | | | 52,329 | | | | | | (581) | | | | | | | | | | Treasury shares | | | | | | | | (581) | | | | | | | | | | | | (581) | | | | | | (2,020) | | | | | | | | | | Interim dividend | | | | | | | | (1,440) | | | | | | | | | | | | (1,441) | | | | | | 1,303 | | | | | | | | | | Net profit (loss) | | | | | | | | (8,778) | | | | | | | | | | | | (1,464) | | | | | | 63,186 | | | | | | | | | | Total Eni shareholders’ equity | | | | | | | | 55,493 | | | | | | | | | | | | 53,037 | | | | | | 65,641 | | | | | | | | | | TOTAL SHAREHOLDERS’ EQUITY | | | | | | | | 57,409 | | | | | | | | | | | | 53,086 | | | | | | 150,366 | | | | | | | | | | TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | 139,001 | | | | | | | | | | | | 124,545 | | | | | | | | | |
| January 1, 2018 | | | | | | | | | December 31, 2019 | | | December 31, 2018 | | | Total amount | | | of which with related parties | | | | | | Note | | | Total amount | | | of which with related parties | | | Total amount | | | of which with related parties | | | | | | | | | | | | ASSETS | | | | | | | | | | | | | | | | | | | | | | | | | | | Current assets | | | | | | | | | | | | | | | | | | | | 7,363 | | | | | | | Cash and cash equivalents | | | (5) | | | 5,994 | | | | | | 10,836 | | | | | | | | 6,219 | | | | | | | Financial assets held for trading | | | (6) | | | 6,760 | | | | | | 6,552 | | | | | | | | 316 | | | | 73 | | | Other current financial assets | | | (16) | | | 384 | | | 60 | | | 300 | | | 49 | | | | | 14,156 | | | | 834 | | | Trade and other receivables | | | (7) | | | 12,873 | | | 704 | | | 14,101 | | | 633 | | | | | 4,621 | | | | | | | Inventories | | | (8) | | | 4,734 | | | | | | 4,651 | | | | | | | | 191 | | | | | | | Income tax receivables | | | (9) | | | 192 | | | | | | 191 | | | | | | | | 2,768 | | | | 30 | | | Other current assets | | | (10) (23) | | | 3,972 | | | 219 | | | 2,819 | | | 71 | | | | | 35,634 | | | | | | | | | | | | | 34,909 | | | | | | 39,450 | | | | | | | | | | | | | | | Non-current assets | | | | | | | | | | | | | | | | | | | | 63,158 | | | | | | | Property, plant and equipment | | | (11) | | | 62,192 | | | | | | 60,302 | | | | | | | | | | | | | | | Right-of-use assets | | | (12) | | | 5,349 | | | | | | | | | | | | | | 3,012 | | | | | | | Intangible assets | | | (13) | | | 3,059 | | | | | | 3,170 | | | | | | | | 1,283 | | | | | | | Inventory – Compulsory stock | | | (8) | | | 1,371 | | | | | | 1,217 | | | | | | | | 3,474 | | | | | | | Equity-accounted investments | | | (15) | | | 9,035 | | | | | | 7,044 | | | | | | | | 900 | | | | | | | Other investments | | | (15) | | | 929 | | | | | | 919 | | | | | | | | 1,675 | | | | 1,214 | | | Other non-current financial assets | | | (16) | | | 1,174 | | | 911 | | | 1,253 | | | 915 | | | | | 4,315 | | | | | | | Deferred tax assets | | | (22) | | | 4,360 | | | | | | 3,931 | | | | | | | | 182 | | | | | | | Income tax receivables | | | (9) | | | 173 | | | | | | 168 | | | | | | | | 1,141 | | | | 46 | | | Other non-current assets | | | (10) (23) | | | 871 | | | 181 | | | 624 | | | 160 | | | | | 79,140 | | | | | | | | | | | | | 88,513 | | | | | | 78,628 | | | | | | | | 323 | | | | | | | Assets held for sale | | | (24) | | | 18 | | | | | | 295 | | | | | | | | 115,097 | | | | | | | TOTAL ASSETS | | | | | | 123,440 | | | | | | 118,373 | | | | | | | | | | | | | | | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | | | | | | | | | | Current liabilities | | | | | | | | | | | | | | | | 2,242 | | | | 164 | | | Short-term debt | | | (18) | | | 2,452 | | | 46 | | | 2,182 | | | 661 | | | | | 2,286 | | | | | | | Current portion of long-term debt | | | (18) | | | 3,156 | | | | | | 3,601 | | | | | | | | | | | | | | | Current portion of long-term lease liabilities | | | (12) | | | 889 | | | 5 | | | | | | | | | | | 15,305 | | | | 2,808 | | | Trade and other payables | | | (17) | | | 15,545 | | | 2,663 | | | 16,747 | | | 3,664 | | | | | 472 | | | | | | | Income tax payables | | | (9) | | | 456 | | | | | | 440 | | | | | | | | 4,317 | | | | 60 | | | Other current liabilities | | | (10) (23) | | | 7,146 | | | 155 | | | 5,412 | | | 63 | | | | | 24,622 | | | | | | | | | | | | | 29,644 | | | | | | 28,382 | | | | | | | | | | | | | | | Non-current liabilities | | | | | | | | | | | | | | | | | | | | 20,179 | | | | | | | Long-term debt | | | (18) | | | 18,910 | | | | | | 20,082 | | | | | | | | | | | | | | | Long-term lease liabilities | | | (12) | | | 4,759 | | | 8 | | | | | | | | | | | 13,124 | | | | | | | Provisions | | | (20) | | | 14,106 | | | | | | 11,626 | | | | | | | | 1,022 | | | | | | | Provisions for employee benefits | | | (21) | | | 1,136 | | | | | | 1,117 | | | | | | | | 5,937 | | | | | | | Deferred tax liabilities | | | (22) | | | 4,920 | | | | | | 4,272 | | | | | | | | 359 | | | | | | | Income tax payables | | | (9) | | | 454 | | | | | | 287 | | | | | | | | 1,443 | | | | 23 | | | Other non-current liabilities | | | (10) (23) | | | 1,611 | | | 23 | | | 1,475 | | | 23 | | | | | 42,064 | | | | | | | | | | | | | 45,896 | | | | | | 38,859 | | | | | | | | 87 | | | | | | | Liabilities directly associated with assets held for sale | | | (24) | | | | | | | | | 59 | | | | | | | | 66,773 | | | | | | | TOTAL LIABILITIES | | | | | | 75,540 | | | | | | 67,300 | | | | | | | | | | | | | | | SHAREHOLDERS’ EQUITY | | | (25) | | | | | | | | | | | | | | | | | 49 | | | | | | | Non-controlling interest | | | | | | 61 | | | | | | 57 | | | | | | | | | | | | | | | Eni shareholders’ equity | | | | | | | | | | | | | | | | | | | | 4,005 | | | | | | | Share capital | | | | | | 4,005 | | | | | | 4,005 | | | | | | | | 36,211 | | | | | | | Retained earnings | | | | | | 37,436 | | | | | | 36,702 | | | | | | | | 4,818 | | | | | | | Cumulative currency translation differences | | | | | | 7,209 | | | | | | 6,605 | | | | | | | | 1,889 | | | | | | | Other reserves | | | | | | 1,564 | | | | | | 1,672 | | | | | | | | (581) | | | | | | | Treasury shares | | | | | | (981) | | | | | | (581) | | | | | | | | (1,441) | | | | | | | Interim dividend | | | | | | (1,542) | | | | | | (1,513) | | | | | | | | 3,374 | | | | | | | Net profit | | | | | | 148 | | | | | | 4,126 | | | | | | | | 48,275 | | | | | | | Total Eni shareholders’ equity | | | | | | 47,839 | | | | | | 51,016 | | | | | | | | 48,324 | | | | | | | TOTAL SHAREHOLDERS’ EQUITY | | | | | | 47,900 | | | | | | 51,073 | | | | | | | | 115,097 | | | | | | | TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | 123,440 | | | | | | 118,373 | | | | |
See the accompanying notes.
(a)
Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles.
CONSOLIDATED PROFIT AND LOSS ACCOUNT (euro€ million except as otherwise stated) | | | | | | | | 2014(a) | | 2015(a) | | 2016 | | | | | | 2019 | | 2018 | | 2017 | | | | Note | | Total amount | | of which with related parties | | Total amount | | of which with related parties | | Total amount | | of which with related parties | | | | REVENUES | | | | (39) | | | | | | Net sales from operations | | | | | | | | | 98,218 | | | | | 1,497 | | | | | 72,286 | | | | | 1,342 | | | | | 55,762 | | | | | 1,238 | | | | | | | | Note | | Total amount | | of which with related parties | | Total amount | | of which with related parties | | Total amount | | of which with related parties | | REVENUES AND OTHER INCOME | | | (28) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales from operations | | | | | | | 69,881 | | | | | 1,248 | | | | | 75,822 | | | | | 1,383 | | | | | 66,919 | | | | | 1,567 | | | Other income and revenues | | | | | | | | | 1,079 | | | | | 69 | | | | | 1,252 | | | | | 69 | | | | | 931 | | | | | 74 | | | | | | | | | 1,160 | | | | | 4 | | | | | 1,116 | | | | | 8 | | | | | 4,058 | | | | | 41 | | | | | | | | | | | | 99,297 | | | | | | | | | | 73,538 | | | | | | | | | | 56,693 | | | | | | | | | | 71,041 | | | | | | | | | | 76,938 | | | | | | | | | | 70,977 | | | | | | | | OPERATING EXPENSES | | | | (40) | | | | | | COSTS | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Purchases, services and other | | | | | | | | | 77,404 | | | | | 7,143 | | | | | 56,848 | | | | | 6,882 | | | | | 44,124 | | | | | 8,212 | | | | | (29) | | | | (50,874) | | | | | (9,173) | | | | | (55,622) | | | | | (8,009) | | | | | (51,548) | | | | | (9,164) | | | Net (impairment losses) reversals of trade and other receivables | | | (7) | | | | (432) | | | | | 28 | | | | | (415) | | | | | 26 | | | | | (913) | | | | | | | | Payroll and related costs | | | | | | | | | 2,929 | | | | | 60 | | | | | 3,119 | | | | | 55 | | | | | 2,994 | | | | | 24 | | | | | (29) | | | | (2,996) | | | | | (28) | | | | | (3,093) | | | | | (22) | | | | | (2,951) | | | | | (34) | | | OTHER OPERATING (EXPENSE) INCOME | | | | (40) | | | | | 145 | | | | | 208 | | | | | (485) | | | | | 96 | | | | | 16 | | | | | 247 | | | | | Other operating income (expense) | | | (23) | | �� | | | 287 | | | | | 19 | | | | | 129 | | | | | 319 | | | | | (32) | | | | | 331 | | | Depreciation and amortization | | | | (40) | | | | | 7,676 | | | | | | | | | | 8,940 | | | | | | | | | | 7,559 | | | | | | (11) (12) (13) | | | | (8,106) | | | | | | | | | | (6,988) | | | | | | | | | | (7,483) | | | | | | | | Net Impairments/reversal | | | | (40) | | | | | 1,270 | | | | | | | | | | 6,534 | | | | | | | | | | (475) | | | | | | Net (impairment losses) reversals of tangible and intangible assets and right-of-use assets | | | (14) | | | | (2,188) | | | | | | | | | | (866) | | | | | | | | | | 225 | | | | | | | | Write-off of tangible and intangible assets | | | | (40) | | | | | 1,198 | | | | | | | | | | 688 | | | | | | | | | | 350 | | | | | | (11) (13) | | | | (300) | | | | | | | | | | (100) | | | | | | | | | | (263) | | | | | | | | OPERATING PROFIT (LOSS) | | | | | | | | | 8,965 | | | | | | | | | | (3,076) | | | | | | | | | | 2,157 | | | | | | OPERATING PROFIT | | | | | | | 6,432 | | | | | | | | | | 9,983 | | | | | | | | | | 8,012 | | | | | | | | FINANCE INCOME (EXPENSE) | | | | (41) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Finance income | | | | | | | | | 5,701 | | | | | 46 | | | | | 8,635 | | | | | 83 | | | | | 5,850 | | | | | 157 | | | | | (30) | | | | 3,087 | | | | | 96 | | | | | 3,967 | | | | | 115 | | | | | 3,924 | | | | | 191 | | | Finance expense | | | | | | | | | (7,057) | | | | | (41) | | | | | (10,104) | | | | | (50) | | | | | (6,232) | | | | | (145) | | | | | (30) | | | | (4,079) | | | | | (36) | | | | | (4,663) | | | | | (283) | | | | | (5,886) | | | | | (4) | | | Net Finance income from financial assets held for trading | | | | | | | | | 24 | | | | | | | | | | 3 | | | | | | | | | | (21) | | | | | | Derivatives financial instruments | | | | | | | | | 165 | | | | | | | | | | 160 | | | | | | | | | | (482) | | | | | 27 | | | | | Net finance income (expense) from financial assets held for trading | | | (30) | | | | 127 | | | | | | | | | | 32 | | | | | | | | | | (111) | | | | | | | | Derivative financial instruments | | | (23) (30) | | | | (14) | | | | | | | | | | (307) | | | | | | | | | | 837 | | | | | | | | | | | | | | | | | (1,167) | | | | | | | | | | (1,306) | | | | | | | | | | (885) | | | | | | | | | | (879) | | | | | | | | | | (971) | | | | | | | | | | (1,236) | | | | | | | | INCOME (EXPENSE) FROM INVESTMENTS | | | | (42) | | | | | | (15) (31) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Share of profit (loss) from equity-accounted investments | | | | | | | | | 110 | | | | | | | | | | (471) | | | | | | | | | | (326) | | | | | | | | | | (88) | | | | | | | | | | (68) | | | | | | | | | | (267) | | | | | | | | Other gain (loss) from investments | | | | | | | | | 366 | | | | | | | | | | 576 | | | | | | | | | | (54) | | | | | | | | | | 281 | | | | | | | | | | 1,163 | | | | | | | | | | 335 | | | | | | | | | | | | | | | | | 476 | | | | | | | | | | 105 | | | | | | | | | | (380) | | | | | | | | | | 193 | | | | | | | | | | 1,095 | | | | | | | | | | 68 | | | | | | | | PROFIT BEFORE INCOME TAXES | | | | | | | | | 8,274 | | | | | | | | | | (4,277) | | | | | | | | | | 892 | | | | | | | | | | 5,746 | | | | | | | | | | 10,107 | | | | | | | | | | 6,844 | | | | | | | | Income taxes | | | | (43) | | | | | (6,466) | | | | | | | | | | (3,122) | | | | | | | | | | (1,936) | | | | | | (32) | | | | (5,591) | | | | | | | | | | (5,970) | | | | | | | | | | (3,467) | | | | | | | | Net profit (loss) for the year - Continuing operations | | | | | | | | | 1,808 | | | | | | | | | | (7,399) | | | | | | | | | | (1,044) | | | | | | Net profit (loss) for the year - Discontinued operations | | | | (35) | | | | | (949) | | | | | 867 | | | | | (1,974) | | | | | 142 | | | | | (413) | | | | | | Net profit (loss) for the year | | | | | | | | | 859 | | | | | | | | | | (9,373) | | | | | | | | | | (1,457) | | | | | | Net profit | | | | | | | 155 | | | | | | | | | | 4,137 | | | | | | | | | | 3,377 | | | | | | | | Attributable to Eni | | | | | | | | | 148 | | | | | | | | | | 4,126 | | | | | | | | | | 3,374 | | | | | | | | – continuing operations | | | | | | | | | 1,720 | | | | | | | | | | (7,952) | | | | | | | | | | (1,051) | | | | | | – discontinued operations | | | | (35) | | | | | (417) | | | | | | | | | | (826) | | | | | | | | | | (413) | | | | | | | | | | | | | | | 1,303 | | | | | | | | | | (8,778) | | | | | | | | | | (1,464) | | | | | | Attributable to non-controlling interest | | | | (36) | | | | | | | | | | 7 | | | | | | | | | | 11 | | | | | | | | | | 3 | | | | | | | | - continuing operations | | | | | | | | | 88 | | | | | | | | | | 553 | | | | | | | | | | 7 | | | | | | - discontinued operations | | | | (35) | | | | | (532) | | | | | | | | | | (1,148) | | | | | | | | | | | | | | | | | | | | | | (444) | | | | | | | | | | (595) | | | | | | | | | | 7 | | | | | | | | | | 155 | | | | | | | | | | 4,137 | | | | | | | | | | 3,377 | | | | | | | | Earnings per share attributable to Eni (€ per share) | | | | (44) | | | | | | (33) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Basic | | | | | | | | | 0.36 | | | | | | | | | | (2.44) | | | | | | | | | | (0.41) | | | | | | | | | | 0.04 | | | | | | | | | | 1.15 | | | | | | | | | | 0.94 | | | | | | | | Diluted | | | | | | | | | 0.36 | | | | | | | | | | (2.44) | | | | | | | | | | (0.41) | | | | | | | | | | 0.04 | | | | | | | | | | 1.15 | | | | | | | | | | 0.94 | | | | | | | | Earnings per share attributable to Eni - Continuing operations (€ per share) | | | | (44) | | | | | | Basic | | | | | | | | | 0.48 | | | | | | | | | | (2.21) | | | | | | | | | | (0.29) | | | | | | Diluted | | | | | | | | | 0.48 | | | | | | | | | | (2.21) | | | | | | | | | | (0.29) | | | | | | | | | | | |
See the accompanying notes.
(a)
Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles.
CONSOLIDATED STATEMENTSSTATEMENT OF COMPREHENSIVE INCOME (euro€ million) | | | | | | | | Note | | | 2014(a) | | | 2015(a) | | | 2016 | | Net profit | | | | | | | | | | | 859 | | | | | | (9,373) | | | | | | (1,457) | | | Other items of comprehensive income | | | | | | Items that are not reclassified to profit in later periods | | | | | | Remeasurements of defined benefit plans | | | | | (36) | | | | | | (82) | | | | | | 36 | | | | | | 16 | | | Share of other comprehensive income on equity accounted entities in relation to remeasurements of defined benefit plans | | | | | (36) | | | | | | 3 | | | | | Tax effect related to other comprehensive income not to be reclassified to profit or loss in subsequent periods | | | | | (36) | | | | | | 22 | | | | | | (21) | | | | | | (35) | | | | | | | | | | | | | | (57) | | | | | | 15 | | | | | | (19) | | | Items that may be reclassified to profit in later periods | | | | | | Currency translation differences | | | | | (36) | | | | | | 5,427 | | | | | | 4,837 | | | | | | 1,198 | | | Change in the fair value of available-for-sale investments | | | | | (36) | | | | | | (77) | | | | | Change in the fair value of other available-for-sale financial instruments | | | | | (36) | | | | | | 7 | | | | | | (4) | | | | | | (4) | | | Change in the fair value of cash flow hedging derivatives | | | | | (36) | | | | | | (167) | | | | | | (256) | | | | | | 883 | | | Share of other comprehensive income on equity-accounted entities | | | | | (36) | | | | | | 4 | | | | | | (9) | | | | | | 32 | | | Tax effect related to other comprehensive income to be reclassified to profit or loss in subsequent periods | | | | | (36) | | | | | | 30 | | | | | | 66 | | | | | | (220) | | | | | | | | | | | | | | 5,224 | | | | | | 4,634 | | | | | | 1,889 | | | Total other items of comprehensive income | | | | | | | | | | | 5,167 | | | | | | 4,649 | | | | | | 1,870 | | | Total comprehensive income | | | | | | | | | | | 6,026 | | | | | | (4,724) | | | | | | 413 | | | Attributable to Eni | | | | | | - continuing operations | | | | | | | | | | | 6,817 | | | | | | (3,416) | | | | | | 819 | | | - discontinued operations | | | | | (35) | | | | | | (390) | | | | | | (779) | | | | | | (413) | | | | | | | | | | | | | | 6,427 | | | | | | (4,195) | | | | | | 406 | | | Attributable to non-controlling interest | | | | | | - continuing operations | | | | | | | | | | | 91 | | | | | | 554 | | | | | | 7 | | | - discontinued operations | | | | | (35) | | | | | | (492) | | | | | | (1,083) | | | | | | | | | | | | | | | | | (401) | | | | | | (529) | | | | | | 7 | | | |
| | | | | | | | Note | | | 2019 | | | 2018 | | | 2017 | | Net profit | | | | | | | | | | | 155 | | | | | | 4,137 | | | | | | 3,377 | | | Other items of comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | | | | | | | Items that are not reclassified to profit or loss in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | Remeasurements of defined benefit plans | | | | | (25) | | | | | | (42) | | | | | | (15) | | | | | | (33) | | | Share of other comprehensive income (loss) on equity-accounted investments related to benefit plans remeasurements | | | | | (25) | | | | | | (7) | | | | | | | | | | | | | | | Change of minor investments measured at fair value with effects to other comprehensive income | | | | | (25) | | | | | | (3) | | | | | | 15 | | | | | | | | | Tax effect | | | | | (25) | | | | | | 5 | | | | | | (2) | | | | | | 29 | | | | | | | | | | | | | | (47) | | | | | | (2) | | | | | | (4) | | | Items that may be reclassified to profit or loss in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | Currency translation differences | | | | | (25) | | | | | | 604 | | | | | | 1,787 | | | | | | (5,573) | | | Change in the fair value of available-for-sale financial instruments | | | | | | | | | | | | | | | | | | | | | | | (5) | | | Change in the fair value of cash flow hedging derivatives | | | | | (25) | | | | | | (679) | | | | | | (243) | | | | | | (6) | | | Share of other comprehensive income (loss) on equity-accounted investments | | | | | (25) | | | | | | (6) | | | | | | (24) | | | | | | 69 | | | Tax effect | | | | | (25) | | | | | | 197 | | | | | | 58 | | | | | | 1 | | | | | | | | | | | | | | 116 | | | | | | 1,578 | | | | | | (5,514) | | | Total other items of comprehensive income (loss) | | | | | | | | | | | 69 | | | | | | 1,576 | | | | | | (5,518) | | | Total comprehensive income (loss) | | | | | | | | | | | 224 | | | | | | 5,713 | | | | | | (2,141) | | | Attributable to Eni | | | | | | | | | | | 217 | | | | | | 5,702 | | | | | | (2,144) | | | Attributable to non-controlling interest | | | | | | | | | | | 7 | | | | | | 11 | | | | | | 3 | | | | | | | | | | | | | | 224 | | | | | | 5,713 | | | | | | (2,141) | | |
See the accompanying notes.
(a)
Information on the restatement of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (euro€ million) | | | | | | Eni shareholders’ equity | | | | | | | | | | | | | | | | | Note | | | Share capital | | | Legal reserve of Eni SpA | | | Reserve for treasury shares | | | Reserve related to the fair value of cash flow hedging derivatives net of the tax effect | | | Reserve related to the fair value of available- for-sale financial instruments net of the tax effect | | | Reserve for defined benefit plans net of the tax effect | | | Other reserves | | | Cumulative currency translation differences | | | Treasury shares | | | Retained earnings | | | Interim dividend | | | Net profit (loss) for the year | | | Other comprehensive income (loss) related to discontinued operations | | | Total | | | Non- controlling interest | | | Total shareholders’ equity | | Balance at December 31, 2013 | | | | | | | | 4,005 | | | | | | 959 | | | | | | 6,201 | | | | | | (154) | | | | | | 81 | | | | | | (72) | | | | | | 296 | | | | | | (698) | | | | | | (201) | | | | | | 44,626 | | | | | | (1,993) | | | | | | 5,160 | | | | | | | | | | | | 58,210 | | | | | | 2,839 | | | | | | 61,049 | | | Changes in accounting principles (SEM) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3,001 | | | | | | | | | | | | | | | | | | | | | | | | 3,001 | | | | | | 3 | | | | | | 3,004 | | | Balance at January 1, 2014 | | | | | | | | 4,005 | | | | | | 959 | | | | | | 6,201 | | | | | | (154) | | | | | | 81 | | | | | | (72) | | | | | | 296 | | | | | | (698) | | | | | | (201) | | | | | | 47,627 | | | | | | (1,993) | | | | | | 5,160 | | | | | | | | | | | | 61,211 | | | | | | 2,842 | | | | | | 64,053 | | | Net profit (loss) for the year | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,303 | | | | | | | | | | | | 1,303 | | | | | | (444) | | | | | | 859 | | | Other items of comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Items that are not reclassified to profit in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Remeasurements of defined benefit plans net of tax effect | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (51) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (51) | | | | | | (9) | | | | | | (60) | | | Share of “Other comprehensive income” on equity-accounted entities in relation to remeasurements of defined benefit plans net of tax effect | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | | | 1 | | | | | | 3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (49) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (49) | | | | | | (8) | | | | | | (57) | | | Items that may be reclassified to profit in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Currency translation differences | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | 5,137 | | | | | | | | | | | | 232 | | | | | | | | | | | | | | | | | | | | | | | | 5,368 | | | | | | 59 | | | | | | 5,427 | | | Change and reversal of the fair value of investments net of tax effect | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (76) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (76) | | | | | | | | | | | | (76) | | | Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6 | | | | | | | | | | | | 6 | | | Change and reversal the fair value of cash flow hedge derivatives net of tax effect | | | | | | | | | | | | | | | | | | | | | | | | | | (130) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (130) | | | | | | (7) | | | | | | (137) | | | Share of “Other comprehensive income” on equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5 | | | | | | (1) | | | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (130) | | | | | | (70) | | | | | | (1) | | | | | | 5 | | | | | | 5,137 | | | | | | | | | | | | 232 | | | | | | | | | | | | | | | | | | | | | | | | 5,173 | | | | | | 51 | | | | | | 5,224 | | | Total comprehensive income of the year | | | | | | | | | | | | | | | | | | | | | | | | | | (130) | | | | | | (70) | | | | | | (50) | | | | | | 5 | | | | | | 5,137 | | | | | | | | | | | | 232 | | | | | | | | | | | | 1,303 | | | | | | | | | | | | 6,427 | | | | | | (401) | | | | | | 6,026 | | | Transactions with shareholders | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dividend distribution of Eni SpA (€0.55 per share in settlement of 2013 interim dividend of €0.55 per share) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,993 | | | | | | (3,979) | | | | | | | | | | | | (1,986) | | | | | | | | | | | | (1,986) | | | Interim dividend distribution of Eni SpA (€0.56 per share) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (2,020) | | | | | | | | | | | | | | | | | | (2,020) | | | | | | | | | | | | (2,020) | | | Dividend distribution of other companies | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (49) | | | | | | (49) | | | Allocation of 2013 net profit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,181 | | | | | | | | | | | | (1,181) | | | | | | | | | | | | | | | | | | | | | | | | | | | Acquisition of treasury shares | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (380) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (380) | | | | | | | | | | | | (380) | | | Payments and reimbursements by/to minority shareholders | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ��� | | 1 | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (380) | | | | | | 1,181 | | | | | | (27) | | | | | | (5,160) | | | | | | | | | | | | (4,386) | | | | | | (48) | | | | | | (4,434) | | | Other changes in shareholders’ equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Elimination of intercompany profit between companies with different Group interest | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (62) | | | | | | | | | | | | | | | | | | | | | | | | (62) | | | | | | 62 | | | | | | | | | Stock options expired | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (7) | | | | | | | | | | | | | | | | | | | | | | | | (7) | | | | | | | | | | | | (7) | | | Other changes | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (94) | | | | | | | | | | | | | | | | | | 97 | | | | | | | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | 3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (94) | | | | | | | | | | | | | | | | | | 28 | | | | | | | | | | | | | | | | | | | | | | | | (66) | | | | | | 62 | | | | | | (4) | | | Balance at December 31, 2014 | | | (36) | | | | | 4,005 | | | | | | 959 | | | | | | 6,201 | | | | | | (284) | | | | | | 11 | | | | | | (122) | | | | | | 207 | | | | | | 4,439 | | | | | | (581) | | | | | | 49,068 | | | | | | (2,020) | | | | | | 1,303 | | | | | | | | | | | | 63,186 | | | | | | 2,455 | | | | | | 65,641 | | | Net profit (loss) for the year | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (8,778) | | | | | | | | | | | | (8,778) | | | | | | (595) | | | | | | (9,373) | | | Other items of comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Items that are not reclassified to profit in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Remeasurements of defined benefit plans net of tax effect | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 14 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 14 | | | | | | 1 | | | | | | 15 | | | Reclassification of “Other comprehensive loss” related to discontinued operations | | | (35) (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (8) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 22 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (8) | | | | | | 14 | | | | | | 1 | | | | | | 15 | | | Items that may be reclassified to profit in later periods | | | | | | | | | | | | | | | | | | | Currency translation differences | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | 4,722 | | | | | | | | | | | | 54 | | | | | | | | | | | | | | | | | | | | | | | | 4,775 | | | | | | 62 | | | | | | 4,837 | | | Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (3) | | | | | | | | | | | | (3) | | | Change and reversal the fair value of cash flow hedge derivatives net of tax effect | | | (36) | | | | | | | | | | | | | | | | | | | | | | | (194) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (194) | | | | | | 3 | | | | | | (191) | | | Share of “Other comprehensive income” on equity-accounted entities | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (9) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (9) | | | | | | | | | | | | (9) | | | Reclassification of “Other comprehensive income” related to discontinued operations | | | (35) (36) | | | | | | | | | | | | | | | | | | | | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | (32) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 28 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (190) | | | | | | (3) | | | | | | (1) | | | | | | (9) | | | | | | 4,690 | | | | | | | | | | | | 54 | | | | | | | | | | | | | | | | | | 28 | | | | | | 4,569 | | | | | | 65 | | | | | | 4,634 | | | Total comprehensive income of the year | | | | | | | | | | | | | | | | | | | | | | | | | | (190) | | | | | | (3) | | | | | | 21 | | | | | | (9) | | | | | | 4,690 | | | | | | | | | | | | 54 | | | | | | | | | | | | (8,778) | | | | | | 20 | | | | | | (4,195) | | | | | | (529) | | | | | | (4,724) | | | Transactions with shareholders | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dividend distribution of Eni SpA (€0.56 per share in settlement of 2014 interim dividend of €0.56 per share) | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,020 | | | | | | (4,037) | | | | | | | | | | | | (2,017) | | | | | | | | | | | | (2,017) | | | Interim dividend distribution of Eni SpA (€0.40 per share) | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1,440) | | | | | | | | | | | | | | | | | | (1,440) | | | | | | | | | | | | (1,440) | | | Dividend distribution of other companies | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (21) | | | | | | (21) | | | Allocation of 2014 net loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (2,734) | | | | | | | | | | | | 2,734 | | | | | | | | | | | | | | | | | | | | | | | | | | | Payments and reimbursements by/to minority shareholders | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (2,734) | | | | | | 580 | | | | | | (1,303) | | | | | | | | | | | | (3,457) | | | | | | (20) | | | | | | (3,477) | | | Other changes in shareholders’ equity | | | | | | | | | | | | | | | | | | | Elimination of intercompany profit between companies with different Group interest | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (28) | | | | | | | | | | | | | | | | | | | | | | | | (28) | | | | | | 28 | | | | | | | | | Exclusion from the scope of consolidation of non-significant companies and changes in non-controlling interests | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (7) | | | | | | | | | | | | | | | | | | | | | | | | (7) | | | | | | (10) | | | | | | (17) | | | Reclassification of the reserve for treasury shares | | | | | | | | | | | | | | | | | | | | (5,620) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5,620 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other changes | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (18) | | | | | | | | | | | | | | | | | | 12 | | | | | | | | | | | | | | | | | | | | | | | | (6) | | | | | | (8) | | | | | | (14) | | | | | | | | | | | | | | | | | | | | | | | (5,620) | | | | | | | | | | | | | | | | | | | | | | | | (18) | | | | | | | | | | | | | | | | | | 5,597 | | | | | | | | | | | | | | | | | | | | | | | | (41) | | | | | | 10 | | | | | | (31) | | | Balance at December 31, 2015 | | | (36) | | | | | 4,005 | | | | | | 959 | | | | | | 581 | | | | | | (474) | | | | | | 8 | | | | | | (101) | | | | | | 180 | | | | | | 9,129 | | | | | | (581) | | | | | | 51,985 | | | | | | (1,440) | | | | | | (8,778) | | | | | | 20 | | | | | | 55,493 | | | | | | 1,916 | | | | | | 57,409 | | |
| | | | | | Eni shareholders’ equity | | | | | | | | | | | | | | | | | Note | | | Share capital | | | Retained earnings | | | Cumulative currency translation differences | | | Other reserves | | | Treasury shares | | | Interim dividend | | | Net profit for the year | | | Total | | | Non- controlling interest | | | Total shareholders’ equity | | Balance at December 31, 2018 | | | (25) | | | | | 4,005 | | | | | | 36,702 | | | | | | 6,605 | | | | | | 1,672 | | | | | | (581) | | | | | | (1,513) | | | | | | 4,126 | | | | | | 51,016 | | | | | | 57 | | | | | | 51,073 | | | Changes in accounting policies (IAS 28) | | | (3) | | | | | | | | | | | (4) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | | | | | | | (4) | | | Balance at January 1, 2019 | | | | | | | | 4,005 | | | | | | 36,698 | | | | | | 6,605 | | | | | | 1,672 | | | | | | (581) | | | | | | (1,513) | | | | | | 4,126 | | | | | | 51,012 | | | | | | 57 | | | | | | 51,069 | | | Net profit for the year | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 148 | | | | | | 148 | | | | | | 7 | | | | | | 155 | | | Other items of comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Items that are not reclassified to profit or loss in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Remeasurements of defined benefit plans net of tax effect | | | (25) | | | | | | | | | | | | | | | | | | | | | | | (37) | | | | | | | | | | | | | | | | | | | | | | | | (37) | | | | | | | | | | | | (37) | | | Share of other comprehensive income (loss) on equity accounted investments related to benefit plans remeasurements | | | (25) | | | | | | | | | | | | | | | | | | | | | | | (7) | | | | | | | | | | | | | | | | | | | | | | | | (7) | | | | | | | | | | | | (7) | | | Change of minor investments measured at fair value with effects to OCI | | | (25) | | | | | | | | | | | | | | | | | | | | | | | (3) | | | | | | | | | | | | | | | | | | | | | | | | (3) | | | | | | | | | | | | (3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (47) | | | | | | | | | | | | | | | | | | | | | | | | (47) | | | | | | | | | | | | (47) | | | Items that may be reclassified to profit or loss in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Currency translation differences | | | (25) | | | | | | | | | | | | | | | | | 604 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 604 | | | | | | | | | | | | 604 | | | Change in the fair value of cash flow hedge derivatives net of tax effect | | | (25) | | | | | | | | | | | | | | | | | | | | | | | (482) | | | | | | | | | | | | | | | | | | | | | | | | (482) | | | | | | | | | | | | (482) | | | Share of “Other comprehensive income (loss)” on equity-accounted investments | | | (25) | | | | | | | | | | | | | | | | | | | | | | | (6) | | | | | | | | | | | | | | | | | | | | | | | | (6) | | | | | | | | | | | | (6) | | | | | | | | | | | | | | | | | | | | | | | 604 | | | | | | (488) | | | | | | | | | | | | | | | | | | | | | | | | 116 | | | | | | | | | | | | 116 | | | Total comprehensive income (loss) of the year | | | | | | | | | | | | | | | | | | | | 604 | | | | | | (535) | | | | | | | | | | | | | | | | | | 148 | | | | | | 217 | | | | | | 7 | | | | | | 224 | | | Transactions with shareholders | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dividend distribution of Eni SpA (€0.41 per share in settlement of 2018 interim dividend of €0.42 per share) | | | (25) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,513 | | | | | | (2,989) | | | | | | (1,476) | | | | | | | | | | | | (1,476) | | | Interim dividend distribution of Eni SpA (€0.43 per share) | | | (25) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1,542) | | | | | | | | | | | | (1,542) | | | | | | | | | | | | (1,542) | | | Dividend distribution of other companies | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | (4) | | | Allocation of 2018 net income | | | | | | | | | | | | | | 1,137 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1,137) | | | | | | | | | | | | | | | | | | | | | Reimbursements to minority shareholders | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | (1) | | | Acquisition of treasury shares | | | (25) | | | | | | | | | | | (400) | | | | | | | | | | | | 400 | | | | | | (400) | | | | | | | | | | | | | | | | | | (400) | | | | | | | | | | | | (400) | | | | | | | | | | | | | | | | | 737 | | | | | | | | | | | | 400 | | | | | | (400) | | | | | | (29) | | | | | | (4,126) | | | | | | (3,418) | | | | | | (5) | | | | | | (3,423) | | | Other changes in shareholders’ equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Long-term share-based incentive plan | | | | | | | | | | | | | | 9 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 9 | | | | | | | | | | | | 9 | | | Other changes | | | | | | | | | | | | | | (8) | | | | | | | | | | | | 27 | | | | | | | | | | | | | | | | | | | | | | | | 19 | | | | | | 2 | | | | | | 21 | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | 27 | | | | | | | | | | | | | | | | | | | | | | | | 28 | | | | | | 2 | | | | | | 30 | | | Balance at December 31, 2019 | | | (25) | | | | | 4,005 | | | | | | 37,436 | | | | | | 7,209 | | | | | | 1,564 | | | | | | (981) | | | | | | (1,542) | | | | | | 148 | | | | | | 47,839 | | | | | | 61 | | | | | | 47,900 | | |
See the accompanying notes.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued) (euro€ million) | | | | | | Eni shareholders’ equity | | | | | | | | | | | | | | | | | Note | | | Share capital | | | Legal reserve of Eni SpA | | | Reserve for treasury shares | | | Reserve related to the fair value of cash flow hedging derivatives net of the tax effect | | | Reserve related to the fair value of available- for-sale financial instruments net of the tax effect | | | Reserve for defined benefit plans net of the tax effect | | | Other reserves | | | Cumulative currency translation differences | | | Treasury shares | | | Retained earnings | | | Interim dividend | | | Net profit (loss) for the year | | | Other comprehensive income (loss) related to discontinued operations | | | Total | | | Non- controlling interest | | | Total shareholders’ equity | | Balance at December 31, 2015 | | | (36) | | | | | 4,005 | | | | | | 959 | | | | | | 581 | | | | | | (474) | | | | | | 8 | | | | | | (101) | | | | | | 180 | | | | | | 9,129 | | | | | | (581) | | | | | | 51,985 | | | | | | (1,440) | | | | | | (8,778) | | | | | | 20 | | | | | | 55,493 | | | | | | 1,916 | | | | | | 57,409 | | | Net profit (loss) for the year | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1,464) | | | | | | | | | | | | (1,464) | | | | | | 7 | | | | | | (1,457) | | | Other items of comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Items that are not reclassified to profit in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Remeasurements of defined benefit plans net of tax effect | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (19) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (19) | | | | | | | | | | | | (19) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (19) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (19) | | | | | | | | | | | | (19) | | | Items that may be reclassified to profit in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Currency translation differences | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 8 | | | | | | | | | | | | 1,190 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,198 | | | | | | | | | | | | 1,198 | | | Change and reversal of the fair value of other available-for-sale financial instruments net of tax effect | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | | | | | | | (4) | | | Change and reversal the fair value of cash flow hedge derivatives net of tax effect | | | (36) | | | | | | | | | | | | | | | | | | | | | | | 663 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 663 | | | | | | | | | | | | 663 | | | Share of “Other comprehensive income” on equity-accounted entities | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 32 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 32 | | | | | | | | | | | | 32 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 663 | | | | | | (4) | | | | | | 8 | | | | | | 32 | | | | | | 1,190 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,889 | | | | | | | | | | | | 1,889 | | | Total comprehensive income of the year | | | | | | | | | | | | | | | | | | | | | | | | | | 663 | | | | | | (4) | | | | | | (11) | | | | | | 32 | | | | | | 1,190 | | | | | | | | | | | | | | | | | | | | | | | | (1,464) | | | | | | | | | | | | 406 | | | | | | 7 | | | | | | 413 | | | Transactions with shareholders | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dividend distribution of Eni SpA (€0.40 per share in settlement of 2015 interim dividend of €0.40 per share) | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1,028) | | | | | | 1,440 | | | | | | (1,852) | | | | | | | | | | | | (1,440) | | | | | | | | | | | | (1,440) | | | Interim dividend distribution of Eni SpA (€0.40 per share) | | | (36) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1,441) | | | | | | | | | | | | | | | | | | (1,441) | | | | | | | | | | | | (1,441) | | | Dividend distribution of other companies | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | (4) | | | Allocation of 2015 net loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (10,630) | | | | | | | | | | | | 10,630 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (11,658) | | | | | | (1) | | | | | | 8,778 | | | | | | | | | | | | (2,881) | | | | | | (4) | | | | | | (2,885) | | | Other changes in shareholders’ equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exclusion from the scope of consolidation of Saipem group following the sale of the control | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1,872) | | | | | | (1,872) | | | Reclassification to profit and loss account of amounts previously recognized in other comprehensive income related to Saipem | | | (35) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (8) | | | | | | | | | | | | | | | | | | (20) | | | | | | (28) | | | | | | | | | | | | (28) | | | Other changes | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | 48 | | | | | | | | | | | | | | | | | | | | | | | | 47 | | | | | | 2 | | | | | | 49 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | 40 | | | | | | | | | | | | | | | | | | (20) | | | | | | 19 | | | | | | (1,870) | | | | | | (1,851) | | | Balance at December 31, 2016 | | | (36) | | | | | 4,005 | | | | | | 959 | | | | | | 581 | | | | | | 189 | | | | | | 4 | | | | | | (112) | | | | | | 211 | | | | | | 10,319 | | | | | | (581) | | | | | | 40,367 | | | | | | (1,441) | | | | | | (1,464) | | | | | | | | | | | | 53,037 | | | | | | 49 | | | | | | 53,086 | | |
| | | | | | Eni shareholders’ equity | | | | | | | | | | | | | | | | | Note | | | Share capital | | | Retained earnings | | | Cumulative currency translation differences | | | Other reserves | | | Treasury shares | | | Interim dividend | | | Net profit for the year | | | Total | | | Non- controlling interest | | | Total shareholders’ equity | | Balance at December 31, 2017 | | | | | | | | 4,005 | | | | | | 35,966 | | | | | | 4,818 | | | | | | 1,889 | | | | | | (581) | | | | | | (1,441) | | | | | | 3,374 | | | | | | 48,030 | | | | | | 49 | | | | | | 48,079 | | | Changes in accounting policies (IFRS 9 and 15) | | | | | | | | | | | | | | 245 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 245 | | | | | | | | | | | | 245 | | | Balance at January 1, 2018 | | | | | | | | 4,005 | | | | | | 36,211 | | | | | | 4,818 | | | | | | 1,889 | | | | | | (581) | | | | | | (1,441) | | | | | | 3,374 | | | | | | 48,275 | | | | | | 49 | | | | | | 48,324 | | | Net profit for the year | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4,126 | | | | | | 4,126 | | | | | | 11 | | | | | | 4,137 | | | Other items of comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Items that are not reclassified to profit or loss in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Remeasurements of defined benefit plans net of tax effect | | | (25) | | | | | | | | | | | | | | | | | | | | | | | (17) | | | | | | | | | | | | | | | | | | | | | | | | (17) | | | | | | | | | | | | (17) | | | Change of minor investments measured at fair value with effects to OCI | | | (25) | | | | | | | | | | | | | | | | | | | | | | | 15 | | | | | | | | | | | | | | | | | | | | | | | | 15 | | | | | | | | | | | | 15 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (2) | | | | | | | | | | | | | | | | | | | | | | | | (2) | | | | | | | | | | | | (2) | | | Items that may be reclassified to profit or loss in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Currency translation differences | | | (25) | | | | | | | | | | | | | | | | | 1,787 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,787 | | | | | | | | | | | | 1,787 | | | Change in the fair value of cash flow hedge derivatives net of tax effect | | | (25) | | | | | | | | | | | | | | | | | | | | | | | (185) | | | | | | | | | | | | | | | | | | | | | | | | (185) | | | | | | | | | | | | (185) | | | Share of “Other comprehensive income (loss)” on equity-accounted investments | | | (25) | | | | | | | | | | | | | | | | | | | | | | | (24) | | | | | | | | | | | | | | | | | | | | | | | | (24) | | | | | | | | | | | | (24) | | | | | | | | | | | | | | | | | | | | | | | 1,787 | | | | | | (209) | | | | | | | | | | | | | | | | | | | | | | | | 1,578 | | | | | | | | | | | | 1,578 | | | Total comprehensive income (loss) of the year | | | | | | | | | | | | | | | | | | | | 1,787 | | | | | | (211) | | | | | | | | | | | | | | | | | | 4,126 | | | | | | 5,702 | | | | | | 11 | | | | | | 5,713 | | | Transactions with shareholders | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dividend distribution of Eni SpA (€0.40 per share in settlement of 2017 interim dividend of €0.40 per share) | | | (25) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,441 | | | | | | (2,881) | | | | | | (1,440) | | | | | | | | | | | | (1,440) | | | Interim dividend distribution of Eni SpA (€0.42 per share) | | | (25) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1,513) | | | | | | | | | | | | (1,513) | | | | | | | | | | | | (1,513) | | | Dividend distribution of other companies | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (3) | | | | | | (3) | | | Allocation of 2017 net income | | | | | | | | | | | | | | 493 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (493) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 493 | | | | | | | | | | | | | | | | | | | | | | | | (72) | | | | | | (3,374) | | | | | | (2,953) | | | | | | (3) | | | | | | (2,956) | | | Other changes in shareholders’ equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Long-term share-based incentive plan | | | | | | | | | | | | | | 5 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5 | | | | | | | | | | | | 5 | | | Other changes | | | | | | | | | | | | | | (7) | | | | | | | | | | | | (6) | | | | | | | | | | | | | | | | | | | | | | | | (13) | | | | | | | | | | | | (13) | | | | | | | | | | | | | | | | | (2) | | | | | | | | | | | | (6) | | | | | | | | | | | | | | | | | | | | | | | | (8) | | | | | | | | | | | | (8) | | | Balance at December 31, 2018 | | | (25) | | | | | 4,005 | | | | | | 36,702 | | | | | | 6,605 | | | | | | 1,672 | | | | | | (581) | | | | | | (1,513) | | | | | | 4,126 | | | | | | 51,016 | | | | | | 57 | | | | | | 51,073 | | |
See the accompanying notes.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (continued) (€ million)
| | | Eni shareholders’ equity | | | | | | | | | | | | | | Share capital | | | Retained earnings | | | Cumulative currency translation differences | | | Other reserves | | | Treasury shares | | | Interim dividend | | | Net profit (loss) for the year | | | Total | | | Non- controlling interest | | | Total shareholders’ equity | | | Balance at December 31, 2016 | | | 4,005 | | | | | 40,367 | | | | | | 10,319 | | | | | | 1,832 | | | | | | (581) | | | | | | (1,441) | | | | | | (1,464) | | | | | | 53,037 | | | | | | 49 | | | | | | 53,086 | | | | Net profit for the year | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3,374 | | | | | | 3,374 | | | | | | 3 | | | | | | 3,377 | | | | Other items of comprehensive income (loss) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Items that are not reclassified to profit or loss in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Remeasurements of defined benefit plans net of tax effect | | | | | | | | | | | | | | | | | | | | (4) | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | | | | | | | (4) | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | | | | | | | (4) | | | | Items that may be reclassified to profit or loss in later periods | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Currency translation differences | | | | | | | | | | | | | | (5,575) | | | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | (5,573) | | | | | | | | | | | | (5,573) | | | | Change in the fair value of other available-for-sale financial instruments net of tax effect | | | | | | �� | | | | | | | | | | | | | | (4) | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | | | | | | | (4) | | | | Change in the fair value of cash flow hedge derivatives net of tax effect | | | | | | | | | | | | | | | | | | | | (6) | | | | | | | | | | | | | | | | | | | | | | | | (6) | | | | | | | | | | | | (6) | | | | Share of “Other comprehensive income (loss)” on equity-accounted investments | | | | | | | | | | | | | | | | | | | | 69 | | | | | | | | | | | | | | | | | | | | | | | | 69 | | | | | | | | | | | | 69 | | | | | | | | | | | | | | | | | | (5,575) | | | | | | 61 | | | | | | | | | | | | | | | | | | | | | | | | (5,514) | | | | | | | | | | | | (5,514) | | | | Total comprehensive income (loss) of the year | | | | | | | | | | | | | | (5,575) | | | | | | 57 | | | | | | | | | | | | | | | | | | 3,374 | | | | | | (2,144) | | | | | | 3 | | | | | | (2,141) | | | | Transactions with shareholders | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dividend distribution of Eni SpA (€0.40 per share in settlement of 2016 interim dividend of €0.40 per share) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,441 | | | | | | (2,881) | | | | | | (1,440) | | | | | | | | | | | | (1,440) | | | | Interim dividend distribution of Eni SpA (€0.40 per share) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1,441) | | | | | | | | | | | | (1,441) | | | | | | | | | | | | (1,441) | | | | Dividend distribution of other companies | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (3) | | | | | | (3) | | | | Allocation of 2016 net loss | | | | | | | | (4,345) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4,345 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (4,345) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,464 | | | | | | (2,881) | | | | | | (3) | | | | | | (2,884) | | | | Other changes in shareholders’ equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other changes | | | | | | | | (56) | | | | | | 74 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 18 | | | | | | | | | | | | 18 | | | | | | | | | | | | (56) | | | | | | 74 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 18 | | | | | | | | | | | | 18 | | | | Balance at December 31, 2017 | | | 4,005 | | | | | 35,966 | | | | | | 4,818 | | | | | | 1,889 | | | | | | (581) | | | | | | (1,441) | | | | | | 3,374 | | | | | | 48,030 | | | | | | 49 | | | | | | 48,079 | | | |
CONSOLIDATED STATEMENT OF CASH FLOWS (euro€ million) | | | Note | | 2014(a) | | 2015(a) | | 2016 | | | Note | | 2019 | | 2018 | | 2017 | | Net profit (loss) of the year – Continuing operations | | | | | | | | | 1,808 | | | | | | | | | | (7,399) | | | | | | | | | | (1,044) | | | | Net profit | | | | | | | 155 | | | | | 4,137 | | | | | 3,377 | | | Adjustments to reconcile net profit to net cash provided by operating activities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | | | (40) | | | | | 7,676 | | | | | | | | | | 8,940 | | | | | | | | | | 7,559 | | | | (11) (12) (13) | | | | 8,106 | | | | | 6,988 | | | | | 7,483 | | | Net Impairments/reversal | | | | (40) | | | | | 1,270 | | | | | | | | | | 6,534 | | | | | | | | | | (475) | | | | Net Impairments (reversals) of tangible and intangible assets and right-of-use assets | | | (14) | | | | 2,188 | | | | | 866 | | | | | (225) | | | Write-off of tangible and intangible assets | | | | (40) | | | | | 1,198 | | | | | | | | | | 688 | | | | | | | | | | 350 | | | | (11) (13) | | | | 300 | | | | | 100 | | | | | 263 | | | Share of (profit) loss of equity-accounted investments | | | | (42) | | | | | (110) | | | | | | | | | | 471 | | | | | | | | | | 326 | | | | (15) (31) | | | | 88 | | | | | 68 | | | | | 267 | | | Gain on disposal of assets, net | | | | | | | | | (224) | | | | | | | | | | (577) | | | | | | | | | | (48) | | | | Net gain on disposal of assets | | | | | | | (170) | | | | | (474) | | | | | (3,446) | | | Dividend income | | | | (42) | | | | | (385) | | | | | | | | | | (402) | | | | | | | | | | (143) | | | | (31) | | | | (247) | | | | | (231) | | | | | (205) | | | Interest income | | | | | | | | | (162) | | | | | | | | | | (164) | | | | | | | | | | (209) | | | | | | | | (147) | | | | | (185) | | | | | (283) | | | Interest expense | | | | | | | | | 681 | | | | | | | | | | 659 | | | | | | | | | | 645 | | | | | | | | 1,027 | | | | | 614 | | | | | 671 | | | Income taxes | | | | (43) | | | | | 6,466 | | | | | | | | | | 3,122 | | | | | | | | | | 1,936 | | | | (32) | | | | 5,591 | | | | | 5,970 | | | | | 3,467 | | | Other changes | | | | | | | | | 852 | | | | | | | | | | 586 | | | | | | | | | | (9) | | | | | | | | (179) | | | | | (474) | | | | | 894 | | | Changes in working capital: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - inventories | | 1,620 | | 1,638 | | (273) | | | | | | | (200) | | | | | 15 | | | | | (346) | | | - trade receivables | | 2,051 | | 4,944 | | 1,286 | | | | | | | 1,023 | | | | | 334 | | | | | 657 | | | - trade payables | | (1,669) | | (2,342) | | 1,495 | | | | | | | (940) | | | | | 642 | | | | | 284 | | | - provisions for contingencies | | (234) | | 43 | | (1,043) | | | - provisions | | | | | | | 272 | | | | | (238) | | | | | 96 | | | - other assets and liabilities | | 431 | | 498 | | 647 | | | | | | | 211 | | | | | 879 | | | | | 749 | | | Cash flow from changes in working capital | | | | | | | | | 2,199 | | | | | | | | | | 4,781 | | | | | | | | | | 2,112 | | | | | | | | 366 | | | | | 1,632 | | | | | 1,440 | | | Net change in the provisions for employee benefits | | | | | | | | | 12 | | | | | | | | | | (3) | | | | | | | | | | 22 | | | | | | | | (23) | | | | | 109 | | | | | 38 | | | Dividends received | | | | | | | | | 603 | | | | | | | | | | 545 | | | | | | | | | | 212 | | | | | | | | 1,346 | | | | | 275 | | | | | 291 | | | Interest received | | | | | | | | | 107 | | | | | | | | | | 81 | | | | | | | | | | 160 | | | | | | | | 88 | | | | | 87 | | | | | 104 | | | Interest paid | | | | | | | | | (851) | | | | | | | | | | (692) | | | | | | | | | | (780) | | | | | | | | (1,029) | | | | | (609) | | | | | (582) | | | Income taxes paid, net of tax receivables received | | | | | | | | | (6,671) | | | | | | | | | | (4,295) | | | | | | | | | | (2,941) | | | | | | | | (5,068) | | | | | (5,226) | | | | | (3,437) | | | Net cash provided by operating activities – Continuing operations | | | | | | | | | 14,469 | | | | | | | | | | 12,875 | | | | | | | | | | 7,673 | | | | Net cash provided by operating activities – Discontinued operations | | | | (35) | | | | | 273 | | | | | | | | | | (1,226) | | | | | | | | | | | | | | Net cash provided by operating activities | | | | | | | | | 14,742 | | | | | | | | | | 11,649 | | | | | | | | | | 7,673 | | | | | | | | 12,392 | | | | | 13,647 | | | | | 10,117 | | | - of which with related parties | | | | (47) | | | | | (3,203) | | | | | | | | | | (3,966) | | | | | | | | | | (3,749) | | | | (36) | | | | (6,356) | | | | | (2,707) | | | | | (2,843) | | | Investing activities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - tangible assets | | | | (16) | | | | | (11,646) | | | | | | | | | | (11,177) | | | | | | | | | | (9,067) | | | | (11) | | | | (8,049) | | | | | (8,778) | | | | | (8,490) | | | - prepaid right-of-use assets | | | (12) | | | | (16) | | | | | | | | | | | | | - intangible assets | | | | (18) | | | | | (226) | | | | | | | | | | (125) | | | | | | | | | | (113) | | | | (13) | | | | (311) | | | | | (341) | | | | | (191) | | | - consolidated subsidiaries and businesses net of cash and cash equivalent acquired | | | | (37) | | | | | (36) | | | | | | | | | | | | | | | (26) | | | | (5) | | | | | (119) | | | | | | | | - investments | | | | (20) | | | | | (372) | | | | | | | | | | (228) | | | | | | | | | | (1,164) | | | | (15) | | | | (3,003) | | | | | (125) | | | | | (510) | | | - securities | | | | | | | | | (77) | | | | | | | | | | (201) | | | | | | | | | | (1,336) | | | | - financing receivables | | | | | | | | | (1,289) | | | | | | | | | | (1,103) | | | | | | | | | | (1,208) | | | | - change in payables in relation to investing activities and capitalized depreciation | | | | | | | | | 669 | | | | | | | | | | (1,058) | | | | | | | | | | (8) | | | | - securities held for operating purposes | | | | | | | (8) | | | | | (8) | | | | | | | | - financing receivables held for operating purposes | | | | | | | (229) | | | | | (358) | | | | | (585) | | | - change in payables in relation to investing activities | | | | | | | (307) | | | | | 408 | | | | | 152 | | | Cash flow from investing activities | | | | | | | | | (12,977) | | | | | | | | | | (13,892) | | | | | | | | | | (12,896) | | | | | | | | (11,928) | | | | | (9,321) | | | | | (9,624) | | | Disposals: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - tangible assets | | | | | | | | | 104 | | | | | | | | | | 427 | | | | | | | | | | 19 | | | | | | | | 264 | | | | | 1,089 | | | | | 2,745 | | | - intangible assets | | | | | | | | | 1 | | | | | | | | | | 32 | | | | | | | | | | | | | | 17 | | | | | 5 | | | | | 2 | | | - consolidated subsidiaries and businesses net of cash and cash equivalent disposed of | | | | (37) | | | | | | | | | | | | | | | 73 | | | | | | | | | | (362) | | | | (26) | | | | 187 | | | | | (47) | | | | | 2,662 | | | - tax on disposals | | | | | | | (3) | | | | | | | | | | (436) | | | - investments | | | | | | | | | 3,579 | | | | | | | | | | 1,726 | | | | | | | | | | 508 | | | | | | | | 39 | | | | | 195 | | | | | 482 | | | - securities | | | | | | | | | 57 | | | | | | | | | | 18 | | | | | | | | | | 20 | | | | - financing receivables | | | | | | | | | 506 | | | | | | | | | | 533 | | | | | | | | | | 8,063 | | | | - securities held for operating purposes | | | | | | | 17 | | | | | 15 | | | | | 1 | | | - financing receivables held for operating purposes | | | | | | | 178 | | | | | 279 | | | | | 493 | | | - change in receivables in relation to disposals | | | | | | | | | 155 | | | | | | | | | | 160 | | | | | | | | | | 205 | | | | | | | | 95 | | | | | 606 | | | | | (434) | | | Cash flow from disposals | | | | | | | | | 4,402 | | | | | | | | | | 2,969 | | | | | | | | | | 8,453 | | | | | | | | 794 | | | | | 2,142 | | | | | 5,515 | | | Net change in securities and financing receivables held for non-operating purposes (a) | | | | | | | (279) | | | | | (357) | | | | | 341 | | | Net cash used in investing activities | | | | | | | | | (8,575) | | | | | | | | | | (10,923) | | | | | | | | | | (4,443) | | | | | | | | (11,413) | | | | | (7,536) | | | | | (3,768) | | | - of which with related parties | | | | (47) | | | | | (1,458) | | | | | | | | | | (1,583) | | | | | | | | | | 3,752 | | | | (36) | | | | (2,912) | | | | | (3,314) | | | | | (3,115) | | | | |
See the accompanying notes. (a)
Information onFrom 2019, Eni’s cash flow statement is reporting in a dedicated line-item the restatementnet cash outflow (investments minus divestments) in held-for-trading financial assets and current non-operating receivables financing, with the latter being investment of temporary cash surpluses. Those two assets are netted against financial liabilities to determine the Group net borrowings in accordance to applicable listing standards. In previous reporting periods, cash inflows and outflows relating those assets were reported among investing activities or divesting activities relating to securities and financing receivables, respectively. The cash flow statements of comparative data in application of IAS 8 is reported in note 5 — Changes in accounting principles.periods have been reclassified accordingly.
CONSOLIDATED STATEMENT OF CASH FLOWS (continued) (euro€ million) | | | Note | | 2014 (a) | | 2015 (a) | | 2016 | | | | | | Note | | 2019 | | 2018 | | 2017 | | Increase in long-term financial debt | | | | (29) | | | | | 1,916 | | | | | 3,376 | | | | | 4,202 | | | | (18) | | | | 1,811 | | | | | 3,790 | | | | | 1,842 | | | Repayments of long-term financial debt | | | | (29) | | | | | (2,751) | | | | | (4,466) | | | | | (2,323) | | | | (18) | | | | (3,512) | | | | | (2,757) | | | | | (2,973) | | | Payments of lease liabilities | | | (12) | | | | (877) | | | | | | | | | | | | | Increase (decrease) in short-term financial debt | | | | (24) | | | | | 207 | | | | | 3,216 | | | | | (2,645) | | | | (18) | | | | 161 | | | | | (713) | | | | | (581) | | | | | | | | | | | | (628) | | | | | 2,126 | | | | | (766) | | | | | | | | (2,417) | | | | | 320 | | | | | (1,712) | | | Net capital contributions by non-controlling interest | | | | | | | | | 1 | | | | | 1 | | | | | Dividends paid to Eni’s shareholders | | | | | | | | | (4,006) | | | | | (3,457) | | | | | (2,881) | | | | | | | | (3,018) | | | | | (2,954) | | | | | (2,880) | | | Dividends paid to non-controlling interest | | | | | | | | | (49) | | | | | (21) | | | | | (4) | | | | | | | | (4) | | | | | (3) | | | | | (3) | | | Reimbursements to non-controlling interest | | | | | | | (1) | | | | | | | | | | | | | Acquisition of additional interests in consolidated subsidiaries | | | | | | | (1) | | | | | | | | | | | | | Acquisition of treasury shares | | | | | | | | | (380) | | | | | | | | | | | | | | | | | | (400) | | | | | | | | | | | | | Net cash used in financing activities | | | | | | | | | (5,062) | | | | | (1,351) | | | | | (3,651) | | | | | | | | (5,841) | | | | | (2,637) | | | | | (4,595) | | | - of which with related parties | | | | (47) | | | | | (99) | | | | | 13 | | | | | (192) | | | | (36) | | | | (817) | | | | | 16 | | | | | (16) | | | Effect of change in consolidation (inclusion/ exclusion of significant/insignificant subsidiaries) | | | | | | | | | 2 | | | | | (13) | | | | | (5) | | | | Effect of cash and cash equivalents pertaining to discontinued operations | | | | (37) | | | | | | | | | | (889) | | | | | 889 | | | | Effect of exchange rate changes on cash and cash equivalents and other changes | | | | | | | | | 76 | | | | | 122 | | | | | 2 | | | | Net cash flow of the year | | | | | | | | | 1,183 | | | | | (1,405) | | | | | 465 | | | | Cash and cash equivalents - beginning of the year (excluding discontinued operations) | | | | (8) | | | | | 5,431 | | | | | 6,614 | | | | | 5,209 | | | | Cash and cash equivalents - end of the year (excluding discontinued operations) | | | | (8) | | | | | 6,614 | | | | | 5,209 | | | | | 5,674 | | | | | | Effect of change in consolidation (inclusion/exclusion of significant/insignificant subsidiaries) | | | | | | | (7) | | | | | | | | | | 7 | | | Effect of exchange rate changes and other changes on cash and cash equivalents | | | | | | | 8 | | | | | 18 | | | | | (72) | | | Net increase (decrease) in cash and cash equivalents | | | | | | | (4,861) | | | | | 3,492 | | | | | 1,689 | | | Cash and cash equivalents – beginning of the year | | | (5) | | | | 10,855 | | | | | 7,363 | | | | | 5,674 | | | Cash and cash equivalents – end of the year(b) | | | (5) | | | | 5,994 | | | | | 10,855 | | | | | 7,363 | | |
See the accompanying notes. (a)(b)
Information onIn 2018, cash and cash equivalents at the restatementend of comparative data in applicationthe year included €19 million of IAS 8 iscash and cash equivalents of consolidated subsidiaries held for sale that were reported in note 5 — Changes in accounting principles.the item “Assets held for sale”.
Notes on Consolidated Financial Statements 1 Significant accounting policies, estimates and judgements Basis of preparation The Consolidated Financial Statements of the Eni Group have been prepared on a going concern basis in accordance with International Financial Reporting Standards (IFRS)1 as issued by the International Accounting Standards Board (IASB). Oil and natural gas exploration and production activity is accounted for in accordance with internationally accepted accounting standards taking into account the requirements in IFRSs that apply. In particular, starting from January 1, 2016, Eni has adopted, on a voluntary basis, the so-called Successful Efforts Method (hereinafter also SEM) to recognize and measure costs related to exploration activities, in order to improve the comparability of Eni’s results with those of the competitors, as well as to ensure financial reporting that is proper, reliable and consistent with the decision-making processes related to the evaluation of the exploration and production activities’ results. The recognition and measurement criteria for the oil&gas exploration and production activities are indicated in the accounting policy for “Oil and natural gas exploration, appraisal, development and production expenditure”; the effects arising from the adoption of SEM are indicated in note 5 “Changes in accounting policies”. The Consolidated Financial Statements have been prepared under the historical cost convention, taking into account, where appropriate, value adjustments, except for certain items that under IFRSs must be measured at fair value as described in the note 3 “Significant accounting policies”.policies that follow. The 20162019 Consolidated Financial Statements included in the Annual Report on Form 20-F, approved by the Eni’s Board of Directors on March 17, 2017,18, 2020, were audited by the external auditor Ernst & YoungPricewaterhouseCoopers SpA. The external auditor of Eni SpA, as the main external auditor, is wholly in charge of the auditing activities of the Consolidated Financial Statements; when there are other external auditors, Ernst & YoungPricewaterhouseCoopers SpA takes the responsibility of their work. AmountsThe Consolidated Financial Statements are presented in euros and all values are rounded to the nearest million euros (€ million), except where otherwise indicated.
Significant accounting estimates and judgements The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses recognised in the financial statements, andas well as amounts included in the notes thereto, including disclosure of contingent assets and contingent liabilities. Estimates made are expressedbased on complex judgements and past experience of other assumptions deemed reasonable in millionsconsideration of euros (euro million).the information available at the time. The accounting policies and areas that require the most significant judgements and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of financial and non-financial assets, leases, decommissioning and restoration liabilities, environmental liabilities, business combinations, employee benefits, revenue from contracts with customers, fair value measurements and income taxes. Although the Company uses its best estimates and judgements, actual results could differ from the estimates and assumptions used. The accounting estimates and judgements relevant for the preparation of the Consolidated Financial Statement are described below. 2 Principles of consolidation
Subsidiaries The Consolidated Financial Statements comprise the financial statements of the parent Company Eni SpA and those of its Italian and foreign subsidiaries, being those entities over which the Company has control, either directly or indirectly, through exposure or rights to their variable returns and the ability to affect those returns through its power over the investees. To have power over an investee, the investor must have existing rights that give it the current ability to direct the relevant activities of the investee, i.e. the activities that significantly affect the investee’s returns. 1
IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations developed by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC).
Subsidiaries are consolidated, on the basis of consistent accounting policies, from the date on which control is obtained until the date that control ceases. Assets, liabilities, income and expenses of consolidated subsidiaries are fully recognised with those of the parent in the Consolidated Financial Statements; the parent’s investment in each subsidiary is eliminated against the corresponding parent’s portion of equity of each subsidiary. Non-controlling interests are presented separately on the balance sheet within equity; the profit or loss attributable to non-controlling interests is presented in a specific line item of the profit and loss account. For entities acting as sole-operator in the management of oil&gas and gas contracts on behalf of companies participating in a joint project, the activities are financed proportionally based on a budget approved by the participating companies upon presentation of periodical reports of proceeds and expenses. Costs and revenuesrevenue and other operating data (production, reserves, etc.) of the project, as well as the related obligations arising from the project, are recognizedrecognised directly in the financial statements of the companies involved based on their own share. Some subsidiaries are not consolidated because they are immaterial, either individually or in the aggregate; this exclusion has not produced significantmaterial2 effects on the Consolidated Financial Statements. (1)
IFRSs include also International Accounting Standards (IAS), currently effective, as well as the interpretations issued by the IFRS Interpretations Committee, previously named International Financial Reporting Interpretations Committee (IFRIC) and initially Standing Interpretations Committee (SIC)Statements3.
(2)
According to the requirements of the Conceptual Framework for IFRS, “information is material if omitting it or misstating it could influence decisions that users make on the basis of financial information about a specific reporting entity”.
Subsidiaries are consolidated from the date on which control is obtained until the date that such control ceases. 100% of assets, liabilities, income and expenses of consolidated subsidiaries are combined with those of the parent in the Consolidated Financial Statements; the net book value of these subsidiaries is eliminated against the corresponding portion of the shareholders’ equity. Equity and net profit attributable to non-controlling interests are included in specific line items of equity and profit and loss account.
When the proportion of the equity held by non-controlling interests changes, any difference between the consideration paid/received and the amount by which the non-controlling interests are adjusted is attributed to the GroupEni shareholders’ equity. Conversely, the sale of equity interests with loss of control determines the recognition in the profit and loss account of: (i) any gain/gain or loss calculated as the difference between the consideration received and the corresponding transferred portion of equity;net assets; (ii) any gain or loss recognizedrecognised as a result of the re-measurementremeasurement of any investment retained in the former subsidiary toat its fair value; and (iii) any amount related to the former subsidiary previously recognizedrecognised in other comprehensive income which canmay be reclassified subsequently to the profit and loss account34. Any investment retained in the former subsidiary is recognizedrecognised at its fair value at the date when control is lost and shall be accounted for in accordance with the applicable measurement criteria. Interests in joint arrangements A joint arrangement is an arrangement of which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. Investments in joint ventures are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”. A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have enforceable rights to the assets, and enforceable obligations for the liabilities, relating to the arrangement. Judgment is required in assessing whether a joint arrangement creates enforceable rights and obligations; this assessment is made considering the design and purpose of the joint arrangement, the terms of the contractual arrangements, as well as any other facts and circumstances that are relevant for this assessment. In the Consolidated Financial Statements, the Eni’sEni recognises its share of the assets/liabilities and revenues/revenue/expenses of joint operations is recognized uponon the basis of its rights and obligations relating to the arrangements. After the initial recognition, the assets/liabilities and revenues/revenue/expenses of the joint operations are measured in accordance with the applicable measurement criteria applicable to each case.criteria. Immaterial joint operations structured through a separate vehicle are accounted for using the equity method or, if this does not result in a misrepresentation of the Company’s financial position and performance, at cost net of any impairment losses. InterestsInvestments in associates
An associate is an entity over which Eni has significant influence, that is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control of those policies. Investments in associates are accounted for using the equity method as described in the accounting policy for “The equity method of accounting”. 2
According to the requirements of the Conceptual Framework for Financial Reporting, “information is material if omitting it or misstating it could influence decisions that users make on the basis of financial information about a specific reporting entity”. 3
Unconsolidated subsidiaries are accounted for as described in the accounting policy for “The equity method of accounting”. 4
Conversely, any amount related to the former subsidiary previously recognised in other comprehensive income, which may not be reclassifiedsubsequently to the profit and loss account, are reclassified in another item of equity.
Consolidated companies’ financial statements are audited by external auditors who audit also the information required for the preparation of the Consolidated Financial Statements. (3)
Conversely, any amount related to the former subsidiary previously recognized in other comprehensive income, which cannot be reclassified subsequently to the profit and loss account, are reclassified within retained earnings.
The equity method of accounting Investments in immaterial subsidiaries, joint ventures, associates and associatesimmaterial unconsolidated subsidiaries, are accounted for using the equity methodmethod.45 6. Under the equity method, investments are initially recognizedrecognised at cost, allocating, similarly to business combinations procedures, the purchase price of the investment to the investee’s identifiable assets/liabilities; if this allocation is provisionally recognizedrecognised at initial recognition, it can be retrospectively adjusted within one year from the date of initial recognition, to reflect new information obtained about facts and circumstances that existed at the date of initial recognition. Subsequently, the carrying amount is adjusted to reflect: (i) the investor’s share of the profit or loss of the investee after the date of acquisition, adjusted to account for depreciation, amortization and any impairment losses of the equity-accounted entity’s assets based on their fair values at the date of acquisition; and (ii) the investor’s share of the investee’s other comprehensive income. Changes in the net assets of an equity-accounted investee, not arising from the investee’s profit or loss or other comprehensive income, are recognized in the investor’s profit and loss account, as they basically represent a gain or loss from a disposal of an interest in the investee’s equity. Distributions received from an equity-accounted investee reduce the carrying amount of the investment. In applying the equity method, consolidation adjustments are considered (see also the accounting policy for “Subsidiaries”). WhenLosses arising from the application of the equity method in excess of the carrying amount of the investment, recognised in the profit and loss account within “Income (Expense) from investments”, reduce the carrying amount, net of the related expected credit losses (see below), of any financing receivables towards the investee for which settlement is neither planned nor likely to occur in the foreseeable future (the so-called long-term interests), which are, in substance, an extension of the investment in the investee. The investor’s share of any losses of an equity-accounted investee that exceeds the carrying amount of the investment and any long-term interests (the so-called net investment), is recognised in a specific provision only to the extent that the investor has incurred legal or constructive obligations or made payments on behalf of the investee. Whenever there is objective evidence of impairment (see also(e.g. relevant breaches of contracts, significant financial difficulty, probable default of the accounting policy for “Current financial assets”counterparty, etc.), the recoverabilitynet investment is tested for impairment by comparing theits carrying amount andwith the related recoverable amount, determined by adopting the criteria indicated in the accounting policy for “Property, plant and equipment”. Immaterial subsidiaries, joint ventures and associates are accounted for at cost, net“Impairment of any impairment losses, if this does not result in a misrepresentation of the Group financial position and performance.non-financial assets”. When an impairment loss no longer exists or has decreased, aany reversal of the impairment loss is recognizedrecognised in the profit and loss account within “Other gain (loss)“Income (Expense) from investments”. The impairment reversal cannotof the net investment shall not exceed the previously recognizedrecognised impairment losses. The sale of equity interests with loss of joint control or significant influence over the investee determines the recognition in the profit and loss account of: (i) any gain/gain or loss calculated as the difference between the consideration received and the corresponding transferred share; (ii) any gain or loss recognizedrecognised as a result of the re-measurementremeasurement of any investment retained in the former joint venture/associate toat its fair value57; and (iii) any amount related to the former joint venture/associate previously recognizedrecognised in other comprehensive income which canmay be reclassified subsequently to the profit and loss account68. Any investment retained in the former joint venture/associate is recognizedrecognised at its fair value at the date when joint control or significant influence is lost and shall be accounted for in accordance with the applicable measurement criteria. The investor’s share of losses of an equity-accounted investee, that exceeds the carrying amount of the investment, is recognized in a specific provision only to the extent the investor is required to fulfill legal or constructive obligations of the investee or to fund its losses.
Business combinations Business combinations are recognizedaccounted for by applying the acquisition method. The consideration transferred in a business combination is measured at the acquisition date and is the sum of the acquisition-date fair valuesvalue of the assets transferred, the liabilities incurred as well as anyand the equity instrumentsinterests issued by the acquirer. Acquisition-related costs are accounted for as expenses when they are incurred. At the acquisition date, the acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values7, unless another measurement basis is required by IFRSs. The excess of the consideration transferred over the Group’s share of the net of the acquisition-date amounts of the identifiable assets acquired and liabilities assumed is recognized as goodwill; a gain from a bargain purchase is recognized in the profit and loss account.
(4)5
In the case of step acquisition of significant influence (or joint(joint control), the investment is recognized,recognised, at the acquisition date of significant influence (joint control), at the amount deriving from the use of the equity method assuming the adoption of this method since initial acquisition; the “step-up” of the carrying amount of interests owned before the acquisition of significant influence (joint control) is taken to equity. (5)6
Joint ventures, associates and immaterial unconsolidated subsidiaries are accounted for at cost less any accumulated impairment losses, if this does not result in a misrepresentation of the Company’s financial position and performance. 7
If the retained investment continues to be accounted for using the equity method, no remeasurement toat fair value is recognizedrecognised in the profit and loss account. (6)8
Conversely, any amount related to the former joint venture/associate previously recognizedrecognised in other comprehensive income, which cannotmay not be reclassified subsequently to the profit and loss account, are reclassified in another item of equity. (7)
Fair value measurement principles are described below in the accounting policy for “Fair value measurements”.
The acquirer shall measure the identifiable assets acquired and liabilities assumed at their acquisition-date fair values9, unless another measurement basis is required by IFRSs. The excess of the consideration transferred over the Group’s share of the acquisition-date fair values of the identifiable assets acquired and liabilities assumed is recognised, on the balance sheet, as goodwill; conversely, a gain on a bargain purchase is recognised in the profit and loss account. Any non-controlling interest isinterests are measured as the proportionate share in the recognizedrecognised amounts of the acquiree’s identifiable net assets at the acquisition date excluding the portion of goodwill attributable to them (partial goodwill method); as an alternative, it is allowed the recognition of the entire amount of goodwill deriving from the acquisition, including also the goodwill attributable to non-controlling interests (full goodwill method). In the last case, non-controlling interests aremay be measured at their fair value, which thereforemeans that goodwill includes the goodwillportion attributable to them (full goodwill method)810. The choice of measurement basis offor goodwill (partial goodwill method vs. full goodwill method) is made on a transaction-by-transaction basis. In a business combination achieved in stages, the purchase price is determined by summing the acquisition-date fair value of previously held equity interests in the acquiree and the consideration transferred for the acquisition ofobtaining control; the previously held equity interests are re-measuredremeasured at their acquisition-date fair value and the resulting gain or loss, if any, is recognizedrecognised in the profit and loss account. Furthermore, on obtaining control, any amount of the acquiree previously recognizedrecognised in other comprehensive income related to the previously held equity interests is chargedreclassified to the profit and loss account, or in another item of equity when thesuch amount cannotmay not be reclassified to the profit and loss account. If control is obtained over a business formerly classified as joint operation, the previously held interest in its assets and liabilities is not re-measured to its fair value. If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognizedrecognised at the acquisition date shall be retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed as of the acquisition date. The acquisition of interests in a joint operation in which thewhose activity constitutes a business is recognizedaccounted for applying the principles on business combinations accounting. In this regard, if the entity obtains control over a business that was a joint operation, the previously held interest in the joint operation is remeasured at the acquisition-date fair value and the resulting gain or loss is recognized in the profit and loss account.11 Significant accounting estimates and judgements: investments and business combinations The assessment of the existence of control, joint control, significant influence over an investee, as well as for joint operations, the assessment of the existence of enforceable rights and obligations imply that the management makes complex judgements on the basis of the characteristics of the investee’s structure, arrangements between parties and other relevant principlesfacts and circumstances. Significant accounting estimates by management are required also for measuring the identifiable assets acquired and the liabilities assumed in a business combinations.combination at their acquisition-date fair values. For such measurement, to be performed also for the application of the equity method, Eni adopts the valuation techniques generally used by market participants taking into account the available information; for the most significant business combinations, Eni engages external independent evaluators. Intragroup transactions All balances and transactions between consolidated companies, and not yet realised with third parties, including unrealizedunrealised profits arising from such transactions have been eliminated. UnrealizedUnrealised profits arising from transactions between the Group and its equity-accounted entities are eliminated to the extent of the Group’s interest in the equity-accounted entity. In both cases, unrealizedunrealised losses are not eliminated when they provideunless the transaction provides evidence of an impairment loss of the asset transferred.
9
Fair value measurement principles are described in the accounting policy for “Fair value measurements”. 10
The choice between the partial goodwill and full goodwill method is made also for business combinations resulting in the recognition of a gain on bargain purchase in the profit and loss account. 11
If the entity acquires additional interests in a joint operation that is a business, while retaining joint control, the previously held interest in the joint operation is not remeasured.
Foreign currency translation The financial statements of foreign operations having a functional currency other than the euro, that represents the parent’s functional currency, are translated into euroeuros using the spot exchange rates on the balance sheet date for assets and liabilities, historical exchange rates for equity and average exchange rates for the profit and loss account and the statement of cash flows (source: WMR/IPSE)Reuters — WMR). The cumulative amount of the resulting translationexchange differences isare presented in the separate component of the GroupEni shareholders’ equity “Cumulative currency translation differences”912. Cumulative amount of exchange differences relating to a foreign operation are reclassified to the profit and loss account when the entity disposes the entire interest in athat foreign operation or when the partial disposal involves the loss of control, joint control or significant influence of aover the foreign operation. On a partial disposal that does not involve loss of control of a subsidiary that includes a foreign operation, the proportionate share of the cumulative exchange differences is reattributed to the non-controlling interests in that foreign operation. On a partial disposal of interests in joint arrangements or in associates that does not involve loss of joint control or significant influence, the proportionate share of the cumulative exchange differences is reclassified to the profit and loss account. The repayment of share capital made by a subsidiary having a functional currency other than the euro, without a change in the ownership interest, implies that the proportionate share of the cumulative amount of exchange differences relating to the subsidiary is reclassified to the profit and loss account. (8)
The choice between partial goodwill and full goodwill method is made also for business combinations resulting in the recognition of a gain on bargain purchase in the profit and loss account.
(9)
When the foreign subsidiary is partially owned, the cumulative exchange differences, that are attributable to the non-controlling interests, are allocated to and recognized as part of “Non-controlling interest”.
The financial statements of foreign operations which are translated into euroeuros are denominated in the foreign operations’ functional currencies which generally is the U.S. dollar. The main foreign exchange rates used to translate the financial statements into the parent’s functional currency are indicated below: (currency amount for 1 €) | | Annual average exchange rate 2014 | | Exchange rate at December 31, 2014 | | Annual average exchange rate 2015 | | Exchange rate at December 31, 2015 | | Annual average exchange rate 2016 | | Exchange rate at December 31, 2016 | | | Annual average exchange rate 2019 | | Exchange rate at December 31, 2019 | | Annual average exchange rate 2018 | | Exchange rate at December 31, 2018 | | Annual average exchange rate 2017 | | Exchange rate at December 31, 2017 | | U.S. Dollar | | | | 1.33 | | | | | 1.21 | | | | | 1.11 | | | | | 1.09 | | | | | 1.11 | | | | | 1.05 | | | | | | 1.12 | | | | | 1.12 | | | | | 1.18 | | | | | 1.15 | | | | | 1.13 | | | | | 1.20 | | | Pound Sterling | | | | 0.81 | | | | | 0.78 | | | | | 0.73 | | | | | 0.73 | | | | | 0.82 | | | | | 0.86 | | | | | | 0.88 | | | | | 0.85 | | | | | 0.88 | | | | | 0.89 | | | | | 0.88 | | | | | 0.89 | | | Norwegian Krone | | | | 8.35 | | | | | 9.04 | | | | | 8.95 | | | | | 9.60 | | | | | 9.29 | | | | | 9.09 | | | | Australian Dollar | | | | 1.47 | | | | | 1.48 | | | | | 1.48 | | | | | 1.49 | | | | | 1.49 | | | | | 1.46 | | | | | | 1.61 | | | | | 1.60 | | | | | 1.58 | | | | | 1.62 | | | | | 1.47 | | | | | 1.53 | | | | |
3 Significant accounting policies
The most significant accounting policies used in the preparation of the Consolidated Financial Statements are described below. Oil and natural gas exploration, appraisal, development and production expenditureactivities Oil and natural gas exploration, appraisal and development activities are accounted for using the principles of the successful efforts method of accounting as described below. Acquisition of exploration rights Costs incurred for the acquisition of exploration rights (or their extension) are initially capitalizedcapitalised within the line item “Intangible assets” as “exploration rights — unproved” pending determination of whether the exploration and appraisal activities in the reference areas are successful or not. Unproved exploration rights are not amortized,amortised, but reviewed to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review is based on the confirmation of the commitment of the Company to continue the exploration activities and on the analysis of facts and circumstances that can showindicate the existenceabsence of uncertainties related to the recoverability of the carrying amount. If no future activity is planned, the carrying amount of the related exploration rights is recognizedrecognised in the profit and loss account as write-off. Lower value exploration rights are pooled and amortizedamortised on a straight-line basis over the estimated period of exploration. In the event of a discovery of proved reserves (i.e. upon recognition of 12
When the foreign subsidiary is partially owned, the cumulative exchange differences, that are attributable to the non-controlling interests, are allocated to and recognised as part of “Non-controlling interest”.
proved reserves and internal approval for development), the carrying amount of the related unproved exploration rights is reclassified to “proved exploration rights”, within the line item “Intangible assets”. When theUpon reclassification, is recognized, as well as whetheror when there is any indication of impairment, the carrying amount of exploration rights to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration rights are amortizedamortised according to the unit of production method (the so-called UOP method, described in the accounting policy for “UOP depreciation, depletion and amortization”amortisation”). Acquisition of mineral interests Costs incurred for the acquisition of mineral interests are capitalizedcapitalised in connection with the assets acquired (such as exploration potential, possible and probable reserves and proved reserves). When the acquisition is related to a set of exploration potential and reserves, the cost is allocated to the different assets acquired based on their expected discounted cash flows. Acquired exploration potential is measured underin accordance with the criteria indicatedillustrated in the accounting policy for “Acquisition of exploration rights”. Costs associated with proved reserves are amortized on aamortised according to the UOP basismethod (see the accounting policy for “UOP depreciation, depletion and amortization”amortisation”). Expenditure associated with possible and probable reserves (unproved mineral interests) is not amortizedamortised until classified as proved reserves; in case of a negative result, it is written-off.written off. Exploration and appraisal expenditure Geological and geophysical exploration costs are recognizedrecognised as an expense as incurred.
Costs directly associated with an exploration well are initially recognizedrecognised within tangible assets in progress, as “exploration and appraisal costs — unproved” (exploration wells in progress) until the drilling of the well is completed and can continue to be capitalizedcapitalised in the following 12-month period pending the evaluation of drilling results (suspended exploration wells). If, at the end of this period, it is ascertained that the result is negative (no hydrocarbon found) or that the discovery is not sufficiently significant to justify the development, the wells are declared dry/unsuccessful and the related costs are written-off. Conversely, these costs continue to be capitalizedcapitalised if and until: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well, and (ii) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project; on the contrary, the capitalizedcapitalised costs are recognizedrecognised in the profit and loss account as write-off. Analogous recognition criteria are adopted for the costs related to the appraisal activity. When proved reserves of oil and/or natural gas are determined, the relevant expenditure recognizedrecognised as unproved is reclassified to proved exploration and appraisal costs within tangible assets in progress. When theUpon reclassification, is recognized, as well as whether there is any indication of impairment, the carrying amount of the costs to reclassify as proved is tested for impairment considering the higher of their value in use and their fair value less costs of disposal. From the commencement of production, proved exploration and appraisal costs are depreciated according to the UOP method (see the accounting policy for “UOP depreciation, depletion and amortization”amortisation”). Development expenditure Development expenditure, including the costs related to unsuccessful and damaged development wells, are capitalizedcapitalised as “Tangible asset in progress — proved”. Development expenditurescosts are costs incurred to obtain access to proved reserves and to provide facilities to extract, gatherfor extracting, treating, gathering and storestoring the oil&gas. and gas. They are amortized,amortised, from the commencement of production, generally on a UOP basis (see the accounting policy for “UOP depreciation, depletion and amortization”).basis. When development projects are unfeasible/not carried on, the related costs are written-offwritten off when it is decided to abandon the project. Development costs are tested for impairment in accordance with the criteria described in the accounting policy for “Property, plant and equipment”. UOP depreciation, depletion and amortizationamortisation Proved oil&gas and gas assets are depreciated generally under the UOP method, as their useful life is closely related to the availability of proved oil&gas and gas reserves, by applying, to the depreciable amounts at the end of each quarter a rate representing the ratio between the volumes extracted during the quarter and the reserves existing at the end of the quarter, increased by the volumes extracted during the quarter. This
method is applied with reference to the smallest aggregate representing a direct correlation between expenditures to be depreciated and oil&gas and gas reserves. Proved exploration rights and acquired proved mineral interests are amortizedamortised over proved reserves; proved exploration and appraisal costs and development expenditure are depreciated over proved developed reserves, while common facilities are depreciated over total proved reserves. Production costs Production costs are those costs incurred to operate and maintain wells and field equipment and are recognizedrecognised as an expense as incurred. Production Sharing Agreements and buy-back contracts Oil and gas reserves related to Production Sharing Agreements and buy-back contracts are determined on the basis of contractual terms related to the recovery of the contractor’s costs to undertake and finance exploration, development and production activities at its own risk (Cost Oil) and the Company’s stipulated share of the production remaining after such cost recovery (Profit Oil). Revenues from the sale of the lifted production, entitlements against both Cost Oil and Profit Oil, are accounted for on an accrual basis, whilst exploration, development and production costs are accounted for according to the above-mentioned accounting policies. The Company’s share of production volumes and reserves representing the Profit Oil includes the share of hydrocarbons that corresponds to the taxes to be paid, according to the contractual agreement, by the national government on behalf of the Company. As a consequence, the Company has to recognizerecognise at the same time an increase in the taxable profit, through the increase of the revenues,revenue, and a tax expense. DecommissioningPlugging and restoration liabilitiesabandonment of wells
Costs expected to be incurred with respect to the plugging and abandonment of a well, dismantlement and removal of production facilities, as well as site restoration, are capitalized, consistentlycapitalised, consistent with the accounting policy described under “Property, plant and equipment”, and then depreciated on a UOP basis. Significant accounting estimates and judgements: oil and natural gas activities Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil and gas reserves can be categorised as “proved”, the accuracy of reserve estimates depends on a number of factors, assumptions and variables, including: (i) the quality of available geological, technical and economic data and their interpretation and judgement; (ii) projections regarding future rates of production and operating costs as well as timing and amount of development expenditures; (iii) changes in the prevailing tax rules, other government regulations and contractual conditions; (iv) results of drilling, testing and the actual production performance of Eni’s reservoirs after the date of the estimates which may drive substantial upward or downward revisions; and (v) changes in oil and natural gas prices which could affect expected future cash flows and the quantities of Eni’s proved reserves since the estimates of reserves are based on prices and costs existing as of the date when these estimates are made. Lower oil prices or the projections of higher operating and development costs may impair the ability of the Company to economically produce reserves leading to downward reserve revisions. Many of the factors, assumptions and variables involved in estimating proved reserves are subject to change over time and therefore affect the estimates of oil and natural gas reserves. The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is made within a year after well completion. The evaluation process of a discovery, which requires performing additional appraisal activities on the potential oil and natural gas field and establishing the optimum development plans, can take longer, in most cases, depending on the complexity of the project and on the size of capital expenditures required. During this period, the costs related to these exploration wells remain suspended on the balance sheet. In any case, all such capitalised costs are reviewed, at least, on an annual basis to confirm the continued intent to develop, or otherwise to extract value from the discovery.
Field reserves will be categorised as proved only when all the criteria for attribution of proved status have been met. Initially, all booked reserves are classified as proved undeveloped. Subsequently, volumes are reclassified from proved undeveloped to proved developed as a consequence of development activity. Generally, reserves are booked as proved developed when the first oil or gas is produced. Major development projects typically take one to four years from the time of initial booking to the start of production. Estimated proved reserves are used in determining depreciation, amortisation and depletion charges and impairment charges. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation, amortisation and depletion charge under the UOP method. Conversely, a decrease in estimated proved developed reserves increases depreciation, amortisation and depletion charge. Property, plant and equipment Property, plant and equipment, including investment properties, are recognizedrecognised using the cost model and stated at their purchase price or construction cost including any costs directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by management. WhenFor assets that necessarily take a substantial period of time is required to make the assetget ready for their intended use, the purchase price or construction cost includescomprises the borrowing costs incurred in the period to get the asset ready for use that couldwould have otherwise been avoided if the expenditure had not been made. In the case of a present obligation for dismantling and removal of assets and restoration of sites, the initial carrying amount of an item of property, plant and equipment includes the estimated (discounted) costs to be incurred when the removal event occurs (aoccurs; a corresponding amount is recognizedrecognised as part of a specific provision). Changes in provisions due to the passage of time and changes in discount rates are recognized as described inprovision (see the accounting policy for “Provisions, contingent assets“Decommissioning and restoration liabilities”10. Property, plant and equipment are not revalued for financial reporting purposes. Assets under finance lease, or under arrangements that do not take the legal form of a finance lease but substantially transfer all the risks and rewards of ownership of the leased asset, are recognized, at the commencement of the lease term, at fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments. Leased assets are included within property, plant and equipment. A corresponding financial debt to the lessor is recognized. These assets are depreciated as described below. If there is no reasonable certainty that the lessee will obtain ownership by the end of the lease term, the assets are depreciated over the shorter of the lease term and the useful life of the asset.
Expenditures on upgrading, revamping and reconversion are recognizedrecognised as items of property, plant and equipment when it is probable that they will increase the expected future economic benefits of the asset. Assets acquired for safety or environmental reasons, although not directly increasing the future economic benefits of any particular existing item of property, plant and equipment, qualify for recognition as assets when they are necessary to obtain future economic benefits from other assets.for running the business. Depreciation of tangible assets begins when they are available for use, i.e. when they are in the location and condition necessary for it to be capable of operating as planned. Property, plant and equipment are depreciated on a systematic basis using a straight-line method over their useful life. The useful life is the period over which an asset is expected to be available for use by the Company. When tangible assets are composed of more than one significant part with different useful lives, each part is depreciated separately. The depreciable amount is the asset’s carrying amount less its residual value at the end of its useful life, if it is significant and can be reasonably determined. Land is not depreciated, even when purchasedacquired together with a building. Tangible assets held for sale are not depreciated (see the accounting policy for “Assets held for sale and discontinued operations” below)). A change in the depreciation method, deriving from changesChanges in the asset’s useful life, in its residual value or in the pattern of consumption of the future economic benefits embodied in the asset, shall be recognizedare accounted for prospectively. Assets that canto be used free of charge by third partieshanded over for no consideration are depreciated over the shorter term ofbetween the duration of the concession or the asset’s useful life. Replacement costs of identifiable parts in complex assets are capitalizedcapitalised and depreciated over their useful life; the residual carrying amount of the part that has been substituted is charged to the profit and loss account. Leasehold improvement costsNon-removable leasehold improvements are depreciated over the earlier of the useful life of the improvements or, if lower, over the residual length ofand the lease considering any renewal period if renewal depends entirely on the lessee and is virtually certain.term. Expenditures for ordinary maintenance and repairs are recognizedrecognised as an expense as incurred. The carrying amount of property, plant and equipment is reviewed for impairment whenever there is any indication that the carrying amounts of those assets may not be recoverable. The recoverability of an asset is assessed by comparing its carrying amount with the recoverable amount, which is the higher of the 10
These liabilities relate essentially to assets in the Exploration & Production segment. Decommissioning and restoration liabilities associated with tangible assets of Refining & Marketing, Chemical and Gas & Power segments/businesses are recognized when the amount of the liability can be reliably estimated, considering that undetermined settlement dates for assets dismantlement and restoration do not allow a discounting estimate of the obligation. With regard to this, Eni performs periodic reviews of its tangible assets of Refining & Marketing, Chemical and Gas & Power segments/businesses for any changes in facts and circumstances that might require recognition of a decommissioning and restoration liability.
asset’s fair value less costs of disposal and its value in use. Value in use is the present value of the future cash flows expected to be derived from continuing use of the asset and, if significant and reliably measurable, the cash flows expected to be obtained from its disposal at the end of its useful life, after deducting the costs of disposal. Expected cash flows are determined on the basis of reasonable and supportable assumptions that represent management’s best estimate of the range of economic conditions that will exist over the remaining useful life of the asset, giving greater weight to external evidence.
With reference to commodity prices, management assumes the price scenario adopted for economic and financial projections and for whole life appraisal for capital expenditures. In particular, for the cash flows associated to oil, natural gas and petroleum products prices (and prices derived from them), the price scenario is approved by the Board of Directors and is based on management’s long-term planning assumptions and, if there is a sufficient liquidity and reliability level, on the forward prices prevailing in the marketplace. When commodity prices fluctuate quite considerably, management considers the most updated variables available.
Discounting is carried out at a rate that reflects a current market assessment of the time value of money and of the risks specific to the asset that are not reflected in the expected future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific country risk of the asset. These adjustments are measured considering information from external parties. WACC differs considering the risk associated with each operating segments where the asset operates. In particular, for the assets belonging to the Gas & Power segment and the Chemical business, taking into account their different risk compared with Eni as a whole, specific WACC rates have been defined on the basis of a sample of companies operating in the same segment/business, adjusted to take into consideration the risk premium of the specific country of the activity. For the other segments, a single WACC is used considering that the risk is the same to that of Eni as a whole. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate deriving, through an iteration process, from a post-tax valuation. Valuation is carried out for each single asset or, if the recoverable amount of a single asset cannot be determined, for the smallest identifiable group of assets that generates independent cash inflows from their continuous use, the so-called “cash-generating unit”. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognized in the profit and loss account. The reversal shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years.
The carrying amount of property, plant and equipment is derecognizedderecognised on disposal or when no future economic benefits are expected from its use or disposal; the arising gain or loss is recognizedrecognised in the profit and loss account.
Leases13 14 A contract is, or contains, a lease, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration15; such right exists whether, throughout the period of use, the customer has both the right to obtain substantially all of the economic benefits from use of the identified asset and the right to direct the use of the identified asset. At the commencement date of the lease (i.e. the date on which the underlying asset is available for use), a lessee recognises on the balance sheet an asset representing its right to use the underlying leased asset (hereinafter also referred as right-of-use asset) and a liability representing its obligation to make lease payments during the lease term (hereinafter also referred as lease liability).16 The lease term is the non-cancellable period of a contract, together with, if reasonably certain, periods covered by extension options or by the non-exercise of termination options. In particular, the lease liability is initially recognised at the present value of the following lease payments17 that are not paid at the commencement date: (i) fixed payments (including in-substance fixed payments), less any lease incentives receivable; (ii) variable lease payments that depend on an index or a rate18; (iii) amounts expected to be payable by the lessee under residual value guarantees; (iv) the exercise price of a purchase option if the lessee is reasonably certain to exercise that option; and (v) payments of penalties for terminating the lease, if the lease term reflects the lessee exercising an option to terminate the lease. The lease payments are discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the lessee’s incremental borrowing rate. The latter is determined considering the term of the lease, the frequency and currency of the contractual lease payments, as well as the features of the lessee’s economic environment (reflected in the country risk premium assigned to each country where Eni operates). After the initial recognition, the lease liability is measured on an amortised cost basis and is remeasured, normally, as an adjustment to the carrying amount of the related right-of-use asset, to reflect changes to the lease payments due, essentially, to: (i) modifications in the lease contract not accounted as a separate lease; (ii) changes in indexes or rates (used to determine the variable lease payments); or (iii) changes in the assessment of contractual options (e.g. options to purchase the underlying asset, extension or termination options). The right-of-use asset is initially measured at cost, which comprises: (i) the amount of the initial measurement of the lease liability; (ii) any initial direct costs incurred by the lessee19; (iii) any lease payments made at or before the commencement date, less any lease incentives received; and (iv) an estimate of costs to be incurred by the lessee in dismantling and removing the underlying asset, restoring the site on which it is located or restoring the underlying asset to the condition required by the terms and conditions of the lease. After the initial recognition, the right-of-use asset is adjusted for any accumulated depreciation20, any accumulated impairment losses (see the accounting policy for “Impairment of non-financial assets”) and any remeasurement of the lease liability. In the oil and gas activities, the operator of an unincorporated joint operation which enters into a lease contract as the sole signatory recognises on the balance sheet: (i) the entire lease liability if, based on 13
The accounting policies related to leases have been defined on the basis of IFRS 16 “Leases” effective from January 1, 2019. As allowed by the accounting standard, the new requirements have been applied without restating the comparative years. The previous accounting policies about leases required essentially that: (i) assets held under finance lease, or under arrangements that did not take the legal form of a finance lease but substantially transferred all the risks and rewards incidental to ownership of the leased asset, were recognised, at the commencement of the lease, at their fair value, net of grants attributable to the lessee or, if lower, at the present value of the minimum lease payments, within property, plant and equipment as a contra account to a financing payable to the lessor; and (ii) lease payments under an operating lease were recognised as an expense over the lease term. 14
As expressly provided for in IFRS 16, this accounting policy does not apply to leases to explore for and extract resources such as those for oil and gas rights, leases of land and any rights of way related to oil and gas activities. 15
The assessment of whether the contract is, or contains, a lease is performed at the inception date, that is the earlier of the date of a lease agreement and the date of commitment by the parties to the principal terms and conditions of the lease. 16
Eni applies the recognition exemptions allowed for short-term leases (for certain classes of underlying assets) and low-value leases, by recognising the lease payments associated with those leases as an expense on a straight-line basis over the lease term. 17
Eni, in accordance with the practical expedient allowed by the accounting standard, does not separate non-lease components from lease components except for main contracts related to upstream activities (drilling rigs), which provide for single payments relating to both lease and non-lease components. 18
Conversely, the other kinds of variable lease payments (e.g. payments that depend on the use of an underlying leased asset) are not included in the carrying amount of the lease liability, but are recognised in the profit and loss account as operating expenses over the lease term. 19
Initial direct costs are incremental costs of obtaining a lease that would not have been incurred if the lease had not been obtained. 20
Depreciation charges are recognised on a systematic basis from the commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. Nevertheless, if the lease transfers ownership of the underlying asset to the lessee by the end of the lease term, or if the cost of the right-of-use asset reflects that the lessee will exercise a purchase option, the right-of-use asset is depreciated from the commencement date to the end of the useful life of the underlying asset.
the contractual provisions and any other relevant facts and circumstances, it has primary responsibility for the liability towards the third-party supplier; and (ii) the entire right-of-use asset, unless, on the basis of the terms and conditions of the contract, there is a sublease with the followers. The followers’ share of the right-of-use asset, recognised by the operator, will be recovered according to the joint operation’s contractual arrangements by billing the project costs attributable to the followers and collecting the related cash calls. Costs recovered from the followers are recognised as “Other income and revenues” in the profit and loss account and as net cash provided by operating activities in the statement of cash flows. Differently, if a lease contract is signed by all the partners, Eni recognises its share of the right-of-use asset and lease liability on the balance sheet based on its working interest. If Eni does not have primary responsibility for the lease liability, it does not recognise any right-of-use asset and lease liability related to the lease contract. When lease contracts are entered into by companies other than subsidiaries that act as operators on behalf of the other participating companies (the so-called operating companies), consistent with the provision to recover from the followers the costs related to the oil and gas activities, the participating companies recognise their share of the right-of-use assets and the lease liabilities based on their working interest, defined according to the expected use, to the extent that it is reliably determinable, of the underlying assets. Significant accounting estimates and judgements: lease transactions With reference to lease contracts, management made significant estimates and judgements related to: (i) determining the lease term, making assumptions about the exercise of extension and/or termination options; (ii) determining the lessee’s incremental borrowing rate; (iii) identifying and, where appropriate, separating non-lease components from lease components, where an observable stand-alone price is not readily available, taking into account also the analysis performed with external experts; (iv) recognising lease contracts, for which the underlying assets are used in oil and gas activities (mainly drilling rigs and FPSOs), entered into as operator within an unincorporated joint operation, considering if the operator has primary responsibility for the liability towards the third-party supplier and the relationships with the followers; (v) identifying the variable lease payments and the related characteristics in order to include them in the measurement of the lease liability. Intangible assets Intangible assets are identifiable non-monetary assets without physical substance, controlled by the Company and able to produce future economic benefits, and goodwill acquired in business combinations.goodwill. An asset is classified as intangible when management is able to distinguish it clearly from goodwill. This condition is normally met when: (i) the intangible asset arises from contractual or other legal rights, or (ii) the asset is separable, i.e. can be sold, transferred, licensed, rented or exchanged, either individually or together with other assets. An entity controls an intangible asset if it has the power to obtain the future economic benefits flowing from the underlying asset and to restrict the access of others to those benefits. Intangible assets are initially recognizedrecognised at cost as determined by the criteria used for tangible assets and they are not revalued for financial reporting purposes. Intangible assets with finite useful lives are amortizedamortised on a systematic basis over their useful life estimated as the period over which the assets will be available for use by the Company;life; the amount to be amortizedamortised and the recoverability of the carrying amount are determined in accordance with the criteria described in the accounting policy for “Property, plant and equipment”. Goodwill and intangible assets with indefinite useful lives are not amortized. Theiramortised. For the recoverability of the carrying amounts are tested for impairment at least annuallyof the goodwill and whenever there is any indicationother intangible assets see the accounting policy “Impairment of impairment. Goodwill is tested for impairment at the lowest level within the entity at which it is monitored for internal managementnon-financial assets”.
purposes. WhenCosts of obtaining a contract with a customer are recognised on the carrying amountbalance sheet if the Company expects to recover those costs. The intangible asset arising from those costs is amortised on a systematic basis, that is consistent with the transfer to the customer of the cash-generating unit, including goodwill allocated thereto, calculated considering anygoods or services to which the asset relates, and is tested for impairment loss of the non-current assets belonging to the cash-generating unit, exceeds its recoverable amount1121, the excess is recognized as an impairment loss. The impairment loss is allocated first to reduce the carrying amount of goodwill; any remaining excess is allocated to the other assets of the unit pro-rata on the basis of the carrying amount of each asset in the unit, up to the recoverable amount of assets with finite useful lives. An impairment loss recognized for goodwill is not reversed in a subsequent period12.
Directly attributable customer acquisition costs are capitalized when the following conditions are met: (i) the capitalized costs can be measured reliably; (ii) there is a contract binding the customer for a specified period of time; and (iii) it is probable that the costs will be recovered through the revenues from the sales, or, where the customer withdraws from the contract in advance, through the collection of a penalty.
Costs of technological development activities are capitalizedcapitalised when: (i) the cost attributable to the development activity can be measured reliably; (ii) there is the intention and the availability of financial and technical resources to make the asset available for use or sale; and (iii) it can be demonstrated that the asset is able to generate probable future economic benefits. The carrying amount of intangible assets is derecognizedderecognised on disposal or when no future economic benefits are expected from its use or disposal; any arisingresulting gain or loss is recognizedrecognised in the profit and loss account. Impairment of non-financial assets Non-financial assets (tangible assets, intangible assets and right-of-use assets) are tested for impairment whenever events or changes in circumstances indicate that the carrying amounts for those assets may not be recoverable. The recoverability assessment is performed for each cash-generating unit (hereinafter also CGU) represented by the smallest identifiable group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or group of assets. CGUs are identified considering, inter alia, how management monitors the entity’s operations (such as by business lines) or how management makes decisions about continuing or disposing of the entity’s assets and operations. Cash-generating units may include corporate assets which do not generate cash inflows independently of other assets or group of assets, allocable on a reasonable and consistent basis. Corporate assets not attributable to a single cash-generating unit are allocated to a group of cash-generating units. Goodwill is tested for impairment at least annually, and whenever there is any indication of impairment, at the lowest level within the entity at which it is monitored for internal management purposes. Right-of-use assets, which generally do not generate cash inflows independently of other assets or groups of assets, are allocated to the CGU to which they belong; the right-of-use assets which cannot be fully attributed to a CGU are considered as corporate assets. The recoverability of a CGU is assessed by comparing its carrying amount with the recoverable amount, which is the higher of the CGU’s fair value less costs of disposal and its value in use. Value in use is the present value of the future cash flows expected to be derived from continuing use of the CGU and, if significant and reliably measurable, the cash flows expected to be obtained from its disposal at the end of its useful life, after deducting the costs of disposal. The expected cash flows are determined on the basis of reasonable and supportable assumptions that represent management’s best estimate of the range of economic conditions that will exist over the remaining useful life of the cash-generating unit, giving greater weight to external evidence. The value in use of CGUs which include material right-of-use assets is calculated, normally, by ignoring lease payments included in the measurement of the lease liabilities. With reference to commodity prices, management uses the price scenario adopted for economic and financial projections and for the evaluation of investments over their entire life. In particular, for the cash flows associated with oil, natural gas and petroleum products prices (and prices derived from them), the price scenario is approved by the Board of Directors and is based on management’s planning assumptions, in the short and medium term, takes into account the projections of market analysts and, if there is a sufficient liquidity and reliability level, on the forward prices prevailing in the marketplace. For impairment test purposes, cash outflows expected to be incurred to guarantee compliance with laws and regulations regarding CO2 emissions (e.g. Emission Trading Scheme) or on a voluntary basis 21
The accounting policies adopted until 2017 (before applying IFRS 15) required the capitalisation of directly attributable customer acquisition costs when all the following conditions were met: (i) the capitalised costs can be measured reliably; (ii) there is a contract binding the customer for a specified period of time; and (iii) it is probable that the costs will be recovered through the revenue from the sales, or, where the customer withdraws from the contract in advance, through the collection of a penalty.
(e.g. cash outflows related to forestry certificates acquired or produced consistent with the Company’s decarbonization strategy — hereinafter also forestry) are taken into account. In particular, in estimating value in use, the cash outflows for forestry projects22 are included, consistent with the medium term target of the decarbonization strategy, within the expected cash outflows of the segment whose emissions are offset. Currently, considering that the forestry projects can be developed in countries where Eni does not carry out operating activities and considering the difficulty to allocate such cash outflows, on a reasonable and consistent basis, to the CGUs of the segment, the related discounted cash outflows are treated as a reduction of the headroom of that segment. For the determination of value in use, the estimated future cash flows are discounted using a rate that reflects a current market assessment of the time value of money and of the risks specific to the asset that are not reflected in the estimated future cash flows. In particular, the discount rate used is the Weighted Average Cost of Capital (WACC) adjusted for the specific country risk of the CGU. These adjustments are measured considering information from external parties. WACC differs considering the risk associated with each operating segment/business where the asset operates. In particular, for the assets belonging to the Gas & Power segment and the Chemical business, taking into account their different risk compared to Eni as a whole, specific WACC rates have been defined on the basis of a sample of comparable companies, adjusted to take into account the specific country-risk premium. For the other segments/businesses, a single WACC is used considering that the risk is the same to that of Eni as a whole. Value in use is calculated net of the tax effect as this method results in values similar to those resulting from discounting pre-tax cash flows at a pre-tax discount rate derived, through an iteration process, from a post-tax valuation. When the carrying amount of the CGU, including goodwill allocated thereto, determined taking into account any impairment loss of the non-current assets belonging to the CGU, exceeds its recoverable amount, the excess is recognised as an impairment loss. The impairment loss is allocated first to reduce the carrying amount of goodwill; any remaining excess is allocated to the other assets of the unit pro-rata on the basis of the carrying amount of each asset in the CGU, up to the recoverable amount of assets with finite useful lives. When an impairment loss no longer exists or has decreased, a reversal of the impairment loss is recognised in the profit and loss account. The impairment reversal shall not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. An impairment loss recognised for goodwill is not reversed in a subsequent period.23 Grants related to assets Government grants related to assets are recognizedrecognised by deducting them in calculating the carrying amount of the related assets when there is reasonable assurance that the Company will comply with the conditions attaching to them and the grants will be received. Inventories Inventories, including compulsory stock, are measured at the lower of purchase or production cost and net realizablerealisable value. Net realizablerealisable value is the net amount expected to be realized from the sale of inventoriesestimated selling price in the ordinary course of business less the estimated costs of completion and the estimated costs necessary to make the sale, or, with reference to inventories of crude oil and petroleum products already included in binding sale contracts, the contractual saleselling price. Inventories which are principally acquired with the purpose of selling in the near future and generating a profit from fluctuations in price are measured at fair value less costs to sell. Materials and other supplies held for use in production are not written down below cost if the finished products in which they will be incorporated are expected to be sold at or above cost. The cost of inventories of hydrocarbons (crude oil, condensates and natural gas) and petroleum products is determined by applying the weighted average cost method on a three-month basis, or on a different time period (e.g. monthly), when it is justified by the use and the turnover of inventories of crude oil and petroleum products; the cost of inventories of the Chemical business is determined by applying the weighted average cost on an annual basis. 22
For the recognition criteria of forestry certificates see the accounting policy for “Costs”. 23
Impairment losses recognised for goodwill in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognised in a smaller amount or would not have been recognised.
When take-or-pay clauses are included in long-term gas purchase contracts, pre-paid gas volumes that are not withdrawn to fulfill minimum annual take obligations are measured using the pricing formulas contractually defined. They are recognizedrecognised under “Other assets” as “Deferred costs” as a contra to “Other payables” or, after the settlement, to “Cash and cash equivalents”. The allocated deferred costs are charged to the profit and loss account: (i) when natural gas is actually withdrawn — the related cost is included in the determination of the weighted average cost of inventories; and (ii) for the portion which is not recoverable, when it is not possible to withdraw the previously pre-paid gas, within the contractually defined deadlines. Furthermore, the allocated deferred costs are tested for economic recoverability by comparing the related carrying amount and their net realizablerealisable value, determined adopting the same criteria described for inventories. Significant accounting estimates and judgements: impairment of non-financial assets The recoverability of non-financial assets is assessesed whenever events or changes in circumstances indicate that carrying amounts of the assets are not recoverable. Such impairment indicators include changes in the Group’s business plans, changes in commodity prices leading to unprofitable performance, a reduced capacity utilisation of plants and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities or significant increase of the estimated development and production costs. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain and complex matters such as future commodity prices, future discount rates, future development expenditure and production costs, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply-and-demand conditions also with reference to the decarbonization process and the effects of changes in regulatory requirements. Similar remarks are valid for assessing the physical recoverability of assets recognised on the balance sheet (deferred costs — see also the accounting policy for “Inventories”) related to natural gas volumes not withdrawn under long-term supply contracts with take-or-pay clauses. The expected future cash flows used for impairment analyses are based on judgemental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate which considers the risks specific to the asset. For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and undeveloped proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. The estimate of the future amount of production is based on assumptions related to future commodity prices, lifting and development costs, field decline rates, market demand and other factors. The cash flows associated to oil and gas commodities are estimated on the basis of forward market information, if there is a sufficient liquidity and reliability level, on the consensus of independent specialised analysts and on management’s forecasts about the evolution of the supply and demand fundamentals. Financial instruments24 Financial assets Financial assets are classified, on the basis of both contractual cash flow characteristics and the entity’s business model for managing them, in the following categories: (i) financial assets measured at amortised cost; (ii) financial assets measured at fair value through other comprehensive income (hereinafter also OCI); (iii) financial assets measured at fair value through profit or loss. At initial recognition, a financial asset is measured at its fair value plus, in the case of a financial asset not at fair value through profit or loss, transaction costs that are directly attributable; at initial recognition, trade receivables that do not have a significant financing component are measured at their transaction price. (11)24
ForThe accounting policies related to financial instruments were defined on the definitionbasis of recoverable amount seeIFRS 9 “Financial Instruments” effective from 2018; as required by the accounting policy for “Property, plant and equipment”.
(12)
Impairment losses recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they wouldstandard, the new requirements have been recognized in a smaller amount or would not haveapplied starting from January 1, 2018 without restating the comparative information. With reference to the financial instruments held by the Company, the previous accounting policies (applied until2017) required essentially: (i) the classification of financial assets on the basis of the categories under IAS 39; (ii) recognition and measurement of impairment losses if there was objective evidence that an impairment loss had been recognized.incurred (the so-called incurred loss model); and (iii) more stringent hedge accounting requirements (mainly referred to the assessment of hedge effectiveness).
Financial instruments
CurrentAfter initial recognition, financial assets
Cash whose contractual terms give rise to cash flows that are solely payments of principal and cash equivalents include cashinterest on hand, demand deposits, as well asthe principal amount outstanding are measured at amortised cost if they are held within a business model whose objective is to hold financial assets originally due within 90 days, readily convertiblein order to known amount ofcollect contractual cash and subjectflows (the so-called hold to an insignificant risk of changes in value.
Available-for-salecollect business model). For financial assets includemeasured at amortised cost, interest income determined using the effective interest rate, foreign exchange differences and any impairment losses25 (see the accounting policy for “Impairment of financial assets”) are recognised in the profit and loss account.
Conversely, financial assets other than derivative financialthat are debt instruments loans and receivables, held for trading financial assets and held-to-maturity financial assets. Held-for-trading financial assets and available-for-sale financial assets are measured at fair value with gains orthrough OCI (hereinafter also FVTOCI) if they are held within a business model whose objective is achieved by both collecting contractual cash flows and selling financial assets (the so-called hold to collect and sell business model). In these cases: (i) interest income determined using the effective interest rate, foreign exchange differences and any impairment losses recognized(see the accounting policy for “Impairment of financial assets”) are recognised in the line item of the profit and loss account “Finance income (expense)” andaccount; (ii) changes in fair value of the instruments are recognised in equity, within other comprehensive income. The accumulated changes in fair value, recognised in the equity reserve13 related to other comprehensive income, respectively. Changes in fair value of available-for-sale financial assets recognized in equity are chargedis reclassified to the profit and loss account when the assets are derecognized or impaired. The objective evidence that an impairment loss has occurredfinancial asset is verified considering, inter alia, significant breaches of contracts, serious financial difficulties orderecognised. Currently the risk of bankruptcy and other financial reorganization of the counterparty; impairment losses of available-for-sale financial assets are included in the carrying amount.
Interests and dividends onGroup does not have any financial assets measured at fair value are accountedthrough OCI.
A financial asset represented by a debt instrument that is neither measured at amortised cost nor at FVTOCI, is measured at fair value through profit or loss (hereinafter FVTPL); financial assets held for trading fall into this category. Interest income on an accrual basisassets held for trading contributes to the fair value measurement of the instrument and is recognised in “Finance income (expense)”14 and “Other gain (loss), within “Net finance income (expense) from investments”, respectively. financial assets held for trading”. When the purchase or sale of a financial asset is under a contract whose terms require delivery of the asset within the time frame established generally by regulation or convention in the marketplace concerned, the transaction is accounted for on the settlement date. Receivables are measured at amortized cost (see below the accounting policy for “Non-current financial assets”).
Non-currentImpairment of financial assets
Investments
Investments in equityThe expected credit loss model is adopted for the impairment of financial assets that are debt instruments,15 but are not measured at fair value with gainsthrough profit or loss.
In particular, the expected credit losses recognized inare generally measured by multiplying: (i) the equity reserve related to other comprehensive income; the amounts recognized in equity are reclassifiedexposure to the profit and loss account when the investment is impaired or derecognized. When investments do not have a quoted price in an active market and their fair value cannot be reliably measured, they are measured at cost,counterparty’s credit risk net of any impairment losses; impairment losses shallcollateral held and other credit enhancements (Exposure At Default, EAD); (ii) the probability that the default of the counterparty occurs (Probability of Default, PD); and (iii) the percentage estimate of the exposure that will not be reversed16recovered in case of default (Loss Given Default, LGD), considering the past experiences and the range of recovery tools that can be activated (e.g. extrajudicial and/or legal proceedings, etc.).
ReceivablesWith reference to trade and held-to-maturity financial assetsother receivables, Probabilities of Default of counterparties are determined by adopting the internal credit ratings already used for credit worthiness and are periodically reviewed using, inter alia, back-testing analyses; for government entities (e.g. National Oil Companies), the Probability of Default, represented essentially by the probability of a delayed payment, is determined by using, as input data, the country risk premium adopted to determine WACC for the impairment review of non-financial assets.
Receivables and held-to-maturity financial assetsFor customers without internal credit ratings, the expected credit losses are accounted for at cost, that ismeasured by using a provision matrix, defined by grouping, where appropriate, receivables into adequate clusters to which apply expected loss rates defined on the fair valuebasis of the initial consideration plus transaction costs (e.g. fees, transaction costs, etc.). The initial carrying amount is thentheir historical credit loss experiences, adjusted, where appropriate, to take into account principal repayments, plus or minus the cumulative amortization of any difference between the initial amount and the maturity amount and minus any reductions for impairment or uncollectibility. Amortization is carried outforward-looking information on the basiscredit risk of the effective interest rate represented bycounterparty or clusters of counterparties.26
Considering the rate that equalizes, at the momentcharacteristics of the initial recognition, the present value of expected cash flowsreference markets, financial assets with more than 180 days past due or, in any case, with counterparties undergoing litigation, restructuring or renegotiation, are considered to the initial carrying amount (so-called “amortized cost method”). Receivables for finance leasesbe in default. Counterparties are recognized at an amount equal to the present value of the lease payments and the purchase option price or any residual value; the amount is discounted at the interest rate implicit in the lease.considered undergoing litigation when judicial/legal proceedings aimed (13)25
Changes in the carrying amount of available-for-saleReceivables and other financial assets relating to changes in foreign exchange ratesmeasured at amortised cost are recognized inpresented on the profit andbalance sheet net of their loss account.allowance.
(14)
Interests accrued on held for trading financial assets impact the total fair value measurement of the instrument and are recognized, within the line item “Finance income (expense)”, in the sub-item “Net finance income on financial assets held for trading”. Conversely, interests accrued on financial assets available-for-sale are recognized, within the line item “Finance income (expense)”, in the sub-item “Finance income”.
(15)26
For investments in joint venturescredit exposures arising from intragroup transactions, the recovery rate is normally assumed equal to 100% taking into account, inter alia, the Group central treasury function which supports both financial and associates, see “The equity methodcapital needs of accounting”.
(16)
Impairment losses recognized in an interim period are not reversed also when, considering conditions existing in a subsequent interim period, they would have been recognized in a smaller amount or would not have been recognized.subsidiaries.
If thereto recover a receivable have been activated or are going to be activated. Impairment losses of trade and other receivables are recognised in the profit and loss account, net of any impairment reversal, within the line item of the profit and loss account “Net (impairment losses) reversals of trade and other receivables”.
The financing receivables held for operating purposes, granted to associates and joint ventures, for which settlement is objective evidence that anneither planned nor likely to occur in the foreseeable future and which in substance form part of the entity’s net investment in these investees, are tested for impairment, first, on the basis of the expected credit loss has been incurred (see alsomodel and, then, together with the carrying amount of the investment in the associate/joint venture, in accordance with the criteria indicated in the accounting policy for “Current financial assets”), the impairment loss is measured as the difference between the carrying amount and the present value“The equity method of accounting”. In applying the expected cash flows discounted at the effective interest rate computed at initial recognition, or at the moment of its updating to reflect re-pricings contractually established. Receivables and held-to-maturity financial assets are presented net of the allowance for impairment losses; when the impairmentcredit loss is definite, the allowance for impairment losses is reversed for charges, otherwise for excess. Changesmodel, any adjustments to the carrying amount of receivables orlong-term interest that arise from applying the accounting policy for “The equity method of accounting” are not taken into account. Significant accounting estimates and judgements: impairment of financial assets Measuring impairment losses of financial assets requires management evaluation of complex and highly uncertain elements such as, for example, Probabilities of Default of counterparties, the existence of any collateral or other credit enhancements, the expected exposure that will not be recovered in accordance withcase of default, as well as the amortizeddefinition of customers’ clusters to be adopted. Investments in equity instruments Investments in equity instruments that are not held for trading are measured at fair value through other comprehensive income, without subsequent transfer of fair value changes to profit or loss on derecognition of these investments; conversely, dividends from these investments are recognised in the profit and loss account, within the line item “Income (Expense) from investments”, unless they clearly represent a recovery of part of the cost method are recognized as “Finance income (expense)”.of the investment. In limited circumstances, an investment in equity instruments can be measured at cost if it is an appropriate estimate of fair value. Financial liabilities FinancialAt initial recognition, financial liabilities, other than derivative financial instruments, are measured at amortized cost (see above the accounting policy for “Non-current financial assets”).their fair value, minus transaction costs that are directly attributable, and are subsequently measured at amortised cost.
Derivative financial instruments and hedge accounting Derivative financial instruments, including embedded derivatives (see below) that are separated from the host contract, are assets and liabilities measured at their fair value. Derivatives are designated asWith reference to the defined risk management objectives and strategy, the qualifying criteria for hedge accounting requires: (i) the existence of an economic relationship between the hedged item and the hedging instruments wheninstrument in order to offset the related value changes and the effects of counterparty credit risk do not dominate the economic relationship between the hedged item and the hedging instrument; and (ii) the definition of the relationship between the derivative andquantity of the hedged item is formally documented and the quantity of the hedging instrument (the so-called hedge ratio) consistent with the entity’s risk management objectives, under a defined risk management strategy; the hedge ratio is regarded as highly effective and reviewedadjusted, where appropriate, after taking into account any adequate rebalancing. A hedging relationship is discontinued prospectively, in its entirety or a part of it, when it no longer meets the risk management objectives on an ongoing basis. the basis of which it qualified for hedge accounting, it ceases to meet the other qualifying criteria or after rebalancing it.
When derivatives hedge the risk of changes in the fair value of the hedged itemitems (fair value hedge, e.g. hedging of the variability in the fair value of fixed interest rate assets/liabilities), the derivatives are measured at fair value through profit and loss account. Consistently, the carrying amount of the hedged item is adjusted to reflect, in the profit and loss account, the changes in fair value of the hedged item attributable to the hedged risk; this applies even if the hedged item should be otherwise measured. When derivatives hedge the exposure to variability in cash flows of the hedged itemitems (cash flow hedge, e.g. hedging the variability in the cash flows of assets/liabilities as a result of the fluctuations of exchange rate), the effective changes in the fair value of the derivatives that are designated as effective hedging instruments, are initially recognizedrecognised in the equity reserve
related to other comprehensive income and then reclassified to the profit and loss account in the same period during which the hedged transaction affects the profit and loss account. If a hedged forecast transaction subsequently results in the recognition of a non-financial asset or a non-financial liability, the accumulated changes in fair value of hedging derivatives, recognised in equity, are included directly in the carrying amount of the hedged non-financial asset/liability (commonly referred to as a “basis adjustment”). The changes in the fair value of derivatives that are not designated as effective hedging instruments, including any ineffective portion of changes in fair value of hedging derivatives, are recognizedrecognised in the profit and loss account. In particular, the changes in the fair value of non-hedging derivatives on interest rates and exchange rates are recognizedrecognised in the profit and loss account line item “Finance income (expense)”; conversely, the changes in the fair value of non-hedging derivatives on commodities are recognizedrecognised in the profit and loss account line item “Other operating (expense) income”. Embedded derivatives Derivatives embedded in financial assets are not accounted for separately; in such circumstances, the entire hybrid instrumentsinstrument is classified depending on the contractual cash flow characteristics of the financial instrument and the business model for managing it (see the accounting policy for “Financial assets”). Derivatives embedded in financial liabilities and/or non-financial assets are separated from the host contract and accounted for as a derivative if the hybrid instruments are not measured at fair value with changes in fair value recognized in the profit and loss account and ifif: (i) the economic characteristics and risks of the embedded derivativesderivative are not closely related to thosethe economic characteristics and risks of the host contracts. The entitycontract; (ii) a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative; and (iii) the entire hybrid contract is not measured at FVTPL.
Eni assesses the existence of embedded derivatives to be separated when it becomes party to the contract and, afterwards, when a change in the terms of the contract that modifies its cash flows occurs. Contracts to buy or sell commodities entered into and continuecontinued to be held for the purpose of their receipt or delivery in accordance with the Group’s expected purchase, sale or usage requirements are recognizedrecognised on an accrual basis (the so-called normal sale and normal purchase exemption or own use exemption). Offsetting of financial assets and liabilities Financial assets and liabilities are set off inon the balance sheet if the Group currently has a legally enforceable right to set off and intends to settle on a net basis (or to realizerealise the asset and settle the liability simultaneously).
Derecognition of financial assets and liabilities Transferred financial assets are derecognizedderecognised when the contractual rights to receive the cash flows from the financial assets expire or are realized, expired or transferred.transferred to another party. Financial liabilities are derecognizedderecognised when they are extinguished, or when the obligation specified in the contract is discharged, cancelled or expired. Cash and cash equivalents Cash and cash equivalents include cash on hand, demand deposits, as well as financial assets originally due, generally, within 90 days, readily convertible to known amount of cash and subject to an insignificant risk of changes in value. Provisions, contingent assetsliabilities and liabilitiescontingent assets A provision is a liability of uncertain timing or amount aton the balance sheet date. Provisions are recognizedrecognised when: (i) there is a present obligation, legal or constructive, as a result of a past event; (ii) it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and (iii) the amount of the obligation can be reliably estimated. The amount recognizedrecognised as a provision is the best estimate of the expenditure required to settle the present obligation or to transfer it to third parties at the balance sheet date. The amount recognizedrecognised for onerous contracts is the lower of the cost necessary to fulfill the obligations, net of expected economic benefits deriving from the contracts, and any compensation or penalties arising from failure to fulfill these obligations. Where the effect of the time value is material, and the payment date of the obligations can be reasonably estimated, provisions to be accrued
are the present value of the expenditures expected to be required to settle the obligation at a discount rate that reflects the Company’s average borrowing rate taking into account the risks associated with the obligation. The increase in the provision due to the passage of time is recognizedrecognised as “Finance income (expense)”. Where an obligation exists for an item of property, plant and equipment (e.g. site dismantling and restoration), the provision is recognized together with a corresponding amount as part of the related item of property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the same rate as the rest of the asset.
A provision for restructuring costs is recognizedrecognised only when the Company has a detailed formal plan for the restructuring and has raised a valid expectation in the affected parties that it will carry out the restructuring. Provisions are periodically reviewed and adjusted to reflect changes in the estimates of costs, timing and discount rates. Changes in provisions are recognizedrecognised in the same profit and loss account line item where the original provision was charged, or, when the liability regards tangible assets (e.g. site dismantling and restoration), changes in the provision are recognized with a corresponding entry to the assets to which they refer, to the extent of the assets’ carrying amounts; any excess amount is recognized in the profit and loss account.charged. Contingent liabilities are disclosed as follows:are: (i) possible but not probable obligations arising from past events, whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company; or (ii) present obligations arising from past events, whose amount cannot be reliably measured or whose settlement will probably not result in an outflow of resources embodying economic benefits. Contingent liabilities are not recognised in the financial statements, but are disclosed. Contingent assets, that are possible assets arising from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the Company, are not recognizedrecognised unless the realizationrealisation of economic benefits is virtually certain. Contingent assets are disclosed when an inflow of economic benefits is probable. Contingent assets are assessed periodically to ensure that developments are appropriately reflected in the financial statements; if it has become virtually certain that an inflow of economic benefits will arise, the asset and the related income are recognizedrecognised in the financial statements of the period in which the change occurs. Decommissioning and restoration liabilities Liabilities for decommissioning and restoration costs are recognized, together with a corresponding amount as part of the related property, plant and equipment, when the Group has a legal or constructive obligation and when a reliable estimate can be made.27 Considering the long time span between the recognition of the obligation and its settlement, the amount recognised is the present value of the future expenditures expected to be required to settle the obligation. The increase in the provision due to the unwinding of the discount is recognised as “Finance income (expense)”. Such liabilities are reviewed regularly to take into account the changes in the expected costs to be incurred, contractual obligations, regulatory requirements and practices in force in the countries where the tangible assets are located. The effects of any changes in the estimate of the liability are recognised generally as an adjustment to the carrying amount of the related property, plant and equipment; however, if the resulting decrease in the liability exceeds the carrying amount of the related asset, the excess is recognised in the profit and loss account. Significant accounting estimates and judgements: decommissioning and restoration liabilities, environmental liabilities and other provisions The Group holds provisions for dismantling and removing items of property, plant and equipment, and restoring land or seabed at the end of the oil and gas production activity. Estimating obligations to dismantle, remove and restore items of property, plant and equipment is complex. It requires management 27
These liabilities relate essentially to the Exploration & Production segment’s assets. The decommissioning and restoration liabilities associated with the Refining & Marketing and Chemical and Gas & Power segments’ assets are generally not recognised, as the obligations cannot be reliably estimated, given their indeterminate settlement dates. In this regard, Eni performs periodic reviews of Refining & Marketing and Chemical and Gas & Power segments’ tangible assets for any changes in facts and circumstances that might require recognition of a decommissioning and restoration liability.
to make estimates and judgements with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations. The discount rate used to determine the provision and the timing of future cash outflows, as well as any related update, are based on complex managerial judgements. As other oil and gas companies, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil and gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental liabilities are recognised when it becomes probable that an outflow of resources will be required to settle the obligation and such obligation can be reliably estimated.28 Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provisions already recognised, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements. In addition to environmental and decommissioning and restoration liabilities, Eni recognises provisions primarily related to legal and trade proceedings. These provisions are estimated on the basis of complex managerial judgements related to the amounts to be recognised and the timing of future cash outflows. After the initial recognition, provisions are periodically reviewed and adjusted to reflect the current best estimate. Employee benefits Employee benefits are considerations given by the Group in exchange for service rendered by employees or for the termination of employment. Post-employment benefit plans, including informal arrangements, are classified as either defined contribution plans or defined benefit plans depending on the economic substance of the plan as derived from its principal terms and conditions. Under defined contribution plans, the Company’s obligation, which consists in making payments to the State or to a trust or a fund, is determined on the basis of contributions due.
The liabilities related to defined benefit plans, net of any plan assets, are determined on the basis of actuarial assumptions and charged on an accrual basis during the employment period required to obtain the benefits. Net interest includes the return on plan assets and the interestsinterest cost to be recognizedrecognised in the profit and loss account. Net interest is measured by applying to the liability, net of any plan assets, the discount rate used to calculate the present value of the liability; net interest of defined benefit plans is recognizedrecognised in “Finance income (expense)”. Re-measurementsRemeasurements of the net defined benefit liability, comprising actuarial gains and losses, resulting from changes in the actuarial assumptions used or from changes arising from experience adjustments, and the return on plan assets excluding amounts included in net interest, are recognizedrecognised within the statement of comprehensive income. Re-measurementsRemeasurements of the net defined benefit liability, recognized in the equity reserve related torecognised within other comprehensive income, are not reclassified subsequently to the profit and loss accountaccount.
28
With reference to the environmental liabilities assumed, the expected operating costs to be incurred for managing groundwater treatment plants are not included in the estimates of environmental liabilities because it is not possible to reliably define a subsequent period.time horizon within which the operations of the plant will be terminated. In this regard, Eni performs periodic reviews for any changes in facts and circumstances, including changes in regulatory framework and technology, that might require the recognition of the environmental liability.
Obligations for long-term benefits are determined by adopting actuarial assumptions. The effects of re-measurementsremeasurements are taken to profit and loss account in their entirety. Share-based payments The line item “Payroll and related costs” includes the cost of the share-based incentive plan, consistent with its actual remunerative nature.29 The cost of the share-based incentive plan is measured by reference to the fair value of the equity instruments granted and the estimate of the number of shares that eventually vest; the cost is recognised on an accrual basis pro rata temporis over the vesting period, that is the period between the grant date and the settlement date. The fair value of the shares underlying the incentive plan is measured at the grant date, taking into account the estimate of achievement of market conditions (e.g. Total Shareholder Return), and is not adjusted in subsequent periods; when the achievement is linked also to non-market conditions, the number of shares expected to vest is adjusted during the vesting period to reflect the updated estimate of these conditions. If, at the end of the vesting period, the incentive plan does not vest because of failure to satisfy the performance conditions, the portion of cost related to market conditions is not reversed to the profit and loss account. Significant accounting estimates and judgements: employee benefits and share-based payments Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, mortality rates, estimated retirement dates and medical cost trends. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates are based on the market yields on high quality corporate bonds (or, in the absence of a deep market of these bonds, on the market yields on government bonds) and on the expected inflation rates in the reference currency area; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilisation, changes in health status of the participants and the contributions paid to health funds; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved. Differences in the amount of the net defined benefit liability (asset), deriving from the remeasurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. Similar to the approach followed for the fair value measurement of financial instruments, the fair value of the shares underlying the incentive plans is measured by using complex valuation techniques and identifying, through structured judgements, the assumptions to be adopted. Treasury shares Treasury shares, including shares held to meet the future requirements of the share-based incentive plans, are recognizedrecognised as deductions from equity at cost. Any gain or loss resulting from subsequent sales is recognizedrecognised in equity. RevenuesRevenue from contracts with customers
Revenue from contracts with customers is recognised on the basis of the following five steps: (i) identifying the contract with the customer; (ii) identifying the performance obligations, that are promises in a contract to transfer goods and/or services to a customer; (iii) determining the transaction price; (iv) allocating the transaction price to each performance obligation on the basis of the relative stand-alone selling prices of each good or service; and costs Revenues from the sale of products and the rendering of services are recognized(v) recognising revenue when the significant risks and rewards of ownership have been(or as) a performance obligation is satisfied, that is when a promised good or service is transferred to a customer. A promised good or service is transferred when (or as) the customer or when the transactionobtains control of it. Control can be consideredtransferred over time or at a
29
The current share-based incentive plan, to be settled andby treasury shares, was approved by the associatedshareholders’ meeting held on April 13, 2017.
point in time. With reference to the most important products sold by Eni, revenue can be reliably measured. In particular, revenues are recognized for the sale of:is generally recognised for: •
crude oil, generally upon shipment; •
natural gas and electricity, upon delivery to the customer; •
petroleum products sold to retail distribution networks, generally upon delivery to the service stations, whereas all other sales of petroleum products are generally recognizedrecognised upon shipment; and •
chemical products and other products, generally upon shipment. Revenues are recognized upon shipment when, at that date, significant risks are transferred to the buyer.
RevenuesRevenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers are recognizedis recognised on the basis of Eni’s net working interest in those properties (entitlementthe quantities actually lifted and sold (sales method). Higher/lower production volume withdrawn as compared to Eni’s net working interest volume is recognized at current prices at; costs are recognised on the balance sheet date.
Revenues arising from rendering of services are recognized by reference to the stage of completion at the endbasis of the reporting period, provided that: (i) the amount of revenues can be measured reliably; (ii) itquantities actually sold.30
Revenue is probable that the economic benefits associated with the transaction will flow to the entity; (iii) the stage of completion of the transaction at the end of the reporting period can be measured reliably; and (iv) the related costs can be measured reliably. When the outcome of the transaction involving the rendering of services cannot be estimated reliably, revenue is recognized only to the extent of the expenses recognized that are recoverable. Revenues are measured at the fair value of the consideration received or receivable net of returns, discounts, rebates, bonuses and related taxes. Amounts collected orto which the Company expects to be entitled in exchange for transferring promised goods and/or services to a customer, excluding amounts collected on behalf of third parties are not revenues.
Award credits, related to customer loyalty programs, are recognized as a separately identifiable componentparties. In determining the transaction price, the promised amount of consideration is adjusted for the effects of the sales transaction in which they are granted. Therefore,time value of money if the timing of payments agreed to by the parties to the contract provides the customer or the entity with a significant benefit of financing the transfer of goods or services to the customer. The promised amount of consideration is not adjusted for the effect of the significant financing component if, at contract inception, it is expected that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less. If the consideration allocatedpromised in a contract includes a variable amount, the Company estimates the amount of consideration to which it will be entitled in exchange for transferring the promised goods and/or services to a customer; in particular, the amount of consideration can vary because of discounts, refunds, incentives, price concessions, performance bonuses, penalties or if the price is contingent on the occurrence or non-occurrence of future events.
If, in a contract, the Company grants a customer the option to acquire additional goods or services for free or at a discount (e.g. sales incentives, customer award points, etc.), this option gives rise to a separate performance obligation in the contract only if the option provides a material right to the award credits, measured by reference to their fair value, represents deferred revenues andcustomer that it is recognized in
the line item “Other liabilities”. The deferred revenues are reversed in the profit and loss account at the redemption or forfeiture of the award credits by customers.would not receive without entering into that contract. When goods or services are exchanged for goods or services thatwhich are of a similar nature and value, the exchange is not regarded as a transaction which generates revenue.
Significant accounting estimates and judgements: revenue from contracts with customers Revenue from sales of electricity and gas to retail customers includes amount accrued for electricity and gas supplied between the date of the last invoiced meter reading (actual or estimated) of volumes consumed and the end of the year. These estimates consider mainly information provided by the grid managers about the volumes allocated among the customers of the secondary distribution network, about the actual and estimated volumes consumed by customers. Therefore, revenue is accrued as a revenue.result of a complex estimate based on the volumes distributed and allocated, communicated by third parties, likely to be adjusted, according to applicable regulations, within the fifth year following the one in which they are accrued. Considering the contractual obligations on the supply delivery points, revenue from sales of electricity and gas to retail customers includes costs for transportation and dispatching and in these cases the gross amount of consideration to which the Company is entitled is recognised. 30
In accordance with the accounting policy adopted until 2017 (entitlement method, before applying IFRS 15), revenue from crude oil and natural gas production from properties in which Eni has an interest together with other producers were recognised on the basis of Eni’s net working interest in those properties. On the balance sheet, lifting imbalances were recognised respectively as payables and receivables and measured at current prices at the balance sheet date.
Costs Costs are recognizedrecognised when the related goods and services are sold or consumed during the year, when they are allocated on a systematic basis or when their future economic benefits cannot be identified. Costs associated with emission quotas, incurred to meet the compliance requirements (e.g. Emission Trading Scheme) determined on the basis of the market prices, are recognizedrecognised in relation to the amountamounts of the carbon dioxide emissions that exceed free allowances. Costs related to the purchase of the emission rights that exceed the amount necessary to meet regulatory obligations are recognizedrecognised as intangible assets net of any imbalance between the amount of actual emissions and the free allowances. Revenuesassets. Revenue related to emission quotas are recognizedis recognised when they are sold and, if applicable, purchased emission rights are considered the first to be sold. Monetary receivables granted to replace the free award emission rights are recognizedrecognised as a contra to the line item “Other income and revenues”. The costs incurred on a voluntary basis for the acquisition or production of forestry certificates, also taking into account the absence of an active market, are recognised in the profit and loss account when incurred. Operating lease payments are recognized as an expense over the lease term. The costs for the acquisition of new knowledge or discoveries, the study of products or alternative processes, new techniques or models, the planning and construction of prototypes or, in any case, costs incurred for other scientific research activities or technological development, which cannot be capitalizedcapitalised (see abovealso the accounting policy for “Intangible assets”), are included in the profit and loss account when they are incurred.
Grants not related to assets are recognized in the profit and loss account on an accrual basis matching the related costs when incurred.
Exchange differences Revenues and costs associated with transactions in foreign currencies are translated into the functional currency by applying the exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the spot exchange rate on the balance sheet date and any resulting exchange differences are included in the profit and loss account.account within “Finance income (expense)” or, if designated as hedging instruments for the foreign currency risk, in the same line item in which the economic effects of the hedged item are recognised. Non-monetary assets and liabilities denominated in foreign currencies, measured at cost, are not retranslated subsequent to initial recognition. Non-monetary items measured at fair value, recoverable amount or net realizablerealisable value are retranslated using the exchange rate at the date when the value is determined. Dividends Dividends are recognized atrecognised when the dateright to receive payment of the generaldividend is established. Dividends and interim dividends to owners are shown as changes in equity when the dividends are declared by, respectively, the shareholders’ meeting in which they were declared, except whenand the saleBoard of shares before the ex-dividend date is certain.Directors. Income taxes Current income taxes are determined on the basis of estimated taxable income. The estimated liability is included in “Income taxes payable”.profit. Current income tax assets and liabilities are measured at the amount expected to be paid to (recovered from) the taxation authorities, using tax rates and the tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred tax assets and liabilities are recognizedrecognised for temporary differences arising between the carrying amounts of the assets and liabilities and their tax bases, based on tax rates and tax laws that are expected to apply to the period when the asset is realised or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted for future years.by the end of the reporting period. Deferred tax assets are recognizedrecognised when their recoverability is considered probable; in particular, deferred tax assets are recoverableprobable, i.e. when it is probable that sufficient taxable profit will be available in the same year as the reversal of the deductible temporary difference. Similarly, deferred tax assets for the carry-forward of unused tax credits and unused tax losses are recognizedrecognised to the extent that their recoverability is probable. IncomeThe carrying amount of the deferred tax assets is reviewed, at least, on an annual basis. If there is uncertainty over income tax treatments, if the company concludes it is probable that arethe taxation authority will accept an uncertain tax treatment, it determines the (current and/or deferred) income taxes to be recognised in the amount financial statements consistent with the tax treatment used or planned
to be recovered are recognizedused in accordanceits income tax filings. Conversely, if the company concludes it is not probable that the taxation authority will accept an uncertain tax treatment, the company reflects the effect of uncertainty in determining the (current and/or deferred) income taxes to be recognised in the probable threshold.financial statements. Relating to the taxable temporary differences associated with investments in subsidiaries and associates, and interests in joint arrangements, the related deferred tax liabilities are not recognizedrecognised if the investor is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. Deferred tax assets and liabilities are
included in presented within non-current assets and liabilities and are offset at a single entity level if related to off-settable taxes. The balance of the offset, if positive, is recognizedrecognised in the line item “Deferred tax assets”; and, if negative, in the line item “Deferred tax liabilities”. When the results of transactions are recognizedrecognised directly in shareholders’ equity, the related current and deferred taxes are also charged to the shareholders’ equity.
Significant accounting estimates and judgements: income taxes The computation of income taxes involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. Although Eni aims to maintain a relationship with the taxation authorities characterised by transparency, dialogue and cooperation (e.g. by not using aggressive tax planning and by using, if available, procedures intended to eliminate or reduce tax litigations), there can be no assurance that there will not be a tax litigation with the taxation authorities where the legislation could be open to more than one interpretation. The resolution of tax disputes, through negotiations with relevant taxation authorities or through litigation, could take several years to complete. The estimate of liabilities related to uncertain tax treatments requires complex judgements by management. After the initial recognition, these liabilities are periodically reviewed for any changes in facts and circumstances. Moreover, management makes complex judgements regarding the assessment of the recoverability of deferred tax assets, related both to deductible temporary differences and unused tax losses, which requires estimates and evaluations about the amount and the timing of future taxable profits. Assets held for sale and discontinued operations Non-current assets and current and non-current assets included within disposal groups, are classified as held for sale if their carrying amountamounts will be recovered principally through a sale transaction rather than through their continuing use. For this to be the case,This condition is regarded as met only when the sale must beis highly probable and the asset or the disposal group must beis available for immediate sale in its present condition. When there is a sale plan involving loss of control of a subsidiary, all the assets and liabilities of that subsidiary are classified as held for sale, regardless of whether a non-controlling interest in its former subsidiary will be retained after the sale. The classification of non-current assets (or disposal groups) as held for sale requires the management to perform subjective judgments based on assumptions deemed reasonable in consideration of the information available at the time. Non-current assets held for sale, current and non-current assets included within disposal groups that have been classified as held for sale and the liabilities directly associated with them are recognized inrecognised on the balance sheet separately from other assets and liabilities. Immediately before the initial classification of a non-current asset and/or a disposal group as held for sale, the non-current asset and/or the assets and liabilities ofin the disposal group are measured in accordance with applicable IFRSs. Subsequently, non-current assets held for sale are not depreciated or amortised and they are measured at the lower of the fair value less costs to sell and their carrying amount. After the classification as held for sale ofIf an equity-accounted investment, the investment, or thea portion of thethat investment that meets the criteria to be classified as held for sale, it is no longer accounted for using the equity method; therefore, in this case,method and it is measured at the lower of its carrying amount ofat the investment in accordance withdate the equity method represents the carrying amount for the measurement as non-current asset held for sale.is discontinued, and its fair value less costs to sell. Any retained portion of the equity-accounted investment that has not been classified as held for sale is accounted for using the equity method until disposal of the portion that is classified as held for sale takes place. After the disposal, takes place, any retained investmentinterest in the investee is measured in accordance with the measurement criteria indicated in the accounting policy for “Non-current financial assets — Investments”“Investments in equity instruments”, unless the retained interest continues to be an equity-accounted investment. Any difference between the carrying amount of the non-current assets and the fair value less costs to sell is taken to the profit and loss account as an impairment loss; any subsequent reversal is recognizedrecognised up to the cumulative impairment losses, including those recognizedrecognised prior to qualification of the asset as held
for sale. Non-current assets and current and non-current assets included within disposal groups, classified as held for sale and disposal groups are considered a discontinued operation if they, alternatively: (i) represent a separate major line of business or geographical area of operations; (ii) are part of a disposal program of a separate major line of business or geographical area of operations; or (iii) are a subsidiary acquired exclusively with a view to resale. The results of discontinued operations, as well as any gain or loss recognizedrecognised on the disposal, are indicated in a separate line item of the profit and loss account, net of the related tax effects; the economic figures of discontinued operations are indicated also for prior periods presented in the financial statements. If events or circumstances occur that no longer allow to classify a non-current asset or a disposal group as held for sale, the non-current asset or the disposal group is reclassified into the original line items of the balance sheet and measured at the lower of: (i) its carrying amount at the date of classification as held for sale adjusted for any depreciation, amortisations,amortisation impairment losses and reversals that would have been recognizedrecognised had the asset or disposal group not been classified as held for sale, and (ii) its recoverable amount at the date of the subsequent decision not to sell. If the interruption of a plan of sale concerns a subsidiary, joint operation, joint venture, associate, or a portion of an interest in a joint venture or an associate, financial statements for the period since classification as held for sale are amended. If a discontinued operation is reclassified as held for use, its results previously presented in the separate line item of the profit and loss account are reclassified and included in income from continuing operations for all periods presented.
Fair value measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (not in a forced liquidation or a distress sale) at the measurement
date (exit price). Fair value measurement is based on the market conditions existing at the measurement date and on the assumptions of market participants (market-based measurement). A fair value measurement assumes that the transaction to sell the asset or transfer the liability takes place in the principal market for the asset or liability, or in the absence of a principal market, in the most advantageous market to which the entity has access, independently from the entity’s intention to sell the asset or transfer the liability to be measured. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. Highest and best use is determined from the perspective of market participants, even if the entity intends a different use; an entity’s current use of a non-financial asset is presumed to be its highest and best use, unless market or other factors suggest that a different use by market participants would maximizemaximise the value of the asset. The fair value of a liability, both financial and non-financial, or of athe Company’s own equity instrument, in the absence of a quoted price, is measured from the perspective of a market participant that holds the identical item as an asset at the measurement date. The fair value of financial instruments takes into account the counterparty’s credit risk for a financial asset (Credit Valuation Adjustment, CVA) and the entity’sCompany’s own credit risk for a financial liability (Debit Valuation Adjustment, DVA). In the absence of available market quotation, fair value is measured by using valuation techniques that are appropriate in the circumstances, maximizingmaximising the use of relevant observable inputs and minimizingminimising the use of unobservable inputs. 4 FinancialSignificant accounting estimates and judgements: fair value
Fair value measurement, although based on the best available information and on the use of appropriate valuation techniques, is inherently uncertain, requires the use of professional judgement and could result in expected values other than the actual ones. 2 Primary financial statements1731 Assets and liabilities on the balance sheet are classified as current and non-current. Items onin the profit and loss account are presented by naturenature.1832. Assets and liabilities are classified as current when: (i) they are expected to be realized/realised/settled in the entity’s normal operating cycle or within twelve months after the 31
The impacts on the primary financial statements arising from the adoption, starting from January 1, 2019, of the new IFRSs, as well as the other changes in the primary financial statements, are described in note 3 — Changes in accounting policies. 32
Further information about classification of financial instruments is provided in note 27 — Guarantees, commitments and risks — Other information about financial instruments.
balance sheet date; (ii) they are cash or cash equivalents unless they are restricted from being exchanged or used to settle a liability for at least twelve months after the balance sheet date; or (iii) they are held primarily for the purpose of trading. Derivative financial instruments held for trading are classified as current, apart from their maturity date. Non hedging derivative financial instruments, which are entered into to manage risk exposures but do not satisfy the formal requirements to be considered as hedging, and hedging derivative financial instruments are classified as current when they are expected to be realized/realised/settled within twelve months after the balance sheet date; on the contrary they are classified as non-current. The statement of comprehensive income (loss) shows net profit integrated with income and expenses that are recognizednot recognised directly in equitythe profit and loss account according to IFRS.IFRSs. The statement of changes in shareholders’ equity includes the total comprehensive income (loss) for the year, transactions with shareholders in their capacity as shareholders and other changes in shareholders’ equity. The statement of cash flows is presented using the indirect method, whereby net profit (loss) is adjusted for the effects of non-cash transactions. 53 Changes in accounting policies
In accordance with IAS 8 “Accounting Policies, Changes in Accounting Estimates and Errors”, the adoption of SEM represents a voluntary change in accounting policies, in order to increase the
(17)
The financial statements are the same presented in the last Annual Report on Form 20-F, with the exception of: (i) the profit and loss account and the statement of cash flows that include the new line item “Write-off” which presents the loss from the derecognition of property, plant and equipment or intangible assets. The presentation of this new line item is regarded as relevant by management due to the adoption, on a voluntary basis, of the recognition and measurement criteria for the costs related to the oil and gas activities in accordance with the Successful Efforts Method (SEM), as described in note 5 “Changes in accounting policies”; (ii) the profit and loss account that include the new line item “Net impairment losses (reversals)”, which includes the net balance of impairment losses/reversals of tangible and intangible assets. The presentation of this new line item is regarded as relevant by management in order to avoid that the compensation between depreciations/amortizations and net impairment reversals would provide a misleading representation to users of financial statements.
(18)
Further information on financial instruments as classified in accordance with IFRS is provided in note 38 - Guarantees, commitments and risks — Other information about financial instruments.
comparability with the companies operating in the same industry and provide a reliable and more relevant financial information. SEM has been applied retrospectively; therefore, comparative amounts have been restated. Under the previous accounting policy: (i) the costs for the acquisition of exploration rights were amortized on a straight-line basis over the exploration period as contractually established; (ii) the costs associated with exploration activities were initially capitalized, in order to reflect their nature as capital expenditure, and fully amortized as incurred.
Furthermore, because of the withdrawal of Versalis sale plan, the criteria for its classification as disposal group and discontinued operations are no longer met; therefore the 2014 and 2015 comparative figures have been amended as if Versalis had never been classified as held for sale. The financial statements line items affected by the above-mentioned changes are presented below.
(€ million) | | | January 1, 2014 | | Selected line items only | | | As reported | | | Adoption of the SEM | | | As restated | | Non-current assets | | | | | 85,584 | | | | | | 4,085 | | | | | | 89,669 | | | - of which property, plant and equipment | | | | | 63,763 | | | | | | 3,524 | | | | | | 67,287 | | | - of which intagible assets | | | | | 3,876 | | | | | | 860 | | | | | | 4,736 | | | Non-current liabilities | | | | | 44,283 | | | | | | 1,081 | | | | | | 45,364 | | | Total Shareholders’ Equity | | | | | 61,049 | | | | | | 3,004 | | | | | | 64,053 | | |
(€ million) | | | January 1, 2015 | | Selected line items only | | | As reported | | | Adoption of the SEM | | | As restated | | Non-current assets | | | | | 91,344 | | | | | | 4,159 | | | | | | 95,503 | | | - of which property, plant and equipment | | | | | 71,962 | | | | | | 4,029 | | | | | | 75,991 | | | - of which intagible assets | | | | | 3,645 | | | | | | 775 | | | | | | 4,420 | | | Non-current liabilities | | | | | 46,659 | | | | | | 727 | | | | | | 47,386 | | | Total Shareholders’ Equity | | | | | 62,209 | | | | | | 3,432 | | | | | | 65,641 | | | |
(€ million) | | | December 31, 2015 | | Selected line items only | | | As reported | | | Restatement of Versalis in continuing operations | | | Adoption of the SEM | | | As restated | | Current assets | | | | | 39,982 | | | | | | 1,388 | | | | | | | | | | | | 41,370 | | | Non-current assets | | | | | 77,294 | | | | | | 889 | | | | | | 3,915 | | | | | | 82,098 | | | - of which property, plant and equipment | | | | | 63,795 | | | | | | 323 | | | | | | 3,887 | | | | | | 68,005 | | | - of which intagible assets | | | | | 2,433 | | | | | | 55 | | | | | | 546 | | | | | | 3,034 | | | Discontinued operations and assets held for sale | | | | | 17,516 | | | | | | (1,983) | | | | | | | | | | | | 15,533 | | | Current liabilities | | | | | 29,565 | | | | | | 370 | | | | | | | | | | | | 29,935 | | | Non-current liabilities | | | | | 44,488 | | | | | | 215 | | | | | | 469 | | | | | | 45,172 | | | Discontinued operations and liabilities directly associated with assets held for sale | | | | | 7,070 | | | | | | (585) | | | | | | | | | | | | 6,485 | | | Total Shareholders’ Equity | | | | | 53,669 | | | | | | 294 | | | | | | 3,446 | | | | | | 57,409 | | | |
(€ million) | | | 2014 | | Selected line items only | | | As reported | | | Restatement of Versalis in continuing operations | | | Adoption of the SEM | | | As restated | | Revenue | | | | | 94,226 | | | | | | 5,078 | | | | | | (7) | | | | | | 99,297 | | | Operating expense | | | | | 73,930 | | | | | | 3,106 | | | | | | 368 | | | | | | 77,404 | | | Depreciation, amortization | | | | | 9,134 | | | | | | 99 | | | | | | (1,557) | | | | | | 7,676 | | | Net impairment (reversal) | | | | | 1,013 | | | | | | 96 | | | | | | 161 | | | | | | 1,270 | | | Write-off of tangible and intangible assets | | | | | 137 | | | | | | 1 | | | | | | 1,060 | | | | | | 1,198 | | | Operating profit (loss) | | | | | 7,585 | | | | | | 1,419 | | | | | | (39) | | | | | | 8,965 | | | Finance income and expense | | | | | (1,181) | | | | | | | | | | | | 14 | | | | | | (1,167) | | | Income (expense) from investments | | | | | 469 | | | | | | (3) | | | | | | 10 | | | | | | 476 | | | Income taxes | | | | | 6,681 | | | | | | (191) | | | | | | (24) | | | | | | 6,466 | | | Net profit – continuing operations | | | | | 192 | | | | | | 1,607 | | | | | | 9 | | | | | | 1,808 | | | Net profit – discontinued operations | | | | | 658 | | | | | | (1,607) | | | | | | | | | | | | (949) | | | Net profit | | | | | 850 | | | | | | | | | | | | 9 | | | | | | 859 | | | Net profit attributable to Eni | | | | | 1,291 | | | | | | | | | | | | 12 | | | | | | 1,303 | | | - attributable to Eni in continuing operations | | | | | 101 | | | | | | 1,607 | | | | | | 12 | | | | | | 1,720 | | | - attributable to Eni in discontinued operations | | | | | 1,190 | | | | | | (1,607) | | | | | | | | | | | | (417) | | | Net cash provided by operating activities | | | | | 15,110 | | | | | | | | | | | | (368) | | | | | | 14,742 | | | Net cash used in investing activities | | | | | (8,943) | | | | | | | | | | | | 368 | | | | | | (8,575) | | | Net cash used in financing activities | | | | | (5,062) | | | | | | | | | | | | | | | | | | (5,062) | | | Net cash flow for the period | | | | | 1,183 | | | | | | | | | | | | | | | | | | 1,183 | | | |
(€ million) | | | 2015 | | Selected line items only | | | As reported | | | Restatement of Versalis in continuing operations | | | Adoption of the SEM | | | As restated | | Revenue | | | | | 68,945 | | | | | | 4,603 | | | | | | (10) | | | | | | 73,538 | | | Operating expense | | | | | 53,958 | | | | | | 2,636 | | | | | | 254 | | | | | | 56,848 | | | Depreciation, amortization | | | | | 9,654 | | | | | | 108 | | | | | | (822) | | | | | | 8,940 | | | Net impairment (reversal) | | | | | 4,826 | | | | | | 998 | | | | | | 710 | | | | | | 6,534 | | | Write-off of tangible and intangible assets | | | | | 25 | | | | | | | | | | | | 663 | | | | | | 688 | | | Operating profit (loss) | | | | | (2,781) | | | | | | 520 | | | | | | (815) | | | | | | (3,076) | | | Finance income and expense | | | | | (1,323) | | | | | | 3 | | | | | | 14 | | | | | | (1,306) | | | Income (expense) from investments | | | | | 124 | | | | | | (20) | | | | | | 1 | | | | | | 105 | | | Income taxes | | | | | 3,147 | | | | | | 486 | | | | | | (511) | | | | | | 3,122 | | | Net profit - continuing operations | | | | | (7,127) | | | | | | 17 | | | | | | (289) | | | | | | (7,399) | | | Net profit - discontinued operations | | | | | (2,251) | | | | | | 277 | | | | | | | | | | | | (1,974) | | | Net profit | | | | | (9,378) | | | | | | 294 | | | | | | (289) | | | | | | (9,373) | | | Net profit attributable to Eni | | | | | (8,783) | | | | | | 294 | | | | | | (289) | | | | | | (8,778) | | | - attributable to Eni in continuing operations | | | | | (7,680) | | | | | | 17 | | | | | | (289) | | | | | | (7,952) | | | - attributable to Eni in discontinued operations | | | | | (1,103) | | | | | | 277 | | | | | | | | | | | | (826) | | | Net cash provided by operating activities | | | | | 11,903 | | | | | | | | | | | | (254) | | | | | | 11,649 | | | Net cash used in investing activities | | | | | (11,177) | | | | | | | | | | | | 254 | | | | | | (10,923) | | | Net cash used in financing activities | | | | | (1,351) | | | | | | | | | | | | | | | | | | (1,351) | | | Net cash flow for the period | | | | | (1,414) | | | | | | 9 | | | | | | | | | | | | (1,405) | | | |
The amendments to IFRSs effectiveStarting from January 1, 2016 did not have a significant impact on the financial statements.
6 Significant accounting estimates or judgements
The preparation of the Consolidated Financial Statements requires the use of estimates and assumptions that affect the assets, liabilities, revenues and expenses recognized in the financial statements, as well as amounts included in the notes thereto, including disclosure of contingent assets and liabilities. Estimates made are based on complex or subjective judgments and past experience of other assumptions deemed reasonable in consideration of the information available at the time. The accounting policies and
areas that require the most significant judgments and estimates to be used in the preparation of the Consolidated Financial Statements are in relation to the accounting for oil and natural gas activities, specifically in the determination of proved and proved developed reserves, impairment of fixed assets, intangible assets and goodwill, decommissioning and restoration liabilities, business combinations, employee benefits and recognition of environmental liabilities. Although the Company uses its best estimates and judgments, actual results could differ from the estimates and assumptions used. The accounting estimates and judgements relevant for the preparation of the Consolidated Financial Statement are described below.
Oil and natural gas activities
Engineering estimates of the Company’s oil&gas reserves are inherently uncertain. Proved reserves are the estimated volumes of crude oil, natural gas and gas condensates, liquids and associated substances which geological and engineering data demonstrate that can be economically producible with reasonable certainty from known reservoirs under existing economic conditions and operating methods. Although there are authoritative guidelines regarding the engineering and geological criteria that must be met before estimated oil&gas reserves can be categorized as “proved”, the accuracy of any reserve estimate depends on the quality of available data, the engineering and geological interpretation of such data and management’s judgment.
The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is made within a year after well completion. The evaluation process of a discovery, which requires performing additional appraisal activities on the potential oil and natural gas field and establishing the optimum development plans, can take longer, in most cases, depending on the complexity of the project and on the size of capital expenditure required. During this period, the costs related to these exploration wells remain suspended on the balance sheet. In any case, all such carried costs are reviewed on at least an annual basis to confirm the continued intent to develop, or otherwise to extract value from the discovery.
Field reserves will be categorized as proved only when all the criteria for attribution of proved status have been met. Initially, all booked reserves are classified as proved undeveloped. Subsequently, volumes are reclassified from proved undeveloped to proved developed as a consequence of development activity. Generally, reserves are booked as proved developed when the first oil or gas is produced. Major development projects typically take one to four years from the time of initial booking to the start of production.2019, Eni reassesses its estimate of proved reserves periodically. The estimated proved reserves of oil and natural gas may be subject to future revision. Upward or downward revision may be made to the initial booking of reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. In particular, changes in oil and natural gas prices could impact the amount of Eni’s proved reserves in regards to the initial estimate and, in the case of production sharing agreements and buy-back contracts, the share of production and reserves to which Eni is entitled. Accordingly, the estimated reserves could be materially different from the quantities of oil and natural gas that ultimately will be recovered. Oil and natural gas reserves have a direct impact on certain amounts reported in the Consolidated Financial Statements. Estimated proved reserves are used in determining depreciation and depletion charges and impairment charges. Depreciation and depletion rates of oil&gas assets using the UOP basis are determined from the ratio between the amount of hydrocarbons extracted in the quarter and proved developed reserves existing at the end of the quarter increased by the amounts extracted during the quarter. Assuming all other variables are held constant, an increase in estimated proved developed reserves for each field decreases depreciation and depletion charge. Conversely, a decrease in estimated proved developed reserves increases depreciation and depletion charge. Estimated proved reserves are affected, inter alia, by the trend of reference oil and gas commodity prices and by the specific legal agreement for the oil&gas activity.
In addition, estimated proved reserves are used to calculate future cash flows from oil&gas properties, which are used to assess any impairment loss. The larger is the volume of estimated reserves, the lower is the likelihood of asset impairment.
Impairment of assets
Assets are impaired when there are events or changes in circumstances that indicate that carrying amounts of the assets are not recoverable. Such impairment indicators include changes in the Group’s
business plans, changes in commodity prices leading to unprofitable performance, a reduced capacity utilization of plants and, for oil&gas properties, significant downward revisions of estimated proved reserve quantities or significant increase of the estimated development costs. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain and complex matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for demand and supply conditions on a global or regional scale. Similar remarks are valid for assessing the physical recoverability of assets recognized in the balance sheet (deferred costs — see also the accounting policy for “Inventories”) related to natural gas volumes not withdrawn under long-term supply contracts with take-or-pay clauses, as well as for assessing the recoverability of deferred tax assets. The amount of an impairment loss is determined by comparing the carrying amount of an asset with its recoverable amount. Recoverable amount of an asset is the higher of an asset’s fair value less costs of disposal and its value in use. The estimate of an asset’s value in use is based on the present value of the future cash flows expected to be derived from continuing use of the asset and, if significant and reasonably determinable, the cash flows expected to be obtained from the disposal of the asset at the end of its useful life after deducting the costs of disposal. The expected future cash flows used for impairment analyses are based on judgmental assessments of future production volumes, prices and costs, considering available information at the date of review and are discounted by using a rate which considers the risks specific to the asset. For oil and natural gas properties, the expected future cash flows are estimated principally based on developed and undeveloped proved reserves including, among other elements, production taxes and the costs to be incurred for the reserves yet to be developed. The estimate of the future amount of production is based on assumptions related to the commodity future prices, lifting and development costs, field decline rates, market demand and other factors. The cash flows associated to oil&gas commodities are estimated on the basis of forward market information, if there is a sufficient liquidity and reliability level, on the consensus of independent specialized analysts and on management’s forecasts about the evolution of the supply and demand fundamentals. The discount rate reflects the current market valuation of the time value of money and of the specific risks of the asset not reflected in the estimate of the future cash flows.
Goodwill and intangible assets with indefinite useful lives are not subject to amortization. The Company tests for impairment such assets on an annual basis and whenever there is any indication that they may be impaired. In particular, goodwill impairment is based on the lowest level (cash-generating unit) to which goodwill can be allocated on a reasonable and consistent basis. A cash-generating unit is the smallest aggregate on which the Company, directly or indirectly, evaluates the return on the capital expenditure. If the recoverable amount of a cash-generating unit, to which goodwill has been allocated, is less than its carrying amount, goodwill allocated to that cash-generating unit is impaired up to that difference; if the carrying amount of goodwill is lower than the amount of the impairment loss, the other assets of the cash-generating unit are impaired pro-rata on the basis of their carrying amounts for the residual difference, up to the recoverable amount of assets with finite useful lives.
Decommissioning and restoration liabilities
The Group holds provisions for dismantling and removing items of property, plant and equipment, and restoring land or seabed at the end of the oil and gas production activity. Estimating obligations to dismantle, remove and restore items of property, plant and equipment is complex. It requires management to make estimates and judgments with respect to removal obligations that will come to term many years into the future and contracts and regulations are often unclear as to what constitutes removal. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known as asset removal technologies and costs constantly evolve in the countries where Eni operates, as do political, environmental, safety and public expectations. The complexity of these estimates is also due to the accounting that requires the initial recognition of the present value of the decommissioning and restoration liabilities as a part of the cost of property, plant and equipment. Then the carrying amount of decommissioning and restoration liabilities is adjusted to reflect the passage of time and any change in the estimates following the modification of amount and timing of future cash flows and discount rates adopted. The discount rate used to determine the provision is based on complex and subjective managerial judgments.
Business combinations
Accounting for business combinations requires the allocation of the purchase price to the identifiable assets and liabilities of the acquired business generally at their fair values. Any positive residual difference is
recognized as goodwill. Any negative residual difference is recognized in the profit and loss account. If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the provisional amounts recognized at the acquisition date are retrospectively adjusted within one year from the acquisition date, to reflect new information obtained about facts and circumstances that existed as of the acquisition date. Management uses all available information to make these fair value measurements and, for major business combinations, engages independent external advisors; the purchase price allocation, that requires, also in consideration of the available information, management to make complex judgments, is also relevant for the application of the equity method.
Environmental liabilities
As other oil&gas companies, Eni is subject to numerous EU, national, regional and local environmental laws and regulations concerning its oil&gas operations, production and other activities. They include legislations that implement international conventions or protocols. Environmental provisions are recognized when it becomes probable that a liability will be incurred and the liability can be reliably estimated. Management, considering the actions already taken, insurance policies obtained to cover environmental risks and provision for risks accrued, does not expect any material adverse effect on Eni’s consolidated results of operations and financial position as a result of such laws and regulations. However, there can be no assurance that there will not be a material adverse impact on Eni’s consolidated results of operations and financial position due to: (i) the possibility of an unknown contamination; (ii) the results of the ongoing surveys and other possible effects of statements required by applicable laws; (iii) the possible effects of future environmental legislations and rules; (iv) the effects of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, against other potentially responsible parties with respect to such litigations and the possible reimbursements.
Employee benefits
Defined benefit plans are evaluated with reference to uncertain events and based upon actuarial assumptions including, among others, discount rates, expected rates of salary increases, mortality rates, estimated retirement dates and medical cost trends. The significant assumptions used to account for defined benefit plans are determined as follows: (i) discount and inflation rates reflect the rates at which benefits could be effectively settled, taking into account the duration of the obligation. Indicators used in selecting the discount rate include market yields on high quality corporate bonds (or, in the absence of a deep market of these bonds, on the market yields on government bonds). The inflation rates reflect market conditions observed in the reference currency area; (ii) the future salary levels of the individual employees are determined including an estimate of future changes attributed to general price levels (consistent with inflation rate assumptions), productivity, seniority and promotion; (iii) healthcare cost trend assumptions reflect an estimate of the actual future changes in the cost of the healthcare related benefits provided to the plan participants and are based on past and current healthcare cost trends, including healthcare inflation, changes in healthcare utilization and changes in health status of the participants; and (iv) demographic assumptions such as mortality, disability and turnover reflect the best estimate of these future events for individual employees involved.
Differences in the amount of the net defined benefit liability (asset), deriving from the re-measurements, comprising, among others, changes in the current actuarial assumptions, differences in the previous actuarial assumptions and what has actually occurred and differences in the return on plan assets, excluding amounts included in net interest, usually occur. Re-measurements are recognized within statement of comprehensive income for defined benefit plans and within the profit and loss account for long-term plans.
Other provisions
In addition to liabilities related to environmental decommissioning and restoration liabilities and employee benefits, Eni recognizes provisions primarily related to legal and tax proceedings. These provisions are estimated on the basis of managerial judgments related to the amounts to recognize and the timing of future cash outflows. After the initial recognition, provisions are periodically reviewed and adjusted to reflect the current best estimate.
Revenues and receivables
Revenues from the sale of electricity and gas to retail customers include amount accrued for electricity and gas supplied between the date of the last meter reading and the end of the year. These estimates consider information provided by the grid managers about the volumes allocated among the customers of the secondary distribution network, about the actual and estimated volumes consumed by customers, as well as they rely on other factors, considered by management, which can impact on them. Therefore accrued revenues derive from complex estimates based on distributed and allocated volumes, communicated by third parties; these revenues may be adjusted, according to the applicable regulations, within the fifth year subsequent the one in which they were accrued.
Complex and/or subjective judgements are required in assessing the recoverability of overdue receivables and determining whether an allowance against those receivables is required. Factors considered include, among others, the credit rating of the counterparty (if available), the amount and timing of anticipated future payments, any collateral held as a security and other credit enhancements, as well as any possible actions that can be taken to mitigate the risk of non-payment.
7 IFRSs not yet adopted
On May 28, 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers” (hereinafter IFRS 15), which sets out the requirements for recognizing and measuring revenues arising from contracts with customers, including construction contracts. In particular, IFRS 15 requires that, to recognize revenue, a company shall apply the following five steps: (i) identify the contract with the customer; (ii) identify the performance obligations (that are promises in a contract to transfer to a customer goods and/or services); (iii) determine the transaction price; (iv) allocate the transaction price to each performance obligation on the basis of the relative standalone selling prices of each good or service promised in the contract; and (v) recognize revenue when a performance obligation is satisfied. Moreover, IFRS 15 includes more disclosure requirements about the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. IFRS 15 shall be applied for annual periods beginning on or after January 1, 2018; IFRS 15 shall be applied retrospectively, by providing for the possibility of recognizing the cumulative effect of initially applying IFRS 15 as an adjustment to the opening balance of equity as January 1, 2018, having regard only to the contracts that are not completed at the date of initial application. Furthermore, on April 12, 2016, the IASB issued the document “Clarifications to IFRS 15 Revenue from Contracts with Customers” (hereinafter clarifications to IFRS 15), which provides clarifications to support implementation of the new standard. The clarifications to IFRS 15 shall be applied for annual periods beginning on or after January 1, 2018.
In 2016, the Group started analytical activities aimed to identify potentially critical issues for each operating segment, to assess the potential effects on the financial statements and verify the need to adjust internal control system over financial reporting. At the current stage of the analysis, the following areas may be affected by the new provisions of the standard: (i) accounting for certain types of agreements with partners within oil&gas projects, considering their different nature from customers; (ii) representation on a gross or net basis of certain types of costs closely related to supplying of goods or services; (iii) multiple-element arrangements; (iv) capitalization of the customer acquisition costs principally in the Gas & Power segment; (v) contracts with options to acquire additional goods/services that provide a material right that customers would not receive without entering into the contracts; (vi) contracts with variable consideration; (vii) licenses of intellectual property principally in the Refining & Marketing and Chemical segment.
On July 24, 2014, the IASB completed its project to replace IAS 39 by issuing the final version of IFRS 9 “Financial Instruments” (hereinafter IFRS 9). In particular, IFRS 9: (i) changes the classification and measurement approach for financial assets, basing it on the characteristics of the financial instrument and on the business model adopted by the entity for managing it; (ii) introduces a new impairment model for financial assets, which considers the expected credit losses; and (iii) includes an improved hedge accounting model. IFRS 9 shall be applied for annual periods beginning on or after January 1, 2018.
In 2016, the Group started analytical activities with reference to the three main updated areas above-mentioned. In particular, the Group is assessing if the new classification requirements of IFRS 9 will impact the current way of classification of financial instruments; at the current stage of the analysis, the Group has not identified relevant impacts. An in-depth analysis on the fair value measurements of minority
investments in equity instruments that, under current provisions, are measured at cost when their fair value cannot be reliably measured, is being carried out.
With reference to the application of the expected credit loss model, the ongoing activities essentially concern: (i) for counterparties with an identifiable credit risk factor (e.g. the credit rating), the adoption of the expected loss model, defined having regard also to the current credit enhancements held (e.g. collaterals, guarantees, insurance contracts, etc.); (ii) for retail customers, the implementation of provision matrix to represent adequately the credit standing of the counterparty; and (iii) the revision and optimization of the operating processes to ensure the availability of information for implementing the evaluation models and drawing up the financial reporting.
In relation to hedge accounting, analyses on the applicability of the new qualifying criteria provided by IFRS 9 and on the implementation of rebalancing mechanism to maintain a hedge ratio that complies with the hedge effectiveness requirements, is being carried out.
At the current stage of the analyses, the likely impacts deriving from the application of the new IFRS 15 and IFRS 9 are not yet reasonably estimable.
On September 11, 2014, the IASB issued the amendments to IFRS 10 and IAS 28 “Sale or Contribution of Assets between an Investor and its Associate or Joint Venture” (hereinafter the amendments to IFRS 10 and IAS 28), which define the recognition criteria of the economic effects mainly related to the loss of control of an investment as a consequence of its transfer to an associate or a joint venture. On December 17, 2015, the IASB issued an amendment that postpones the application of the amendments to IFRS 10 and IAS 28 indefinitely.
On January 13, 2016, the IASB issued IFRS 16 “Leases” (hereinafter IFRS 16), which replaces IAS 17 and related interpretations. In particular, IFRS 16 defines a lease as a contract that conveys to the lessee the right to control the use of an identified asset for a period of time in exchange for consideration. The new IFRS eliminates the classification of leases as either operating leases or finance leases for the preparation of lessees’ financial statements; for all leases with a term of more than 12 months, the lessee shall recognize an asset, as the right-of-use, and a liability, as the present value of the lease payments.statements. Conversely, a lessor continues to classify its leases as either operating leases or finance leases. IFRS 16 enhances disclosures both for lessees and for lessors. IFRS 16 shall be applied for annual periods beginning on or after
With reference to the lessee’s primary financial statements, starting from January 1, 2019.2019: On January 19, 2016,-
on the IASB issuedbalance sheet, right-of-use assets and lease liabilities are recognised and presented separately from other assets and other liabilities; -
in the amendmentsprofit and loss account, depreciation charges and any impairment losses/write-offs of the right-of-use asset are recognised within operating expenses and the interest expense on the lease liability, if not capitalised, is recognised within finance expense rather than recognising the operating lease payments within operating expenses under IAS 17. The depreciation charges of the right-of-use asset and the interest expenses on the lease liability directly attributable to IAS 12 “Recognition of Deferred Tax Assets for Unrealized Losses”, which provide clarifications about the recognition and measurement of deferred tax assets. The amendments to IAS 12 shall be applied for annual periods beginning on or after January 1, 2017. On January 29, 2016, the IASB issued the amendments to IAS 7 “Disclosure Initiative”, which enhance disclosures required in case of changes in liabilities arising from financing activities, including both changes arising from cash flows and non-cash changes. The amendments to IAS 7 shall be applied for annual periods beginning on or after January 1, 2017.
On December 8, 2016, the IASB issued the IFRIC Interpretation 22 “Foreign Currency Transactions and Advance Consideration” (hereinafter IFRIC 22), which sets out that the exchange rate to use on initial recognitionconstruction of an asset are capitalised as part of the cost of such asset and subsequently recognised in the profit and loss account through depreciation/impairments or write-off, mainly in the case of exploration assets. Moreover, the profit and loss account includes: (i) the expenses relating to short-term leases and low-value leases; (ii) the expenses relating to variable lease payments that are not included in the measurement of the lease liability (e.g. payments that depend on the use of the underlying asset); and (iii) the expenses relating to any non-lease components accounted for separately from the lease component;
-
in the statement of cash flows, cash payments for the principal portion of the lease liability are classified within financing activities, whereas interest expense is classified within operating activities, if they are recognised in the profit and loss account, or incomewithin investing activities if they are capitalised in reference to leased assets that are used for the construction of other assets.33 Consequently, compared to the requirements of IAS 17 related to operating leases, the adoption of IFRS 16 has a significant impact in the statement of cash flows, by determining: (a) an advance consideration, previously paid or received in a foreign currency, is the rate used at the date of initial recognitionimprovement of the non-monetary asset or non-monetarynet cash provided by operating activities, which no longer includes operating lease payments, not capitalised, but only includes the cash payments for the interest portion of the lease liability arising fromthat are not capitalised34; (b) an improvement of the payment or receiptnet cash used in investing activities, which no longer includes capitalised lease payments, but only includes cash payments for the capitalised interest portion of that advance consideration. The IFRIC 22 shall be appliedthe lease liability; and (c) a worsening in the net cash used in financing activities, which includes cash payments for annual periods beginning on or after January 1, 2018.the principal portion of the lease liability. On December 8, 2016, the IASB issued the document “Annual Improvements to IFRS Standards 2014-2016 Cycle”, which include, basically, technical and editorial changes to existing standards. The amendments to the standards shall be applied for annual periods beginning on or after January 1, 201819.
Eni is currently reviewing these new IFRSs to determine the likely impact on the Group’s results.
(19)33
The clarificationprepayments for right-of-use assets, made before the commencement date of lease contracts, are classified within investing activities. 34
The net cash provided by operating activities will include also: (i) short-term lease payments and payments for low-value leases; (ii) variable lease payments not included in the scopemeasurement of the IFRS 12 “Disclosure of Interests in Other Entities” shall be appliedlease liabilities; and (iii) payments for annual periods beginning on or after January 1, 2017.non-lease components.
The adoption of the new requirements affects most of the Group companies; in terms of amounts and/or volumes, the main cases are the following: (i) in the Exploration & Production segment, contracts for the lease of drilling rigs and floating production storage and offloading vessels (the so-called FPSOs); (ii) in the Refining & Marketing and Chemical segment, highway concessions, leases of land, service stations for the sale of oil products, as well as the car fleet dedicated to the car sharing business (enjoy); (iii) in the Gas & Power segment, leases of vessels used for shipping activities and gas distribution facilities, as well as tolling contracts; (iv) for Corporate activities, leases of property. IFRS 16 has been applied, starting from January 1, 2019, by recognising, as allowed by the transition requirements of the accounting standard, the cumulative effect of the initial application as an adjustment to the opening balance of equity at January 1, 2019, with no restatement of comparative information (the so-called modified retrospective approach). In particular, the adoption of IFRS 16 resulted in the recognition of right-of-use assets for €5.7 billion and lease liabilities for €5.8 billion; the amount of the lease liabilities includes also the payables for lease fees outstanding at January 1, 2019, previously classified as trade payables. Such impacts take into account the indications of the IFRS Interpretations Committee according to which, in the case of unincorporated joint operations, the operator recognises the entire lease liability, as, by signing the contract, it has primary responsibility for the liability towards the third-party supplier. Therefore, if based on the contractual provisions and any other relevant facts and circumstances, Eni has primary responsibility, it recognises on the balance sheet: (i) the entire lease liability and (ii) the entire right-of-use asset, unless, based on the contractual provisions, there is a sublease with the followers. In particular, the amount of the lease liabilities at January 1, 2019, includes the share of the lease liabilities corresponding to the followers’ working interest for €2.0 billion, while the Eni working interest is €3.7 billion. On initial application, Eni has elected to apply the following practical expedients allowed by IFRS 16: -
possibility to not reassess each contract existing at January 1, 2019, by applying IFRS 16 to all contracts previously identified as leases (under IAS 17 and IFRIC 4), while not applying IFRS 16 to contracts that were not previously identified as leases; -
for contracts previously classified as operating leases, possibility to measure the right-of-use asset at an amount equal to the lease liability, adjusted, if necessary, by any prepaid amounts already recognised on the balance sheet; -
as an alternative to performing an impairment review, possibility to adjust the right-of-use asset, existing at January 1, 2019, by the amount of any provision for onerous lease contracts recognised at December 31, 2018; -
possibility to exclude initial direct costs from the measurement of the right-of-use asset at January 1, 2019. Moreover, on transition, Eni has elected to not consider leases for which the lease term ends within 12 months of January 1, 2019 as short-term leases.
The breakdown of the abovementioned quantitative effects and reclassifications deriving from the initial application, as at January 1, 2019, of IFRS 16, is as follows: (€ million) | | | | | Selected line items only | | | December 31, 2018 | | | Adoption of IFRS 16 | | | Reclassifications IFRS 16 | | | Total effect of the first application | | | As restated January 1, 2019 | | Current assets | | | | | 39,450 | | | | | | | | | | | | (12) | | | | | | (12) | | | | | | 39,438 | | | of which: Trade and other receivables | | | | | 14,101 | | | | | | | | | | | | (12) | | | | | | (12) | | | | | | 14,089 | | | Non-current assets | | | | | 78,628 | | | | | | 5,656 | | | | | | (13) | | | | | | 5,643 | | | | | | 84,271 | | | of which: Property, plant and equipment | | | | | 60,302 | | | | | | | | | | | | (46) | | | | | | (46) | | | | | | 60,256 | | | of which: Right-of-use assets | | | | | | | | | | | 5,656 | | | | | | 33 | | | | | | 5,689 | | | | | | 5,689 | | | Assets held for sale | | | | | 295 | | | | | | | | | | | | 13 | | | | | | 13 | | | | | | 308 | | | Current liabilities | | | | | 28,382 | | | | | | 665 | | | | | | (15) | | | | | | 650 | | | | | | 29,032 | | | of which: Current portion of long-term debt | | | | | 3,601 | | | | | | | | | | | | (16) | | | | | | (16) | | | | | | 3,585 | | | of which: Current portion of long-term lease liabilities | | | | | | | | | | | 665 | | | | | | 129 | | | | | | 794 | | | | | | 794 | | | of which: Trade and other payables | | | | | 16,747 | | | | | | | | | | | | (128) | | | | | | (128) | | | | | | 16,619 | | | Non-current liabilities | | | | | 38,859 | | | | | | 4,991 | | | | | | (10) | | | | | | 4,981 | | | | | | 43,840 | | | of which: Long-term debt | | | | | 20,082 | | | | | | | | | | | | (36) | | | | | | (36) | | | | | | 20,046 | | | of which: Long-term lease liabilities | | | | | | | | | | | 4,991 | | | | | | 26 | | | | | | 5,017 | | | | | | 5,017 | | | Liabilities directly associated with assets held for sale | | | | | 59 | | | | | | | | | | | | 13 | | | | | | 13 | | | | | | 72 | | |
The reconciliation between the amount of future minimum lease payments under non-cancellable operating leases at December 31, 2018, discounted using the lessee’s incremental borrowing rate at the date of initial application of IFRS 16, and the opening balance of the lease liabilities at January 1, 2019, is provided below: (€ billion) | | | | | | | | Future minimum lease payments under non-cancellable operating leases at December 31, 2018 | | | | | 4.0 | | | - Recognition of the shares of leases related to followers | | | | | 2.0 | | | - Effect of discounting | | | | | (1.5) | | | - Extension options | | | | | 1.2 | | | - Other changes | | | | | 0.1 | | | Lease liability at January 1, 2019 | | | | | 5.8 | | |
In particular, the weighted average discount rate used to measure the lease liabilities as at January 1, 2019 is equal to 6.8%. Moreover, starting from January 1, 2019 the following IFRSs are effective: (i)
the amendments to IAS 28 “Long-term Interests in Associates and Joint Ventures”, which clarify that entities account for any financing receivables towards an associate or joint venture, for which settlement is neither planned nor likely to occur in the foreseeable future (the so-called long-term interests) that, in substance, form part of the entity’s net investment in the investee, using the requirements of IFRS 9, including those related to impairment. These amendments did not have a significant impact on the Consolidated Financial Statements; (ii)
IFRIC 23 “Uncertainty over Income Tax Treatments”, which clarifies the accounting for (current and/or deferred) tax assets and liabilities when there is uncertainty over income tax treatments. In particular, if there is uncertainty over income tax treatments, if the company concludes it is
probable that the taxation authority will accept an uncertain tax treatment, it determines the (current and/or deferred) income taxes to be recognised in the financial statements consistent with the tax treatment used or planned to be used in its income tax filings. Conversely, if the company concludes it is not probable that the taxation authority will accept an uncertain tax treatment, the company reflects the effect of uncertainty in determining the (current and/or deferred) income taxes to be recognised in the financial statements. IFRIC 23 did not have a significant impact on the measurement of income taxes. Nevertheless, with reference to the presentation on the primary financial statements, in September 2019, the IFRS Interpretations Committee has indicated that the uncertain tax assets and liabilities shall be presented in the line items where income tax assets and income tax liabilities are recognised, and not in other line items. In this regard, as the uncertain tax liabilities include also the provisions for litigation concerning income taxes, these provisions have been reclassified out of the line item “Provisions” into the new line item “Income tax liabilities” within the non-current section of the balance sheet. Moreover, the balance sheet has been integrated with the new line items “Income tax assets”, within the non-current section, to present assets (other than deferred tax assets) related to income taxes, in specific, and not residual, line items.35 Furthermore, starting from 2019, on the balance sheet, within the current section, the line items “Other tax receivables” and “Other tax payables” have been deleted and the related amounts have been reclassified into the line items “Other assets” and “Other liabilities”. This change has been carried out because the separate presentation is not considered useful to understand the Group’s financial position. The balance sheet as at January 1, 2018 has been presented due to the material effect of such reclassifications. 4 IFRSs not yet adopted On May 18, 2017, the IASB issued IFRS 17 “Insurance Contracts” (hereinafter IFRS 17), which sets out the accounting for the insurance contracts issued and the reinsurance contracts held. IFRS 17, which replaces IFRS 4 “Insurance Contracts”, shall be applied for annual reporting periods beginning on or after January 1, 2021. On March 29, 2018, the IASB issued the document “Amendments to References to the Conceptual Framework in IFRS Standards”, which includes, basically, technical and editorial changes to existing IFRS standards in order to update references in those standards to previous versions of the IFRS Framework with the new Conceptual Framework for Financial Reporting, issued by the IASB on the same date. These amendments shall be applied for annual reporting periods beginning on or after January 1, 2020. On October 22, 2018, the IASB issued amendments to IFRS 3 “Business Combinations” (hereinafter the amendments to IFRS 3), which clarify the definition of a business. The amendments to IFRS 3 shall be applied for annual reporting periods beginning on or after January 1, 2020. On October 31, 2018, the IASB issued amendments to IAS 1 and IAS 8 “Definition of Material” (hereinafter the amendments to IAS 1 and IAS 8), which clarify, and align across all IFRS Standards and other publications, the definition of material to help companies make better materiality judgements. In particular, information is material if omitting, misstating or obscuring it could be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements. The amendments to IAS 1 and IAS 8 shall be applied for annual reporting periods beginning on or after January 1, 2020. On September 26, 2019, the IASB issued amendments to IFRS 9, IAS 39 and IFRS 7 “Interest Rate Benchmark Reform” (hereinafter amendments to IFRS 9, IAS 39 and IFRS 7), which provide temporary exceptions from applying specific hedge accounting requirements to all hedging relationships directly affected by the interest rate benchmark reform. The amendments to IFRS 9, IAS 39 and IFRS 7 shall be applied for annual reporting periods beginning on or after January 1, 2020. 35
In previous reporting periods, income tax receivables and income tax payables were recognised within the non-current section of the balance sheet, respectively, in the line items “Other assets” and “Other liabilities”.
On January 23, 2020, the IASB issued amendments to IAS 1 “Presentation of Financial Statements: Classification of Liabilities as Current assetsor Non-current” (hereinafter amendments to IAS 1), which clarify how to classify debt and other liabilities as current or non-current. The amendments to IAS 1 shall be applied for annual reporting periods beginning on or after January 1, 2022. 8Eni is currently reviewing the IFRSs not yet adopted in order to determine the likely impact on the Consolidated Financial Statements.
5 Cash and cash equivalents Cash and cash equivalents of €5,674€5,994 million (€5,20910,836 million at December 31, 2015)2018) included financial assets with maturity generally of up to three months or less at the date of inception amounting to €4,379€3,984 million (€3,2898,732 million at December 31, 2015)2018) and mainly included short-term deposits in euro and U.S. dollars with financial institutions, having notice of more than 48 hours.hours, to meet the Group’s short-term financing needs. Restricted cash amounted to €198 million. The average maturity of financial assets due within 90 daysbank deposits in euro of €3,086 million was 79 days and the averageeffective interest rate was a negative and amounted to 0.01% (positive 0.25% at December 31, 2015)0.22%; the average maturity of bank deposits in U.S. dollars of €864 million was 8 days with an effective interest rate of 1.95%. 96 Financial assets held for trading
(€ million) | | December 31, 2015 | | December 31, 2016 | | | December 31, 2019 | | December 31, 2018 | | Quoted bonds issued by sovereign states | | | | 925 | | | | | 996 | | | | Bonds issued by sovereign states | | | | | 1,462 | | | | | 1,083 | | | Other | | | | 4,103 | | | | | 5,170 | | | | | | 5,298 | | | | | 5,469 | | | | | | | 5,028 | | | | | 6,166 | | | | | | 6,760 | | | | | 6,552 | | | | |
Financial assets held for trading of €6,166 million (€5,028 million at December 31, 2015) related to Eni SpA for €6,062 million (€5,028 million at December 31, 2015) and to Eni Insurance DAC per €104 million.
Financial assets held for trading of Eni SpA include securities subject to lending agreements of €665 million. The Company has established a liquidity reserve as part of its internal targets and financial strategy.strategy with a view of ensuring an adequate level of flexibility to the Group development plans and of coping with unexpected fund requirements or difficulties in accessing financial markets. The management of this liquidity reserve is performed through trading activities in view of the financial optimization of returns, within a predefined and authorized level of risk tolerance, targeting the preservation of the invested capital and the ability to promptly convert it into cash.
Financial assets held for trading include securities subject to lending agreements of €1,347 million (€1,301 million at December 31, 2018). The breakdown by currency is provided below: (€ million) | | | December 31, 2015 | | | December 31, 2016 | | Euro | | | | | 3,906 | | | | | | 4,319 | | | U.S. dollar | | | | | 272 | | | | | | 699 | | | British pound | | | | | 271 | | | | | | 632 | | | Swiss franc | | | | | 524 | | | | | | 413 | | | Canadian dollar | | | | | 36 | | | | | | 52 | | | Australian dollar | | | | | 19 | | | | | | 51 | | | | | | | | 5,028 | | | | | | 6,166 | | | |
(€ million) | | | December 31, 2019 | | | December 31, 2018 | | Euro | | | | | 4,272 | | | | | | 4,573 | | | U.S. dollars | | | | | 2,279 | | | | | | 1,614 | | | Other currencies | | | | | 209 | | | | | | 365 | | | | | | | | 6,760 | | | | | | 6,552 | | |
The breakdown by issuing entity and credit rating is presented below: | | Nominal value (€ million) | | Fair Value (€ million) | | Rating - Moody’s | | Rating - S&P | | | Nominal value (€ million) | | Fair Value (€ million) | | Rating – Moody’s | | Rating – S&P | | Quoted bonds issued by sovereign states | | | | | | | | | | | | | | | | | | | Fixed rate bonds | | | | | | | | | | | | | | | | | | | Italy | | | | 539 | | | | | 548 | | | Baa2 | | BBB- | | | | | 734 | | | | | 743 | | | Baa3 | | BBB | | Spain | | | | 158 | | | | | 166 | | | Baa2 | | BBB+ | | | Poland | | | | 62 | | | | | 64 | | | A2 | | BBB+ | | | Slovenia | | | | 33 | | | | | 36 | | | Baa3 | | A | | | Germany | | | | 23 | | | | | 24 | | | Aaa | | AAA | | | Ireland | | | | 10 | | | | | 11 | | | A3 | | A+ | | | Chile | | | | 8 | | | | | 8 | | | Aa3 | | AA- | | | | | 177 | | | | | 181 | | | A1 | | A+ | | Slovakia | | | | 5 | | | | | 5 | | | A2 | | A+ | | | Sweden | | | | 5 | | | | | 5 | | | Aaa | | AAA | | | Other(*) | | | | | 216 | | | | | 224 | | | from Aaa to Baa1 | | from AAA to BBB+ | | | | | | 843 | | | | | 867 | | | | | | | 1,127 | | | | | 1,148 | | | | | | | Floating rate bonds | | | | | | | | | | | | | | | | | | | Italy | | | | 100 | | | | | 100 | | | Baa2 | | BBB- | | | | | 126 | | | | | 126 | | | Baa3 | | BBB | | Spain | | | | 30 | | | | | 29 | | | Baa2 | | BBB+ | | | Germany | | | | | 106 | | | | | 106 | | | Aaa | | AAA | | Other(*) | | | | | 81 | | | | | 82 | | | from Aaa to Baa3 | | from AAA to BBB | | | | | | 130 | | | | | 129 | | | | | | | 313 | | | | | 314 | | | | | | | Total quoted bonds issued by sovereign states | | | | 973 | | | | | 996 | | | | | | | 1,440 | | | | | 1,462 | | | | | | | Other Bonds | | | | | | | | | | | | | | | | | | | Fixed rate bonds | | | | | | | | | | | | | | | | | | | Quoted bonds issued by industrial companies | | | | 2,264 | | | | | 2,344 | | | from Aaa to Baa3 | | from AAA to BBB- | | | | | 1,183 | | | | | 1,212 | | | from Aa2 to Baa3 | | from AA to BBB- | | Quoted bonds issued by financial and insurance companies | | | | 1,981 | | | | | 2,031 | | | from Aaa to Baa3 | | from AAA to BBB- | | | | | 862 | | | | | 879 | | | from Aa3 to Baa3 | | from AA- to BBB- | | European Investment Bank | | | | 8 | | | | | 8 | | | Aaa | | AAA | | | Other bonds | | | | | 105 | | | | | 106 | | | from Aaa to Baa2 | | from AAA to BBB | | | | | | 4,253 | | | | | 4,383 | | | | | | | 2,150 | | | | | 2,197 | | | | | | | Floating rate bonds | | | | | | | | | | | | | | | | | | | Quoted bonds issued by industrial companies | | | | | 1,530 | | | | | 1,535 | | | from Aa1 to Baa3 | | from AA+ to BBB- | | Quoted bonds issued by financial and insurance companies | | | | 553 | | | | | 556 | | | from Aaa to Baa3 | | from AAA to BBB- | | | | | 1,116 | | | | | 1,122 | | | from Aa1 to Baa3 | | from AA+ to BBB- | | Quoted bonds issued by industrial companies | | | | 231 | | | | | 231 | | | from Aaa to Baa3 | | from AAA to BBB- | | | Other bonds | | | | | 444 | | | | | 444 | | | from Aaa to Baa2 | | from AAA to BBB | | | | | | 784 | | | | | 787 | | | | | | | 3,090 | | | | | 3,101 | | | | | | | Total other bonds | | | | 5,037 | | | | | 5,170 | | | | | | | 5,240 | | | | | 5,298 | | | | | | | Total other financial assets held for trading | | | | 6,010 | | | | | 6,166 | | | | | | | | | | 6,680 | | | | | 6,760 | | | | | | | | |
The fair value was determined based on market quotations. (*)
Amounts included herein are lower than €50 million. The fair value hierarchy is level 1. 10 Financial assets available1 for sale
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Securities held for operating purposes | | | | Quoted bonds issued by sovereign states | | | | | 243 | | | | Quoted securities issued by financial institutions | | | | | 39 | | | | | | | | | | | 282 | | | | | | Securities held for non-operating purposes | | | | Quoted bonds issued by sovereign states | | | | | | | | | | | 210 | | | Quoted securities issued by financial institutions | | | | | | | | | | | 28 | | | | | | | | | | | | | | 238 | | | Total | | | | | 282 | | | | | | 238 | | | |
The breakdown by currency is provided below:
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Euro | | | | | 241 | | | | | | 199 | | | U.S. Dollar | | | | | 41 | | | | | | 39 | | | | | | | | 282 | | | | | | 238 | | | |
At December 31, 2016, bonds issued by sovereign states amounted to €210€6,219 million (€243 million at December 31, 2015). The breakdown is presented below:
| | | Nominal value (€ million) | | | Fair Value (€ million) | | | Nominal rate of return (%) | | | Maturity date | | | Rating – Moody’s | | | Rating – S&P | | Fixed rate bonds | | | | | | | | Belgium | | | | | 27 | | | | | | 32 | | | | from 3.75 to 4.25 | | | from 2019 to 2021 | | | Aa3 | | | AA | | Spain | | | | | 25 | | | | | | 28 | | | | from 1.40 to 5.50 | | | from 2018 to 2021 | | | Baa2 | | | BBB+ | | Italy | | | | | 22 | | | | | | 22 | | | | from 0.00 to 3.50 | | | from 2017 to 2020 | | | Baa2 | | | BBB- | | France | | | | | 17 | | | | | | 19 | | | | from 1.00 to 3.25 | | | from 2018 to 2023 | | | Aa2 | | | AA | | Poland | | | | | 16 | | | | | | 19 | | | | from 4.50 to 6.38 | | | from 2019 to 2022 | | | A2 | | | BBB+ | | Ireland | | | | | 16 | | | | | | 18 | | | | from 0.80 to 4.40 | | | from 2019 to 2022 | | | A3 | | | A+ | | Iceland | | | | | 15 | | | | | | 16 | | | | from 2.50 to 5.88 | | | from 2020 to 2022 | | | A3 | | | BBB+ | | Slovakia | | | | | 10 | | | | | | 10 | | | | from 1.50 to 4.20 | | | from 2017 to 2018 | | | A2 | | | A+ | | Finland | | | | | 9 | | | | | | 9 | | | | from 1.13 to 1.75 | | | from 2017 to 2019 | | | Aa1 | | | AA+ | | Portugal | | | | | 7 | | | | | | 8 | | | | 4.75 | | | 2019 | | | Ba1 | | | BB+ | | Czech Republic | | | | | 7 | | | | | | 8 | | | | 3.63 | | | 2021 | | | A1 | | | AA- | | Slovenia | | | | | 7 | | | | | | 8 | | | | 2.25 | | | 2022 | | | Baa3 | | | A | | United States of America | | | | | 7 | | | | | | 7 | | | | from 1.25 to 3.13 | | | from 2019 to 2020 | | | Aaa | | | AA+ | | Canada | | | | | 5 | | | | | | 5 | | | | 1.63 | | | 2019 | | | Aaa | | | AAA | | Netherlands | | | | | 1 | | | | | | 1 | | | | 4.00 | | | 2018 | | | Aaa | | | AAA | | Total | | | | | 191 | | | | | | 210 | | | | | | | | | | | | | | | |
Quoted securities amounting to €28 million (€39 million at December 31, 2015)and level 2 for €541 million. During 2019, there were issued by financial institutions with a rating from Aaa to Aa1 (Moody’s) and from AAA to AA (S&P).
Securities held for non-operating purposes of €238 million related tono transfers between the Group’s insurance company Eni Insurance DAC.
From January 1, 2016, insurance companies are required to meet certain capital and solvency ratios as minimum requirements to continue performing the insurance activity based on the provisions of EU Solvency II Directive (the so-called Minimum Capital Requirement — MCR — and Solvency Capital Requirement — SCR). Therefore, while it is advisable to maintain a sound investment policy of the proceeds associated with the business, insurance companies have been waived from committing financial assets to funding the loss provisions. Accordingly, available-for-sale securities held by Eni’s subsidiary Eni Insurance DAC at the opening balance for €282 million have been reclassified as held for non-operating purposes. The same reclassification has been applied to financial receivables held by Eni Insurance DAC (see note 11 — Trade and other receivables).
The effectsdifferent hierarchy levels of fair value measurement of securities are set out below:
(€ million) | | | Carrying amount at December 31, 2015 | | | Changes recognized in equity | | | Reversal of the year | | | Carrying amount at December 31, 2016 | | Fair value | | | | | 9 | | | | | | (3) | | | | | | (1) | | | | | | 5 | | | Deferred tax liabilities | | | | | (1) | | | | | | | | | | | | | | | | | | (1) | | | Other reserves of shareholders’ equity | | | | | 8 | | | | | | (3) | | | | | | (1) | | | | | | 4 | | | |
The fair value was determined based on market quotations. The fair value hierarchy is level 1. value.
117 Trade and other receivables
(€ million) | | December 31, 2015 | | December 31, 2016 | | | December 31, 2019 | | December 31, 2018 | | Trade receivables | | | | 12,616 | | | | | 11,186 | | | | | | 8,519 | | | | | 9,520 | | | Financing receivables | | | | - for operating purposes – short-term | | | | 375 | | | | | 86 | | | | - for operating purposes – current portion of long-term receivables | | | | 1,247 | | | | | 72 | | | | - for non-operating purposes | | | | 685 | | | | | 385 | | | | Receivables from divestments | | | | | 30 | | | | | 122 | | | Receivables from joint ventures in exploration and production activities | | | | | 2,637 | | | | | 3,024 | | | Other receivables | | | | | 1,687 | | | | | 1,435 | | | | | | | 2,307 | | | | | 543 | | | | | | 12,873 | | | | | 14,101 | | | Other receivables | | | | - from disposals | | | | 33 | | | | | 171 | | | | - other | | | | 6,684 | | | | | 5,693 | | | | | | | | 6,717 | | | | | 5,864 | | | | | | | | 21,640 | | | | | 17,593 | | | | | |
Generally, trade receivables do not bear interest and provide payment terms within 180 days. Trade receivables decreased by €1,430€1,001 million, of which €1,298€874 million in the Gas & Power segment because an increased volume of receivables were sold to financial institutions as a result of factoring transactions. Receivables are stated net of the valuation allowance for doubtful accounts of €2,371 million (€2,083 million at December 31, 2015):
(€ million) | | | Carrying amount at December 31, 2015 | | | Additions | | | Deductions | | | Other changes | | | Carrying amount at December 31, 2016 | | Trade receivables | | | | | 1,915 | | | | | | 503 | | | | | | (607) | | | | | | 6 | | | | | | 1,817 | | | Financing receivables | | | | | 66 | | | | | | | | | | | | | | | | | | 2 | | | | | | 68 | | | Other receivables | | | | | 102 | | | | | | 367 | | | | | | (4) | | | | | | 21 | | | | | | 486 | | | | | | | | 2,083 | | | | | | 870 | | | | | | (611) | | | | | | 29 | | | | | | 2,371 | | | |
Additions to allowance for doubtful accounts amounted to €503 million (€588 million in 2015) and related mainly to the Gas & Power segment for €399 million. This is reflective of the continuing difficulties in the collection of overdue receivables in the retail customers segment. The mitigation measures regarding the counterparty risk executed by Eni through specific actions of recovery and through specialized external services have led to a reduction of overdue receivables during the year 2016.
Utilizations amounting to €607 million (€249 million in 2015) related to the Gas & Power segment for €559 millionfollowing a drop in prices and relatedvolumes of gas sold in the fourth quarter 2019 compared to the recognitionsame period of losses on doubtful accounts in the retail business.2018.
At December 31, 2016,2019, Eni sold without recourse trade receivables due in 20172020 for €1,769€1,782 million to financial institutions (€7501,769 million at December 31, 20152018 due in 2016)2019). Derecognized receivables related to the Gas & Power segment (€1,434 million)for €1,369 million and to the Refining & Marketing and Chemical segment (€335 million).business line for €413 million. Trade receivables outstanding at December 31, 2016 comprised receivablesReceivables from divestments decreased by €92 million during 2019 due to the collection of €1,764the last installment of €123 million for hydrocarbons supplies made by the Exploration & Production segmentrelated to national oil companies. That amount includes overdue receivables related to: (i) State-owned oil companies in Egypt, which overdue amount was €420 million. This was significantly lower than the overdue amount of €771 million outstanding at December 31, 2015 and was driven by the implementation of a plan intended to trim the overdue amounts, which comprised the settlement of certain commercial and industrial agreements with the counterparties. The residual amount outstanding at the reporting date has been further reduced by a payment dated January 2017 amounting to $240 million (€228 million); (ii) State-owned companies in Iran as part of a settlement agreement signed in 2015 regarding the recovery of past costs associated to certain petroleum projects already completed for €264 million. This amount was curtailed compared to December 31, 2015 (€312 million). The State counterparties expressed their willingness to negotiate a repayment plan of overdue receivables based on arrangements relating the sale of volumes ofa 10% interest in the Iranian counterpart equity crude and the attributionZohr asset in Egypt made to Eni of a percentage of the sale proceeds. This agreementBP in 2017.
Receivables from joint ventures in exploration and production activities included amounts due by partners in unincorporated joint operations in Nigeria for €1,052 million (€977 million at December 31, 2018) in respect of the contractual recovery of expenditures incurred at certain projects operated by Eni. The amount due by the Nigerian national oil company NNPC was €764 million (€681 million at December 31, 2018), of which 70% is overdue. This overdue amount is subject to a “Repayment Agreement”, whereby Eni is to be reimbursed through the sale of the profit oil attributable to NNPC in certain rig-less petroleum initiatives with low mineral risk. Based on Eni’s Brent price scenario, the reimbursement will be accomplished over a time horizon of three to five years. This plan has been firstly enacted inallowed to recover about 45% of the last monthsoriginal amount from the implementation of 2016 withthe agreement two years ago. The overdue receivable is stated net of a reimbursementdiscount factor. A local oil company owed us about €113 million, net of a provision based on the loss given default (LGD) defined by Eni for international oil companies. Initiatives for the definition of a repayment plan are underway. A receivable of equivalent amount was reclassified to non-current assets following the definition of a repayment plan based on the attribution to Eni of $44the proceeds for the sale of the productions attributable to the partner. This receivable has been considered as performing because the production is operated by Eni. Other receivables comprised the recoverable amounts for €373 million (€42 million). Negotiations are underway300 million at December 31, 2018) of certain overdue trade receivables towards the state-owned oil company of Venezuela, PDVSA, in relation to identify additional crudegas equity volumes supplied by the joint venture Cardón IV, equally participated by Eni and Repsol. Those trade receivables were agreed to be marketed, sometransferred from the joint venture to the two shareholders. The receivables are stated net of which have already been awardedan allowance for doubtful accounts determined on the basis of the average recovery percentages obtained by creditors in the context of sovereign defaults, adjusted to Enireflect the strategic value of the Oil&Gas sector, and also applied for assessing the recoverability of the carrying amount of the investment and the long-term interest in early 2017, with the aim of fully recovering the overdue amounts.initiative, as described in note 16 — Other financial assets. The ageing ofTrade and other receivables stated in euro and U.S. dollars amounted to €6,303 million and €5,480 million, respectively.
Credit risk exposure and expected losses relating to trade and other receivables is presented below: | | | December 31, 2015 | | | December 31, 2016 | | (€ million) | | | Trade receivables | | | Other receivables | | | Trade receivables | | | Other receivables | | Neither impaired nor past due | | | | | 9,814 | | | | | | 5,371 | | | | | | 9,243 | | | | | | 4,869 | | | Impaired (net of the valuation for doubtful accounts) | | | | | 1,085 | | | | | | 93 | | | | | | 759 | | | | | | 432 | | | Not impaired and past due in the following periods: | | | | | | - within 90 days | | | | | 1,080 | | | | | | 92 | | | | | | 744 | | | | | | 58 | | | - 3 to 6 months | | | | | 110 | | | | | | 502 | | | | | | 49 | | | | | | 81 | | | - 6 to 12 months | | | | | 226 | | | | | | 485 | | | | | | 69 | | | | | | 249 | | | - over 12 months | | | | | 301 | | | | | | 174 | | | | | | 322 | | | | | | 175 | | | | | | | | 1,717 | | | | | | 1,253 | | | | | | 1,184 | | | | | | 563 | | | | | | | | 12,616 | | | | | | 6,717 | | | | | | 11,186 | | | | | | 5,864 | | | |
The Group has not booked anybeen prepared on the basis of internal ratings as follows:
| | | Performing receivables | | | Defaulted receivables | | | Eni gas e luce customers | | | Total | | (€ million) | | | Low risk | | | Medium Risk | | | High Risk | | December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Business customers | | | | | 1,922 | | | | | | 2,882 | | | | | | 840 | | | | | | 1,396 | | | | | | | | | | | | 7,040 | | | National Oil Companies and public administrations | | | | | 1,201 | | | | | | 472 | | | | | | 244 | | | | | | 2,710 | | | | | | | | | | | | 4,627 | | | Other counterparties | | | | | 1,646 | | | | | | 103 | | | | | | 381 | | | | | | 217 | | | | | | 2,105 | | | | | | 4,452 | | | Gross amount | | | | | 4,769 | | | | | | 3,457 | | | | | | 1,465 | | | | | | 4,323 | | | | | | 2,105 | | | | | | 16,119 | | | Allowance for doubtful accounts | | | | | (13) | | | | | | (4) | | | | | | (16) | | | | | | (2,547) | | | | | | (666) | | | | | | (3,246) | | | Net amount | | | | | 4,756 | | | | | | 3,453 | | | | | | 1,449 | | | | | | 1,776 | | | | | | 1,439 | | | | | | 12,873 | | | Expected loss (% net of counterpart risk mitigation factors) | | | | | 0.3 | | | | | | 0.1 | | | | | | 1.1 | | | | | | 58.9 | | | | | | 31.6 | | | | | | 20.1 | | | December 31, 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Business customers | | | | | 2,454 | | | | | | 3,585 | | | | | | 1,152 | | | | | | 1,350 | | | | | | | | | | | | 8,541 | | | National Oil Companies and public administrations | | | | | 1,292 | | | | | | 157 | | | | | | 672 | | | | | | 2,217 | | | | | | | | | | | | 4,338 | | | Other counterparties | | | | | 1,494 | | | | | | 77 | | | | | | 156 | | | | | | 271 | | | | | | 2,374 | | | | | | 4,372 | | | Gross amount | | | | | 5,240 | | | | | | 3,819 | | | | | | 1,980 | | | | | | 3,838 | | | | | | 2,374 | | | | | | 17,251 | | | Allowance for doubtful accounts | | | | | (9) | | | | | | (3) | | | | | | (44) | | | | | | (2,237) | | | | | | (857) | | | | | | (3,150) | | | Net amount | | | | | 5,231 | | | | | | 3,816 | | | | | | 1,936 | | | | | | 1,601 | | | | | | 1,517 | | | | | | 14,101 | | | Expected loss (% net of counterpart risk mitigation factors) | | | | | 0.2 | | | | | | 0.1 | | | | | | 2.6 | | | | | | 62.5 | | | | | | 36.1 | | | | | | 18.3 | | |
Eni has classified its business customers and the associated commercial or industrial exposures based on an individual assessment of the credit merit and the counterparty loss on certain traderisks. Business customers other than National Oil Companies (NOC) and other receivables which were overdue at the balance sheet date, because they pertained to highly-rated Italian and foreign public administrations, each of whom have undergone specific credit evaluations, have been assigned a probability of default calculated based on internal ratings which factor in: (i) a full assessment of each customer profitability, financial condition and liquidity and business a financial prospects on an ongoing basis; (ii) history of the contractual relationship (timeliness in invoice
payment, number of claims, etc.); (iii) presence of mitigation factors of the credit risk (e.g. securitization package, insurance against the credit risk, guarantee from third parties, etc.); (iv) other specialized pieces of information obtained by the Company’s business commercial departments or by specialized info-providers; (v) industrial and market trends. Internal ratings and the probability of default are constantly updated by means of back-testing analysis and risk assessment of the current credit portfolio. The loss given default associated with those industrial customers is estimated by the business departments based on the past experience in credit recoverability; in the case of defaulting customers, loss given default is estimated based on the recovery rates obtained in situations of credit restructurings or litigation procedures. The probability of default associated with NOCs and public administrations is estimated based on the country risk premium incorporated in the risk-adjusted weighted average cost of capital utilized by the Company to other highly-reliable counterparties for suppliesperform the impairment review of oil, naturalits fixed assets. The loss given default of these business partners, essentially represented by the probability of a delay in repaying due amounts, is estimated based on historical averages of delays in collecting overdue receivables, substantially assessing the time value of money. The resulting loss given default is adjusted to factor in any existing mitigation factor. In case of particular market conditions or sovereign defaults, the expected loss associated with NOCs is re-rated based on the empirical evidence and outcomes obtained from restructuring of sovereign debts considering the specificities of trading relationships with energy companies. Customers of the Eni subsidiary “Eni gas refinede luce”, which engages in marketing gas and chemical productspower to residential customers, were grouped into homogeneous clusters with different credit risk and probability of default which have been estimated based on past experience on credit collection, systematically updated and, in case of particular market conditions, adjusted to take into account expected market and credit trends in any given cluster. The exposure to credit risk and expected losses relating to retail customers of the Gas & Power segment overdue by less than 90 days. Trade receivables in currencies other than euro amounted to €3,629 million (€3,995 million at December 31, 2015).
Financing receivables associated with operating purposes of €158 million (€1,622 million at December 31, 2015) included loans granted to joint ventures and associates to fundwas assessed on the execution of Eni’s capital projects for €28 million (€1,135 million at December 31, 2015). The decrease for €1,464 million comprised the reclassification for €1,054 million to other non-current financial assets of the financing loan granted to the equity-accounted investee CARDÓN IV SA (Eni’s share being 50%) (€1,112 million at December 31, 2015).
Financing receivables for operating purposes outstanding at December 31, 2015, of €287 million relating to Eni Insurance DAC were reclassified as financing receivables not associated with operating activities following the adoption of the provisions of EU Solvency II Directive on capital requirements to be met for operating in the insurance activity. More information is reported in note 10 — Financial assets available for sale.
Financing receivables not associated with operating activities amounted to €385 million (€685 million at December 31, 2015) and related to: (i) restricted deposits in escrow for €137 million of Eni Trading & Shipping SpA (€209 million at December 31, 2015) of which €113 million with BNP Paribas and €24 million with Citibank relating to derivatives; (ii) deposits of Eni Insurance DAC for €225 million.
Financing receivables in currencies other than euro amounted to €121 million (€1,329 million as of December 31, 2015).
Receivables from divestments amounted to €171 million (€33 million at December 31, 2015), of which €166 million related to the current portion of the receivable arising from the divestment finalized in 2008basis of a 1.71% interest in the Kashagan project to the local partner KazMunayGas for a total amount of €463 million. The reimbursement of the receivable is scheduled in three annual instalments commencing from the date when the agreed production target is achieved. The receivable accrues interest income at market rates. Due to the restart of the project, the production milestone was reached in the fourth quarter 2016 and, consequently, the first installment of the sale price including interests has been repaid (€152 million). The description of the transaction is provided in note 23 — Other non-current assets.provision matrix as follows:
Other receivables of €5,693 million (€6,684 million at December 31, 2015) included €4,111 million of receivables owed by Eni’s partners in unincorporated joint ventures that are currently executing exploration
| | | Ageing | | (€ million) | | | Not-past due | | | from 0 to 3 months | | | from 3 to 6 months | | | from 6 to 12 months | | | over 12 months | | | Total | | December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Customers – Eni gas e luce: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Retail | | | | | 991 | | | | | | 105 | | | | | | 60 | | | | | | 86 | | | | | | 376 | | | | | | 1,618 | | | - Middle | | | | | 93 | | | | | | 29 | | | | | | 4 | | | | | | 14 | | | | | | 263 | | | | | | 403 | | | - Other | | | | | 76 | | | | | | 3 | | | | | | 1 | | | | | | 2 | | | | | | 2 | | | | | | 84 | | | Gross amount | | | | | 1,160 | | | | | | 137 | | | | | | 65 | | | | | | 102 | | | | | | 641 | | | | | | 2,105 | | | Allowance for doubtful accounts | | | | | (16) | | | | | | (27) | | | | | | (26) | | | | | | (49) | | | | | | (548) | | | | | | (666) | | | Net amount | | | | | 1,144 | | | | | | 110 | | | | | | 39 | | | | | | 53 | | | | | | 93 | | | | | | 1,439 | | | Expected loss (%) | | | | | 1.4 | | | | | | 19.7 | | | | | | 40.0 | | | | | | 48.0 | | | | | | 85.5 | | | | | | 31.6 | | | December 31, 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Customers – Eni gas e luce: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Retail | | | | | 575 | | | | | | 49 | | | | | | 34 | | | | | | 64 | | | | | | 554 | | | | | | 1,276 | | | - Middle | | | | | 449 | | | | | | 43 | | | | | | 13 | | | | | | 29 | | | | | | 349 | | | | | | 883 | | | - Other | | | | | 207 | | | | | | 2 | | | | | | 1 | | | | | | 2 | | | | | | 3 | | | | | | 215 | | | Gross amount | | | | | 1,231 | | | | | | 94 | | | | | | 48 | | | | | | 95 | | | | | | 906 | | | ��� | | | 2,374 | | | Allowance for doubtful accounts | | | | | (20) | | | | | | (18) | | | | | | (18) | | | | | | (56) | | | | | | (745) | | | | | | (857) | | | Net amount | | | | | 1,211 | | | | | | 76 | | | | | | 30 | | | | | | 39 | | | | | | 161 | | | | | | 1,517 | | | Expected loss (%) | | | | | 1.6 | | | | | | 19.1 | | | | | | 37.5 | | | | | | 58.9 | | | | | | 82.2 | | | | | | 36.1 | | | |
Trade and production projects. The largest outstanding amount asother receivables are stated net of December 31, 2016 relatedthe allowance for doubtful accounts which has been determined considering the counterparty risk mitigation factors amounting to partners in Nigeria (€1,775 million) and among these the Nigerian national oil company NNPC in respect of: (i) receivables of €382€2,914 million (€7733,072 million at December 31, 2015)2018): (€ million) | | | 2019 | | | 2018 | | Carrying amount – beginning of the year | | | | | 3,150 | | | | | | 2,639 | | | Changes in accounting policies (IFRS 9) | | | | | | | | | | | 427 | | | Carrying amount – restated | | | | | 3,150 | | | | | | 3,066 | | | Additions on trade and other performing receivables | | | | | 95 | | | | | | 126 | | | Additions on trade and other defaulted receivables | | | | | 525 | | | | | | 372 | | | Deductions on trade and other performing receivables | | | | | (119) | | | | | | (189) | | | Deductions on trade and other defaulted receivables | | | | | (484) | | | | | | (532) | | | Other changes | | | | | 79 | | | | | | 307 | | | Carrying amount – end of the year | | | | | 3,246 | | | | | | 3,150 | | |
Additions to allowance for doubtful accounts on trade and other performing receivables related for €67 million (€108 million in 2018) to the Gas & Power segment, particularly in the retail business; in the Exploration & Production segment provisions of €23 million (€16 million in 2018) related to cash calls towards joint operators — State oil Companies or International Oil Companies — in oil projects operated by Eni. Additions to allowance for doubtful accounts on trade and other defaulted receivables related to the contractual recoveryExploration & Production segment for €339 million (€291 million in 2018) and were in relation with receivables for the supply of costs incurredequity hydrocarbons to State-owned companies and receivables towards joint operators for twocash calls in oil projects (oneoperated by Eni. Utilizations of which is operated) under arbitration procedures. After the issuance of favorable arbitration rulings, the Company is negotiating a settlement agreement with the aim of being reimbursed of a part of the amount awarded by the arbitration procedures. The amount being negotiated will be reimbursed through the assignmentallowance for doubtful accounts on trade and other performing and defaulted receivables amounted to Eni of crude oil quantities owned by the state company over a period of three years. The impairment loss€603 million (€721 million in 2018) and mainly related to the receivables resulting fromGas & Power segment for €385 million (€613 million in 2018), in particular utilizations against charges of €344 million (€579 million in 2018) mainly in the agreement under negotiation amountedretail business. The mitigation measures regarding the counterparty risk executed by the Company, including better customer selection, allowed to €332reduce the incidence of unpaid amounts on retail sales of gas and power to physiological levels. Utilizations in Exploration & Production segment of €177 million plus the discount effect of the expected future cash flows, which reflected the mineral risk (€42 million); (ii) receivables of €71666 million were overdue at the balance sheet date in relation2018) related to the cash calls owed by NNPC at certain projects operated by Eni. Atprogress in the opening balance, partcollection of these receivables was denominated in local currency and consequently their carrying amounts were negatively affected by the currency devaluation occurred in 2016. Eni and NNPC agreed on a repayment plan providing for a reimbursement in U.S. dollars and the attribution to Eni of a portion of the proceeds from the sale of the hydrocarbon productions which will be obtained from development activities with a low risk profile (rigless) in order to fully repay the overdue amounts within a period of five years. The expenses through profit included foreign exchange losses for $80 million (€72 million) and the discounting effect for $96 million (€87 million), which was determined taking into account the mineral risk.cash calls. Other receivables were as follows:
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Receivables originated from divestments | | | | | 33 | | | | | | 171 | | | Accounts receivable from | | | | - joint venture partners in exploration and production | | | | | 4,656 | | | | | | 4,111 | | | - prepayments for services | | | | | 540 | | | | | | 372 | | | - insurance companies | | | | | 113 | | | | | | 147 | | | - non-financial government entities | | | | | 104 | | | | | | 49 | | | - factoring arrangements | | | | | 90 | | | | | | 81 | | | - non-Italian oil entities for oil tax refunds | | | | | 27 | | | | | | 40 | | | - other receivables | | | | | 1,154 | | | | | | 893 | | | | | | | | 6,684 | | | | | | 5,693 | | | | | | | | 6,717 | | | | | | 5,864 | | | |
Receivables from joint venture partners in exploration and production activities of €60 million (€281 million at December 31, 2015) included the liability for benefit plans (see note 31 — Provisions for employee benefits).
Receivables from factoring arrangements of €81 million (€90 million at December 31, 2015) related to Serfactoring SpA and consisted of advances for factoring arrangements with recourse and receivables for factoring arrangements without recourse.
Other receivables in currencies other than euro amounted to €5,253 million (€5,913 million at December 31, 2015).
Because of the short-term maturity and conditions of remunerationNet (impairment losses) reversals of trade and other receivables the fair value approximated the carrying amount.are disclosed as follows:
(€ million) | | | 2019 | | | 2018 | | Net (impairment losses) reversals of trade and other receivables | | | | | | | | | | | | | | New or increased provisions | | | | | (620) | | | | | | (498) | | | Credit losses | | | | | (45) | | | | | | (37) | | | Reversals | | | | | 233 | | | | | | 120 | | | | | | | | (432) | | | | | | (415) | | |
Receivables with related parties are describeddisclosed in note 4736 — Transactions with related parties.
12 Inventories8 Non-current and current inventories
| | | December 31, 2015 | | | December 31, 2016 | | (€ million) | | | Crude oil, gas and petroleum products | | | Chemical products | | | Other | | | Total | | | Crude oil, gas and petroleum products | | | Chemical products | | | Other | | | Total | | Raw and auxiliary materials and consumables | | | | | 222 | | | | | | 142 | | | | | | 1,933 | | | | | | 2,297 | | | | | | 550 | | | | | | 135 | | | | | | 1,903 | | | | | | 2,588 | | | Products being processed and semi-finished products | | | | | 97 | | | | | | 9 | | | | | | 1 | | | | | | 107 | | | | | | 99 | | | | | | 9 | | | | | | 1 | | | | | | 109 | | | Work in progress | | | | | | | | | | | | | | | | | 7 | | | | | | 7 | | | | | | | | | | | | | | | | | | 2 | | | | | | 2 | | | Finished products and goods | | | | | 1,573 | | | | | | 448 | | | | | | 72 | | | | | | 2,093 | | | | | | 1,394 | | | | | | 389 | | | | | | 86 | | | | | | 1,869 | | | Certificates and emission rights | | | | | | | | | | | | | | | | | 75 | | | | | | 75 | | | | | | | | | | | | | | | | | | 69 | | | | | | 69 | | | | | | | | 1,892 | | | | | | 599 | | | | | | 2,088 | | | | | | 4,579 | | | | | | 2,043 | | | | | | 533 | | | | | | 2,061 | | | | | | 4,637 | | | |
OtherCurrent inventories of raware disclosed as follows:
(€ million) | | | December 31, 2019 | | | December 31, 2018 | | Raw and auxiliary materials and consumables | | | | | 950 | | | | | | 889 | | | Consumables for infrastructure and facility maintenance of perforation activities | | | | | 1,477 | | | | | | 1,451 | | | Finished products and goods | | | | | 2,284 | | | | | | 2,274 | | | Work in progress | | | | | 8 | | | | | | | | | Certificates and emission rights | | | | | 15 | | | | | | 37 | | | | | | | | 4,734 | | | | | | 4,651 | | |
Raw and auxiliary materials and consumables of €1,903 million (€1,933 million at December 31, 2015)include oil-based feedstock, catalysts and other consumables pertaining to refining and chemical activities. Materials and supplies include materials to be consumed in drilling activities and spare parts related to the Exploration & Production segment for €1,699€1,359 million (€1,7321,334 million at December 31, 2015)2018). Finished products and primarily comprised materials relating to perforation activitiesgoods included gas and the maintenance of infrastructurespetroleum products for €1,467 million (€1,543 million at December 31, 2018) and facilities.chemical products for €547 million (same amount at December 31, 2018). Certificates and emission rights of €69 million (€75 million at December 31, 2015) are measured at the fair value determined based on market quotations.prices. The fair value hierarchy is level 1. Inventories of €82€95 million (€87 million(same amount at December 31, 2015)2018) were pledged to guarantee the potential balancing with respect toestimated imbalance in volumes input to/off-taken from the national gas network operated by Snam Rete Gas SpA. Changes in inventories and in the loss provision were as follows:
(€ million) | | | Carrying amount at the beginning of the year | | | Changes | | | New or increased provisions | | | Deductions | | | Currency translation differences | | | Other changes | | | Carrying amount at the end of the year | | 2015 | | | | | | | | | Gross carrying amount | | | | | 8,027 | | | | | | (1,082) | | | | | | | | | | | | | | | | | | 249 | | | | | | (2,307) | | | | | | 4,887 | | | Loss provision | | | | | (472) | | | | | | | | | | | | (93) | | | | | | 212 | | | | | | (10) | | | | | | 55 | | | | | | (308) | | | Net carrying amount | | | | | 7,555 | | | | | | (1,082) | | | | | | (93) | | | | | | 212 | | | | | | 239 | | | | | | (2,252) | | | | | | 4,579 | | | 2016 | | | | | | | | | Gross carrying amount | | | | | 4,887 | | | | | | (29) | | | | | | | | | | | | | | | | | | 61 | | | | | | (27) | | | | | | 4,892 | | | Loss provision | | | | | (308) | | | | | | | | | | | | (125) | | | | | | 163 | | | | | | (5) | | | | | | 20 | | | | | | (255) | | | Net carrying amount | | | | | 4,579 | | | | | | (29) | | | | | | (125) | | | | | | 163 | | | | | | 56 | | | | | | (7) | | | | | | 4,637 | | | |
Negative changesInventories are stated net of the period amounting to €29write-down provisions of €377 million (€578 million at December 31, 2018).
Inventories held for compliance purposes of €1,371 million (€1,217 million at December 31, 2018) related to Italian subsidiaries for €1,353 million (€1,200 million at December 31, 2018) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws. 9 Income tax receivables and payables (€ million) | | | December 31, 2019 | | | December 31, 2018 | | | Receivables | | | Payables | | | Receivables | | | Payables | | | Current | | | Non-Current | | | Current | | | Non-Current | | | Current | | | Non-Current | | | Current | | | Non-Current | | Income taxes | | | | | 192 | | | | | | 173 | | | | | | 456 | | | | | | 454 | | | | | | 191 | | | | | | 168 | | | | | | 440 | | | | | | 287 | | |
Income taxes are described in note 32 — Income tax expense. Non-current income tax payables include the Chemical business line for €96 million partially offset by the increaselikely outcome of pending litigation with tax authorities in the Refining & Marketing segment for €75 million. The increase in loss provisionrelation to uncertain tax matters relating to foreign subsidiaries of €125 million related to the Exploration & Production segment for €72 million. Deductions of €163€362 million for loss provision primarily related to the Refining & Marketing business line (€122 million). Other changes of €2,252255 million as ofat December 31, 2015, included the reclassification of €2,183 million as discontinued operations.
13 Current tax assets
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Italian subsidiaries | | | | | 182 | | | | | | 134 | | | Subsidiaries outside Italy | | | | | 178 | | | | | | 249 | | | | | | | | 360 | | | | | | 383 | | | |
Income taxes are described in note 43 — Income tax expense.2018).
1410 Other current tax assets and liabilities
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | VAT | | | | | 386 | | | | | | 447 | | | Excise and customs duties | | | | | 121 | | | | | | 161 | | | Other taxes and duties | | | | | 123 | | | | | | 81 | | | | | | | | 630 | | | | | | 689 | | | |
15 Other current assets
(€ million) | | | | December 31, 2019 | | December 31, 2018 | | | | Assets | | Liabilities | | Assets | | Liabilities | | | December 31, 2015 | | December 31, 2016 | | | Current | | Non-current | | Current | | Non-current | | Current | | Non-current | | Current | | Non-current | | Fair value of derivative financial instruments | | | | 3,220 | | | | | 2,248 | | | | | | 2,573 | | | | | 54 | | | | | 2,704 | | | | | 50 | | | | | 1,594 | | | | | 68 | | | | | 1,445 | | | | | 40 | | | Other current assets | | | | 422 | | | | | 343 | | | | Contract liabilities | | | | | | | | | | | | | | | 1,669 | | | | | 456 | | | | | | | | | | | | | | | 1,108 | | | | | 518 | | | Other Taxes | | | | | 766 | | | | | 223 | | | | | 1,411 | | | | | 63 | | | | | 561 | | | | | 254 | | | | | 1,432 | | | | | 34 | | | Other | | | | | 633 | | | | | 594 | | | | | 1,362 | | | | | 1,042 | | | | | 664 | | | | | 302 | | | | | 1,427 | | | | | 883 | | | | | | | 3,642 | | | | | 2,591 | | | | | | 3,972 | | | | | 871 | | | | | 7,146 | | | | | 1,611 | | | | | 2,819 | | | | | 624 | | | | | 5,412 | | | | | 1,475 | | | | |
The fair value related to derivative financial instruments is disclosed in note 3423 — Derivative financial instruments.instruments and hedge accounting. Other assets amountingAssets related to €343other current taxes refer to VAT for €742 million, of which €557 million are current, and related to advances made in December (€422608 million at December 31, 2015) included2018, of which €383 million current).
Other assets include: (i) gas volumes prepayments that were made in previous reporting periodyears due to the take-or-pay obligations in relation to the Company’s long-term supply contracts asof €174 million (€26 million at December 31, 2018); in 2019 the Company is forecastingopted to make-upincrease the take-or-pay advance with a view of optimizing its gas portfolio, expecting to recover the underlying gas volumes within the next year; (ii) non-current receivables for investing activities for €11 million (€9 million at December 31, 2018). Contract liabilities included: (i) advances denominated in local currency of €1,228 million (€716 million at December 31, 2018) to offset future supplies of equity hydrocarbons to our Egyptian State-owned partners in relation to the operations of Eni’s Concession Agreements in the next 12 months. The residual amount asCountry, in particular, among these, the Zohr project; (ii) the current portion of advances received by Engie SA (former Suez) relating to a long-term agreement for supplying natural gas and electricity for €64 million (€66 million at December 31, 2016 for €902018); the non-current portion amounted to €455 million reflected the off-taken of underlying volumes achieved during the period that reduced the amount outstanding(€518 million at the end of 2015 by €108 million. In 2016, the carrying amountDecember 31, 2018). Other current liabilities included overlifting imbalances of the prepayment, assimilatedExploration & Production segment for €917 million (€1,004 million at December 31, 2018). Liabilities related to a receivable in kind, was written down by €24other current taxes include excise duties and consumer taxes for €628 million to align it to(€636 million at December 31, 2018) and VAT liabilities for €311 million (€359 million at December 31, 2018). Other non-current liabilities include cautionary deposits from retail customers for the current pricessupply of gas.gas and electricity of €231 million (€233 million at December 31 2018). Transactions with related parties are described in note 4736 — Transactions with related parties. Non-current assets
16 Property, plant and equipment
(€ million) | | | Net book amount at the beginning of the year | | | Additions | | | Depreciation | | | Net Impairments/ reversal | | | Write-off | | | Currency translation differences | | | Reclassification to discontinued operations and assets held for sale | | | Other changes | | | Net book amount at the end of the year | | | Gross book amount at the end of the year | | | Provisions for depreciation and impairments | | 2015 | | | | | | | | | | | | | Land | | | | | 615 | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | (13) | | | | | | (98) | | | | | | 5 | | | | | | 510 | | | | | | 534 | | | | | | 24 | | | Buildings | | | | | 1,633 | | | | | | 32 | | | | | | (70) | | | | | | (47) | | | | | | | | | | | | 16 | | | | | | (602) | | | | | | (144) | | | | | | 818 | | | | | | 3,374 | | | | | | 2,556 | | | Plant and machinery | | | | | 47,506 | | | | | | 369 | | | | | | (8,403) | | | | | | (3,624) | | | | | | | | | | | | 3,276 | | | | | | (6,264) | | | | | | 7,807 | | | | | | 40,667 | | | | | | 147,969 | | | | | | 107,302 | | | Industrial and commercial equipment | | | | | 590 | | | | | | 49 | | | | | | (85) | | | | | | (1) | | | | | | (2) | | | | | | 14 | | | | | | (197) | | | | | | (42) | | | | | | 326 | | | | | | 1,368 | | | | | | 1,042 | | | Other assets | | | | | 458 | | | | | | 57 | | | | | | (88) | | | | | | (6) | | | | | | | | | | | | 17 | | | | | | (37) | | | | | | 2 | | | | | | 403 | | | | | | 2,169 | | | | | | 1,766 | | | Tangible assets in progress and advances | | | | | 25,189 | | | | | | 10,669 | | | | | | | | | | | | (2,312) | | | | | | (676) | | | | | | 2,009 | | | | | | (311) | | | | | | (9,287) | | | | | | 25,281 | | | | | | 29,835 | | | | | | 4,554 | | | | | | | | 75,991 | | | | | | 11,177 | | | | | | (8,646) | | | | | | (5,990) | | | | | | (678) | | | | | | 5,319 | | | | | | (7,509) | | | | | | (1,659) | | | | | | 68,005 | | | | | | 185,249 | | | | | | 117,244 | | | 2016 | | | | | | | | | | | | | Land | | | | | 510 | | | | | | 1 | | | | | | | | | | | | (64) | | | | | | | | | | | | 1 | | | | | | (8) | | | | | | 8 | | | | | | 448 | | | | | | 537 | | | | | | 89 | | | Buildings | | | | | 818 | | | | | | 22 | | | | | | (66) | | | | | | (3) | | | | | | | | | | | | 1 | | | | | | (2) | | | | | | 40 | | | | | | 810 | | | | | | 3,416 | | | | | | 2,606 | | | Plant and machinery | | | | | 40,667 | | | | | | 204 | | | | | | (7,087) | | | | | | 345 | | | | | | (198) | | | | | | 1,329 | | | | | | (1) | | | | | | 15,011 | | | | | | 50,270 | | | | | | 167,007 | | | | | | 116,737 | | | Industrial and commercial equipment | | | | | 326 | | | | | | 32 | | | | | | (66) | | | | | | (1) | | | | | | (2) | | | | | | | | | | | | | | | | | | 11 | | | | | | 300 | | | | | | 1,415 | | | | | | 1,115 | | | Other assets | | | | | 403 | | | | | | 42 | | | | | | (89) | | | | | | (17) | | | | | | | | | | | | 4 | | | | | | | | | | | | (34) | | | | | | 309 | | | | | | 2,160 | | | | | | 1,851 | | | Tangible assets in progress and advances | | | | | 25,281 | | | | | | 8,766 | | | | | | | | | | | | (174) | | | | | | (89) | | | | | | 551 | | | | | | | | | | | | (15,679) | | | | | | 18,656 | | | | | | 22,737 | | | | | | 4,081 | | | | | | | | 68,005 | | | | | | 9,067 | | | | | | (7,308) | | | | | | 86 | | | | | | (289) | | | | | | 1,886 | | | | | | (11) | | | | | | (643) | | | | | | 70,793 | | | | | | 197,272 | | | | | | 126,479 | | | |
A breakdown by segment11 Property, plant and equipment
(€ million) | | | Land and buildings | | | E&P wells, plant and machinery | | | Other plant and machinery | | | E&P exploration assets and appraisal | | | E&P tangible assets in progress | | | Other tangible assets in progress and advances | | | Total | | 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net carrying amount – beginning of the year | | | | | 1,274 | | | | | | 42,856 | | | | | | 3,901 | | | | | | 1,267 | | | | | | 9,195 | | | | | | 1,809 | | | | | | 60,302 | | | Additions | | | | | 12 | | | | | | 144 | | | | | | 223 | | | | | | 508 | | | | | | 6,170 | | | | | | 992 | | | | | | 8,049 | | | Depreciation capitalized | | | | | | | | | | | | | | | | | | | | | | | 14 | | | | | | 202 | | | | | | | | | | | | 216 | | | Depreciation (*) | | | | | (60) | | | | | | (6,435) | | | | | | (537) | | | | | | | | | | | | | | | | | | | | | | | | (7,032) | | | Reversals | | | | | 44 | | | | | | 65 | | | | | | 69 | | | | | | | | | | | | 65 | | | | | | 139 | | | | | | 382 | | | Impairment | | | | | (47) | | | | | | (659) | | | | | | (500) | | | | | | | | | | | | (669) | | | | | | (537) | | | | | | (2,412) | | | Write-off | | | | | | | | | | | | | | | | | (5) | | | | | | (216) | | | | | | (49) | | | | | | | | | | | | (270) | | | Disposals | | | | | (1) | | | | | | (3) | | | | | | (1) | | | | | | (22) | | | | | | (80) | | | | | | (6) | | | | | | (113) | | | Currency translation differences | | | | | 2 | | | | | | 815 | | | | | | 21 | | | | | | 24 | | | | | | 181 | | | | | | 1 | | | | | | 1,044 | | | Initial recognition and changes in estimates | | | | | | | | | | | 2,028 | | | | | | | | | | | | 25 | | | | | | 21 | | | | | | | | | | | | 2,074 | | | Transfers | | | | | 42 | | | | | | 7,568 | | | | | | 597 | | | | | | (42) | | | | | | (7,526) | | | | | | (639) | | | | | | | | | Other changes | | | | | (48) | | | | | | 113 | | | | | | (136) | | | | | | 5 | | | | | | (98) | | | | | | 116 | | | | | | (48) | | | Net carrying amount – end of the year | | | | | 1,218 | | | | | | 46,492 | | | | | | 3,632 | | | | | | 1,563 | | | | | | 7,412 | | | | | | 1,875 | | | | | | 62,192 | | | Gross carrying amount – end of the year | | | | | 4,067 | | | | | | 144,789 | | | | | | 28,191 | | | | | | 1,563 | | | | | | 11,406 | | | | | | 2,799 | | | | | | 192,815 | | | Provisions for depreciation and impairments | | | | | 2,849 | | | | | | 98,297 | | | | | | 24,559 | | | | | | | | | | | | 3,994 | | | | | | 924 | | | | | | 130,623 | | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net carrying amount – beginning of the year | | | | | 1,313 | | | | | | 45,782 | | | | | | 3,877 | | | | | | 1,371 | | | | | | 9,469 | | | | | | 1,346 | | | | | | 63,158 | | | Additions | | | | | 18 | | | | | | 432 | | | | | | 173 | | | | | | 330 | | | | | | 6,947 | | | | | | 878 | | | | | | 8,778 | | | Depreciation (*) | | | | | (65) | | | | | | (6,012) | | | | | | (529) | | | | | | | | | | | | | | | | | | | | | | | | (6,606) | | | Reversal | | | | | 41 | | | | | | 299 | | | | | | 86 | | | | | | | | | | | | | | | | | | | | | | | | 426 | | | Impairment | | | | | (61) | | | | | | (477) | | | | | | (73) | | | | | | | | | | | | (548) | | | | | | (117) | | | | | | (1,276) | | | Write-off | | | | | | | | | | | (12) | | | | | | (1) | | | | | | (66) | | | | | | (4) | | | | | | (1) | | | | | | (84) | | | Disposals | | | | | (2) | | | | | | (400) | | | | | | (9) | | | | | | (32) | | | | | | (198) | | | | | | 2 | | | | | | (639) | | | Currency translation differences | | | | | 2 | | | | | | 1,623 | | | | | | 36 | | | | | | 53 | | | | | | 385 | | | | | | (1) | | | | | | 2,098 | | | Changes in the scope of consolidation | | | | | 1 | | | | | | (4,388) | | | | | | 32 | | | | | | (58) | | | | | | (474) | | | | | | 10 | | | | | | (4,877) | | | Transfers | | | | | 81 | | | | | | 6,795 | | | | | | 461 | | | | | | (294) | | | | | | (6,501) | | | | | | (542) | | | | | | | | | Other changes | | | | | (54) | | | | | | (786) | | | | | | (152) | | | | | | (37) | | | | | | 119 | | | | | | 234 | | | | | | (676) | | | Net carrying amount – end of the year | | | | | 1,274 | | | | | | 42,856 | | | | | | 3,901 | | | | | | 1,267 | | | | | | 9,195 | | | | | | 1,809 | | | | | | 60,302 | | | Gross carrying amount – end of the year | | | | | 4,060 | | | | | | 135,467 | | | | | | 27,516 | | | | | | 1,267 | | | | | | 12,559 | | | | | | 2,415 | | | | | | 183,284 | | | Provisions for depreciation and impairments | | | | | 2,786 | | | | | | 92,611 | | | | | | 23,615 | | | | | | | | | | | | 3,364 | | | | | | 606 | | | | | | 122,982 | | | |
(*)
Before capitalization of capital expenditures made in 2016 is provided below:depreciation | | | | | (€ million) | | | 2015 | | | 2016 | | Capital expenditure | | | | Exploration & Production | | | | | 9,943 | | | | | | 8,217 | | | Gas & Power | | | | | 109 | | | | | | 66 | | | Refining & Marketing and Chemical | | | | | 614 | | | | | | 655 | | | Engineering & Construction | | | | | 550 | | | | Corporate and other activities | | | | | 46 | | | | | | 42 | | | Elimination of intragroup profits | | | | | (85) | | | | | | 87 | | | | | | | | 11,177 | | | | | | 9,067 | | | |
Capital expenditures included capitalized finance expenses of €105€93 million (€16552 million in 2015) and2018) related to the Exploration & Production segment for €71 million (€90 million)37 million in 2018). The interest ratesrate used for capitalizing finance expense ranged from 2.7%2.6% to 5.3% (2.4% and 5.3%2.8% (2.3% to 2.4% at December 31, 2015)2018). Capital expenditures primarily related to the Exploration & Production segment for €6,889 million (€7,757 million in 2018) and included the consideration of €400 million paid for the acquisition of a proved and unproved mineral interest in an already participated producing field in the United States, an entry bonus in a property under development in Algeria and the residual entry bonus in a concession in the United Arab Emirates; therefore, part of those expenditures increased unproved mineral properties. More information is reported in note 35 — Segment information and information by geographical area. The main depreciation rates used were substantially unchanged from the previous year and ranged as follows: (%) | | | | | | | | Buildings | | | | | 2 - 10– 10 | | | PlantMineral exploration wells and plants | | | | | UOP | | | Refining and chemical plants | | | | | 3 – 17 | | | Gas pipelines and compression stations | | | | | 4 – 12 | | | Power plants | | | | | 4 – 5 | | | Other plant and machinery | | | 2 - 15 | | 6 – 12 | | | Industrial and commercial equipment | | | 4 - 33 | | 5 – 25 | | | Other assets | | | 6 - 33 | | 10 – 20 | | | |
The criteria adopted by Eni for determining net impairments/reversals is reported in note 19 — Impairment/reversal of tangible and intangible assets.
Write-off of €289 million (€678 million in 2015) related for €193 million to the EST conversion plant units at the Sannazzaro refinery, damaged in an accident occurred in December 2016. The Exploration & Production booked €93 million of asset write-offs (€676 million in 2015), of which €88 million mainly relating exploration wells capitalized in previous reporting periods. Wells write-offs comprised suspended exploration wells that did not encountered enough quantities of commercial hydrocarbons to justify their completion as productive wells in Libya, Angola, Congo and Indonesia.
Foreign currency translation differences of €1,886 million primarily related to translations of entities accounts denominated in U.S. dollar (€1,761 million), Norwegian krone (€318 million) and, as decrease, in in British pound (€215 million).
Other changes of €643 million related to the initial recognition and change in estimates of decommissioning costs and site restoration in the Exploration & Production segment amounting to €665 million (€817 million at December 31, 2015) mainly due to a steeper discount rate curve, especially for the U.S. dollar and to the revision of cost estimates. These effects were partially offset by the recognition of new obligations incurred during the year. Other changes in tangible assets in progress and advances of €15,679 million included the reclassification from plant and machinery of the carrying amount of the idle units of the EST plant of the Sannazzaro refinery for €485 million until the re-entry into operations of the damaged section.
TangibleThe criteria adopted by Eni for determining impairment losses and reversal is reported in note 14 — Impairment review of tangible and intangible assets in progress and advances include costsright-of-use assets.
Foreign currency translation differences primarily related to exploration activitiessubsidiaries which utilize the U.S. dollar as functional currency (€976 million). Initial recognition and appraisalchanges in estimates include the increase in the asset retirement cost of Exploration & Production tangible assets due to the decrease in the discount rate curve and new obligations recorded during the year. Transfers from E&P tangible assets in progress to E&P UOP wells, plant and advancesmachinery related for €4,560 million to progress in the development of reserves primarily in Egypt, Mexico, Libya, Ghana and Angola. Changes in exploration and appraisal activities related to: (i) the successful completion of exploration and appraisal activities at certain suspended exploration wells and their transfer to tangible assets for €46 million, primarily in Egypt and Angola; (ii) write-off of unsuccessful exploration wells costs for €183 million mainly in Australia, Kazakhstan, Pakistan, China and United Kingdom. Exploration and appraisal activities related for €1,246 million to costs of suspended exploration wells pending final determination and for €317 million to costs of exploration wells in progress at the end of the Exploration & Production segment: (€ million) | | | Book amount at the beginning of the year | | | Additions | | | Net impairments/ reversals | | | Write-off | | | Reclassifications | | | Other changes and currency translation differences | | | Book amount at the end of the year | | 2015 | | | | | | | | | Exploration activity and appraisal | | | | | | | | | Exploratory wells in progress | | | | | 196 | | | | | | 558 | | | | | | | | | | | | (106) | | | | | | (572) | | | | | | 17 | | | | | | 93 | | | Exploratory wells completed and being evaluated | | | | | 1,568 | | | | | | | | | | | | | | | | | | (501) | | | | | | 520 | | | | | | 150 | | | | | | 1,737 | | | Exploratory successful wells in progress | | | | | 813 | | | | | | | | | | | | (91) | | | | | | | | | | | | 5 | | | | | | 80 | | | | | | 807 | | | | | | | | 2,577 | | | | | | 558 | | | | | | (91) | | | | | | (607) | | | | | | (47) | | | | | | 247 | | | | | | 2,637 | | | Other tangible assets in progress | | | | | | | | | Unproved mineral interest | | | | | 3,092 | | | | | | | | | | | | (998) | | | | | | | | | | | | (203) | | | | | | 321 | | | | | | 2,212 | | | Wells and plants in progress | | | | | 17,958 | | | | | | 9,346 | | | | | | (866) | | | | | | (69) | | | | | | (8,107) | | | | | | 1,196 | | | | | | 19,458 | | | | | | | | 21,050 | | | | | | 9,346 | | | | | | (1,864) | | | | | | (69) | | | | | | (8,310) | | | | | | 1,517 | | | | | | 21,670 | | | | | | | | 23,627 | | | | | | 9,904 | | | | | | (1,955) | | | | | | (676) | | | | | | (8,357) | | | | | | 1,764 | | | | | | 24,307 | | | 2016 | | | | | | | | | Exploration activity and appraisal | | | | | | | | | Exploratory wells in progress | | | | | 93 | | | | | | 402 | | | | | | | | | | | | | | | | | | (282) | | | | | | 8 | | | | | | 221 | | | Exploratory wells completed and being evaluated | | | | | 1,737 | | | | | | | | | | | | | | | | | | (109) | | | | | | 6 | | | | | | 50 | | | | | | 1,684 | | | Exploratory successful wells in progress | | | | | 807 | | | | | | | | | | | | (5) | | | | | | | | | | | | 78 | | | | | | 33 | | | | | | 913 | | | | | | | | 2,637 | | | | | | 402 | | | | | | (5) | | | | | | (109) | | | | | | (198) | | | | | | 91 | | | | | | 2,818 | | | Other tangible assets in progress | | | | | | | | | Unproved mineral interest | | | | | 2,212 | | | | | | 2 | | | | | | 190 | | | | | | | | | | | | (35) | | | | | | 81 | | | | | | 2,450 | | | Wells and plants in progress | | | | | 19,458 | | | | | | 7,777 | | | | | | (210) | | | | | | (6) | | | | | | (15,699) | | | | | | 370 | | | | | | 11,690 | | | Abandonment cost | | | | | | | | | | | | | | | | | | | | | | | 27 | | | | | | | | | | | | 55 | | | | | | 82 | | | | | | | | 21,670 | | | | | | 7,779 | | | | | | (20) | | | | | | 21 | | | | | | (15,734) | | | | | | 506 | | | | | | 14,222 | | | | | | | | 24,307 | | | | | | 8,181 | | | | | | (25) | | | | | | (88) | | | | | | (15,932) | | | | | | 597 | | | | | | 17,040 | | | |
Reclassifications of €15,932 million mainly relatedyear. Changes relating to suspended wells and production plants started to production in the year for €15,699 million, particularly due to the start-up of major oil&gas projects such as the Kashagan project in Kazakhstan, the Goliat project in Norway and the ‘Mpungi field in the West Hub project, Block 15/06 in Angola.are showed:
(€ million) | | | 2019 | | | 2018 | | | 2017 | | Costs for exploratory wells suspended – beginning of the year | | | | | 1,101 | | | | | | 1,263 | | | | | | 1,684 | | | Increases for which is ongoing the determination of proved reserves | | | | | 368 | | | | | | 235 | | | | | | 451 | | | Amounts previously capitalized and expensed in the year | | | | | (183) | | | | | | (61) | | | | | | (217) | | | Reclassification to successful exploratory wells following the estimation of proved reserves | | | | | (46) | | | | | | (297) | | | | | | (278) | | | Disposals | | | | | (15) | | | | | | (6) | | | | | | (199) | | | Changes in the scope of consolidation | | | | | | | | | | | (58) | | | | | | | | | Reclassification to assets held for sale | | | | | | | | | | | (24) | | | | | | | | | Currency translation differences | | | | | 21 | | | | | | 49 | | | | | | (178) | | | Costs for exploratory wells suspended – end of the year | | | | | 1,246 | | | | | | 1,101 | | | | | | 1,263 | | |
The following information relates to the stratification of the suspended wells pending final determination of proved reserves (aging) and the projects to which they relate:(ageing): | | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Costs for exploratory wells suspended at the beginning of the period | | | | | 1,618 | | | | | | 1,568 | | | | | | 1,737 | | | Additions pending the determination of proved reserves | | | | | 373 | | | | | | 550 | | | | | | 282 | | | Amounts charged to expense | | | | | (267) | | | | | | (501) | | | | | | (109) | | | Reclassification to productive wells on determination of proved reserves | | | | | (314) | | | | | | (30) | | | | | | (276) | | | Sales | | | | | | | | | | | (4) | | | | Exchange differences | | | | | 158 | | | | | | 154 | | | | | | 50 | | | Costs for exploratory wells suspended at the end of the period | | | | | 1,568 | | | | | | 1,737 | | | | | | 1,684 | | | |
| | | 2019 | | | 2018 | | | 2017 | | | | | (€ million) | | | (number of wells in Eni’s interest) | | | (€ million) | | | (number of wells in Eni’s interest) | | | (€ million) | | | (number of wells in Eni’s interest) | | Costs capitalized and suspended for exploratory well activity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - within 1 year | | | | | 185 | | | | | | 7.7 | | | | | | 111 | | | | | | 7.0 | | | | | | 222 | | | | | | 8.0 | | | - between 1 and 3 years | | | | | 171 | | | | | | 6.4 | | | | | | 87 | | | | | | 2.9 | | | | | | 241 | | | | | | 3.9 | | | - beyond 3 years | | | | | 890 | | | | | | 26.4 | | | | | | 903 | | | | | | 24.2 | | | | | | 800 | | | | | | 21.4 | | | | | | | | 1,246 | | | | | | 40.5 | | | | | | 1,101 | | | | | | 34.1 | | | | | | 1,263 | | | | | | 33.3 | | | Costs capitalized for suspended wells | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - fields including wells drilled over the last 12 months | | | | | 185 | | | | | | 7.7 | | | | | | 111 | | | | | | 7.0 | | | | | | 148 | | | | | | 5.9 | | | - fields for which the delineation campaign is in progress | | | | | 556 | | | | | | 11.3 | | | | | | 217 | | | | | | 4.7 | | | | | | 261 | | | | | | 4.7 | | | - fields including commercial discoveries that proceeds to sanctioning | | | | | 505 | | | | | | 21.5 | | | | | | 773 | | | | | | 22.4 | | | | | | 854 | | | | | | 22.7 | | | | | | | | 1,246 | | | | | | 40.5 | | | | | | 1,101 | | | | | | 34.1 | | | | | | 1,263 | | | | | | 33.3 | | |
| | | | | | | | 2014 | | | 2015 | | | 2016 | | | | | (€ million) | | | (number of wells in Eni’s interest) | | | (€ million) | | | (number of wells in Eni’s interest) | | | (€ million) | | | (number of wells in Eni’s interest) | | Costs capitalized and suspended for exploratory well activity | | | | | | | | - within 1 year | | | | | 392 | | | | | | 7.85 | | | | | | 368 | | | | | | 5.32 | | | | | | 16 | | | | | | 1.05 | | | - between 1 and 3 years | | | | | 756 | | | | | | 15.07 | | | | | | 634 | | | | | | 11.14 | | | | | | 609 | | | | | | 10.25 | | | - beyond 3 years | | | | | 420 | | | | | | 12.87 | | | | | | 735 | | | | | | 18.97 | | | | | | 1,059 | | | | | | 21.55 | | | | | | | | 1,568 | | | | | | 35.79 | | | | | | 1,737 | | | | | | 35.43 | | | | | | 1,684 | | | | | | 32.85 | | | Costs capitalized for suspended wells | | | | | | | | - fields including wells drilled over the last 12 months | | | | | 392 | | | | | | 7.85 | | | | | | 368 | | | | | | 5.32 | | | | | | 9 | | | | | | 0.55 | | | - fields for which the delineation campaign is in progress | | | | | 1,043 | | | | | | 21.90 | | | | | | 228 | | | | | | 4.13 | | | | | | 251 | | | | | | 3.51 | | | - fields including commercial discoveries that are progressing to sanctioning | | | | | 133 | | | | | | 6.04 | | | | | | 1,141 | | | | | | 25.98 | | | | | | 1,424 | | | | | | 28.79 | | | | | | | | 1,568 | | | | | | 35.79 | | | | | | 1,737 | | | | | | 35.43 | | | | | | 1,684 | | | | | | 32.85 | | | |
Suspended wells costs awaiting a final investment decision amounted to €505 million and included a significant amount relating to the exploration costs incurred for the Mamba discovery in Mozambique’s offshore Area 4, for which the venture partners are completing the activities for sanctioning the project. The other suspended costs refer to initiatives ongoing in the main countries of presence (Nigeria, Angola, Congo and Egypt), none of which, however, represents an individually significant amount. Unproved mineral interests include the purchase price allocated to unproved reserves following business combinations or acquisition of individual properties. Unproved mineral interests were recognized in connection with the purchase price allocation as part of business combinations or acquisitions of individual properties:follows: (€ million) | | | Book amount at the beginning of the year | | | Acquisitions | | | Net reversals (impairments) | | | Reclassification to proved mineral interest | | | Other changes and currency translation differences | | | Book amount at the end of the year | | 2015 | | | | | | | | Congo | | | | | 1,214 | | | | | | | | | | | | (201) | | | | | | (127) | | | | | | 135 | | | | | | 1,021 | | | Nigeria | | | | | 823 | | | | | | | | | | | | | | | | | | | | | | | | 85 | | | | | | 908 | | | Turkmenistan | | | | | 524 | | | | | | | | | | | | (411) | | | | | | | | | | | | 52 | | | | | | 165 | | | Algeria | | | | | 373 | | | | | | | | | | | | (386) | | | | | | (22) | | | | | | 35 | | | | USA | | | | | 123 | | | | | | | | | | | | | | | | | | (20) | | | | | | 6 | | | | | | 109 | | | Egypt | | | | | 35 | | | | | | | | | | | | | | | | | | (34) | | | | | | 8 | | | | | | 9 | | | | | | | | 3,092 | | | | | | | | | | | | (998) | | | | | | (203) | | | | | | 321 | | | | | | 2,212 | | | 2016 | | | | | | | | Congo | | | | | 1,021 | | | | | | | | | | | | 190 | | | | | | | | | | | | 43 | | | | | | 1,254 | | | Nigeria | | | | | 908 | | | | | | | | | | | | | | | | | | | | | | | | 30 | | | | | | 938 | | | Turkmenistan | | | | | 165 | | | | | | | | | | | | | | | | | | (31) | | | | | | 4 | | | | | | 138 | | | USA | | | | | 109 | | | | | | | | | | | | | | | | | | | | | | | | 4 | | | | | | 113 | | | Egypt | | | | | 9 | | | | | | 2 | | | | | | | | | | | | (4) | | | | | | | | | | | | 7 | | | | | | | | 2,212 | | | | | | 2 | | | | | | 190 | | | | | | (35) | | | | | | 81 | | | | | | 2,450 | | | |
In 2016, Eni recorded reversals of previous impairment losses for €190 million (see note 19 – Impairment/reversal of tangible and intangible assets).
(€ million) | | | Congo | | | Nigeria | | | Turkmenistan | | | USA | | | Algeria | | | Egypt | | | United Arab Emirates | | | Total | | 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Book amount at the beginning of the year | | | | | 769 | | | | | | 921 | | | | | | 77 | | | | | | 103 | | | | | | 77 | | | | | | 29 | | | | | | 502 | | | | | | 2,478 | | | Additions | | | | | | | | | | | | | | | | | | | | | | | 97 | | | | | | 135 | | | | | | 1 | | | | | | 23 | | | | | | 256 | | | Net (impairments) reversals | | | | | (533) | | | | | | | | | | | | 65 | | | | | | (27) | | | | | | | | | | | | | | | | | | | | | | | | (495) | | | Reclassification to proved mineral interest | | | | | | | | | | | | | | | | | (4) | | | | | | (14) | | | | | | (99) | | | | | | (12) | | | | | | | | | | | | (129) | | | Currency translation differences | | | | | 17 | | | | | | 18 | | | | | | 1 | | | | | | 3 | | | | | | 2 | | | | | | 1 | | | | | | 10 | | | | | | 52 | | | Book amount at the end of the year | | | | | 253 | | | | | | 939 | | | | | | 139 | | | | | | 162 | | | | | | 115 | | | | | | 19 | | | | | | 535 | | | | | | 2,162 | | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Book amount at the beginning of the year | | | | | 1,162 | | | | | | 825 | | | | | | 192 | | | | | | 99 | | | | | | 105 | | | | | | 7 | | | | | | | | | | | | 2,390 | | | Additions | | | | | 26 | | | | | | 56 | | | | | | | | | | | | | | | | | | | | | | | | 23 | | | | | | 487 | | | | | | 592 | | | Net (impairments) reversals | | | | | (429) | | | | | | | | | | | | (76) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (505) | | | Reclassification to proved mineral interest | | | | | (32) | | | | | | | | | | | | (44) | | | | | | | | | | | | (32) | | | | | | (2) | | | | | | | | | | | | (110) | | | Other changes and currency translation differences | | | | | 42 | | | | | | 40 | | | | | | 5 | | | | | | 4 | | | | | | 4 | | | | | | 1 | | | | | | 15 | | | | | | 111 | | | Book amount at the end of the year | | | | | 769 | | | | | | 921 | | | | | | 77 | | | | | | 103 | | | | | | 77 | | | | | | 29 | | | | | | 502 | | | | | | 2,478 | | |
Unproved mineral interestinterests comprised a property known asdenominated Oil Prospecting License 245 (“OPL 245”)(OPL 245), located offshore Nigeria, with a net book value of €932€874 million which correspondedcorresponding to the price paid in 2011 to the NigeriaNigerian Government to acquire a 50% interest in OPL 245,the property, together with the partner Shell acquiringwhich acquired the remaining 50%. As of December 31, 2016,2019, the net book value of the property was €1,255amounted to €1,184 million, including capitalized exploration costs and pre-development costs. The acquisition of OPL 245 is subject to judicial proceedings in Italy and in Nigeria for alleged corruption and money laundering in respect of the Resolution Agreement signed on April 29, 2011, relating to the purchase of the license by Eni and Shell. Those proceedings are disclosed in note 38 -27 — Guarantees, Commitments and Risks. On January 27, 2017, Eni 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. Management has concluded that noThe impairment test of the asset was required. Afterconfirmed 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 engagedbook value also considering 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 has also assessed material and the information made available from the judicial authorities, no wrongdoing has been detected on Eni sidestress test assuming possible delays in the awarding process to Enistart of the license.development activities.
Accumulated provisions for impairments amounted to €17,558€18,226 million (€17,48016,471 million at December 31, 2015)2018). Property, plant and equipment include assets subject to leases for €241 million. At December 31, 2016,2019, Eni pledged property, plant and equipment for €24 million primarilyto guarantee payments of excise duties (same amount as collateral against certain borrowings (€21 million atof December 31, 2015)2018). Government grants recorded as a decrease of property, plant and equipment amounted to €90€112 million (€96125 million at December 31, 2015)2018). Assets acquired under financial lease agreements amounted to €29 million (€26 million at December 31, 2015) and related to service stations of the Refining & Marketing business line.
Contractual commitments related to the purchase of property, plant and equipment are disclosed in note 3827 — Guarantees, commitments and risks — Liquidity risk. Property, plant and equipment under concession arrangements are described in note 38 –27 — Guarantees, commitments and risks — Assets under concession arrangements. Property, plant and equipment by segment
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Property, plant and equipment, gross | | | | Exploration & Production | | | | | 154,064 | | | | | | 165,559 | | | Gas & Power | | | | | 6,169 | | | | | | 6,276 | | | Refining & Marketing and Chemical | | | | | 23,818 | | | | | | 24,119 | | | Corporate and other activities | | | | | 1,854 | | | | | | 1,886 | | | Elimination of intragroup profits | | | | | (656) | | | | | | (568) | | | | | | | | 185,249 | | | | | | 197,272 | | | Accumulated depreciation, amortization and impairment losses | | | | Exploration & Production | | | | | 92,569 | | | | | | 101,131 | | | Gas & Power | | | | | 4,287 | | | | | | 4,584 | | | Refining & Marketing and Chemical | | | | | 19,154 | | | | | | 19,477 | | | Corporate and other activities | | | | | 1,436 | | | | | | 1,518 | | | Elimination of intragroup profits | | | | | (202) | | | | | | (231) | | | | | | | | 117,244 | | | | | | 126,479 | | | Property, plant and equipment, net | | | | Exploration & Production | | | | | 61,495 | | | | | | 64,428 | | | Gas & Power | | | | | 1,882 | | | | | | 1,692 | | | Refining & Marketing and Chemical | | | | | 4,664 | | | | | | 4,642 | | | Corporate and other activities | | | | | 418 | | | | | | 368 | | | Elimination of intragroup profits | | | | | (454) | | | | | | (337) | | | | | | | | 68,005 | | | | | | 70,793 | | | |
17 Inventory — compulsory stock
Compulsory inventories of €1,184 million (€909 million at December 31, 2015) were primarily held by Italian subsidiaries for €1,167 million (€893 million at December 31, 2015) in accordance with minimum stock requirements for oil and petroleum products set forth by applicable laws.
12 Right-of-use assets and lease liabilities (€ million) | | | Floating production storage and offloading vessels (FPSO) | | | Drilling rig | | | Naval facilities and related logistic bases for oil and gas transportation | | | Motorway concessions and service stations | | | Oil and gas distribution facilities | | | Office buildings | | | Vehicles | | | Other | | | Total | | First adoption IFRS 16 | | | | | 3,294 | | | | | | 346 | | | | | | 569 | | | | | | 462 | | | | | | 7 | | | | | | 720 | | | | | | 43 | | | | | | 215 | | | | | | 5,656 | | | Reclassifications | | | | | | | | | | | | | | | | | | | | | | | 30 | | | | | | | | | | | | | | | | | | | | | | | | 16 | | | | | | 46 | | | Reclassifications to assets held for sale | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (13) | | | | | | (13) | | | Net carrying amount at January 1, 2019 | | | | | 3,294 | | | | | | 346 | | | | | | 569 | | | | | | 492 | | | | | | 7 | | | | | | 720 | | | | | | 43 | | | | | | 218 | | | | | | 5,689 | | | Additions | | | | | 32 | | | | | | 192 | | | | | | 219 | | | | | | 54 | | | | | | 1 | | | | | | 108 | | | | | | 22 | | | | | | 56 | | | | | | 684 | | | Depreciation(a) | | | | | (240) | | | | | | (224) | | | | | | (272) | | | | | | (61) | | | | | | (1) | | | | | | (115) | | | | | | (23) | | | | | | (63) | | | | | | (999) | | | Impairment losses | | | | | | | | | | | | | | | | | | | | | | | (13) | | | | | | | | | | | | | | | | | | | | | | | | (28) | | | | | | (41) | | | Currency translation differences | | | | | 67 | | | | | | 6 | | | | | | 4 | | | | | | 2 | | | | | | | | | | | | 3 | | | | | | | | | | | | 3 | | | | | | 85 | | | Other changes | | | | | | | | | | | (7) | | | | | | (23) | | | | | | (14) | | | | | | (1) | | | | | | (9) | | | | | | (10) | | | | | | (5) | | | | | | (69) | | | Net carrying amount at December 31, 2019 | | | | | 3,153 | | | | | | 313 | | | | | | 497 | | | | | | 460 | | | | | | 6 | | | | | | 707 | | | | | | 32 | | | | | | 181 | | | | | | 5,349 | | | Gross carrying amount | | | | | 3,393 | | | | | | 528 | | | | | | 757 | | | | | | 532 | | | | | | 7 | | | | | | 806 | | | | | | 54 | | | | | | 274 | | | | | | 6,351 | | | Provisions for depreciation and impairment | | | | | 240 | | | | | | 215 | | | | | | 260 | | | | | | 72 | | | | | | 1 | | | | | | 99 | | | | | | 22 | | | | | | 93 | | | | | | 1,002 | | | |
(a)
Before capitalization of depreciation for tangible and intangible assets The first application of IFRS 16 is disclosed in note 3 — Changes in accounting policies. Right-of-use assets (RoU) related: (i) for €3,895 million to the Exploration & Production segment and mainly comprised the operating leases of certain FPSO vessels hired in connection with operations at offshore development projects in Ghana (OCTP) and Angola (Block 15/06 West and East hub) with expiry date between 10 and 18 years including a renewal option and in addition the lease component of long-term leases of offshore rigs; (ii) for €512 million to the Refining & Marketing and Chemical segment relating to motorway concessions, land leases, leases of service stations for the sale of oil products and the car fleet dedicated to the car sharing business; (iii) for €365 million to the Gas & Power segment relating to the leasing of naval vessels for shipping activities and logistics structures for gas distribution; (iv) for €577 million to the Corporate and Other activities segment mainly regarding property rental contracts. The main leasing contracts signed for which the asset is not yet available concern: (i) a contract with a nominal value of €2.1 billion relating to an FPSO vessel that will be deployed for the development of Area 1 in Mexico. The asset is expected to enter under the Group’s control and be accounted as RoU in 2021, expiring in 2040; (ii) a contract with a nominal value of €438 million relating to leasing of office building with an expiry date of 20 years with an extension option of 6 years. The main future cash outflows potentially due not reflected in the measurements of lease liabilities related to: (i) options for the extension or termination of the lease for office buildings of €297 million; (ii) service stations for the sale of oil products of €155 million; (iii) other extension options related to concessions of land for €60 million and ancillary assets in the upstream business for €84 million. Liabilities for leased assets were as follows: (€ million) | | | Current portion of long-term lease liabilities | | | Long-term lease liabilities | | | Total | | First adoption IFRS 16 | | | | | 665 | | | | | | 4,991 | | | | | | 5,656 | | | Reclassifications | | | | | 132 | | | | | | 36 | | | | | | 168 | | | Reclassifications to liabilities directly associated with assets held for sale | | | | | (3) | | | | | | (10) | | | | | | (13) | | | Carrying amount at January 1, 2019 | | | | | 794 | | | | | | 5,017 | | | | | | 5,811 | | | Additions | | | | | | | | | | | 668 | | | | | | 668 | | | Decreases | | | | | (875) | | | | | | (2) | | | | | | (877) | | | Currency translation differences | | | | | 10 | | | | | | 77 | | | | | | 87 | | | Other changes | | | | | 960 | | | | | | (1,001) | | | | | | (41) | | | Carrying amount at December 31, 2019 | | | | | 889 | | | | | | 4,759 | | | | | | 5,648 | | | |
Lease liabilities related for €1,976 million to the portion of the liabilities attributable to the joint operators in Eni-led projects which will be recovered through the mechanism of the cash calls. Total cash outflows for leases consisted of the following: (i) cash payments for the principal portion of the lease liability for €877 million; (ii) cash payments for the interest portion of €347 million; (iii) prepayment RoU for leased assets for €16 million. The amounts recognised in the profit and loss account consist of the following: (€ million) | | | 2019 | | Other income and revenues | | | | | | | | Income from remeasurement of lease liabilitiy | | | | | 6 | | | | | | | | 6 | | | Purchases, services and other | | | | | | | | Short-term leases | | | | | 115 | | | Low-value leases | | | | | 39 | | | Variable lease payments not included in the measurement of lease liabilities | | | | | 16 | | | Capitalised direct cost associated with self-constructed assets – tangible assets | | | | | (2) | | | | | | | | 168 | | | Depreciation and impairments | | | | | | | | Depreciation of RoU leased assets | | | | | 999 | | | Capitalised direct cost associated with self-constructed assets – tangible assets | | | | | (210) | | | Impairment losses of RoU leased assets | | | | | 41 | | | | | | | | 830 | | | Finance income (expense) from leases | | | | | | | | Interests on lease liabilities | | | | | (378) | | | Capitalised finance expense of ROU leased assets – tangible assets | | | | | 17 | | | Net currency translation differences on lease liabilities | | | | | (6) | | | | | | | | (367) | | |
13 Intangible assets (€ million) | | | Net book amount at the beginning of the year | | | Additions | | | Amortization | | | Net impairments/ reversals | | | Write-off | | | Currency translation differences | | | Reclassification to discontinued operations and assets held for sale | | | Other changes | | | Net book amount at the end of the year | | | Gross book amount at the end of the year | | | Provisions for amortization and impairments | | 2015 | | | | | | | | | | | | | Intangible assets with finite useful lives | | | | | | | | | | | | | Exploration expenditures | | | | | 1,081 | | | | | | 8 | | | | | | (63) | | | | | | (369) | | | | | | (10) | | | | | | 102 | | | | | | | | | | | | (14) | | | | | | 735 | | | | | | 2,195 | | | | | | 1,460 | | | Concessions, licenses, trademarks and similar items | | | | | 479 | | | | | | 8 | | | | | | (117) | | | | | | (2) | | | | | | | | | | | | (1) | | | | | | (4) | | | | | | | | | | | | 363 | | | | | | 2,499 | | | | | | 2,136 | | | Industrial patents and intellectual property rights | | | | | 285 | | | | | | 26 | | | | | | (74) | | | | | | | | | | | | | | | | | | 1 | | | | | | (31) | | | | | | 69 | | | | | | 276 | | | | | | 1,407 | | | | | | 1,131 | | | Service concession arrangements | | | | | 32 | | | | | | | | | | | | (2) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | | | 32 | | | | | | 51 | | | | | | 19 | | | Intangible assets in progress and advances | | | | | 179 | | | | | | 54 | | | | | | | | | | | | (7) | | | | | | | | | | | | | | | | | | (7) | | | | | | (71) | | | | | | 148 | | | | | | 153 | | | | | | 5 | | | Other intangible assets | | | | | 167 | | | | | | 29 | | | | | | (47) | | | | | | (5) | | | | | | | | | | | | 2 | | | | | | (1) | | | | | | 21 | | | | | | 166 | | | | | | 2,576 | | | | | | 2,410 | | | | | | | | 2,223 | | | | | | 125 | | | | | | (303) | | | | | | (383) | | | | | | (10) | | | | | | 104 | | | | | | (43) | | | | | | 7 | | | | | | 1,720 | | | | | | 8,881 | | | | | | 7,161 | | | Intangible assets with indefinite useful lives | | | | | | | | | | | | | Goodwill | | | | | 2,197 | | | | | | | | | | | | | | | | | | (161) | | | | | | | | | | | | 34 | | | | | | (363) | | | | | | (393) | | | | | | 1,314 | | | | | | | | | | 4,420 | | | | | | 125 | | | | | | (303) | | | | | | (544) | | | | | | (10) | | | | | | 138 | | | | | | (406) | | | | | | (386) | | | | | | 3,034 | | | | | 2016 | | | | | | | | | | | | | Intangible assets with finite useful lives | | | | | | | | | | | | | Exploration expenditures | | | | | 735 | | | | | | 15 | | | | | | (18) | | | | | | 385 | | | | | | (61) | | | | | | 36 | | | | | | | | | | | | | | | | | | 1,092 | | | | | | 2,216 | | | | | | 1,124 | | | Concessions, licenses, trademarks and similar items | | | | | 363 | | | | | | 6 | | | | | | (113) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | 255 | | | | | | 2,462 | | | | | | 2,207 | | | Industrial patents and intellectual property rights | | | | | 276 | | | | | | 26 | | | | | | (81) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 38 | | | | | | 259 | | | | | | 1,467 | | | | | | 1,208 | | | Service concession arrangements | | | | | 32 | | | | | | 1 | | | | | | (2) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 31 | | | | | | 52 | | | | | | 21 | | | Intangible assets in progress and advances | | | | | 148 | | | | | | 49 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (49) | | | | | | 148 | | | | | | 153 | | | | | | 5 | | | Other intangible assets | | | | | 166 | | | | | | 16 | | | | | | (39) | | | | | | 4 | | | | | | | | | | | | (4) | | | | | | | | | | | | 21 | | | | | | 164 | | | | | | 2,599 | | | | | | 2,435 | | | | | | | | 1,720 | | | | | | 113 | | | | | | (253) | | | | | | 389 | | | | | | (61) | | | | | | 32 | | | | | | | | | | | | 9 | | | | | | 1,949 | | | | | | 8,949 | | | | | | 7,000 | | | Intangible assets with indefinite useful lives | | | | | | | | | | | | | Goodwill | | | | | 1,314 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6 | | | | | | | | | | | | | | | | | | 1,320 | | | | | | | | | | 3,034 | | | | | | 113 | | | | | | (253) | | | | | | 389 | | | | | | (61) | | | | | | 38 | | | | | | | | | | | | 9 | | | | | | 3,269 | | | | | | | | | | | | | | | |
(€ million) | | | Exploration rights | | | Industrial patents and intellectual property rights | | | Other intangible assets | | | Intangible assets with finite useful lives | | | Goodwill | | | Total | | 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net carrying amount – beginning of the year | | | | | 1,081 | | | | | | 221 | | | | | | 584 | | | | | | 1,886 | | | | | | 1,284 | | | | | | 3,170 | | | Additions | | | | | 78 | | | | | | 23 | | | | | | 210 | | | | | | 311 | | | | | | | | | | | | 311 | | | Amortization | | | | | (81) | | | | | | (93) | | | | | | (117) | | | | | | (291) | | | | | | | | | | | | (291) | | | Impairments | | | | | (19) | | | | | | | | | | | | (72) | | | | | | (91) | | | | | | (26) | | | | | | (117) | | | Write-off | | | | | (28) | | | | | | (1) | | | | | | (1) | | | | | | (30) | | | | | | | | | | | | (30) | | | Currency translation differences | | | | | 18 | | | | | | | | | | | | 1 | | | | | | 19 | | | | | | 3 | | | | | | 22 | | | Other changes | | | | | (18) | | | | | | 45 | | | | | | (37) | | | | | | (10) | | | | | | 4 | | | | | | (6) | | | Net carrying amount at the end of the year | | | | | 1,031 | | | | | | 195 | | | | | | 568 | | | | | | 1,794 | | | | | | 1,265 | | | | | | 3,059 | | | Gross carrying amount at the end of the year | | | | | 1,748 | | | | | | 1,597 | | | | | | 4,373 | | | | | | 7,718 | | | | | | | | | | | | | | | Provisions for amortization and impairment | | | | | 717 | | | | | | 1,402 | | | | | | 3,805 | | | | | | 5,924 | | | | | | | | | | | | | | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net carrying amount – beginning of the year | | | | | 995 | | | | | | 240 | | | | | | 486 | | | | | | 1,721 | | | | | | 1,204 | | | | | | 2,925 | | | Changes in accounting policies (IFRS 15) | | | | | | | | | | | | | | | | | 87 | | | | | | 87 | | | | | | | | | | | | 87 | | | Net carrying amount restated – beginning of the year | | | | | 995 | | | | | | 240 | | | | | | 573 | | | | | | 1,808 | | | | | | 1,204 | | | | | | 3,012 | | | Additions | | | | | 133 | | | | | | 28 | | | | | | 180 | | | | | | 341 | | | | | | | | | | | | 341 | | | Amortization | | | | | (71) | | | | | | (87) | | | | | | (226) | | | | | | (384) | | | | | | | | | | | | (384) | | | Impairments | | | | | | | | | | | | | | | | | (16) | | | | | | (16) | | | | | | | | | | | | (16) | | | Write-off | | | | | (15) | | | | | | | | | | | | (1) | | | | | | (16) | | | | | | | | | | | | (16) | | | Currency translation differences | | | | | 39 | | | | | | | | | | | | | | | | | | 39 | | | | | | 8 | | | | | | 47 | | | Change in the scope of consolidation | | | | | | | | | | | | | | | | | 74 | | | | | | 74 | | | | | | 46 | | | | | | 120 | | | Other changes | | | | | | | | | | | 40 | | | | | | | | | | | | 40 | | | | | | 26 | | | | | | 66 | | | Net carrying amount at the end of the year | | | | | 1,081 | | | | | | 221 | | | | | | 584 | | | | | | 1,886 | | | | | | 1,284 | | | | | | 3,170 | | | Gross carrying amount at the end of the year | | | | | 1,686 | | | | | | 1,534 | | | | | | 4,188 | | | | | | 7,408 | | | | | | | | | | | | | | | Provisions for amortization and impairment | | | | | 605 | | | | | | 1,313 | | | | | | 3,604 | | | | | | 5,522 | | | | | | | | | | | | | | | |
Exploration rights €1,092 million (€735 million at December 31, 2015) comprised the residual book value of license and leasehold property acquisition costs relating to areas with proved reserves, which are amortized based on the UOP criteria and are regularly reviewed for impairment. Furthermore, they include the cost of unproved areas which are suspended pending a final determination of the success of the exploratoryexploration activity or until management confirms its commitment to the initiative. Reversals Additions for the year related to signature bonuses paid for the acquisition of previous impairment losses of €385 million (impairments losses of €369 million were recordednew exploration acreage mainly in 2015) were recognized at proved license acquisition costs in AngolaUnited Arab Emirates, Mozambique, Mexico and Congo. More information is provided in note 19 — impairments and reversal of tangible and intangible assets. Write-offs for €61 million (€10 million in 2015) were booked at unproved exploratory rights due to the negative outcome of certain exploration projects, the most important being an initiative in Angola.Indonesia.
The breakdown of exploration rights by type of asset was as follows: (€ million) | | | December 31, 2015 | | | December 31, 2016 | | Proved license and leasehold property acquisition costs | | | | | 90 | | | | | | 497 | | | Unproved license and leasehold property acquisition costs | | | | | 611 | | | | | | 579 | | | Other mineral interests | | | | | 34 | | | | | | 16 | | | | | | | | 735 | | | | | | 1,092 | | | |
Concessions, licenses, trademarks and similar items for €255 million (€363 million at December 31, 2015) primarily comprised transmission rights for natural gas imported from Algeria of €223 million (€323 million at December 31, 2015) and concessions for mineral exploration of €13 million (€15 million at December 31, 2015).
(€ million) | | | December 31, 2019 | | | December 31, 2018 | | Proved licence and leasehold property acquisition costs | | | | | 291 | | | | | | 357 | | | Unproved licence and leasehold property acquisition costs | | | | | 709 | | | | | | 684 | | | Other mineral interests | | | | | 31 | | | | | | 40 | | | | | | | | 1,031 | | | | | | 1,081 | | |
Industrial patents and intellectual property rights of €259 million (€276 million at December 31, 2015) related to Eni SpA for €235 million (€250 million at December 31, 2015) and essentially concerned costs formainly regarded the acquisition and internal development of software and rights for the use of production processes and software. Service concession arrangements of €31 million primarily pertained to gas distribution activities outside Italy (€32 million at December 31, 2015).
Intangible assets in progress and advances of €148 million (same amount as of December 31, 2015) related to Eni SpA for €44 million (€49 million at December 31, 2015) and primarily concerned cost for software development.
Other intangible assets with finite useful lives of €164comprised: (i) customer acquisition costs relating to the retail gas business for €226 million (€166 million at December 31, 2015) comprised: (i) royalties for the use of licenses by Versalis SpA for €40 million (same amount as of December 31, 2015)2018); (ii) the estimated costs of Eni’s social responsibility projects in relation to oil development programs in Val d’Agriconcessions, licenses, trademarks and in the North Adriatic area connected to mineral rights under concessionsimilar items for €41€102 million (€49151 million at December 31, 2015) following commitments made with the Basilicata Region, the Emilia Romagna Region and the Province and Municipality2018) comprised transmission rights for natural gas imported from Algeria of Ravenna. The criteria adopted by€30 million (€27 million at December 31, 2018); (iii) capital expenditures in progress on natural gas pipelines for which Eni has acquired transport rights for determining net impairments/reversals and the relevant breakdown by segment are reported in note 19 — Impairment/reversal of tangible and intangible assets.€78 million (same amount at December 31, 2018).
The main amortization rates used were substantially unchanged from the previous year and ranged as follows: (%) | | | Exploration rights | | | 14 - 33 | | UOP – 33 | | | Concessions,Transport rights of natural gas | | | | | 3 | | | Other concessions, licenses, trademarks and similar items | | | 3 - 33 | | Industrial patents and intellectual property rights | | | 20 - 333 – 33 | | | Service concession arrangements | | | 2 - 4 | | 20 – 33 | | | Capitalized costs for customer acquisition | | | | | 25 – 33 | | | Other intangible assets | | | | | 4 - 25– 20 | | |
The carrying amount of goodwill at the end of the year was €1,320amounted €2,454 million, (€1,314 million at December 31, 2015) net of cumulative impairments charges amounting to €2,524 million (€2,525 million at December 31, 2015). Acharges. The breakdown of the stated goodwill by operating segment is provided below:
(€ million) | | December 31, 2015 | | December 31, 2016 | | | December 31, 2019 | | December 31, 2018 | | Gas & Power | | | | 1,025 | | | | | 1,025 | | | | | | 981 | | | | | 977 | | | Exploration & Production | | | | 196 | | | | | 202 | | | | | | 190 | | | | | 187 | | | Refining & Marketing | | | | 93 | | | | | 93 | | | | Refining & Marketing and Chemicals | | | | | 93 | | | | | 119 | | | Other activities | | | | | 1 | | | | | 1 | | | | | | | 1,314 | | | | | 1,320 | | | | | | 1,265 | | | | | 1,284 | | | | |
More information about goodwill is reported in note 19 — Impairment/reversal of tangible and intangible assets.
19 Impairment/reversal of tangible and intangible assets
| | | | | (€ million) | | | 2015 | | | 2016 | | Impairment losses | | | | Tangible assets | | | | | (5,993) | | | | | | (1,067) | | | Intangible assets | | | | | (544) | | | | | | | | | | | | | | (6,537) | | | | | | (1,067) | | | less: | | | | - reversal of tangible assets | | | | | 3 | | | | | | 1,153 | | | - reversal of intangible assets | | | | | | | | | | | 389 | | | | | | | | (6,534) | | | | | | 475 | | | |
In order to verify the recoverabilityAn impairment loss of the carrying amounts of tangible and intangible assets, management assesses at the end of the year whether there are any indications that assets may be impaired. External impairment indicators comprise evidence that the carrying amount of the net assets of Eni are above Eni market capitalization, expectations about future trends in the prices and margins of commodities, forecast trends in monetary variables (interest rates, exchange rates, inflation), country risk or changes in the regulatory/contractual framework. Internal impairment indicators comprise evidence of reservoirs underperformance, increases in costs/investments, obsolescence and other factors. In case of a recovery in the trading environment or better industrial performance with respect to the comparative period, management assesses whether the factors underlying previous impairment losses may no longer exist or may have decreased.
In assessing whether impairment is required, the carrying amounts of the assets are compared with their recoverable amounts. The recoverable amount is the higher of an asset’s fair value less costs to sell and its value-in-use. In the event of an asset’s impairment being reversed, the reversal may not raise the carrying amount above the value it would have stood at taking into account depreciation, if no impairment had originally been recognized.
Given the nature of Eni’s activities, information on asset fair value is usually difficult to obtain unless negotiations with a potential buyer are ongoing. Therefore, the recoverability is verifiedentire allocated goodwill was recorded by estimating assets’ values-in-use (VIU). The valuation is carried out for individual asset or for the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets, or groups of assets (cash generating unit — CGU). The Group has identified the following CGUs: (i) in the Exploration & Production segment, individual oilfields or pools of oilfields where technical, economic or contractual features make underlying cash flows interdependent; (ii) in the Gas & Power segment, in addition to the CGUs to which goodwill arisen from business combinations was allocated, electricity generation plants, international pipelines and LNG vessels; (iii) in the Refining & Marketing business line, refining plants, retail networks and assets related to other distribution channels grouped by country of operations and type of network (retail outlets located along ordinary routes and high-ways, wholesale facilities); and (iv) the Chemical business line has been assessedin relation to be a single CGU.
The value-in-use is calculated by discountingactivities concerning the estimated future cash flows deriving from the continuing usedevelopment, industrialization, licensing of the CGUsbio-chemical technologies and if significant and reasonably determinable, the cash flows deriving from disposal at the end of their useful lives. Cash flows are determinedprocesses based on the best information available atuse of renewable sources.
An increase in goodwill was recorded in connection with the timeallocation of the assessment. Cash flow projectionsacquisition cost of the company SEA SpA, which engages in providing services and solutions for energy efficiency in the first four years of each CGU evaluation are extracted from the Company’s four-year plan adopted by the top management. The plan includes data points on expected oil&gas production volumes, sales volumes, capital expenditure, operating costs and marginsresidential and industrial and marketing set-up, as well as trends on the main macroeconomic variables, including inflation, nominal interest rates and exchange rates. The estimation of CGUs’ terminal values is based on cash flow projections beyond the four-year plan horizon, which are estimated based on management’s long-term assumptions regarding the main macroeconomic variables (inflation rates, commodity prices, etc.) and considering the expected useful lives of the Company’s CGUs and certain assumptions regarding future trends in revenues and costs. In the case of the oil&gas CGUs, management assumed the residual life of the reserves and the associated projections of operating costs and development expenditures. The CGUs of the Refining & Marketing business line and each power plant are evaluated based on the plant economic and technical life and the associated, normalized projections of operating costs and expenditures to support plant efficiency. The CGUs of the gas market business to which goodwill has been allocated are evaluated based on the perpetuity method of the last year-plan result assuming nominal growth rates equal to 0%. The Chemical business CGU considers the average economic useful life of the underlying assets and factors a normalized EBITDA (to reflect the cyclicality of the sector) defined based on the average contribution margin of the plan and applying to the fixed costs the expected inflation rate. In projecting future commodity prices, management assumed the price scenario adopted for the economic and financial projections of the Company’s four-year industrial plans and for the assessment of capital projects returns. The Company’s price scenario is approved by the Board of Directors and is based on internal assumptions about future trends in the fundamentals of demand and supply of crude oil and other commodities as benchmarked against the market consensus forecasts and on forward prices of commodities for future delivery in case the level of liquidity and reliability of future contracts is deemed fair.segments. Values-in-use is estimated by discounting post-tax cash flows at a rate which corresponds for the Exploration & Production and Refining & Marketing to the Company’s weighted average cost of capital
(WACC) net of the risk factors attributable to the Gas & Power segment and the Chemical business line the WACC of which is assessed on a stand-alone basis. Then the discount rates are adjusted to factor in risks specific to each country of activity (adjusted post-tax WACC). Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment.
From the second half of 2016, the oil market has staged a recovery on the back of a better balance between global supply and demand of crude oil, driven by cuts in investments made by oil companies during the downturn and by the year-end agreement of OPEC countries to curb the cartel output, joined also by important non-OPEC countries (in particular Russia). Considering the historical minimum reached in the first half of the year, the price of the crude oil has recovered about 60% of its value. Based on those improved fundamentals, management revised upwardly its long-term assumption for the benchmark Brent price to 70$ per barrel in 2020 real terms, from a previous 65$ per barrel, in elaborating the Group financial projections of the 2017 – 2020 industrial plan and the estimations of the financial report 2016. Furthermore, at the balance sheet date, the market capitalization of Eni amounted to €55.7 billion exceeding the book value of the consolidated net assets equal to €53.1 billion, thereby discontinuing a two-year long downward trend.
Finally, the 2016 WACC of Eni, which is the driver for calculating the WACC of the oil&gas and refining business segments to assess the value-in-use of their relevant CGUs, recorded a marginal decrease, down by 0.1 percentage point to 6.4% compared to 2015. This reduction was driven by a lower premium for the sovereign risk incorporated into the yields on Italian ten-year bonds and a marginal a reduction in the cost of borrowings, offset by an increase in the beta of Eni. The WACC used in the Chemical business line decreased by 1 percentage point to 9% due to a lower country risk, considering that the activities are concentrated in Europe, and to the reduction of the risk-free rate. The WACC in the Gas & Power segment increased by 0.4 percentage points to 5.8% due to a higher country risk of some activities outside Europe. The adjusted WACC rates for 2016 highlighted dispersion compared to the average value of Eni amounting to 6.5%. This reflected a noticeable increase in the country risk in certain upstream areas. The adjusted WACC rates used for impairment test purposes in 2016 ranged from 4.8% to 15.0%.
Considering the upward revision of the long-term Brent price, the Company recorded reversals of previous impairment losses in the Exploration & Production segment for a total of €1,440 million reflecting the increased value-in-use of a number of oil&gas assets. The main reversals were recorded at a CGU which includes unproved mineral interests for €190 million, mainly in Congo; license acquisition costs with proved reserves for €385 million, particularly in Angola; property, plant and equipment for €865 million, particularly in Angola, USA, Algeria, Turkmenistan, United Kingdom and Norway. The post-tax WACC relating to reversals of impairments of more than €100 million regarded two CGUs and was 6%, corresponding to a pre-tax rate ranging from 9.64% to 18.13%, respectively.
These reversals, which correspond to about 28% of the impairment losses recorded in 2015, were partially offset by the recognition of impairment losses of €740 million. Those losses were driven by a weaker price outlook in the gas market in Europe, which negatively affected the recoverable amounts of Italian gas CGUs, and by downward reserve revisions, contractual changes and an increased country risk, which negatively impacted the recoverable amounts at a number of oil&gas properties in various locations. Impairment losses of more than €100 million regarded two CGUs with a post-tax WACC ranging from 4.8% to 6.1%, restated in a pre-tax rate ranging from 7.9% to 25.86%.
Impairment losses recognized in the Refining & Marketing business line of €120 million related to the investments of the year for compliance and stay-in-business related to CGUs fully impaired in prior years for which profitability expectations have remained unchanged from the previous-year impairment review.
Impairment losses net of reversals recognized in the Gas & Power segment amounted to €81 million mainly related to the gas transportation network GreenStream, following the increase in the discount rate for country risk and LNG carriers.
Considering the volatility in the oil scenario and the increased financial and geopolitical instability in certain countries where the Eni’s reserves are located, management assessed the fairness of its assumptions and the outcome of the impairment review by stress testing the headroom of the Group’s properties in high-risk locations. This sensitivity analysis was performed increasing by a full percentage point the discount rate applied to future cash flows with a view of factoring in a higher country risk premium. This exercise comprised Eni’s oil&gas properties in Libya, Egypt, Iraq, Venezuela and Nigeria, which base WACC are still significantly higher than the average WACC of Eni. No major changes in the properties headroom were detected.
A breakdown by segment of impairments losses recorded in 2016 and the associated tax effect is provided below:
| | | | | (€ million) | | | 2015 | | | 2016 | | Impairment losses | | | | Exploration & Production | | | | | 4,682 | | | | | | 740 | | | Gas & Power | | | | | 153 | | | | | | 167 | | | Refining & Marketing and Chemical | | | | | 1,138 | | | | | | 120 | | | Corporate and other activities | | | | | 20 | | | | | | 40 | | | | | | | | 5,993 | | | | | | 1,067 | | | Tax effects | | | | Exploration & Production | | | | | 1,837 | | | | | | 216 | | | Gas & Power | | | | | 38 | | | | | | 35 | | | Refining & Marketing and Chemical | | | | | 38 | | | | | | 32 | | | Corporate and other activities | | | | | 2 | | | | | | | | | | | | | | 1,915 | | | | | | 283 | | | Impairments net of the relevant tax effects | | | | Exploration & Production | | | | | 2,845 | | | | | | 524 | | | Gas & Power | | | | | 115 | | | | | | 132 | | | Refining & Marketing and Chemical | | | | | 1,100 | | | | | | 88 | | | Corporate and other activities | | | | | 18 | | | | | | 40 | | | | | | | | 4,078 | | | | | | 784 | | | |
A breakdown of impairment losses and reversals in the Exploration & Production segment and the associated tax effect is provided below:
| | | | | (€ million) | | | 2015 | | | 2016 | | Impairments (reversal), net | | | | Impairments of tangible assets | | | | | 4,682 | | | | | | 740 | | | Impairments of intangible assets | | | | | 530 | | | | | | | | | Reversals of tangible assets | | | | | | | | | | | (1,055) | | | Reversals of intangible assets | | | | | | | | | | | (385) | | | | | | | | 5,212 | | | | | | (700) | | | Tax effects | | | | Impairments of tangible assets | | | | | 1,837 | | | | | | 216 | | | Impairments of intangible assets | | | | | 106 | | | | Reversals of tangible assets | | | | | | | | | | | (315) | | | Reversals of intangible assets | | | | | | | | | | | (120) | | | | | | | | 1,943 | | | | | | (219) | | | Impairments (reversal) net of the relevant tax effects | | | | Impairments of tangible assets | | | | | 2,845 | | | | | | 524 | | | Impairments of intangible assets | | | | | 424 | | | | Reversals of tangible assets | | | | | | | | | | | (740) | | | Reversals of intangible assets | | | | | | | | | | | (265) | | | | | | | | 3,269 | | | | | | (481) | | | |
Goodwill acquired through business combinations has been allocated to the CGUs that are expected to benefit from the synergies of the acquisition. The amount of goodwill outstanding at the reporting date mainly related to the Gas & Power segment. A breakdown is disclosed below. (€ million) | | | December 31, 2015 | | | December 31, 2016 | | Domestic gas market | | | | | 835 | | | | | | 835 | | | European gas market | | | | | 190 | | | | | | 190 | | | - of which European market | | | | | 188 | | | | | | 188 | | | | | | | | 1,025 | | | | | | 1,025 | | | |
A breakdown is disclosed below: (€ million) | | | December 31, 2019 | | | December 31, 2018 | | Domestic gas market | | | | | 839 | | | | | | 835 | | | Foreign gas market | | | | | 142 | | | | | | 142 | | | | | | | | 981 | | | | | | 977 | | |
Goodwill allocated to the CGU domestic gas market was recognized upon the buy-out of the former Italgas SpA minorities in 2003 through a public offering (€706 million). The acquired entity engaged in the retail sale of gas to the residential sector and middle and small-sized businesses in Italy. In addition, further goodwill amounts have been allocated over the years following business combinations with small, local companies selling gas to residential customers in focused territorial reach and municipalities synergic to Eni’s activities. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of this CGU, including any allocated goodwill. Goodwill allocated to the CGU European gas market, amounting to €188 million, was recorded following the business combinations of Altergaz SA (now Eni Gas & Power France SA) in France, and Nuon Belgium NV (now merged in Eni Gas & Power NV) in Belgium, which represent two stand-alone CGUs. The impairment review performed at the balance sheet date confirmed the recoverability of the carrying amount of both CGUs including any allocated goodwill.
In assessing the recoverability of the carrying amount of the Gas & Power CGUs,CGU domestic gas market, including the allocated portion of goodwill, management determined the value in use of those CGUsthe CGU considering the sales margin exclusively of the retail market (excluding the wholesale margins on sales to wholesalers, industrial and power generation customers). The assessment was performed considering the cash flows of the four-year plan approved by management and incorporating thea terminal value calculated as perpetuity of the last year of the plan to determine the terminal value by assuming a nominal long-term growth rate equal to zero, unchanged from the previous reporting period. These cash flows were discounted by using the post-tax WACC adjusted considering the specific country risk of 4.5%5.3% for Italy and 5.0% for Europe.Italy. Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment. The excessThere are no realistic hypotheses of changes in the discount rate, growth rate, profitability or volumes that would lead to zeroing the headroom amounting to €1,701 million of the recoverable amountvalue in use of the Italian Market CGU with respect to its book value, including the goodwill.
Goodwill allocated to the CGU European gas market related for €95 million to Eni Gas & Power France SA (former Altergaz SA) operating in France and for €45 million to the acquisition in 2018 of the residual 51% interest in Gas Supply Company Thessaloniki-Thessalia SA operating in Greece, previously participated with a 49% of the share capital. The impairment review performed at the balance sheet date by using a method similar to the Domestic gas market over itsCGU confirmed the recoverability of the carrying amount of these gas market CGUs, including any allocated goodwill, by using a post-tax WACC adjusted considering a country risk for France of 5.9%, and 6.2% for Greece. 14 Impairment review of tangible and intangible assets and right-of-use assets In assessing whether impairment is required, the allocated portioncarrying amounts of the assets are compared with their recoverable amounts. The recoverable amount is the higher between an asset’s fair value less costs to sell and its value-in-use. In the event of an asset’s impairment being reversed, the reversal may not raise the carrying amount above the value it would have stood at taking into account depreciation, if no impairment had originally been recognized. Impairment losses of goodwill (headroom) amountingcannot be reversed. Given the nature of Eni’s activities, information on asset fair value is usually difficult to €1,461 million would be reduced to zero under eachobtain unless negotiations with a potential buyer are ongoing. Therefore, the recoverability is verified by estimating assets’ values-in-use. The valuation is carried out for individual assets or for the smallest identifiable group of assets that generates cash inflows that are largely independent from the cash inflows from other assets, or groups of assets (cash generating unit — CGU). The Group has identified the following alternative hypothesis:CGUs: (i) a decrease of 69% on average in the projected commercial margins;Exploration & Production segment, individual oilfields or pools of oilfields when technical, economic or contractual features make underlying cash flows interdependent; (ii) an increase of 10 percentage points in the discount rate;Gas & Power segment, the CGUs to which goodwill arisen from business combinations was allocated and costs for customer acquisition (Italian retail market and other foreign markets), electric power plants, international pipelines and other minor activities; (iii) a negative nominal growth rate of 19%. 20 Investments
Equity-accounted investments
(€ million) | | | Book amount at the beginning of the year | | | Additions and subscriptions | | | Divestments and reimbursements | | | Share of profit of equity- accounted investments | | | Share of loss of equity- accounted investments | | | Deduction for dividends | | | Changes in the scope of consolidation | | | Currency translation differences | | | Other changes | | | Book amount at the end of the year | | 2015 | | | | | | | | | | | | Investments in unconsolidated entities controlled by Eni | | | | | 196 | | | | | | 8 | | | | | | | | | | | | 66 | | | | | | (18) | | | | | | (92) | | | | | | 15 | | | | | | 17 | | | | | | (17) | | | | | | 175 | | | Joint ventures | | | | | 1,269 | | | | | | 93 | | | | | | (8) | | | | | | 59 | | | | | | (60) | | | | | | (28) | | | | | | | | | | | | 74 | | | | | | (124) | | | | | | 1,275 | | | Associates | | | | | 1,707 | | | | | | 124 | | | | | | | | | | | | 25 | | | | | | (537) | | | | | | (22) | | | | | | | | | | | | 168 | | | | | | (62) | | | | | | 1,403 | | | | | | | | 3,172 | | | | | | 225 | | | | | | (8) | | | | | | 150 | | | | | | (615) | | | | | | (142) | | | | | | 15 | | | | | | 259 | | | | | | (203) | | | | | | 2,853 | | | 2016 | | | | | | | | | | | | Investments in unconsolidated entities controlled by Eni | | | | | 175 | | | | | | 8 | | | | | | | | | | | | 10 | | | | | | (8) | | | | | | (2) | | | | | | 5 | | | | | | 5 | | | | | | (25) | | | | | | 168 | | | Joint ventures | | | | | 1,275 | | | | | | 1,085 | | | | | | | | | | | | 50 | | | | | | (208) | | | | | | (45) | | | | | | 564 | | | | | | 12 | | | | | | (58) | | | | | | 2,675 | | | Associates | | | | | 1,403 | | | | | | 63 | | | | | | (138) | | | | | | 17 | | | | | | (154) | | | | | | (53) | | | | | | | | | | | | 29 | | | | | | 30 | | | | | | 1,197 | | | | | | | | 2,853 | | | | | | 1,156 | | | | | | (138) | | | | | | 77 | | | | | | (370) | | | | | | (100) | | | | | | 569 | | | | | | 46 | | | | | | (53) | | | | | | 4,040 | | | |
In 2016, additionsin the Refining & Marketing business line, refining plants, and share capital increases of €1,156 millionassets related to distribution channels grouped by country of operations and type of network (retail outlets located along ordinary routes and high-ways, wholesale facilities); and (iv) in the subscriptionChemical business five lines of the share capital increase of Saipem SpA for €1,069 million.
Divestmentsactivities have been identified as autonomous CGUs: intermediates, polyethylene, styrenes, elastomers and reimbursements of €138 million primarily related to a capital reimbursement of €130 million relating to Angola LNG Ltd.biotech activities.
Eni’s shareAs of profit2019, following the application of equity-accounted investmentsIFRS 16, the book values of the identified CGUs include the right of use assets (RoU), associated to plants and dividend decrease pertainedequipment hired in connection with operations at specific CGUs operations. Because they are instrumental to specific CGUs operation, those RoU assets lack the requisites to be evaluated as autonomous CGUs. The CGUs’ cash flows to which the RoUs have been allocated exclude lease liability repayments according to the following entities:
| | | December 31, 2015 | | | December 31, 2016 | | (€ million) | | | Share of profit of equity- accounted investments | | | Deduction for dividends | | | Eni’s interest (%) | | | Share of profit of equity- accounted investments | | | Deduction for dividends | | | Eni’s interest (%) | | PetroJunín SA | | | | | 29 | | | | | | | | | | | | 40.00 | | | | | | 30 | | | | | | | | | | | | 40.00 | | | United Gas Derivatives Co | | | | | 20 | | | | | | 21 | | | | | | 33.33 | | | | | | 14 | | �� | | | | 14 | | | | | | 33.33 | | | Gas Distribution Company of Thessaloniki – Thessaly SA | | | | | 11 | | | | | | 8 | | | | | | 49.00 | | | | | | 10 | | | | | | 10 | | | | | | 49.00 | | | Eni BTC Ltd | | | | | 59 | | | | | | 90 | | | | | | 100.00 | | | | | | 6 | | | | | | | | | | | | 100.00 | | | Eteria Parohis Aeriou Thessalias AE | | | | | 5 | | | | | | 4 | | | | | | 49.00 | | | | | | 3 | | | | | | 5 | | | | Unión Fenosa Gas SA | | | | | | | | | | | 13 | | | | | | 50.00 | | | | | | 2 | | | | | | | | | | | | 50.00 | | | PetroSucre SA | | | | | | | | | | | | | | | | | 26.00 | | | | | | | | | | | | 30 | | | | | | 26.00 | | | Unimar Llc | | | | | | | | | | | | | | | | | 50.00 | | | | | | | | | | | | 16 | | | | | | 50.00 | | | Other investments | | | | | 26 | | | | | | 6 | | | | | | | | | | | | 12 | | | | | | 25 | | | | | | | | | 150 | | | | | | 142 | | | | | | | | | | | | 77 | | | | | | 100 | | | | | | | | | |
Eni’s shareunlevered valuation methodology used for capital projects. Rather, a small number of lossesRoU not allocated to CGU are considered corporate assets, whose recoverability depends on the whole of equity-accounted investments relatedthe company’s CGUs.
The value-in-use is calculated by discounting the estimated future cash flows deriving from the continuing use of the CGUs and, if significant and reasonably determinable, the cash flows deriving from disposal at the end of their useful lives. Cash flows are determined based on the best information available at the time of the assessment. Cash flow projections for the first four years of each CGU evaluation are extracted from the Company’s four-year plan adopted by the top management. The plan includes data points on expected oil&gas production volumes, reserves, sales volumes, capital expenditure, operating costs and margins and industrial and marketing set-up, as well as trends on the main macroeconomic variables, including inflation, nominal interest rates and exchange rates. The estimation of CGUs’ terminal values is based on cash flow projections beyond the four-year plan horizon, which are estimated based on management’s long-term assumptions regarding the main macroeconomic variables (inflation rates, commodity prices, etc.) and considering the expected useful lives of the Company’s CGUs and certain assumptions regarding future trends in revenues and costs. In the case of the oil&gas CGUs, management assumed the residual life of the reserves considering the expected production rates and the associated projections of operating costs and development expenditures. The CGUs of Refining & Marketing, Chemical and Gas & Power, with a definite useful life, (i.e. power plants) are evaluated based on the plant economic and technical life and the associated, normalized projections of operating costs and expenditures to support plant efficiency. The CGUs of the gas market business to which goodwill has been allocated are evaluated based on the perpetuity method of the last year-plan result assuming nominal growth rates equal to 0%. In the forecast of the operating expenses are considered expected costs to be incurred in compliance to the following entities:so-called CO2 Emission Trading Scheme applicable to CGUs operating within the EU economic space. In projecting future commodity prices, management assumed the price scenario adopted for the economic and financial projections of the Company’s four-year industrial plans and for the assessment of capital projects returns. | | | December 31, 2015 | | | December 31, 2016 | | (€ million) | | | Share of loss of equity- accounted investments | | | Eni’s interest (%) | | | Share of loss of equity- accounted investments | | | Eni’s interest (%) | | Saipem SpA | | | | | | | | | | | | | | | | | 144 | | | | | | 30.76 | | | PetroSucre SA | | | | | 66 | | | | | | 26.00 | | | | | | 92 | | | | | | 26.00 | | | Angola LNG Ltd | | | | | 469 | | | | | | 13.60 | | | | | | 62 | | | | | | 13.60 | | | PetroBicentenario SA | | | | | | | | | | | 40.00 | | | | | | 26 | | | | | | 40.00 | | | CARDÓN IV SA | | | | | 4 | | | | | | 50.00 | | | | | | 20 | | | | | | 50.00 | | | Matrìca SpA | | | | | 17 | | | | | | 50.00 | | | | | | 4 | | | | | | 50.00 | | | Newco Tech SpA | | | | | 5 | | | | | | 81.59 | | | | | | 4 | | | | | | 80.00 | | | Unión Fenosa Gas SA | | | | | 25 | | | | | | 50.00 | | | | | | | | | | | | 50.00 | | | Unimar Llc | | | | | 7 | | | | | | 50.00 | | | | | | | | | | | | 50.00 | | | Westgasinvest Llc | | | | | 1 | | | | | | 50.01 | | | | | | 3 | | | | | | 50.01 | | | Other investments | | | | | 21 | | | | | | | | | | | | 15 | | | | | | | | | | | | | | 615 | | | | | | | | | | | | 370 | | | | | | | | | |
The Company’s price scenario is approved by the Board of Directors and is based on internal assumptions about future trends in the fundamentals of demand and supply of crude oil and other commodities as benchmarked against the market consensus forecasts and on forward prices of commodities for future delivery in case the level of liquidity and reliability of future contracts is deemed fair. The oil market continues to be affected by weak fundamentals against the backdrop of an unabated supply glut, fueled by continuing grow in U.S. tight oil output and a seemingly fading commitment on part of the oil producers of the OPEC+ agreement at supporting crude oil prices going forward. The market is also weighed down by uncertainties about the strength of the global economic recovery, exposed to a wide range of systemic risks, including geopolitical risks, any possible development in the trade dispute between USA and China, the relationship between the EU and the UK post Brexit. Eni’s management forecast a gradual rebalancing of global supplies and demand for crude oil over the medium term, under the assumptions of moderate economic growth and taking into account the stricter capital discipline adopted by major oil companies designed to curtail growth plans to boost shareholders’ returns and lately a shift in the financial approach retained by the U.S. independent producers which have de-emphasized growth to preserve the free cash flow. Based on these considerations and taking into account the outcomeforecasts made by specialized observatories and investment banks, management has retained its assumption of a long-term Brent crude oil price of 70 $/BBL in real terms 2022, substantially in line with the assumption made in the annual report 2018. The oversupply condition is even more severe in the gas market due to excess production of associated gas in the USA and to the ramp-up of several liquefaction projects which have significantly increased global supplies of LNG at a time when the greatest consuming countries have slowed down (China, South Korea and Japan). Management expect gas prices to rebalance in the medium term considering an anticipated recovery of the impairment testing ofAsian economies and also considering an ongoing switch from coal to gas in the underlying project,power generation in Europe. Overall, price assumptions for the book value of the investmentmain gas benchmarks in Petrosucre and the dividends receivable were written off (€65 million). Regarding the projects related to PetroBicentenario and Cardón IV, Eni recorded net losses of €26 million and €20 million, respectively. LossesEurope have been retained at the equity-accounted investment of Angola LNG Ltd of €62 million (€469 millionsame level as the previous planning projections, whilst gas prices assumptions have been revised downward for the reference Henry Hub gas prices in 2015) related to pre-production expenses and operating costs associated with the start-up of the liquefaction plant and an impairment loss of €25 million; in 2015 the amount included impairment charges relating the reduced commodity prices outlook (€433 million). Other negative changes of €53 million related to the impairment of Unión Fenosa Gas SA of €84 millionUSA due to lower profitability prospects.
Changes in the scope of consolidation of €569 million include the initial recognition of the retained interest in Saipem SpA of €564 million (and, in addition to this, the subscription pro-quota of the share capital increase for €1,069 million). On January 22, 2016, Eni closed the sale of a 12.503% interest in Saipem to the Italian governmental agency, CDP Equity SpA. Concurrently, a shareholder agreement between Eni and the acquiree entered into force, which established the joint control of the two parties over the target entity. Those transactions triggered loss of control of Eni over Saipem and its derecognition. The retained interest of 30.55% has been recognized as an investment in an equity-accounted joint venture withstructural headwinds.
an initial carrying amount alignedHaving retained management’s long-term assumptions for crude oil prices unchanged from the previous financial statements, the impairment indicators at the Company’s oil&gas assets were mainly driven by downward reserves revisions and a lowered operating performance.
Furthermore, management is forecasting unchanged spreads for natural gas between the selling prices at Eni’s reference market, Italy, and the spot prices at continental hub to which the gas procurement costs of our long-term contracts are indexed. This latter assumption excludes any evidence of impairment indicator in relation to the share price atG&P fixed assets (particularly the closing dategoodwill recorded in the retail segment). The Company’s downstream businesses of the transaction (€4.2 per share) recognizingrefining and the petrochemicals sectors are currently in a loss through profitdown-cycle due to weak end-demands, excess production capacity and lossoversupplies and continuing competitive pressures from overseas operators who can leverage better cost positions and scale economies (for example Middle East refiners and the ethane-based cracking of €441 million. This loss has been recognized in the Group consolidated accountsU.S. chemicals producers), while environmental issues are expected to negatively affect consumption and profitability of gasoil and single-use plastics. Operating costs for emission allowances as part of gainsthe European Emission Scheme are also forecast to increase. Furthermore, Eni’s complex refineries have been negatively affected by narrowing price differentials between sour crudes with high sulfur content and lossesthe light benchmark Brent crude, thus impairing the cost-advantage of discontinued operations. Atcomplex refineries of processing low-quality crudes that under normal market conditions trade at a discount vs the Brent. Due to those structural weaknesses, management has reduced the profitability outlook of its refineries and petrochemicals plants. Management tested for impairment the totality of the Group’s fixed assets as provided by the Company’s internal guidelines. Values-in-use is estimated by discounting post-tax cash flows at a rate, which corresponds for the Exploration & Production segment and Refining & Marketing business line to the Company’s weighted average cost of capital (WACC) net of specific risk factors attributable to the Gas & Power segment and the Chemical business line, the WACC of which is assessed on a stand-alone basis. Then the discount rates are adjusted to factor in risks specific to each country of activity (adjusted post-tax WACC). Post-tax cash flows and discount rates were adopted as they resulted in an assessment that substantially approximated a pre-tax assessment. In 2019 the weighted-average cost of capital (WACC) to the Group increased marginally from 7.3% in 2018 to 7.4%. Based on our estimation the cost of equity has significantly appreciated driven by a sharp decline in government bond yields in 2019 that lifted the so-called equity risk premium, or the excess return for equities over a risk-free rate of return such as yields on treasuries of benchmark countries like USA and Germany and a step-up in the equity risk premium applied by financial markets to the oil&gas sector reflecting recent underperformance of the sector and uncertainties over future returns considering the structural decline in hydrocarbons prices and the risks associated with the energy transition. However, this impact has been mitigated by a higher leverage following the adoption of the accounting standard IFRS 16 which increased the total finance debt recorded in the balance sheet date,and by this way reduced the fairincrease in the weighted average cost of capital to the Group due to the higher equity risk. Finally, a weighted-average premium for the country risk is added to the cost of equity; the weighting factor is the amount of invested capital in each country of operations. Calculation of country-specific WACC for each country is obtained by adjusting the Group WACC by the difference between the specific risk premium applicable to a given country and the average country risk premium of the Group portfolio. Based on those assumptions, the existence of impairment indicators and estimates of discount rates, management recorded the following net impairment losses: (i) in the Exploration & Production segment the Company recorded impairment losses before taxes for €1,217 million driven by downward reserve revisions and lowered future production rates mainly at properties in Congo (WACC at 7.6%), Italy (WACC at 6.4%) and USA (WACC at 6.5%), in this latter country upward estimates of operating costs and expenditures were projected, as well as a loss on the disposal of a property in Ecuador. In the case of an impairment loss higher than €100 million post-tax, a post-tax WACC of 6.4% was applied, corresponding to pre-tax rate of 6.9%; (ii) in the Refining & Marketing business line impairment losses of €819 million were recorded, with the largest amount relating to the Sannazzaro refinery for €684 million driven by the above mentioned revised profitability outlook and also in connection to higher projected costs for CO2 emissions; the remaining amount related to the investments of the year for compliance and stay-in-business made at
CGUs fully impaired in prior years for which profitability expectations have remained unchanged from the previous-year impairment review. In the case of an impairment loss higher than €100 million post-tax, a post-tax WACC of 6.6% was applied, corresponding to pre-tax rate of 7.1%; (iii) in the Chemicals business impairment losses amounted to €103 million driven by the deteriorated market outlook described above; and (iv) in the G&P segment, €37 million of impairment losses were recorded at power generation plants in connection to a downward revision to the outlook for electricity margins due to higher competition and overcapacity. Furthermore, management assessed the recoverability of the expected costs associated with the Company’s plans to ramp up the participation in projects for forestry conservation and protection from degradation. Those projects which have been started in 2019 envisage the purchase of carbon credits certified in accordance with generally accepted international standards. Management projects to build in future years a portfolio of forestry projects intended to allow the Company to offset the net residual “Scope 1 and 2” carbon emissions of the E&P business calculated on equity production for the achievement of the carbon neutrality of the business from 2030 onwards. Those costs are considered part of the operating expenses of the E&P business and their recoverability has been evaluated in relation to the CGU E&P segment as a whole. When including those costs extrapolated along the reserves residual life in the determination of the value-in-use of the E&P segment, a 2% reduction in the headroom of the segment is observed. Ultimately, under management’s assumptions for a long-term Brent price at 70$/BBL (real terms 2022), which has remained unchanged for the last few years, and at a reference price for the Italian spot gas benchmark of 7.8$/Mbtu, Eni’s oil&gas properties have exhibited a substantial resilience of their carrying amounts, as highlighted by the trend in the recognition of impairment losses in the last three years. In 2017 we recorded a net reversal of €158 million and in 2018 we recorded net impairment losses of €726 million. Impairment losses in those three years have been driven mainly by asset-specific issues, which were acquired during a historic phase of suspected peak supply, and in relation to certain complex operating environments. However, considered the following trends of the sector: the increased volatility of crude oil prices which have been increasingly exposed to macro and global risks; the continued oversupply in the oil markets which has determined a reset in hydrocarbons realized prices and cash flows of oil companies; growing uncertainty about long-term evolution of the global oil demand in light of the rising commitment on part of the international community at fighting climate change and speeding up the pace of the energy transition, the increase in energy alternatives to fossil fuels and changing consumers’ preferences, management has evaluated the recoverability of the book values of Eni’s oil&gas properties at different stress-test scenarios, including the risk of stranded assets. Particularly, under the toughest of the assumptions at a flat long-term Brent price of 50$/BBL and at a flat Italian gas price of 5$/Mbtu, management is estimating that approximately 85% of the Company’s proven and probable/possible reserves (risked at 70% and 30% respectively) will be produced within 2035 realizing 94% of the overall net present value in the same period. The net present value of those production volumes, valued under the most conservative of the scenarios considered, is substantially aligned with the book values of the net fixed assets of Eni’s investmentoil&gas properties, including Eni’s share of the fixed assets of our joint ventures like Vår Energi AS, and including in Saipem, correspondingthe calculation the expected cash outflows committed to the portionCompany’s forestry projects.
15 Investments Equity-accounted investments | | | 2019 | | | 2018 | | (€ million) | | | Investments in unconsolidated entities controlled by Eni | | | Joint ventures | | | Associates | | | Total | | | Investments in unconsolidated entities controlled by Eni | | | Joint ventures | | | Associates | | | Total | | Carrying amount – beginning of the year | | | | | 95 | | | | | | 5,497 | | | | | | 1,452 | | | | | | 7,044 | | | | | | 116 | | | | | | 2,332 | | | | | | 1,063 | | | | | | 3,511 | | | Changes in accounting policies (IFRS 9 and 15) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (34) | | | | | | (3) | | | | | | (37) | | | Changes in accounting policies (IAS 28) | | | | | | | | | | | 22 | | | | | | | | | | | | 22 | | | | | | | | | | | | | | | | | | | | | | | | | | | Carrying amount restated – beginning of the year | | | | | 95 | | | | | | 5,519 | | | | | | 1,452 | | | | | | 7,066 | | | | | | 116 | | | | | | 2,298 | | | | | | 1,060 | | | | | | 3,474 | | | Additions and subscriptions | | | | | 6 | | | | | | 76 | | | | | | 2,910 | | | | | | 2,992 | | | | | | | | | | | | 28 | | | | | | 92 | | | | | | 120 | | | Divestments and reimbursements | | | | | (5) | | | | | | | | | | | | (17) | | | | | | (22) | | | | | | (33) | | | | | | (3) | | | | | | (115) | | | | | | (151) | | | Share of profit of equity-accounted investments | | | | | 6 | | | | | | 80 | | | | | | 75 | | | | | | 161 | | | | | | 8 | | | | | | 16 | | | | | | 385 | | | | | | 409 | | | Share of loss of equity-accounted investments | | | | | (10) | | | | | | (157) | | | | | | (17) | | | | | | (184) | | | | | | (5) | | | | | | (415) | | | | | | (10) | | | | | | (430) | | | Deduction for dividends | | | | | (4) | | | | | | (1,073) | | | | | | (61) | | | | | | (1,138) | | | | | | (6) | | | | | | (19) | | | | | | (25) | | | | | | (50) | | | Change in the scope of consolidation | | | | | 1 | | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | 3,448 | | | | | | | | | | | | 3,448 | | | Currency translation differences | | | | | 2 | | | | | | 67 | | | | | | 17 | | | | | | 86 | | | | | | 2 | | | | | | 25 | | | | | | 54 | | | | | | 81 | | | Other changes | | | | | (5) | | | | | | 80 | | | | | | (2) | | | | | | 73 | | | | | | 13 | | | | | | 119 | | | | | | 11 | | | | | | 143 | | | Carrying amount – end of the year | | | | | 86 | | | | | | 4,592 | | | | | | 4,357 | | | | | | 9,035 | | | | | | 95 | | | | | | 5,497 | | | | | | 1,452 | | | | | | 7,044 | | |
In 2019 additions and subscriptions related to: (i) a 20% equity interest in Abu Dhabi Oil Refining Co (Takreer), UAE acquired for a cash consideration of €2,896 million. The investee operates three refineries in Ruwais (Ruwais East and Ruwais West) and Abu Dhabi, with a refining capacity in excess of 900 KBBL per day. With this transaction, Eni enters the market capitalization, is higher thanUAE downstream sector and increases its global refining capacity by 35%, in line with the net bookCompany’s strategy of making Eni’s overall portfolio more geographically diversified and more balanced along the value recordedchain; (ii) a capital contribution of €39 million made to Lotte Versalis Elastomers Co Ltd, joint venture operating in Eni’s financial statements. However, consideringproduction of elastomers in South Korea. Share of profit of equity-accounted investments included a gain of €49 million related to Vår Energi AS and of €47 million to Angola LNG Ltd. The accounting under the equity method of Saipem SpA resulted in a gain of €4 million. Considering the volatility of the market environment where Saipem is currently engaging,shares and the ongoing uncertainties surrounding a recovery in the investing cycle of oil companies and competitive pressure in the Engineering & Construction segment, management assessed the soundnessperformed an impairment review of the investment to assess its recoverability based on an internal financial model of future cash flows of Saipem. Inputs to that model were estimated based on financial projections made by the sell-side analysts who cover the Saipem shares, publicly available data on Saipem and the observed historical correlation which link the Saipem turnover to crude oil prices and spending in capital projects made by oil companies. This review supported the book value by estimating the value in use of the investment based on the projectionsinvestment. Share of future earnings and cash flows elaborated by a panel of independent sell-side analysts. That review confirmed the recoverability of the carrying amount. The net carrying amountlosses of equity-accounted investments wasincluded a loss of €90 million accounted at the joint venture Cardón IV SA (Eni’s interest 50%) which is operating the Perla gas field affected by the slowdown in the gas supplies to the buyer PDVSA due to a deteriorated operating environment.
Deduction for dividends related for 1,057 million to Vår Energi AS.
Net carrying amount related to the following entities:companies: | | December 31, 2015 | | December 31, 2016 | | | December 31, 2019 | | December 31, 2018 | | (€ million) | | Net carrying amount | | Number of shares held | | Eni’s interest (%) | | Net carrying amount | | Number of shares held | | Eni’s interest (%) | | | Net carrying amount | | % of the investment | | Net carrying amount | | % of the investment | | Investments in unconsolidated entities controlled by Eni | | | | | | | | | | | | | | | | | | | | | | | | Eni BTC Ltd | | | | 96 | | | | | 34,000,000 | | | | | 100.00 | | | | | 106 | | | | | 34,000,000 | | | | | 100.00 | | | | | | 30 | | | | | 100.00 | | | | | 31 | | | | | 100.00 | | | Other investments (*) | | | | 79 | | | | | | | | | | | | | | | 62 | | | | | Other (*) | | | | | 56 | | | | | | | | | | 64 | | | | | | | | | | | | 175 | | | | | | | | | | | | | | | 168 | | | | | | | 86 | | | | | | | | | | 95 | | | | | | | | Joint ventures | | | | | | | | | | | | | | | | | | | | | | | | Saipem | | | | | | | | | | | | | | | | | | | 1,497 | | | | | 3,087,679,689 | | | | | 30.76 | | | | Vår Energi AS | | | | | 2,518 | | | | | 69.60 | | | | | 3,498 | | | | | 69.60 | | | Saipem SpA | | | | | 1,250 | | | | | 30.99 | | | | | 1,228 | | | | | 30.99 | | | Unión Fenosa Gas SA | | | | 503 | | | | | 273,100 | | | | | 50.00 | | | | | 434 | | | | | 273,100 | | | | | 50.00 | | | | | | 326 | | | | | 50.00 | | | | | 335 | | | | | 50.00 | | | PetroJunín SA | | | | 174 | | | | | 44,424,000 | | | | | 40.00 | | | | | 211 | | | | | 44,424,000 | | | | | 40.00 | | | | CARDÓN IV SA | | | | 211 | | | | | 8,605 | | | | | 50.00 | | | | | 197 | | | | | 8,605 | | | | | 50.00 | | | | Cardón IV SA | | | | | 148 | | | | | 50.00 | | | | | 98 | | | | | 50.00 | | | Gas Distribution Company of Thessaloniki – Thessaly SA | | | | 109 | | | | | 94,839,500 | | | | | 49.00 | | | | | 150 | | | | | 130,491,508 | | | | | 49.00 | | | | | | 139 | | | | | 49.00 | | | | | 137 | | | | | 49.00 | | | Lotte Versalis Elastomers Co Ltd | | | | 64 | | | | | 16,520,000 | | | | | 50.00 | | | | | 74 | | | | | 19,200,000 | | | | | 50.00 | | | | | | 74 | | | | | 50.00 | | | | | 75 | | | | | 50.00 | | | Unimar Llc | | | | 57 | | | | | 50 | | | | | 50.00 | | | | | 42 | | | | | 50 | | | | | 50.00 | | | | Eteria Parohis Aeriou Thessalias AE | | | | 43 | | | | | 35,652,008 | | | | | 49.00 | | | | | PetroBicentenario SA | | | | 27 | | | | | 40,000 | | | | | 40.00 | | | | | | | | | | 40,000 | | | | | 40.00 | | | | Other investments (*) | | | | 87 | | | | | | | | | | | | | | | 70 | | | | | PetroJunín SA | | | | | 53 | | | | | 40.00 | | | | | 47 | | | | | 40.00 | | | AET – Raffineriebeteiligungsgesellschaft mbH | | | | | 35 | | | | | 33.33 | | | | | 32 | | | | | 33.33 | | | Other (*) | | | | | 49 | | | | | | | | | | 47 | | | | | | | | | | | | 1,275 | | | | | | | | | | | | | | | 2,675 | | | | | | | 4,592 | | | | | | | | | | 5,497 | | | | | | | | Associates | | | | | | | | | | | | | | | | | | | | | | | | Abu Dhabi Oil Refining Co (Takreer) | | | | | 2,829 | | | | | 20.00 | | | | | | | | | | | | | Angola LNG Ltd | | | | 1,019 | | | | | 1,591,200,000 | | | | | 13.60 | | | | | 916 | | | | | 1.551.760.000 | | | | | 13.60 | | | | | | 1,159 | | | | | 13.60 | | | | | 1,106 | | | | | 13.60 | | | Coral FLNG SA | | | | | 102 | | | | | 25.00 | | | | | 102 | | | | | 25.00 | | | Novamont SpA | | | | | 71 | | | | | 25.00 | | | | | 67 | | | | | 25.00 | | | United Gas Derivatives Co | | | | 113 | | | | | 950,000 | | | | | 33.33 | | | | | 117 | | | | | 950,000 | | | | | 33.33 | | | | | | 69 | | | | | 33.33 | | | | | 62 | | | | | 33.33 | | | Novamont SpA | | | | 77 | | | | | 6,667 | | | | | 25.00 | | | | | 77 | | | | | 6,667 | | | | | 25.00 | | | | AET - Raffineriebeteiligungsgesellschaft mbH | | | | | | | | | | | | | | 33.33 | | | | | 34 | | | | | 1 | | | | | 33.33 | | | | PetroSucre SA | | | | 123 | | | | | 5,727,800 | | | | | 26.00 | | | | | | | | | | 5,727,800 | | | | | 26.00 | | | | Other investments (*) | | | | 71 | | | | | | | | | | | | | | | 53 | | | | | Commonwealth Fusion Systems Llc(a) | | | | | 37 | | | | | | | | | | 42 | | | | | | | | Other (*) | | | | | 90 | | | | | | | | | | 73 | | | | | | | | | | | | 1,403 | | | | | | | | | | | | | | | 1,197 | | | | | | | 4,357 | | | | | | | | | | 1,452 | | | | | | | | | | | | 2,853 | | | | | | | | | | | | | | | 4,040 | | | | | | | | | | | | | | | | 9,035 | | | | | | | | | | 7,044 | | | | | | | | | |
(a)
The ownership cannot be determined. (*)
Each individual amount included herein was lower than €25 million. Equity-accountedAs of December 31, 2019, the book value of investments included Vår Energi SA which was established at the end of 2018 following the merger between the former Eni subsidiary Eni Norge AS and Point Resources AS for maximizing synergies in the development of hydrocarbon reserves in Norway through the sharing of assets and know-how. The decrease of €980 million compared to the opening balance was due to the distribution of dividends classified as part of the cash flow from operating activities considering that Vår Energi SA is an investment integrated in the industrial plans and the upstream growth strategy of Eni. This decrease was partially absorbed by Eni’s share of profit.
Results of equity-accounted investments by segment are disclosed in note 4635 — Information by industry segmentSegment information and information by geographical area. CarryingThe carrying amounts of equity-accounted investments included differences between the purchase price of the interest acquired interests and thetheir underlying book value of the corresponding fraction of net equityassets amounting to €100€72 million, related to Novamont SpA for €43 million and Unión Fenosa Gas SA for €62 million and Novamont SpA for €38€29 million. This goodwill is supportedThese surpluses were driven by the long-term profitability outlook of the acquired companies.companies at the time of the acquisition.
As of December 31, 2016,2019, the market value of the investments listed in regulated stock markets was as follows: | | | Number of shares held | | | Eni’s interest (%) | | | Share price (€) | | | Market value (€ million) | | Saipem SpA | | | | | 3,087,679,689 | | | | | | 30.76 | | | | | | 0.535 | | | | | | 1,652 | | |
| | | Saipem SpA | | Number of shares held | | | | | 308,767,968 | | | % of the investment | | | | | 30.99 | | | Share price (€) | | | | | 4.356 | | | Market value (€ million) | | | | | 1,345 | | | Book value (€ million) | | | | | 1,250 | | | |
The table below sets out the provisions for losses included in the provisions for contingencies of €151 million (€126 million at December 31, 2015), primarily related to the following equity-accounted investments:
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Industria Siciliana Acido Fosforico – ISAF – SpA (in liquidation) | | | | | 93 | | | | | | 95 | | | VIC CBM Ltd | | | | | 10 | | | | | | 34 | | | Société Centrale Eletrique du Congo SA | | | | | 8 | | | | | | 7 | | | Agip Oleoducto de Crudos Pesados BV | | | | | | | | | | | 7 | | | PetroBicentenario SA | | | | | | | | | | | 6 | | | Polimeri Europa Elastomeres France SA | | | | | 8 | | | | Other investments | | | | | 7 | | | | | | 2 | | | | | | | | 126 | | | | | | 151 | | |
Additional information is included in note 4837 — Other information about investments. Other investments (€ million) | | | Net book amount at the beginning of the year | | | Additions | | | Divestments and reimbursements | | | Valuation at fair value | | | Currency translation differences | | | Other changes | | | Value at the end of the year | | | Gross book amount at the end of the year | | | Accumulated impairment charges | | 2015 | | | | | | | | | | | Investments in unconsolidated entities controlled by Eni | | | | | 14 | | | | | | 3 | | | | | | | | | | | | | | | | | | | | | | | | 8 | | | | | | 25 | | | | | | 26 | | | | | | 1 | | | Associates | | | | | 12 | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | | (3) | | | | | | 10 | | | | | | 10 | | | | Other investments: | | | | | | | | | | | - valued at fair value | | | | | 1,744 | | | | | | | | | | | | (1,425) | | | | | | 49 | | | | | | | | | | | | | | | | | | 368 | | | | | | 368 | | | | - valued at cost | | | | | 245 | | | | | | | | | | | | (10) | | | | | | | | | | | | 21 | | | | | | 1 | | | | | | 257 | | | | | | 260 | | | | | | 3 | | | | | | | | 2,015 | | | | | | 3 | | | | | | (1,435) | | | | | | 49 | | | | | | 22 | | | | | | 6 | | | | | | 660 | | | | | | 664 | | | | | | 4 | | | 2016 | | | | | | | | | | | Investments in unconsolidated entities controlled by Eni | | | | | 25 | | | | | | 5 | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | 29 | | | | | | 30 | | | | | | 1 | | | Associates | | | | | 10 | | | | | | 3 | | | | | | | | | | | | | | | | | | (2) | | | | | | (1) | | | | | | 10 | | | | | | 10 | | | | Other investments | | | | | | | | | | | - valued at fair value | | | | | 368 | | | | | | | | | | | | (368) | | | | | | | | | - valued at cost | | | | | 257 | | | | | | | | | | | | (31) | | | | | | | | | | | | 6 | | | | | | 5 | | | | | | 237 | | | | | | 240 | | | | | | 3 | | | | | | | | 660 | | | | | | 8 | | | | | | (399) | | | | | | | | | | | | 4 | | | | | | 3 | | | | | | 276 | | | | | | 280 | | | | | | 4 | | | |
(€ million) | | | 2019 | | | 2018 | | Carrying amount – beginning of the year | | | | | 919 | | | | | | 219 | | | Changes in accounting policies (IFRS 9) | | | | | | | | | | | 681 | | | Carrying amount restated – beginning of the year | | | | | 919 | | | | | | 900 | | | Additions and subscriptions | | | | | 11 | | | | | | 5 | | | Change in the fair value | | | | | (3) | | | | | | 15 | | | Divestments and reimbursements | | | | | (12) | | | | | | (22) | | | Currency translation differences | | | | | 15 | | | | | | 31 | | | Other changes | | | | | (1) | | | | | | (10) | | | Carrying amount – end of the year | | | | | 929 | | | | | | 919 | | |
Divestments and reimbursements of the investments valued atThe fair value of €368 million related the sale of 2.22% interestmain non-controlling interests in Snam SpA through: (i) exercisenon-listed investees on regulated markets, classified within level 3 of the conversion right byfair value hierarchy, was estimated based on a methodology that combines future expected earnings and the holderssum-of-the-parts methodology (so-called residual income approach) and takes into account, inter alia, the following inputs: (i) expected results, as a gauge of convertible bondsthe future profitability of the investees, derived from the business plans, but adjusted, where appropriate, to include the assumptions that market participants would incorporate; (ii) the cost of capital, adjusted to include the risk premium of the specific country in which each investee operates. A stress test based on a 1% change in the cost of capital considered in the valuation did not produce significant changes at the fair value evaluation.
Dividend income from these investments is disclosed in note 31 — Income (expense) from investments. The investment book value as of December 31, 2019 primarily related to 76,888,264 shares, representing approximately 2.2%Nigeria LNG Ltd for €657 million (€651 million at December 31, 2018) and Saudi European Petrochemical Co “IBN ZAHR” for €146 million (€144 million at December 31, 2018). 16 Other financial assets | | | December 31, 2019 | | | December 31, 2018 | | (€ million) | | | Current | | | Non-current | | | Current | | | Non-current | | Long-term financing receivables held for operating purposes | | | | | 60 | | | | | | 1,119 | | | | | | 61 | | | | | | 1,189 | | | Short-term financing receivables held for operating purposes | | | | | 37 | | | | | | | | | | | | 51 | | | | | | | | | | | | | | 97 | | | | | | 1,119 | | | | | | 112 | | | | | | 1,189 | | | Financing receivables held for non-operating purposes | | | | | 287 | | | | | | | | | | | | 188 | | | | | | | | | | | | | | 384 | | | | | | 1,119 | | | | | | 300 | | | | | | 1,189 | | | Securities held for operating purposes | | | | | | | | | | | 55 | | | | | | | | | | | | 64 | | | | | | | | 384 | | | | | | 1,174 | | | | | | 300 | | | | | | 1,253 | | |
Financing receivables are stated net of allowance for doubtful accounts as follows: (€ million) | | | 2019 | | | 2018 | | Carrying amount at the beginning of the year | | | | | 430 | | | | | | 730 | | | Additions | | | | | 11 | | | | | | 279 | | | Deductions | | | | | (88) | | | | | | (596) | | | Currency translation differences | | | | | 7 | | | | | | 17 | | | Other changes | | | | | 19 | | | | | | | | | Carrying amount at the end of the year | | | | | 379 | | | | | | 430 | | |
Financing receivables held for operating purposes related principally to funds provided to joint ventures and associates in the shareExploration & Production segment (€1,041 million) and the Gas & Power segment (€49 million) to execute capital for a total considerationprojects of €332 million correspondinginterest to a priceEni. These receivables are expression of ���4.32 per share and a loss recognized in profit and loss of €32 million; (ii) sale of the remaining 792,619 shares on the open market for a consideration of €4 million.
The net carrying amount of other investments of €276 million (€660 million at December 31, 2015) was related tolong-term interests in the following entities:
| | | December 31, 2015 | | | December 31, 2016 | | (€ million) | | | Net carrying amount | | | Number of shares held | | | Eni’s interest (%) | | | Net carrying amount | | | Number of shares held | | | Eni’s interest (%) | | Investments in unconsolidated entities controlled by Eni (*) | | | | | 25 | | | | | | | | | | | | | | | | | | 29 | | | | | Associates | | | | | 10 | | | | | | | | | | | | | | | | | | 10 | | | | | Other investments: | | | | | | | | - Nigeria LNG Ltd | | | | | 109 | | | | | | 118,373 | | | | | | 10.40 | | | | | | 112 | | | | | | 118,373 | | | | | | 10.40 | | | - Darwin LNG Pty Ltd | | | | | 60 | | | | | | 213,995,164 | | | | | | 10.99 | | | | | | 49 | | | | | | 213,995,164 | | | | | | 10.99 | | | - Snam SpA | | | | | 368 | | | | | | 77,680,883 | | | | | | 2.22 | | | | | | - other(*) | | | | | 88 | | | | | | | | | | | | | | | | | | 76 | | | | | | | | | | 625 | | | | | | | | | | | | | | | | | | 237 | | | | | | | | | | 660 | | | | | | | | | | | | | | | | | | 276 | | | | | | | | | | | | | | | |
(*)
Each individual amount included herein was lower than €25 million.
Additional information is included in note 48 — Other information about investments.
21 Other financial assets
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Receivables held for operating purposes | | | | | 949 | | | | | | 1,785 | | | Securities held for operating purposes | | | | | 77 | | | | | | 75 | | | | | | | | 1,026 | | | | | | 1,860 | | | |
Financing receivables held for operating purposes are stated net of the valuation allowance for doubtful accounts of €480 million (€347 million at December 31, 2015).
(€ million) | | | Amount at December 31, 2015 | | | Additions | | | Currency translation differences | | | Amount at December 31, 2016 | | Reserve of allowance for doubtful accounts of financing receivables | | | | | 347 | | | | | | 121 | | | | | | 12 | | | | | | 480 | | | |
Financing receivables held for operating purposes of €1,785 million (€949 million at December 31, 2015) primarily pertained to loans granted by the Exploration & Production segment (€1,471 million), the Gas & Power segment (€133 million) and Refining & Marketing and Chemical segment (€109 million).
Financing receivables granted to joint ventures and associates amounted to €1,350 million (€396 million at December 31, 2015).Theinitiatives funded. The greatest exposure is towards the joint venture CARDÓNCardón IV SA (Eni’s interest 50%) in Venezuela, which is currently operating and developing the Perla offshore gas field. Due to a deteriorated financial outlook of PDVSA and the continuing refinancing of the outstanding loan granted by Eni to the joint venture, the relevant operating financing receivable was reclassified to non-current assets and, as of December 31, 2016, the recoverability was assessed based on the outcome of the impairment review of the underlying industrial project. At December 31, 2016, Eni’s exposure towards the joint venture amounted to €1,054 million (€1,112 million at 31 December 2015). The receivable is accruing interest income at a rate equal to Libor plus 700 basis points as provided by the agreement between Eni and Cardón IV, which were approved by Eni’s Board of Directors with a cap to the financing up to $1.5 billion. The loan will be repaid through the cash flows generated by the gas produced by the field, and supplied to the Venezuelan State-owned company, PDVSA, on the base of a gas sale agreement expiring in 2036.
In assessing the recoverability of the financing receivable granted to the joint venture Cardón IV, management has evaluated that the loan approximates the provision of equity capital, and its recoverability mainly depends upon the capacity of the joint venture to pay down the loan with its cash flows from
operations. Therefore, the recoverability of the financing receivable has been assessed based on the present value of the project future cash flows, as part of the project impairment review, discounted by using the Eni’s WACC for Venezuela, which takes into account the business risk and the country risk. The project VIU was then compared to the sum of the book values of Eni’s interest in Cardón IV and of the financing receivable with the VIU exceeding the assets book values. Furthermore, given the counterparty risk considering the deteriorated financial situation in Venezuela, the value-in-use has been stress-tested assuming either: i) a two-year delay in the payment of gas supplies to the joint venture by PDVSA; ii) the collection of proceeds on only 70% of the gas sales in line with the current securitization agreements. Under both of these scenarios, the value-in-use retained a headroom over the assets book values.
Allowances for doubtful accounts of financing receivables of €121 million included an impairment for €93 million of a financing receivable granted to Matrìca SpA (Eni’s share 50%), a joint venture with Novamont SpA for the production of chemical products from renewable sources, to reflect the repayment capacity of the venture considering the industrial risks of the project.
Financing receivables held for operating purposes in currencies other than euro amounted to €1,606 million (€649€563 million at December 31, 2015)2019 (€705 million at December 31, 2018).
Financing receivables held for operating purposes due beyond five years amounted to €1,519€1,018 million (€6231,088 million at December 31, 2015)2018). The valuation at fair value of non-current financing receivables held for operating purposes of €1,799€1,119 million has been estimated based on the present value of expected future cash flows discounted at rates ranging from -0.2%-0.3% to 2.6% (0%2.0% (-0.2% and 2.7%2.9% at December 31, 2015)2018). The recoverability of the financial loan granted to the joint venture Cardón IV SA to fund the development projects carried out by the venture was assessed based on the future, expected cash flows of the industrial project. These cash flows are exposed to a counterparty risk given the difficult financial condition of Venezuela and of the national oil company, PDVSA, and to the complexity of the local operating environment. To factor in those risks in assessing the recoverability of the financing, the future cash flows of the project have been adjusted to price possible difficulties in converting future gas sales into cash, essentially assuming a deferral in the time of revenues collection. This schedule was estimated on the basis of a study on empirical evidence relating to the average recovery rates obtained by creditors in the context of sovereign defaults, adjusted to reflect the strategic role of the energy sector to local economy. Those risked cash flows have been then discounted to a risk-adjusted WACC which incorporates the deteriorated local operating environment. This recoverability assessment confirmed the book value of the financial receivable. The same method was used to estimate the recoverable amount of the overdue trade receivables for gas supplies to the state-owned company PDVSA. In 2019, the percentages of the gas revenues collected by the joint venture were in line with the estimates adopted in assessing the loss-given-default applied in the evaluation recoverability performed in 2018; therefore, no adjustment was necessary to the estimation of the percentage of recoverability of these receivables. The recoverability of other long-term financial assets was assessed by considering the expected probability default in the next twelve months only, as the creditworthiness suffered no significant deterioration in the reporting period. Financing receivables held for non-operating purposes related to bank deposits with the purpose to invest cash surpluses and restricted deposits in escrow to guarantee transactions on derivative contracts. Financing receivables held for operating purposes were denominated in euro and U.S. dollar for €370 million and €1,112 million, respectively. Securities of €75 million (€77 million at December 31, 2015), designated as held-to-maturity investments, areheld for operating purposes related to listed bonds issued by sovereign statesstates. Securities for €71€20 million (€70 million(same amount at December 31, 2015) and2018) were pledged as guarantee of the deposit for gas cylinders as provided for by the European Investment Bank for €4 million (€7 million at December 31, 2015).Italian law. The following table analyses securities per issuing entity: | | | Amortized cost (€ million) | | | Nominal value (€ million) | | | Fair Value (€ million) | | | Nominal rate of return (%) | | | Maturity date | | | Rating - Moody’s | | | Rating - S&P | | Sovereign states | | | | | | | | | Fixed rate bonds | | | | | | | | | Italy | | | | | 24 | | | | | | 24 | | | | | | 26 | | | | from 0.45 to 4.75 | | | from 2017 to 2025 | | | Baa2 | | | BBB- | | Spain | | | | | 15 | | | | | | 14 | | | | | | 15 | | | | from 1.40 to 4.30 | | | from 2019 to 2020 | | | Baa2 | | | BBB+ | | Ireland | | | | | 9 | | | | | | 8 | | | | | | 9 | | | | from 4.40 to 4.50 | | | from 2018 to 2019 | | | A3 | | | A+ | | Iceland | | | | | 3 | | | | | | 3 | | | | | | 3 | | | | 2.50 | | | 2020 | | | A3 | | | BBB+ | | Poland | | | | | 3 | | | | | | 2 | | | | | | 3 | | | | 4.20 | | | 2020 | | | A2 | | | BBB+ | | Slovenia | | | | | 2 | | | | | | 2 | | | | | | 2 | | | | 4.13 | | | 2020 | | | Baa3 | | | A | | Belgium | | | | | 2 | | | | | | 2 | | | | | | 2 | | | | 1.40 | | | 2018 | | | Aa3 | | | AA | | Floating rate bonds | | | | | | | | | Italy | | | | | 11 | | | | | | 11 | | | | | | 11 | | | | | | | from 2018 to 2019 | | | Baa2 | | | BBB- | | Mozambique | | | | | 2 | | | | | | 2 | | | | | | 2 | | | | | | | from 2017 to 2019 | | | Caa3 | | | B- | | Total sovereign states | | | | | 71 | | | | | | 68 | | | | | | 73 | | | | | | | European Investment Bank | | | | | 4 | | | | | | 4 | | | | | | 4 | | | | | | | 2018 | | | Aaa | | | AAA | | | | | | | 75 | | | | | | 72 | | | | | | 77 | | | | | | | | | | | | | | | |
| | | Amortized cost (€ million) | | | Nominal value (€ million) | | | Fair Value (€ million) | | | Nominal rate of return (%) | | | Maturity date | | | Rating- Moody’s | | | Rating- S&P | | Sovereign states | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fixed rate bonds | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Italy | | | | | 24 | | | | | | 24 | | | | | | 25 | | | | from 0.20 to 4.75 | | | from 2020 to 2025 | | | Baa3 | | | BBB | | Others (*) | | | | | 23 | | | | | | 23 | | | | | | 23 | | | | from 0.05 to 4.20 | | | from 2020 to 2024 | | | from Aa3 to Baa1 | | | from AA to A- | | Floating rate bonds | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Italy | | | | | 5 | | | | | | 5 | | | | | | 5 | | | | | | | from 2020 to 2022 | | | Baa3 | | | BBB | | Others | | | | | 3 | | | | | | 3 | | | | | | 3 | | | | | | | 2022 | | | Baa3 | | | BBB | | Total sovereign states | | | | | 55 | | | | | | 55 | | | | | | 56 | | | | | | | | | | | | | | |
(*)
Amounts included herein are lower than €10 million. All securities have a maturity within five years (beyond five years for €1 million at December 31, 2015).years. The fair value of securities was derived from quoted market prices. Receivables with related parties are described in note 4736 — Transactions with related parties.
22 Deferred tax assets
Deferred tax assets are stated net of amounts of deferred tax liabilities that can be offset for €4,286 million (€3,355 million at December 31, 2015).
(€ million) | | | Amount at December 31, 2015 | | | Additions | | | Deductions | | | Currency translation differences | | | Other changes | | | Amount at December 31, 2016 | | Deferred tax assets | | | | | 8,952 | | | | | | 2,994 | | | | | | (1,208) | | | | | | 185 | | | | | | (1,511) | | | | | | 9,412 | | | Provisions for impairments | | | | | (5,099) | | | | | | (667) | | | | | | 254 | | | | | | (80) | | | | | | (30) | | | | | | (5,622) | | | | | | | | 3,853 | | | | | | 2,327 | | | | | | (954) | | | | | | 105 | | | | | | (1,541) | | | | | | 3,790 | | | |
Deferred tax assets related for €1,690 million (€1,911 million at December 31, 2015) to the parent company Eni SpA and other Italian subsidiaries which were part of the consolidated accounts for Italian tax purposes. Those assets were recorded on the pre-tax loss of the year and on the recognition of deferred deductible expenses within the limits of the amounts expected to be recovered in future years based on availability of expected future taxable profit.
Additions to the impairment provision of €667 million were explained by projections of lower future taxable profit at Italian subsidiaries (€433 million).
Deferred tax assets are further described in note 32 — Deferred tax liabilities.
Income taxes are described in note 43 — Income taxes.
23 Other non-current assets
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Tax receivables from: | | | | - Italian tax authorities | | | | - income tax | | | | | 44 | | | | | | 73 | | | - interest on tax credits | | | | | 63 | | | | | | 64 | | | | | | | | 107 | | | | | | 137 | | | - non-Italian tax authorities | | | | | 287 | | | | | | 365 | | | | | | | | 394 | | | | | | 502 | | | Other receivables: | | | | - related to divestments | | | | | 567 | | | | | | 222 | | | - other non-current | | | | | 46 | | | | | | 52 | | | | | | | | 613 | | | | | | 274 | | | Fair value of derivative financial instruments | | | | | 218 | | | | | | 108 | | | Other asset | | | | | 533 | | | | | | 464 | | | | | | | | 1,758 | | | | | | 1,348 | | | |
Receivables from divestments amounted to €222 million (€567 million at December 31, 2015) and included the long-term portion of €166 million (€463 million at December 31, 2015) of a receivable related to the divestment of a 1.71% interest in the Kashagan project to the local partner KazMunayGas in 2008 based on the agreements defined between the international partners of the North Caspian Sea PSA and the Kazakh government, which enacted a new contractual framework and a new setup for managing project operations. The repayment of the first of the three installments of the receivable took place in the fourth quarter of 2016 with the achievement of the agreed target production level. The receivable accrues interest income at market rates. The current portion of the receivable is indicated in note 11 —17 Trade and other receivables.payables
The fair value related to derivative financial instrumentsfollowing are the effects of the application of IFRS 16: (€ million) | | | Trade payables | | | Down payments and advances from joint ventures in exploration and production activities | | | Other payables | | | Total trade and other payables | | Carrying amount at December 31, 2018 | | | | | 11,645 | | | | | | 207 | | | | | | 4,895 | | | | | | 16,747 | | | Changes in accounting policies (IFRS 16) | | | | | (128) | | | | | | | | | | | | | | | | | | (128) | | | Carrying amount at January 1, 2019 | | | | | 11,517 | | | | | | 207 | | | | | | 4,895 | | | | | | 16,619 | | |
The first application of IFRS 16 is disclosed in note 343 — Derivative financial instruments. Changes in accounting policies.The breakdown of trade and other payables is the following: (€ million) | | | December 31,2019 | | | December 31,2018 | | Trade payables | | | | | 10,480 | | | | | | 11,645 | | | Down payments and advances from joint ventures in exploration & production activities | | | | | 401 | | | | | | 207 | | | Payables for purchase of non-current assets | | | | | 2,276 | | | | | | 2,530 | | | Payables due to joint ventures in exploration & production activities | | | | | 1,236 | | | | | | 1,151 | | | Other payables | | | | | 1,152 | | | | | | 1,214 | | | | | | | | 15,545 | | | | | | 16,747 | | |
F-56
Trade and other payables were denominated in euro for €5,866 million and in U.S. dollar for €8,371 million.Other non-current assets amounted to €464 million (€533 million at December 31, 2015), of which €113 million (€277 million at December 31, 2015) were deferred costs of take-or-pay gas volumes in connection with the Company’s long-term supply contracts. The amount was recognized due to the obligation to pay the contractual priceBecause of the volumesshort-term maturity and conditions of gas, whichremuneration of trade and other payables, the Company failed to collect up tofair values approximated the minimum contractual take in previous reporting periods in order to fulfill the take-or-pay clause provided by the relevant long-term supply contracts. The Company is entitled to off-take the prepaid volumes in future years alongside contract execution, up to contract expiration or in a shorter term as the case may be. Those deferred costs, which are equivalent to a receivable in-kind, are stated at the purchase cost or the net realizable value, whichever is lower. Prior-year impairment losses are reversed up to the purchase cost, whenever market conditions indicate that impairment no longer exits or may have decreased. In 2016, based on this accounting, an impairment of €31 million was recorded. The reduction in the amount of the deferred costs at the reporting date compared to 2015 wascarrying amounts.
Payables due to the reclassification to other current assets of volumes expected to be recovered by 2017 (€133 million). A portion of the deferred costs has remained classified non-current, because the Company plans to lift the prepaid quantities beyond the term of 12 months. In spite of weak market conditions in the European gas sector due to sluggish demand growth and strong competitive pressures fuelled by oversupplies, management plans to recover volumes underlying the deferred cost within the plan horizon. Transactions with related parties are described in note 4736 — Transactions with related parties.
Current liabilities18 Finance debts
| | | December 31, 2019 | | | December 31, 2018 | | (€ million) | | | Short-term debt | | | Current portion of long-term debt | | | Long-term debt | | | Total | | | Short-term debt | | | Current portion of long-term debt | | | Long-term debt | | | Total | | Banks | | | | | 187 | | | | | | 504 | | | | | | 2,341 | | | | | | 3,032 | | | | | | 383 | | | | | | 768 | | | | | | 2,710 | | | | | | 3,861 | | | Ordinary bonds | | | | | | | | | | | 2,642 | | | | | | 16,137 | | | | | | 18,779 | | | | | | | | | | | | 2,781 | | | | | | 16,923 | | | | | | 19,704 | | | Convertible bonds | | | | | | | | | | | | | | | | | 393 | | | | | | 393 | | | | | | | | | | | | | | | | | | 390 | | | | | | 390 | | | Commercial papers | | | | | 1,778 | | | | | | | | | | | | | | | | | | 1,778 | | | | | | 915 | | | | | | | | | | | | | | | | | | 915 | | | Other financial institutions | | | | | 487 | | | | | | 10 | | | | | | 39 | | | | | | 536 | | | | | | 884 | | | | | | 52 | | | | | | 59 | | | | | | 995 | | | | | | | | 2,452 | | | | | | 3,156 | | | | | | 18,910 | | | | | | 24,518 | | | | | | 2,182 | | | | | | 3,601 | | | | | | 20,082 | | | | | | 25,865 | | |
24 Short-term debt
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Commercial papers | | | | | 4,962 | | | | | | 2,738 | | | Banks | | | | | 142 | | | | | | 155 | | | Other financial institutions | | | | | 616 | | | | | | 503 | | | | | | | | 5,720 | | | | | | 3,396 | | | |
The decrease in short-term debtFinance debts decreased of €2,324€1,347 million primarily relateddue to repayments made net reimbursements for €2,645of new issuance of €1,540 million and as increase,increased due to currency translation differences relating to foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for €452€249 million.
Commercial papers of €2,738 million (€4,962 million at December 31, 2015) were issued by the Group’s financial subsidiaries Eni Finance USA Inc for €1,750 million (€2,189 million at December 31, 2015) and Eni Finance International SA for €988 million (€2,773 million at December 31, 2015). The breakdown by currency of short-term debt is provided below:
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Euro | | | | | 3,056 | | | | | | 1,405 | | | U.S. dollar | | | | | 2,616 | | | | | | 1,982 | | | Other currencies | | | | | 48 | | | | | | 9 | | | | | | | | 5,720 | | | | | | 3,396 | | | |
As of December 31, 2016, the weighted average interest rate on short-term debt was 0.9% (0.6% as of December 31, 2015).
As of December 31, 2016, Eni retained undrawn committed and uncommitted borrowing facilities amounting to €41 million and €12,267 million, respectively (€40 million and €12,708 million at December 31, 2015, respectively). Those facilities bore interests and charges for undrawn that reflect prevailing market conditions.
As of December 31, 2016, Eni did not report any default on covenants or other contractual provisions in relation to borrowing facilities.subsidiaries.
BecauseThe following table reflects long-term debt as of the short-term maturity and conditions of remuneration of short-term debts, the fair value approximated the carrying amount.
Payables due to related parties are described in note 47 — Transactions with related parties.
25 Trade and other payables
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Trade payables | | | | | 9,605 | | | | | | 11,038 | | | Advances | | | | | 637 | | | | | | 526 | | | Other payables | | | | - related to capital expenditures | | | | | 1,884 | | | | | | 2,158 | | | - others | | | | | 2,816 | | | | | | 2,981 | | | | | | | | 4,700 | | | | | | 5,139 | | | | | | | | 14,942 | | | | | | 16,703 | | | |
The increase in trade payables amounting to €1,433 million primarily related to the Gas & Power segment (€985 million).
Down payments and advances for €526 million (€637 million at December 31, 2015) related to the Refining & Marketing business line for €263 million (€253 million at December 31, 2015) and to the Exploration & Production segment for €153 million (€71 million at December 31, 2015).
Other payables were as follows:
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Payables related to capital expenditures due to | | | | Suppliers in relation to investing activities | | | | | 1,544 | | | | | | 1,835 | | | Joint venture operators in exploration and production activities | | | | | 283 | | | | | | 219 | | | Other | | | | | 57 | | | | | | 104 | | | | | | | | 1,884 | | | | | | 2,158 | | | Other payables | | | | Joint venture operators in exploration and production activities | | | | | 1,750 | | | | | | 2,057 | | | Employees | | | | | 207 | | | | | | 180 | | | Social security entities | | | | | 100 | | | | | | 94 | | | Non-financial government entities | | | | | 5 | | | | | | 6 | | | Other | | | | | 754 | | | | | | 644 | | | | | | | | 2,816 | | | | | | 2,981 | | | | | | | | 4,700 | | | | | | 5,139 | | | |
Because of the short-term maturity and conditions of remuneration of trade payables, the fair value approximated the carrying amount.
Payables due to related parties are described in note 47 — Transactions with related parties.
26 Income tax payable
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Italian subsidiaries | | | | | 65 | | | | | | 97 | | | Non-Italian subsidiaires | | | | | 366 | | | | | | 329 | | | | | | | | 431 | | | | | | 426 | | | |
Income tax payable is described in note 43 — Income taxes.
27 Other tax payable
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Excise and customs duties | | | | | 716 | | | | | | 634 | | | Other taxes and duties | | | | | 738 | | | | | | 659 | | | | | | | | 1,454 | | | | | | 1,293 | | | |
28 Other current liabilities
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Fair value of derivatives financial instruments | | | | | 4,261 | | | | | | 2,108 | | | Other liabilities | | | | | 451 | | | | | | 491 | | | | | | | | 4,712 | | | | | | 2,599 | | | |
Fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments.
Other current liabilities of €491 million (€451 million at December 31, 2015) included the current portion of advances received from Suez following a long-term agreement for supplying natural gas and electricity for €73 million (€76 million at December 31, 2015). Non-current portion is disclosed in note 33 — Other non-current liabilities.
Advances cashed in2019 by gas customers were utilized in 2016 for €10 million (versus €11 million at the opening balance). Those customers off-took lower volumes than the contractual minimum take provided by the relevant long-term supply contract in previous reporting periods, paying Eni the relevant cash advance.maturity:
Transactions with related parties are described in note 47 — Transactions with related parties.
Non-current liabilities
29 Long-term debt and current portion of long-term debt
| | | At December 31, | | | | | | | | | Long-term maturity | | (€ million) | | | Maturity range | | | 2015 | | | 2016 | | | Current maturity 2017 | | | 2018 | | | 2019 | | | 2020 | | | 2021 | | | After | | | Total | | Banks | | | 2017 – 2032 | | | | | 3,920 | | | | | | 4,286 | | | | | | 272 | | | | | | 864 | | | | | | 1,485 | | | | | | 484 | | | | | | 341 | | | | | | 840 | | | | | | 4,014 | | | Ordinary bonds | | | 2017 – 2043 | | | | | 17,608 | | | | | | 19,003 | | | | | | 2,959 | | | | | | 1,168 | | | | | | 2,503 | | | | | | 2,422 | | | | | | 940 | | | | | | 9,011 | | | | | | 16,044 | | | Convertible bonds | | | 2022 | | | | | 339 | | | | | | 383 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 383 | | | | | | 383 | | | Other financial institutions | | | 2017 – 2031 | | | | | 206 | | | | | | 171 | | | | | | 48 | | | | | | 48 | | | | | | 50 | | | | | | 3 | | | | | | 3 | | | | | | 19 | | | | | | 123 | | | | | | | | | | | 22,073 | | | | | | 23,843 | | | | | | 3,279 | | | | | | 2,080 | | | | | | 4,038 | | | | | | 2,909 | | | | | | 1,284 | | | | | | 10,253 | | | | | | 20,564 | | | |
Long-term debt and current portion of long-term debt of €23,843 million (€22,073 million at December 31, 2015) increased by €1,770 million. The increase comprised new issuance of €4,202 million net of repayments made for €2,323 million and, as decrease, currency translation differences relating foreign subsidiaries and debt denominated in foreign currency recorded by euro-reporting subsidiaries for €28 million.
Debt due to other financial institutions of €171 million (€206 million at December 31, 2015) included €29 million of finance lease transactions (€26 million at December 31, 2015).
| | | Long-term debt | | (€ million) | | | 2021 | | | 2022 | | | 2023 | | | 2024 | | | After | | | Total | | Banks | | | | | 750 | | | | | | 146 | | | | | | 838 | | | | | | 134 | | | | | | 473 | | | | | | 2,341 | | | Ordinary bonds | | | | | 930 | | | | | | 698 | | | | | | 1,879 | | | | | | 1,641 | | | | | | 10,989 | | | | | | 16,137 | | | Convertible bonds | | | | | | | | | | | 393 | | | | | | | | | | | | | | | | | | | | | | | | 393 | | | Other financial institutions | | | | | 11 | | | | | | 13 | | | | | | 14 | | | | | | 1 | | | | | | | | | | | | 39 | | | | | | | | 1,691 | | | | | | 1,250 | | | | | | 2,731 | | | | | | 1,776 | | | | | | 11,462 | | | | | | 18,910 | | |
Eni entered into long-term borrowing facilities with the European Investment Bank. These borrowing facilities are subject to the maintenanceretention of certain financial ratios based on the Consolidated Financial
Statements of Eni or a minimum level of credit rating. According to the agreements, should the Company lose the minimum credit rating, new guarantees wouldcould be required to be agreed upon with the European Investment Bank. In addition, Eni entered into long and medium-termlong-term facilities subject to the retention of certain financial ratios based on the Consolidated Financial Statements of Eni with Citibank Europe Plc providing for conditions similar to those applied byPlc. In case of default, the European Investment Bank.bank may request early repayment. At December 31, 2016,2019, debts subjected to restrictive covenants amounted to €1,953€1,243 million (€2,1271,337 million at December 31, 2015)2018). Eni compliedwas in compliance with those covenants.
Ordinary bonds of €19,003 million (€17,608 million at December 31, 2015) consisted of bonds issued within the Euro Medium Term Notes Program for a total of €16,528€15,030 million and other bonds for a total of €2,475€3,749 million. The following table provides a breakdown of ordinary bonds by issuing entity, maturity date, interest rate and currency as of December 31, 2016:2019: | | | Amount | | Discount on bond issue and accrued expense | | Total | | Currency | | | Maturity | | Rate % | | | (€ million) | | | Amount | | Discount on bond issue and accrued expense | | Total | | Currency | | | Maturity | | Rate % | | | | Amount | | Discount on bond issue and accrued expense | | Total | | Currency | | | from | | to | | from | | to | | | from | | to | | from | | to | | Issuing entity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Euro Medium Term Notes | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni SpA | | | | 1,500 | | | | | 15 | | | | | 1,515 | | | | | EUR | | | | | | | | | | 2019 | | | | | | | | | | 4.125 | | | | | | 1,200 | | | | | 16 | | | | | 1,216 | | | | | EUR | | | | | | | | | | 2025 | | | | | | | | | | 3.750 | | | Eni SpA | | | | 1,250 | | | | | 6 | | | | | 1,256 | | | | | EUR | | | | | | | | | | 2017 | | | | | | | | | | 4.750 | | | | | | 1,000 | | | | | 38 | | | | | 1,038 | | | | | EUR | | | | | | | | | | 2020 | | | | | | | | | | 4.250 | | | Eni SpA | | | | 1,200 | | | | | 17 | | | | | 1,217 | | | | | EUR | | | | | | | | | | 2025 | | | | | | | | | | 3.750 | | | | | | 1,000 | | | | | 28 | | | | | 1,028 | | | | | EUR | | | | | | | | | | 2029 | | | | | | | | | | 3.625 | | | Eni SpA | | | | 1,000 | | | | | 36 | | | | | 1,036 | | | | | EUR | | | | | | | | | | 2020 | | | | | | | | �� | | | 4.250 | | | | | | 1,000 | | | | | 20 | | | | | 1,020 | | | | | EUR | | | | | | | | | | 2020 | | | | | | | | | | 4.000 | | | Eni SpA | | | | 1,000 | | | | | 31 | | | | | 1,031 | | | | | EUR | | | | | | | | | | 2018 | | | | | | | | | | 3.500 | | | | | | 1,000 | | | | | 10 | | | | | 1,010 | | | | | EUR | | | | | | | | | | 2023 | | | | | | | | | | 3.250 | | | Eni SpA | | | | 1,000 | | | | | 26 | | | | | 1,026 | | | | | EUR | | | | | | | | | | 2029 | | | | | | | | | | 3.625 | | | | | | 1,000 | | | | | 8 | | | | | 1,008 | | | | | EUR | | | | | | | | | | 2026 | | | | | | | | | | 1.500 | | | Eni SpA | | | | 1,000 | | | | | 19 | | | | | 1,019 | | | | | EUR | | | | | | | | | | 2020 | | | | | | | | | | 4.000 | | | | | | 900 | | | | | (4) | | | | | 896 | | | | | EUR | | | | | | | | | | 2024 | | | | | | | | | | 0.625 | | | Eni SpA | | | | 1,000 | | | | | 6 | | | | | 1,006 | | | | | EUR | | | | | | | | | | 2026 | | | | | | | | | | 1.500 | | | | | | 800 | | | | | 2 | | | | | 802 | | | | | EUR | | | | | | | | | | 2021 | | | | | | | | | | 2.625 | | | Eni SpA | | | | 1,000 | | | | | 6 | | | | | 1,006 | | | | | EUR | | | | | | | | | | 2023 | | | | | | | | | | 3.250 | | | | | | 800 | | | | | (1) | | | | | 799 | | | | | EUR | | | | | | | | | | 2028 | | | | | | | | | | 1.625 | | | Eni SpA | | | | 900 | | | | | (7) | | | | | 893 | | | | | EUR | | | | | | | | | | 2024 | | | | | | | | | | 0.625 | | | | | | 750 | | | | | 9 | | | | | 759 | | | | | EUR | | | | | | | | | | 2024 | | | | | | | | | | 1.750 | | | Eni SpA | | | | 800 | | | | | 1 | | | | | 801 | | | | | EUR | | | | | | | | | | 2021 | | | | | | | | | | 2.625 | | | | | | 750 | | | | | 5 | | | | | 755 | | | | | EUR | | | | | | | | | | 2027 | | | | | | | | | | 1.500 | | | Eni SpA | | | | 800 | | | | | (3) | | | | | 797 | | | | | EUR | | | | | | | | | | 2028 | | | | | | | | | | 1.625 | | | | | | 750 | | | | | (4) | | | | | 746 | | | | | EUR | | | | | | | | | | 2034 | | | | | | | | | | 1.000 | | | Eni SpA | | | | 750 | | | | | 13 | | | | | 763 | | | | | EUR | | | | | | | | | | 2019 | | | | | | | | | | 3.750 | | | | | | 700 | | | | | 2 | | | | | 702 | | | | | EUR | | | | | | | | | | 2022 | | | | | | | | | | 0.750 | | | Eni SpA | | | | 750 | | | | | 6 | | | | | 756 | | | | | EUR | | | | | | | | | | 2024 | | | | | | | | | | 1.750 | | | | | | 650 | | | | | 3 | | | | | 653 | | | | | EUR | | | | | | | | | | 2025 | | | | | | | | | | 1.000 | | | Eni SpA | | | | 700 | | | | | | | | | | 700 | | | | | EUR | | | | | | | | | | 2022 | | | | | | | | | | 0.750 | | | | | | 600 | | | | | (4) | | | | | 596 | | | | | EUR | | | | | | | | | | 2028 | | | | | | | | | | 1.125 | | | Eni SpA | | | | 600 | | | | | (6) | | | | | 594 | | | | | EUR | | | | | | | | | | 2028 | | | | | | | | | | 1.125 | | | | Eni Finance International SA | | | | | 1,558 | | | | | (3) | | | | | 1,555 | | | | | USD | | | | | 2026 | | | | | 2027 | | | | | | | | | | variable | | | Eni Finance International SA | | | | 527 | | | | | 14 | | | | | 541 | | | | | GBP | | | | | 2018 | | | | | 2021 | | | | | 4.750 | | | | | 6.125 | | | | | | 295 | | | | | 4 | | | | | 299 | | | | | EUR | | | | | 2028 | | | | | 2043 | | | | | 3.875 | | | | | 5.441 | | | Eni Finance International SA | | | | 395 | | | | | 5 | | | | | 400 | | | | | EUR | | | | | 2017 | | | | | 2043 | | | | | 3.750 | | | | | 5.441 | | | | | | 118 | | | | | 5 | | | | | 123 | | | | | GBP | | | | | | | | | | 2021 | | | | | | | | | | 4.750 | | | Eni Finance International SA | | | | 170 | | | | | 1 | | | | | 171 | | | | | YEN | | | | | 2019 | | | | | 2037 | | | | | 1.955 | | | | | 2.810 | | | | | | 25 | | | | | | | | | | 25 | | | | | YEN | | | | | | | | | | 2021 | | | | | | | | | | 1.955 | | | | | | | 16,342 | | | | | 186 | | | | | 16,528 | | | | | | | 14,896 | | | | | 134 | | | | | 15,030 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other bonds | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni SpA | | | | 1,109 | | | | | 10 | | | | | 1,119 | | | | | EUR | | | | | | | | | | 2017 | | | | | | | | | | 4.875 | | | | | | 890 | | | | | 4 | | | | | 894 | | | | | USD | | | | | | | | | | 2023 | | | | | | | | | | 4.000 | | | Eni SpA | | | | 427 | | | | | 3 | | | | | 430 | | | | | USD | | | | | | | | | | 2020 | | | | | | | | | | 4.150 | | | | | | 890 | | | | | 2 | | | | | 892 | | | | | USD | | | | | | | | | | 2028 | | | | | | | | | | 4.750 | | | Eni SpA | | | | 333 | | | | | | | | | | 333 | | | | | USD | | | | | | | | | | 2040 | | | | | | | | | | 5.700 | | | | | | 890 | | | | | (1) | | | | | 889 | | | | | USD | | | | | | | | | | 2029 | | | | | | | | | | 4.250 | | | Eni SpA | | | | 215 | | | | | 1 | | | | | 216 | | | | | EUR | | | | | | | | | | 2017 | | | | | | | | | | variable | | | | | | 401 | | | | | 4 | | | | | 405 | | | | | USD | | | | | | | | | | 2020 | | | | | | | | | | 4.150 | | | Eni SpA | | | | | 312 | | | | | 1 | | | | | 313 | | | | | USD | | | | | | | | | | 2040 | | | | | | | | | | 5.700 | | | Eni USA Inc | | | | 379 | | | | | (2) | | | | | 377 | | | | | USD | | | | | | | | | | 2027 | | | | | | | | | | 7.300 | | | | | | 356 | | | | | | | | | | 356 | | | | | USD | | | | | | | | | | 2027 | | | | | | | | | | 7.300 | | | | | | | 2,463 | | | | | 12 | | | | | 2,475 | | | | | | | 3,739 | | | | | 10 | | | | | 3,749 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 18,805 | | | | | 198 | | | | | 19,003 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 18,635 | | | | | 144 | | | | | 18,779 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
As of December 31, 2016,2019, ordinary bonds maturing within 18 months of €3,724 million were issued by Eni SpA for €3,622 million and by Eni Finance International SA for €102amounted to €2,611 million. During 2016, Eni SpA issued2019, new bonds for €2,984issued amounted to €1,635 million.
The following table provides a breakdown of convertible bonds issued by Eni SpA as of December 31, 2016:2019: (€ million) | | | Amount | | | Discount on bond issue and accrued expense | | | Total | | | Currency | | | Maturity | | | Rate% | | Issuing entity | | | | | | | | Eni SpA | | | | | 400 | | | | | | (17) | | | | | | 383 | | | | | | EUR | | | | | | 2022 | | | | | | 0.000 | | | | | | | | 400 | | | | | | (17) | | | | | | 383 | | | | | | | | | | | | | | | | | | | | | |
(€ million) | | | Amount | | | Discount on bond issue and accrued expense | | | Total | | | Currency | | | Maturity | | | Rate % | | Eni SpA | | | | | 400 | | | | | | (7) | | | | | | 393 | | | | | | EUR | | | | | | 2022 | | | | | | 0.000 | | |
In 2016, Eni issued aThe non-dilutive equity-linked bond provides for a total nominal value of €400 million with a redemption value linked to the market price of Eni’s shares. The bondholders will have “conversion” rights at certain times and/or in the presence of certain events, while the bonds will be cash-settled. Accordingly, the issue and the conversion of the bonds will not give right to any share of Eni and there will be no dilution for shareholders. To hedge its exposure, Eni purchased cash-settled call options relating to Eni shares that will be settled on a net cash basis. The bonds will have a six-year maturity and will pay no interest and, accordingly, the coupon will be equal to 0%. The bonds were issued at a price equal to 100.5% of par and will be redeemed at par at maturity, unless previously converted or redeemed under their terms. The initialbond conversion price for the bonds has been set at €17.6222, representingis equal €17.62 and includes a 35% premium abovewith respect to the Eni’s share reference price at the date of €13.0535 determined as the arithmetic average of the daily volume-weighted average prices of an ordinary share of Eni on the Milan Stock Exchange over a period of seven consecutive scheduled trading days starting from 7 April 2016. The settlement and closing took place on 13 April 2016.issuance. The convertible bond is measured at amortized cost. The conversion option, embedded in the financial instrument issued, and the call option on Eni’s shares acquired are valued at fair value with effects recognized through profit and loss.
The bond convertible into ordinary shares of Snam SpA, amounting to €339 million as of 31 December 2015, expired on 18 January 2016. Following the exercise of the conversion rights, Eni delivered to the bondholders 76,888,264 shares ordinary representing approximately 2.20% of the share capital of Snam SpA. The residual bonds, amounting to €3.4 million, for which it was not exercised the conversion rights, were redeemed for cash.
The following table provides a breakdown by currency of long-term debt, its current portion and the related weighted average interest rates.
| | | December 31, 2015 (€ million) | | | Average rate (%) | | | December 31, 2016 (€ million) | | | Average rate (%) | | Euro | | | | | 19,623 | | | | | | 3.2 | | | | | | 21,545 | | | | | | 2.7 | | | U.S. dollar | | | | | 1,660 | | | | | | 5.0 | | | | | | 1,587 | | | | | | 5.2 | | | British pound | | | | | 629 | | | | | | 5.3 | | | | | | 540 | | | | | | 5.3 | | | Japanese yen | | | | | 161 | | | | | | 2.6 | | | | | | 171 | | | | | | 2.6 | | | | | | | | 22,073 | | | | | | | | | | | | 23,843 | | | | | | | | | |
As of December 31, 2016, Eni retained undrawn long-term committed borrowing facilities of €6,236 million (€6,577 at December 31, 2015), of which €700 million due in 2017. Those facilities bore interest rates reflecting prevailing conditions on the marketplace. As of 31 December 2016, Eni did not utilize any of its currently committed long-term borrowing facilities (€1 million at December 31, 2015) considering the amount of the liquidity reserves retained by the Company.
Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which €16.3€14.9 billion were drawn as of December 31, 2016.2019. The Group has credit ratingsfollowing table provides a breakdown by currency of BBB+ outlook stablefinance debt and A-2, respectively for longthe related weighted average interest rates: | | | December 31, 2019 | | | December 31, 2018 | | | | | Short term debt (€ million) | | | Average rate (%) | | | Long term debt and current portion of long term debt (€ million) | | | Average rate (%) | | | Short term debt (€ million) | | | Average rate (%) | | | Long term debt and current portion of long term debt (€ million) | | | Average rate (%) | | Euro | | | | | 464 | | | | | | 0.2 | | | | | | 16,526 | | | | | | 2.1 | | | | | | 680 | | | | | | 1.9 | | | | | | 18,635 | | | | | | 2.3 | | | U.S. dollar | | | | | 1,981 | | | | | | 2.3 | | | | | | 5,392 | | | | | | 4.6 | | | | | | 1,007 | | | | | | 2.5 | | | | | | 4,530 | | | | | | 4.3 | | | Other currencies | | | | | 7 | | | | | | (0.7) | | | | | | 148 | | | | | | 4.3 | | | | | | 495 | | | | | | 1.0 | | | | | | 518 | | | | | | 4.2 | | | | | | | | 2,452 | | | | | | | | | | | | 22,066 | | | | | | | | | | | | 2,182 | | | | | | | | | | | | 23,683 | | | | | | | | |
As of December 31, 2019, Eni retained undrawn uncommitted borrowing facilities amounting to €13,299 million (€12,484 million at December 31, 2018) and short-term debt, assigned by Standard & Poor’s and Baa1 outlook stable and P-2, respectively for long and short-term debt, assigned by Moody’s. Eni’s credit rating is linked to the Company’s industrial fundamentals and trendsundrawn long-term committed borrowing facilities of €4,667 million (€5,214 million at December 31, 2018). Those facilities bore interest rates reflecting prevailing conditions in the trading environmentmarketplace. As of December 31, 2019, Eni was in compliance with covenants and other contractual provisions in addition,relation to the sovereign credit rating of Italy. Based on the methodologies used by Standard & Poor’s and Moody’s, a potential downgrade of Italy’s credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni.borrowing facilities.
Fair value of long-term debt, including the current portion of long-term debt amounted to €25,358 million (€23,899 million at December 31, 2015):is described below: (€ million) | | December 31, 2015 | | December 31, 2016 | | | December 31, 2019 | | December 31, 2018 | | Ordinary bonds | | | | 18,984 | | | | | 20,501 | | | | | | 19,173 | | | | | 20,257 | | | Convertible bonds | | | | 341 | | | | | 435 | | | | | | 402 | | | | | 399 | | | Banks | | | | 4,356 | | | | | 4,244 | | | | | | 2,904 | | | | | 3,445 | | | Other financial institutions | | | | 218 | | | | | 178 | | | | | | 49 | | | | | 111 | | | | | | | 23,899 | | | | | 25,358 | | | | | | 22,528 | | | | | 24,212 | | | | |
Fair value of financial debtfinance debts was calculated by discounting the expected future cash flows at discount rates ranging from -0.2%-0.3% to 2.6% (0%2.0% (-0.2% and 2.7%2.9% at December 31, 2015)2018). At December 31, 2016, Eni did not pledge restricted deposits as collateral against its borrowings.Because of the short-term maturity and conditions of remuneration of short-term debts, the fair value approximated the carrying amount.
Changes in liabilities arising from financing activities (€ million) | | | Long-term debt and current portion of long-term debt | | | Short-term debt | | | Long-term and current portion of long-term lease liabilietis | | | Total | | Carrying amount at December 31, 2018 | | | | | 23,683 | | | | | | 2,182 | | | | | | | | | | | | 25,865 | | | First adoption IFRS 16 | | | | | | | | | | | | | | | | | 5,656 | | | | | | 5,656 | | | Reclassifications | | | | | | | | | | | | | | | | | 168 | | | | | | 168 | | | Reclassification to liabilities directly associated with assets held for sale | | | | | | | | | | | | | | | | | (13) | | | | | | (13) | | | Carrying amount at January 1, 2019 | | | | | 23,683 | | | | | | 2,182 | | | | | | 5,811 | | | | | | 31,676 | | | Cash flows | | | | | (1,701) | | | | | | 161 | | | | | | (877) | | | | | | (2,417) | | | Currency translation differences | | | | | 157 | | | | | | 92 | | | | | | 93 | | | | | | 342 | | | Changes in the scope of consolidation | | | | | | | | | | | 5 | | | | | | | | | | | | 5 | | | Other non-monetary changes | | | | | (73) | | | | | | 12 | | | | | | 621 | | | | | | 560 | | | Carrying amount at December 31, 2019 | | | | | 22,066 | | | | | | 2,452 | | | | | | 5,648 | | | | | | 30,166 | | |
Other non-monetary changes include €668 million of lease liabilities assumptions. Lease liabilities are described in note 12 — Right-of-use assets and lease liabilities. Transactions with related parties are described in note 36 — Transactions with related parties 19 Information on net borrowings In assessing its capital structure, Eni uses net borrowings, which is a non-GAAP financial measure. Eni calculates net borrowings as total finance debt (short-term and long-term debt) derived from its Consolidated Financial Statements prepared in accordance with IFRS as endorsed by IASB less: cash and cash equivalents, held-for-trading securities and other financial assets, and certain highly liquidhighly-liquid investments not related to operations including, among others, non-operating financing receivables and available-for-sale securities not related to operations.receivables. Held-for-trading securities and other financial assets are part of a strategic reserve of liquidity that management has established by reinvesting proceeds from the Group disposal plans and is intended to provide a certain degree of financial flexibility in case of a prolonged price downturn, tight financial markets or in view of other Company’s purposes. Non-operating financing receivables consist mainly of deposits with banks and other financing institutions and deposits in escrow. Available-for-sale securities not related to operations consist primarily of government bonds and securities from financing institutions. These assets are generally intended to absorb temporary surpluses of cash as part of the Company’s ordinary management of financing activities.
Management believes that net borrowings is a useful measure of Eni’s financial condition as it provides insight about the soundness of Eni’s capital structure and the ways by which Eni’s operating assets are financed. In addition, management utilizes the ratio of net borrowings to total shareholders’ equity including non-controlling interest (leverage) to assess Eni’s capital structure, to analyze whether the ratio between finance debt | | | December 31, 2019 | | | December 31, 2018 | | (€ million) | | | Current | | | Non-current | | | Total | | | Current | | | Non-current | | | Total | | A. Cash and cash equivalents | | | | | 5,994 | | | | | | | | | | | | 5,994 | | | | | | 10,836 | | | | | | | | | | | | 10,836 | | | B. Held-for-trading financial assets | | | | | 6,760 | | | | | | | | | | | | 6,760 | | | | | | 6,552 | | | | | | | | | | | | 6,552 | | | C Liquidity (A+B) | | | | | 12,754 | | | | | | | | | | | | 12,754 | | | | | | 17,388 | | | | | | | | | | | | 17,388 | | | D. Financing receivables | | | | | 287 | | | | | | | | | | | | 287 | | | | | | 188 | | | | | | | | | | | | 188 | | | E. Short-term debt towards banks | | | | | 187 | | | | | | | | | | | | 187 | | | | | | 383 | | | | | | | | | | | | 383 | | | F. Long-term debt towards banks | | | | | 504 | | | | | | 2,341 | | | | | | 2,845 | | | | | | 768 | | | | | | 2,710 | | | | | | 3,478 | | | G. Bonds | | | | | 2,642 | | | | | | 16,530 | | | | | | 19,172 | | | | | | 2,781 | | | | | �� | 17,313 | | | | | | 20,094 | | | H. Short-term debt towards related parties | | | | | 46 | | | | | | | | | | | | 46 | | | | | | 661 | | | | | | | | | | | | 661 | | | I. Other short-term liabilities | | | | | 2,219 | | | | | | | | | | | | 2,219 | | | | | | 1,138 | | | | | | | | | | | | 1,138 | | | J. Other long-term liabilities | | | | | 10 | | | | | | 39 | | | | | | 49 | | | | | | 52 | | | | | | 59 | | | | | | 111 | | | K. Total borrowings before lease liabilities (E+F+G+H+I+J) | | | | | 5,608 | | | | | | 18,910 | | | | | | 24,518 | | | | | | 5,783 | | | | | | 20,082 | | | | | | 25,865 | | | L. Net borrowings before lease liabilities (K-C-D) | | | | | (7,433) | | | | | | 18,910 | | | | | | 11,477 | | | | | | (11,793) | | | | | | 20,082 | | | | | | 8,289 | | | M. Lease liabilities | | | | | 884 | | | | | | 4,751 | | | | | | 5,635 | | | | | | | | | | | | | | | | | | | | | N. Lease liabilities towards related parties | | | | | 5 | | | | | | 8 | | | | | | 13 | | | | | | | | | | | | | | | | | | | | | O. Total borrowings including lease liabilities (K+M+N) | | | | | 6,497 | | | | | | 23,669 | | | | | | 30,166 | | | | | | 5,783 | | | | | | 20,082 | | | | | | 25,865 | | | P. Net borrowings including lease liabilities (O-C-D) | | | | | (6,544) | | | | | | 23,669 | | | | | | 17,125 | | | | | | (11,793) | | | | | | 20,082 | | | | | | 8,289 | | |
Cash and shareholders’ equity is well balanced according to industry standardscash equivalent are disclosed in note 5 — Cash and to track management’s short-term and medium-term targets. Management continuously monitors trends in net borrowings and trends in leverage in order to optimize the use of internally-generated funds versus funds from third parties. The measure calculated in accordance with IFRS that is most directly comparable to net borrowings is total debt (short-term and long-term debt). The most directly comparable measure, derived from IFRS reported amounts, to calculate leverage is the ratio of total debt to shareholders’ equity (including non-controlling interest). Eni’s presentation and calculation of net borrowings and leverage may not be comparable to that of other companies.cash equivalent. | | | December 31, 2015 | | | December 31, 2016 | | (€ million) | | | Current | | | Non- current | | | Total | | | Current | | | Non- current | | | Total | | A. Cash and cash equivalents | | | | | 5,209 | | | | | | | | | | | | 5,209 | | | | | | 5,674 | | | | | | | | | | | | 5,674 | | | B. Held-for-trading financial assets | | | | | 5,028 | | | | | | | | | | | | 5,028 | | | | | | 6,166 | | | | | | | | | | | | 6,166 | | | C. Available-for-sale financial assets | | | | | | | | | | | | | | | | | | | | | | | 238 | | | | | | | | | | | | 238 | | | D. Liquidity (A+B+C) | | | | | 10,237 | | | | | | | | | | | | 10,237 | | | | | | 12,078 | | | | | | | | | | | | 12,078 | | | E. Financing receivables | | | | | 685 | | | | | | | | | | | | 685 | | | | | | 385 | | | | | | | | | | | | 385 | | | F. Short-term debt towards banks | | | | | 142 | | | | | | | | | | | | 142 | | | | | | 155 | | | | | | | | | | | | 155 | | | G. Long-term debt towards banks | | | | | 455 | | | | | | 3,465 | | | | | | 3,920 | | | | | | 272 | | | | | | 4,014 | | | | | | 4,286 | | | H. Bonds | | | | | 2,176 | | | | | | 15,771 | | | | | | 17,947 | | | | | | 2,959 | | | | | | 16,427 | | | | | | 19,386 | | | I. Short-term debt towards related parties | | | | | 208 | | | | | | | | | | | | 208 | | | | | | 191 | | | | | | | | | | | | 191 | | | L. Other short-term liabilities | | | | | 5,370 | | | | | | | | | | | | 5,370 | | | | | | 3,050 | | | | | | | | | | | | 3,050 | | | M. Other long-term liabilities | | | | | 45 | | | | | | 161 | | | | | | 206 | | | | | | 48 | | | | | | 123 | | | | | | 171 | | | N. Total borrowings (F+G+H+I+L+M) | | | | | 8,396 | | | | | | 19,397 | | | | | | 27,793 | | | | | | 6,675 | | | | | | 20,564 | | | | | | 27,239 | | | O. Net borrowings (N-D-E) | | | | | (2,526) | | | | | | 19,397 | | | | | | 16,871 | | | | | | (5,788) | | | | | | 20,564 | | | | | | 14,776 | | | |
Financial assets held for trading of €6,166 million (€5,028 million at December 31, 2015) related to Eni SpA for €6,062 and to Eni Insurance DAC for €104 million. For further information seeare disclosed in note 96 — Financial assets held for trading. Available-for-sale securities of €238Financing receivables are disclosed in note 16 — Other financial assets.
Finance debts are disclosed in note 18 — Finance debts. Liabilities for leased assets related for €1,976 million were held for non-operating purposes and related to Eni Insurance DAC. Furthermore, Eni held certain held-to-maturity and available-for-sale securities destined to operating purposes amounting to €75 million (€359 million at December 31, 2015). These securities are excluded from the calculation above. The decrease of €282 million was mainly due to the reclassificationshare of securities retainedjoint operators in upstream projects operated by Eni Insurance DAC to securities held for non-operating purposes. In previous reporting periods, those securities were committed to fund the loss reserve of the insurance company. The change in the destination of those assets was permitted by the entry into force from January 1, 2016, of the provisions of EU Solvency II Directive on capital requirements towhich will be met for operating in the insurance activity.recovered through a partner cash-call billing process. More information is reported in note 1012 — FinancialRight-of-use assets available for sale.and lease liabilities. Current financing receivables of €385 million (€685 million at December 31, 2015) were held for non-operating purposes. At the reporting date, the Company held financing receivables which were destined to operating purposes amounting to €158 million (€1,622 million at December 31, 2015), of which €28 million (€1,135 million at December 31, 2015) were in respect of financing granted to joint ventures and affiliates which executed capital projects and investments on behalf of Eni’s Group companies. The decrease of €300 million was mainly due to the repayment of receivables related to margins on derivatives of Eni Trading & Shipping SpA for €457 million and, as increase, the reclassification to financial receivables of €287 million as a consequence of the adoption starting from January 1, 2016, of the provisions of EU Solvency II Directive on capital requirements to be met for operating in the insurance activity. More information is reported in note 10 — Financial assets available for sale.20 Provisions
(€ million) | | | Provisions for site restoration, abandonment and social projects | | | Environmental provisions | | | Provisions for litigations | | | Provisions for taxes other than income taxes | | | Loss adjustments and actuarial provisions for Eni’s insurance companies | | | Provisions for losses on investments | | | Provisions for OIL insurance cover | | | Provisions for redundancy incentives | | | Provisions for disposal and restructuring | | | Other | | | Total | | Carrying amount at December 31, 2018 | | | | | 6,777 | | | | | | 2,595 | | | | | | 824 | | | | | | 180 | | | | | | 327 | | | | | | 204 | | | | | | 130 | | | | | | 108 | | | | | | 66 | | | | | | 415 | | | | | | 11,626 | | | New or increased provisions | | | | | | | | | | | 354 | | | | | | 165 | | | | | | 38 | | | | | | 173 | | | | | | 65 | | | | | | | | | | | | 2 | | | | | | 2 | | | | | | 411 | | | | | | 1,210 | | | Initial recognition and changes in estimates | | | | | 2,074 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,074 | | | Accretion discount | | | | | 247 | | | | | | 7 | | | | | | (2) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3 | | | | | | 255 | | | Reversal of utilized provisions | | | | | (313) | | | | | | (299) | | | | | | (43) | | | | | | (24) | | | | | | (175) | | | | | | | | | | | | | | | | | | (11) | | | | | | (12) | | | | | | (51) | | | | | | (928) | | | Reversal of unutilized provisions | | | | | (7) | | | | | | (25) | | | | | | (105) | | | | | | | | | | | | | | | | | | | | | | | | (19) | | | | | | (29) | | | | | | (10) | | | | | | (7) | | | | | | (202) | | | Currency translation differences | | | | | 112 | | | | | | | | | | | | 13 | | | | | | 8 | | | | | | | | | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | 4 | | | | | | 139 | | | Other changes | | | | | 46 | | | | | | (30) | | | | | | (2) | | | | | | (3) | | | | | | 8 | | | | | | (83) | | | | | | 2 | | | | | | | | | | | | | | | | | | (6) | | | | | | (68) | | | Carrying amount at December 31, 2019 | | | | | 8,936 | | | | | | 2,602 | | | | | | 850 | | | | | | 199 | | | | | | 333 | | | | | | 188 | | | | | | 113 | | | | | | 70 | | | | | | 46 | | | | | | 769 | | | | | | 14,106 | | |
30 Provisions for contingencies
(€ million) | | | Carrying amount at December 31, 2015 | | | New or increased provisions | | | Initial recognition and changes in estimates | | | Accretion discount | | | Utilization | | | Reversal of unutilized provisions | | | Currency translation differences | | | Other changes | | | Carrying amount at December 31, 2016 | | Provision for decommissioning and social projects | | | | | 8,998 | | | | | | | | | | | | (647) | | | | | | 297 | | | | | | (336) | | | | | | (1) | | | | | | 55 | | | | | | 53 | | | | | | 8,419 | | | Environmental provision | | | | | 2,737 | | | | | | 235 | | | | | | | | | | | | 8 | | | | | | (249) | | | | | | (37) | | | | | | | | | | | | (3) | | | | | | 2,691 | | | Provision for litigations | | | | | 1,725 | | | | | | 177 | | | | | | | | | | | | | | | | | | (1,099) | | | | | | (25) | | | | | | 1 | | | | | | 175 | | | | | | 954 | | | Provision for taxes | | | | | 484 | | | | | | 258 | | | | | | | | | | | | | | | | | | (30) | | | | | | (2) | | | | | | 21 | | | | | | 1 | | | | | | 732 | | | Loss adjustments and actuarial provisions for Eni’s insurance companies | | | | | 323 | | | | | | 52 | | | | | | | | | | | | | | | | | | (184) | | | | | | | | | | | | | | | | | | 16 | | | | | | 207 | | | Provision for redundancy incentives | | | | | 201 | | | | | | 1 | | | | | | | | | | | | 3 | | | | | | (13) | | | | | | (8) | | | | | | | | | | | | (8) | | | | | | 176 | | | Provision for onerous contracts | | | | | 273 | | | | | | 6 | | | | | | | | | | | | 3 | | | | | | (103) | | | | | | (6) | | | | | | (7) | | | | | | (1) | | | | | | 165 | | | Provision for losses on investments | | | | | 128 | | | | | | 41 | | | | | | | | | | | | | | | | | | | | | | | | (11) | | | | | | 2 | | | | | | (7) | | | | | | 153 | | | Provision for OIL insurance cover | | | | | 72 | | | | | | 16 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 88 | | | Provision for disposal and restructuring | | | | | 80 | | | | | | 7 | | | | | | | | | | | | | | | | | | (16) | | | | | | (11) | | | | | | (2) | | | | | | | | | | | | 58 | | | Provision for green certificates | | | | | 190 | | | | | | | | | | | | | | | | | | | | | | | | (13) | | | | | | (1) | | | | | | | | | | | | (175) | | | | | | 1 | | | Other (*) | | | | | 164 | | | | | | 213 | | | | | | | | | | | | 1 | | | | | | (72) | | | | | | (7) | | | | | | 4 | | | | | | (51) | | | | | | 252 | | | | | | | | 15,375 | | | | | | 1,006 | | | | | | (647) | | | | | | 312 | | | | | | (2,115) | | | | | | (109) | | | | | | 74 | | | | | | | | | | | | 13,896 | | | |
(*)
Each individual amount included herein was lower than €50 million.
The Group makes full provision forsite restoration, abandonment and social projects include the future costspresent value of decommissioning oil and natural gas wells, facilities and related pipelines on a discounted basis upon installation. The decommissioning provisions at the reporting date amounted to €8,419 million and included future costs for social projects. Those provisions comprised the discounted estimated costs that the Company expects to incur for
decommissioning oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration of the
Exploration & Production segment for €7,901€8,411 million. Negative estimates’ revisionsInitial recognitions and changes in estimates of €647€2,074 million were primarily due tomainly driven by a risedecrease in the discount rate curve in particular for the U.S. dollar and to a lesser extent by the revisionrecognition of previous estimates ofnew decommissioning costs, partially offset by new provisionsobligations due to the activity of the year. The accretionunwinding of discount recognized in thethrough profit and loss account for €297€247 million was determined by adoptingbased on discount rates ranging from -0.1% to 6.1% (from -0.01%-0.2% to 5.8% (from 0.2% to 4.6%6.1% at December 31, 2015)2018). Main expenditures associated with decommissioning operations are expected to be incurred over a 40-year45-year period. Provisions for environmental risks of €2,691 million included the estimated costs for environmental remediationclean-up and restorationremediation of soil and groundwater in areas owned or under concession where the Group conductedperformed in the past industrial operations whichthat were progressively divested, shut down, dismantled or restructured. The provision has beenwas accrued because at the balance sheet date there is a legal or constructive obligation for Eni to carry out cleaning-up operationsenvironmental clean-up and remediation and the expected costs can be estimated reliably. The provision includesincluded the expected charges associated with strict liability related to obligations of restoring the contaminated sitescleaning up and remediating polluted areas that met the parameters set by the law at the time when the pollution occurred but presently are no more in compliance with current environmental laws and regulations, or because Eni assumed the liability of thirdborne by other operators when the Company acquired or otherwise took over the ownership of the site.site operations. Those environmental provisions are recognized when an environmental project is approved by or filed with the relevant administrative authorities or a constructive obligation has arisen whereby the Company commits itself to performperforming certain cleaning-up and restoration projects and a reliable cost estimation is available. At December 31, 2016,2019, environmental provision primarily related to Eni Rewind SpA (former Syndial SpASpA) for €2,211€1,930 million and to the Refining & Marketing business line for €364 million. Additions€416 million which includes the costs of €235 million primarily related to Syndial SpArestoration and environmental remediation as a part of the Memorandum of Understanding signed between Eni and the Ministry for €110 million and to the Refining & Marketing business line for €99 million. Utilizations of €249 million primarily related to the Refining & Marketing business line for €124 million Syndial SpA for €89 million.Environment in December 2019. Provisions for litigations of €954 millionLitigation provisions comprised the expected liabilities associated with legal proceedings and out of court proceedingsother matters arising from contractual claims, contract renegotiations, including arbitration,arbitrations, fines and penalties due to antitrust proceedings and administrative matters. These provisions representedrepresent the Company’s best estimate of the expected and probable liabilities associated with pendingongoing litigation and commercial proceedings and primarily related to the Gas & Power segment for €546 million and the Exploration & Production segment for €261€723 million. Additions and utilizations of €177 million and €1,099 million, respectively, mainly related to the Gas & Power segment and were recognized to take account of gas price revisions at long-term supply and sale contracts, including the settlement of certain arbitrations. Other changes of €175 million related to the reclassification to provisions for litigation of the expected liability incurred in connection with a dispute between EniPower and an Italian authority for the national grid on the use of certain allowances for the fulfillment of the obligations concerning GHG emissions at certain Eni’s plant for the production of co-generative power.
Provisions for taxes of €732 million includedother than income taxes related to the estimated chargeslosses that the Company expects to incur for unsettledto settle uncertain tax matters and tax claims pending with tax authorities in connection withrelation to uncertainties in the application of taxapplying rules at certain Italian andin force for foreign subsidiaries inof the Exploration & Production segment (€704 million).for €169 million. Loss adjustments and actuarial provisions of Eni’s insurance company Eni Insurance DAC of €207 million represented the estimated liabilities accrued on the basis for third partiesparty claims. Against such liability was recorded a receivablereceivables of €147€162 million recognized towards insurance companies for reinsurance contracts. Provisions for redundancy incentives of €176 million were recognized due to a restructuring program involving the Italian personnel related to past reporting periods. Provisions for onerous contracts of €165 million related to the execution of contracts where the expected costs exceed the relevant benefits. In particular, the provision comprised the estimated expected losses on unutilized infrastructures for gas transportation and on a regasification project.
Provisions for losses on investments of €153 million were made with respectincluded provisions relating to certain investeesinvestments whose loss exceeds the equity and primarily related to Industria Siciliana Acido Fosforico — ISAF — SpA (in liquidation) for which expected or incurred losses exceeded carrying amounts.€131 million.
Provisions for the OIL mutual insurance scheme of €88 million included the estimated future increase of insurance premiums which will be charged to Eni in the next five years and that were accrued at the reporting date because of the effective accident rate occurred in past reporting periods. Provisions for redundancy incentives were recognized mainly due to a restructuring program involving the Italian personnel related to past reporting periods. 21 Provisions for employee benefits (€ million) | | | December 31, 2019 | | | December 31, 2018 | | Italian defined benefit plans | | | | | 269 | | | | | | 275 | | | Foreign defined benefit plans | | | | | 412 | | | | | | 385 | | | FISDE, foreign medical plans and other | | | | | 177 | | | | | | 148 | | | Defined benefit plans | | | | | 858 | | | | | | 808 | | | Other benefit plans | | | | | 278 | | | | | | 309 | | | Provision for employee benefits | | | | | 1,136 | | | | | | 1,117 | | | |
Provisions for disposal and restructuringThe liability relating to Eni’s commitment to cover the healthcare costs of €58 million essentially related to the Chemical business line (€32 million) and to Syndial SpA (€14 million).
31 Provisions for employee benefits
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | TFR | | | | | 281 | | | | | | 298 | | | Foreign defined benefit plans | | | | | 533 | | | | | | 276 | | | Supplementary medical reserve for Eni managers (FISDE) and other foreign medical plans | | | | | 156 | | | | | | 124 | | | Other foreign long-term benefit plans | | | | | 153 | | | | | | 170 | | | | | | | | 1,123 | | | | | | 868 | | | |
Provisions for benefits upon termination of employment primarily related to a provisions accrued by Italian companies for employee retirement,personnel is determined using actuarial techniques and regulated by Article 2120 of the Italian Civil Code. The benefit is paid upon retirement as a lump sum, the amount of which corresponds to the total of the provisions accrued during the employees’ service period based on payroll costs as revalued until retirement. Following the changes in the law regime, from January 1, 2007, accruing benefits have been contributing to a pension fund or a treasury fund held by the Italian administration for post-retirement benefits (INPS). For companies with less than 50 employees, it will be possible to continue the scheme as in previous years. Therefore, contributions of future TFR provisions to pension funds or the INPS treasury fund determines that these amounts will be treated in accordance to a defined contribution scheme. Amounts already accrued before January 1, 2007 continue to be accounted for as defined benefits to be assessed based on actuarial assumptions.
Pension funds are defined benefit plans provided by foreign subsidiaries located mainly in Nigeria, Germany and the United Kingdom. Benefits under these plans consist of payments based on seniority and the salary paid in the last year of service, or alternatively, the average annual salary over a defined period prior to the retirement.
Group companies provide healthcare benefits. Liability to these plans (FISDE and other foreign healthcare plans) and the current cost are limited to the contributions made by the Company for retired managers.
Other benefits primarily consisted of monetary and long-term incentive schemes to Group managers, jubilee awards and a defined benefit plan for certain employees engaged in the retail gas activity. Provisions for the monetary incentive scheme are assessed based on the estimated bonuses that will be granted to those managers who will achieve certain individual performance goals weighted with the likelihood that the Company delivers the planned profitability targets. The benefit has a three-year vesting period and incurs when the commitment arises towards Eni’s management, based on the achievement of corporate goals. The estimate is subject to adjustments in subsequent years based on the results achieved and the update of the result forecasted (above or below the target). This benefit is applied pro-rata temporis over the three-year period depending on the results of the performance parameters. Provisions for the long-term incentive scheme are assessed on the basis of the estimated trends of a performance indicator as benchmarked against a group of international oil companies. Both of thesecontributions paid by the Company.
Other employee benefit plans related to deferred monetary incentive schemes normally vest over a three-year period. Jubilee awards are benefits due followingplans for €132 million, the attainment of a minimum period of service and, for the Italian companies, consist of an in-kind remuneration. The a definedisopensione plans (a post retirement benefit plan applicable to a specific category of employees) of Eni gas e luce SpA for certain employees engaged in the retail gas activity is a supplementary pension plan set up in the 70’s€107 million, jubilee awards for €25 million and managed by the Italian national agencyother long-term plans for welfare. This fund, previously considered a defined contribution plan, became a defined benefit plan due to certain regulatory changes. The Eni personnel engaged in the gas activity came from the merger of the former “Italgas Più”.€14 million.
Present value of employee benefits, estimated by applying actuarial techniques, consisted of the following: | | December 31, 2015 | | December 31, 2016 | | | 2019 | | 2018 | | (€ million) | | TFR | | Foreign defined benefit plans | | Fisde and other foreign medical plans | | Other long-term benefit plans | | Total | | TFR | | Foreign defined benefit plans | | Fisde and other foreign medical plans | | Other long-term benefit plans | | Total | | | Italian defined benefit plans | | Foreign defined benefit plans | | FISDE, foreign medical plans and other | | Defined benefit plans | | Other benefit plans | | Total | | Italian defined benefit plans | | Foreign defined benefit plans | | FISDE, foreign medical plans and other | | Defined benefit plans | | Other benefit plans | | Total | | Present value of benefit liabilities at beginning of year | | | | 376 | | | | | 1,282 | | | | | 174 | | | | | 191 | | | | | 2,023 | | | | | 281 | | | | | 1,240 | | | | | 156 | | | | | 153 | | | | | 1,830 | | | | | | 275 | | | | | 925 | | | | | 148 | | | | | 1,348 | | | | | 309 | | | | | 1,657 | | | | | 284 | | | | | 997 | | | | | 135 | | | | | 1,416 | | | | | 194 | | | | | 1,610 | | | Current cost | | | | | | | | | 41 | | | | | 2 | | | | | 54 | | | | | 97 | | | | | | | | | | 28 | | | | | 2 | | | | | 56 | | | | | 86 | | | | | | | | | | | 19 | | | | | 2 | | | | | 21 | | | | | 55 | | | | | 76 | | | | | | | | | | 27 | | | | | 2 | | | | | 29 | | | | | 42 | | | | | 71 | | | Interest cost | | | | 6 | | | | | 41 | | | | | 3 | | | | | 1 | | | | | 51 | | | | | 6 | | | | | 34 | | | | | 3 | | | | | 1 | | | | | 44 | | | | | | 4 | | | | | 37 | | | | | 3 | | | | | 44 | | | | | 1 | | | | | 45 | | | | | 4 | | | | | 31 | | | | | 2 | | | | | 37 | | | | | 1 | | | | | 38 | | | Remeasurements: | | | | (26) | | | | | (20) | | | | | (1) | | | | | (17) | | | | | (64) | | | | | 19 | | | | | 22 | | | | | (17) | | | | | 1 | | | | | 25 | | | | | | 5 | | | | | 41 | | | | | 24 | | | | | 70 | | | | | 1 | | | | | 71 | | | | | 1 | | | | | (25) | | | | | 13 | | | | | (11) | | | | | 30 | | | | | 19 | | | - actuarial (gains) losses due to changes in demographic assumptions | | | | | | | | | (5) | | | | | | | | | | | | | | | (5) | | | | | (2) | | | | | (2) | | | | | (1) | | | | | (2) | | | | | (7) | | | | - actuarial (gains) losses due to changes in financial assumptions | | | | | | | | | 4 | | | | | 2 | | | | | (14) | | | | | (8) | | | | | 11 | | | | | 30 | | | | | (2) | | | | | 2 | | | | | 41 | | | | | | 7 | | | | | 50 | | | | | 3 | | | | | 60 | | | | | 1 | | | | | 61 | | | | | | | | | | (31) | | | | | 1 | | | | | (30) | | | | | 29 | | | | | (1) | | | - experience (gains) losses | | | | (26) | | | | | (19) | | | | | (3) | | | | | (3) | | | | | (51) | | | | | 10 | | | | | (6) | | | | | (14) | | | | | 1 | | | | | (9) | | | | | | (2) | | | | | (9) | | | | | 21 | | | | | 10 | | | | | | | | | | 10 | | | | | 1 | | | | | 6 | | | | | 12 | | | | | 19 | | | | | 1 | | | | | 20 | | | Past service cost and (gains) losses settlements | | | | | | | | | (9) | | | | | (1) | | | | | 13 | | | | | 3 | | | | | | | | | | (7) | | | | | 2 | | | | | (3) | | | | | (8) | | | | | | | | | | | 1 | | | | | 8 | | | | | 9 | | | | | (2) | | | | | 7 | | | | | | | | | | 2 | | | | | 1 | | | | | 3 | | | | | 115 | | | | | 118 | | | Plan contributions: | | | | | | | | | 1 | | | | | | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | | | | | | 1 | | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | - employee contributions | | | | ��� | | | | | 1 | | | | | | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | | | | | | 1 | | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | Benefits paid | | | | (25) | | | | | (56) | | | | | (7) | | | | | (53) | | | | | (141) | | | | | (8) | | | | | (33) | | | | | (6) | | | | | (31) | | | | | (78) | | | | | | (15) | | | | | (28) | | | | | (9) | | | | | (52) | | | | | (88) | | | | | (140) | | | | | (15) | | | | | (35) | | | | | (9) | | | | | (59) | | | | | (74) | | | | | (133) | | | Reclassification to discontinued operations and asset held for sale | | | | (52) | | | | | (181) | | | | | (23) | | | | | (41) | | | | | (297) | | | | | Reclassification to liabilities directly associated with asset held for sale | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (8) | | | | | | | | | | (8) | | | | | | | | | | (8) | | | Changes in the scope of consolidation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (90) | | | | | | | | | | (90) | | | | | (2) | | | | | (92) | | | Currency translation differences and other changes | | | | 2 | | | | | 141 | | | | | 9 | | | | | 5 | | | | | 157 | | | | | | | | | | (390) | | | | | (16) | | | | | (7) | | | | | (413) | | | | | | | | | | | 48 | | | | | 1 | | | | | 49 | | | | | 2 | | | | | 51 | | | | | 1 | | | | | 25 | | | | | 4 | | | | | 30 | | | | | 3 | | | | | 33 | | | Present value of benefit liabilities at end of year (a) | | | | 281 | | | | | 1,240 | | | | | 156 | | | | | 153 | | | | | 1,830 | | | | | 298 | | | | | 895 | | | | | 124 | | | | | 170 | | | | | 1,487 | | | | | | 269 | | | | | 1,044 | | | | | 177 | | | | | 1,490 | | | | | 278 | | | | | 1,768 | | | | | 275 | | | | | 925 | | | | | 148 | | | | | 1,348 | | | | | 309 | | | | | 1,657 | | | Plan assets at beginning of year | | | | | | | | | 710 | | | | | | | | | | | | | | | 710 | | | | | | | | | | 707 | | | | | | | | | | | | | | | 707 | | | | | | | | | | | 545 | | | | | | | | | | 545 | | | | | | | | | | 545 | | | | | | | | | | 588 | | | | | | | | | | 588 | | | | | | | | | | 588 | | | Interest income | | | | | | | | | 24 | | | | | | | | | | | | | | | 24 | | | | | | | | | | 20 | | | | | | | | | | | | | | | 20 | | | | | | | | | | | 20 | | | | | | | | | | 20 | | | | | | | | | | 20 | | | | | | | | | | 17 | | | | | | | | | | 17 | | | | | | | | | | 17 | | | Return on plan assets | | | | | | | | | (11) | | | | | | | | | | | | | | | (11) | | | | | | | | | | 42 | | | | | | | | | | | | | | | 42 | | | | | | | | | | | 23 | | | | | | | | | | 23 | | | | | | | | | | 23 | | | | | | | | | | (21) | | | | | | | | | | (21) | | | | | | | | | | (21) | | | Past service cost and (gains) losses settlements | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (3) | | | | | | | | | | | | | | | (3) | | | | Administration expenses paid | | | | | | | | | (1) | | | | | | | | | | | | | | | (1) | | | | | Plan contributions: | | | | | | | | | 42 | | | | | | | | | | | | | | | 42 | | | | | | | | | | 25 | | | | | | | | | | | | | | | 25 | | | | | | | | | | | 14 | | | | | | | | | | 14 | | | | | | | | | | 14 | | | | | | | | | | 25 | | | | | | | | | | 25 | | | | | | | | | | 25 | | | - employee contributions | | | | | | | | | 1 | | | | | | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | | | | | | 1 | | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | | | | | | | | 1 | | | - employer contributions | | | | | | | | | 41 | | | | | | | | | | | | | | | 41 | | | | | | | | | | 24 | | | | | | | | | | | | | | | 24 | | | | | | | | | | | 13 | | | | | | | | | | 13 | | | | | | | | | | 13 | | | | | | | | | | 24 | | | | | | | | | | 24 | | | | | | | | | | 24 | | | Benefits paid | | | | | | | | | (24) | | | | | | | | | | | | | | | (24) | | | | | | | | | | (19) | | | | | | | | | | | | | | | (19) | | | | | | | | | | | (19) | | | | | | | | | | (19) | | | | | | | | | | (19) | | | | | | | | | | (26) | | | | | | | | | | (26) | | | | | | | | | | (26) | | | Reclassification to discontinued operations and asset held for sale | | | | | | | | | (86) | | | | | | | | | | | | | | | (86) | | | | | Changes in the scope of consolidation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (64) | | | | | | | | | | (64) | | | | | | | | | | (64) | | | Currency translation differences and other changes | | | | | | | | | 53 | | | | | | | | | | | | | | | 53 | | | | | | | | | | (153) | | | | | | | | | | | | | | | (153) | | | | | | | | | | | 49 | | | | | | | | | | 49 | | | | | | | | | | 49 | | | | | | | | | | 26 | | | | | | | | | | 26 | | | | | | | | | | 26 | | | Plan assets at end of year (b) | | | | | | | | | 707 | | | | | | | | | | | | | | | 707 | | | | | | | | | | 619 | | | | | | | | | | | | | | | 619 | | | | | | | | | | | 632 | | | | | | | | | | 632 | | | | | | | | | | 632 | | | | | | | | | | 545 | | | | | | | | | | 545 | | | | | | | | | | 545 | | | Net liability recognized at end of year (a-b) | | | | 281 | | | | | 533 | | | | | 156 | | | | | 153 | | | | | 1,123 | | | | | 298 | | | | | 276 | | | | | 124 | | | | | 170 | | | | | 868 | | | | | | Asset ceiling at beginning of year | | | | | | | | | | 5 | | | | | | | | | | 5 | | | | | | | | | | 5 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Change in asset ceiling | | | | | | | | | | (5) | | | | | | | | | | (5) | | | | | | | | | | (5) | | | | | | | | | | 5 | | | | | | | | | | 5 | | | | | | | | | | 5 | | | Asset ceiling at end of year (c) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5 | | | | | | | | | | 5 | | | | | | | | | | 5 | | | Net liability recognized at end of year (a-b+c) | | | | | 269 | | | | | 412 | | | | | 177 | | | | | 858 | | | | | 278 | | | | | 1,136 | | | | | 275 | | | | | 385 | | | | | 148 | | | | | 808 | | | | | 309 | | | | | 1,117 | | |
Foreign defined benefit plans amounting to €276 million (€533 million at December 31, 2015) primarily related to pension plans for €184 million (€402 million at December 31, 2015).
Foreign employeeEmployee benefit plans included the liability attributable to joint venture partners operating in exploration and production activities of €60€175 million (€281181 million at December 31, 2015)2018). Eni recorded a receivable for an amount equivalent to such liability.
Other employee benefit plans of €170 million (€153 million at December 31, 2015) related to: (i) defined benefit plans for €12 million (€11 million at December 31, 2015) related to the Gas fund; and (ii) long-term benefit plans for €158 million (€142 million at December 31, 2015) of which deferred monetary incentive plans for €99 million (€87 million at December 31, 2015), jubilee awards for €28 million (€27 million at December 31, 2015), long-term incentive plan for €14 million (€6 million at December 31, 2015) and other foreign long-term plans for €17 million (€22 million at December 31, 2015).
Costs charged to the profit and loss account consisted of the following: (€ million) | | TFR | | Foreign defined benefit plans | | Fisde and other foreign medical plans | | Other long-term benefit plans | | Total | | | Italian defined benefit plans | | Foreign defined benefit plans | | FISDE, foreign medical plans and other | | Defined benefit plans | | Other benefit plans | | Total | | 2015 | | | | Current cost | | | | | | | | | 41 | | | | | 2 | | | | | 54 | | | | | 97 | | | | Past service cost and (gains) losses on settlements | | | | | | | | | (9) | | | | | (1) | | | | | 13 | | | | | 3 | | | | Interest cost (income), net: | | | | - interest cost on liabilities | | | | 6 | | | | | 41 | | | | | 3 | | | | | 1 | | | | | 51 | | | | - interest income on plan assets | | | | | | | | | (24) | | | | | | | | | | | | | | | (24) | | | | Total interest cost (income), net | | | | 6 | | | | | 17 | | | | | 3 | | | | | 1 | | | | | 27 | | | | - of which recognized in “Payroll and related cost” | | | | | | | | | | | | | | | | | | | 1 | | | | | 1 | | | | - of which recognized in “Financial income (expense)” | | | | 6 | | | | | 17 | | | | | 3 | | | | | | | | | | 26 | | | | Remeasurements for long-term plans | | | | | | | | | | | | | | | | | | | (17) | | | | | (17) | | | | Other costs/Administration expenses paid | | | | | | | | | 1 | | | | | | | | | | | | | | | 1 | | | | Total | | | | 6 | | | | | 50 | | | | | 4 | | | | | 51 | | | | | 111 | | | | - of which recognized in “Payroll and related cost” | | | | | | | | | 33 | | | | | 1 | | | | | 51 | | | | | 85 | | | | - of which recognized in “Financial income (expense)” | | | | 6 | | | | | 17 | | | | | 3 | | | | | | | | | | 26 | | | | 2016 | | | | 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current cost | | | | | | | | | 28 | | | | | 2 | | | | | 56 | | | | | 86 | | | | | | | | | | | 19 | | | | | 2 | | | | | 21 | | | | | 55 | | | | | 76 | | | Past service cost and (gains) losses on settlements | | | | | | | | | (4) | | | | | 2 | | | | | (3) | | | | | (5) | | | | | | | | | | | 1 | | | | | 8 | | | | | 9 | | | | | (2) | | | | | 7 | | | Interest cost (income), net: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - interest cost on liabilities | | | | 6 | | | | | 34 | | | | | 3 | | | | | 1 | | | | | 44 | | | | | | 4 | | | | | 37 | | | | | 3 | | | | | 44 | | | | | 1 | | | | | 45 | | | - interest income on plan assets | | | | | | | | | (20) | | | | | | | | | | | | | | | (20) | | | | | | | | | | | (20) | | | | | | | | | | (20) | | | | | | | | | | (20) | | | Total interest cost (income), net | | | | 6 | | | | | 14 | | | | | 3 | | | | | 1 | | | | | 24 | | | | | | 4 | | | | | 17 | | | | | 3 | | | | | 24 | | | | | 1 | | | | | 25 | | | - of which recognized in “Payroll and related cost” | | | | | | | | | | | | | | | | | | | 1 | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | 1 | | | - of which recognized in “Financial income (expense)” | | | | 6 | | | | | 14 | | | | | 3 | | | | | | | | | | 23 | | | | | | 4 | | | | | 17 | | | | | 3 | | | | | 24 | | | | | | | | | | 24 | | | Remeasurements for long-term plans | | | | | | | | | | | | | | | | | | | (1) | | | | | (1) | | | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | 1 | | | Total | | | | 6 | | | | | 38 | | | | | 7 | | | | | 53 | | | | | 104 | | | | | | 4 | | | | | 37 | | | | | 13 | | | | | 54 | | | | | 55 | | | | | 109 | | | - of which recognized in “Payroll and related cost” | | | | | | | | | 24 | | | | | 4 | | | | | 53 | | | | | 81 | | | | | | | | | | | 20 | | | | | 10 | | | | | 30 | | | | | 55 | | | | | 85 | | | - of which recognized in “Financial income (expense)” | | | | 6 | | | | | 14 | | | | | 3 | | | | | | | | | | 23 | | | | | | 4 | | | | | 17 | | | | | 3 | | | | | 24 | | | | | | | | | | 24 | | | | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Current cost | | | | | | | | | | 27 | | | | | 2 | | | | | 29 | | | | | 42 | | | | | 71 | | | Past service cost and (gains) losses on settlements | | | | | | | | | | 2 | | | | | 1 | | | | | 3 | | | | | 115 | | | | | 118 | | | Interest cost (income), net: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - interest cost on liabilities | | | | | 4 | | | | | 31 | | | | | 2 | | | | | 37 | | | | | 1 | | | | | 38 | | | - interest income on plan assets | | | | | | | | | | (17) | | | | | | | | | | (17) | | | | | | | | | | (17) | | | Total interest cost (income), net | | | | | 4 | | | | | 14 | | | | | 2 | | | | | 20 | | | | | 1 | | | | | 21 | | | - of which recognized in “Payroll and related cost” | | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | 1 | | | - of which recognized in “Financial income (expense)” | | | | | 4 | | | | | 14 | | | | | 2 | | | | | 20 | | | | | | | | | | 20 | | | Remeasurements for long-term plans | | | | | | | | | | | | | | | | | | | | | | | | | 30 | | | | | 30 | | | Total | | | | | 4 | | | | | 43 | | | | | 5 | | | | | 52 | | | | | 188 | | | | | 240 | | | - of which recognized in “Payroll and related cost” | | | | | | | | | | 29 | | | | | 3 | | | | | 32 | | | | | 188 | | | | | 220 | | | - of which recognized in “Financial income (expense)” | | | | | 4 | | | | | 14 | | | | | 2 | | | | | 20 | | | | | | | | | | 20 | | |
Costs of defined benefit plans recognized in other comprehensive income consisted of the following: | | 2015 | | 2016 | | | 2019 | | 2018 | | (€ million) | | TFR | | Foreign defined benefit plans | | Fisde and other foreign medical plans | | Total | | TFR | | Foreign defined benefit plans | | Fisde and other foreign medical plans | | Other benefit plans | | Total | | | Italian defined benefit plans | | Foreign defined benefit plans | | FISDE, foreign medical plans and other | | Total | | Italian defined benefit plans | | Foreign defined benefit plans | | FISDE, foreign medical plans and other | | Total | | Remeasurements | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Actuarial (gains)/losses due to changes in demographic assumptions | | | | | | | | | (5) | | | | | | | | | | (5) | | | | | (2) | | | | | (2) | | | | | (1) | | | | | 1 | | | | | (4) | | | | Actuarial (gains)/losses due to changes in financial assumptions | | | | | | | | | 4 | | | | | 2 | | | | | 6 | | | | | 11 | | | | | 30 | | | | | (2) | | | | | 1 | | | | | 40 | | | | | | 7 | | | | | 50 | | | | | 3 | | | | | 60 | | | | | | | | | | (31) | | | | | 1 | | | | | (30) | | | Experience (gains) losses | | | | (26) | | | | | (19) | | | | | (3) | | | | | (48) | | | | | 10 | | | | | (6) | | | | | (14) | | | | | | | | | | (10) | | | | | | (2) | | | | | (9) | | | | | 21 | | | | | 10 | | | | | 1 | | | | | 6 | | | | | 12 | | | | | 19 | | | Return on plan assets | | | | | | | | | 11 | | | | | | | | | | 11 | | | | | | | | | | (42) | | | | | | | | | | | | | | | (42) | | | | | | | | | | | (23) | | | | | | | | | | (23) | | | | | | | | | | 21 | | | | | | | | | | 21 | | | Change in asset ceiling | | | | | | | | | | (5) | | | | | | | | | | (5) | | | | | | | | | | 5 | | | | | | | | | | 5 | | | | | | | (26) | | | | | (9) | | | | | (1) | | | | | (36) | | | | | 19 | | | | | (20) | | | | | (17) | | | | | 2 | | | | | (16) | | | | | | 5 | | | | | 13 | | | | | 24 | | | | | 42 | | | | | 1 | | | | | 1 | | | | | 13 | | | | | 15 | | | | |
Plan assets consisted of the following: (€ million) | | | Cash and cash equivalents | | | Equity securities | | | Debt securities | | | Real estate | | | Derivatives | | | Investment funds | | | Assets held by insurance company | | | Other | | | Total | | December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Plan assets with a quoted market price | | | | | 32 | | | | | | 39 | | | | | | 388 | | | | | | 7 | | | | | | 2 | | | | | | 79 | | | | | | 17 | | | | | | 65 | | | | | | 629 | | | Plan assets without a quoted market price | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | 3 | | | | | | | | 32 | | | | | | 39 | | | | | | 388 | | | | | | 7 | | | | | | 2 | | | | | | 79 | | | | | | 20 | | | | | | 65 | | | | | | 632 | | | December 31, 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Plan assets with a quoted market price | | | | | 115 | | | | | | 37 | | | | | | 238 | | | | | | 6 | | | | | | 2 | | | | | | 56 | | | | | | 18 | | | | | | 70 | | | | | | 542 | | | Plan assets without a quoted market price | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | 3 | | | | | | | | 115 | | | | | | 37 | | | | | | 238 | | | | | | 6 | | | | | | 2 | | | | | | 56 | | | | | | 21 | | | | | | 70 | | | | | | 545 | | | |
Plan assets consisted of the following:
(€ million) | | | Cash and cash equivalents | | | Equity securities | | | Debt securities | | | Real estate | | | Derivatives | | | Investment funds | | | Assets held by insurance company | | | Other | | | Total | | December 31, 2015 | | | | | | | | | | | Plan assets with a quoted market price | | | | | 41 | | | | | | 96 | | | | | | 254 | | | | | | 10 | | | | | | 2 | | | | | | 2 | | | | | | 23 | | | | | | 273 | | | | | | 701 | | | Plan assets without a quoted market price | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6 | | | | | | | | | | | | 6 | | | | | | | | 41 | | | | | | 96 | | | | | | 254 | | | | | | 10 | | | | | | 2 | | | | | | 2 | | | | | | 29 | | | | | | 273 | | | | | | 707 | | | December 31, 2016 | | | | | | | | | | | Plan assets with a quoted market price | | | | | 105 | | | | | | 49 | | | | | | 270 | | | | | | 11 | | | | | | 1 | | | | | | 65 | | | | | | 14 | | | | | | 101 | | | | | | 616 | | | Plan assets without a quoted market price | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | 3 | | | | | | | | 105 | | | | | | 49 | | | | | | 270 | | | | | | 11 | | | | | | 1 | | | | | | 65 | | | | | | 17 | | | | | | 101 | | | | | | 619 | | | |
Plan assets are generally managed by external asset managers pursuing investment strategies, defined by Eni’s companies, with the aim of ensuring that assets are sufficient to pay the benefits. For this purpose, the investments are aimed at maximizing the expected return and limit the risk level through proper diversification.
The main actuarial assumptions used in the measurement of the liabilities at year-end and in the estimate of costs expected for 20162020 consisted of the following: | | | | TFR | | Foreign defined benefit plans | | FISDE and other foreign medical plans | | Other long-term benefit plans | | | | | Italian defined benefit plans | | Foreign defined benefit plans | | FISDE, foreign medical plans and other | | Other benefit plans | | 2015 | | | | | 2019 | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | (%) | | | | 2.0 | | | | | 0.8-15.3 | | | | | 2.0 | | | | | 0.5-2.0 | | | | (%) | | | | 0.7 | | | | | 0.0-13.7 | | | | | 0.7 | | | | | 0.0-0.7 | | | Rate of compensation increase | | (%) | | | | 3.0 | | | | | 2.0-13.3 | | | | | (%) | | | | 1.7 | | | | | 1.3-12.5 | | | | | | | | | | | | | Rate of price inflation | | (%) | | | | 2.0 | | | | | 0.6-9.7 | | | | | 2.0 | | | | | 2.0 | | | | (%) | | | | 0.7 | | | | | 0.8-11.3 | | | | | 0.7 | | | | | 0.7 | | | Life expectations on retirement at age 65 | | (years) | | | | | | | | | 13-24 | | | | | 24 | | | | | (years) | | | | | | | | | 13-25 | | | | | 24 | | | | | | | | 2016 | | | | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | (%) | | | | 1.0 | | | | | 0.6-17.5 | | | | | 1.0 | | | | | 0.0-1.0 | | | | (%) | | | | 1.5 | | | | | 0.8-18.0 | | | | | 1.5 | | | | | 0.2-1.5 | | | Rate of compensation increase | | (%) | | | | 2.0 | | | | | 1.0-15.0 | | | | | (%) | | | | 2.5 | | | | | 1.5-16.5 | | | | | | | | | | | | | Rate of price inflation | | (%) | | | | 1.0 | | | | | 0.6-13.5 | | | | | 1.0 | | | | | 1.0 | | | | (%) | | | | 1.5 | | | | | 0.8-16.0 | | | | | 1.5 | | | | | 1.5 | | | Life expectations on retirement at age 65 | | (years) | | | | | | | | | 13-24 | | | | | 24 | | | | | | | | | (years) | | | | | | | | | 13-25 | | | | | 24.0 | | | | | | | | | |
The following is an analysis by geographical area related to the main actuarial assumptions used in the valuation of the principal foreign defined benefit plans: | | | | | | Euro area | | | Rest of Europe | | | Africa | | | Other areas | | | Foreign defined benefit plans | | 20152019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | | (%) | | | | | 2.00.8-1.0 | | | | | | 0.8-3.80.0-2.0 | | | | | | 3.5-15.32.6-13.7 | | | | | | 9.4-9.57.3-11.3 | | | | | | 0.8-15.30.0-13.7 | | | Rate of compensation increase | | | (%) | | | | | 2.0-3.01.3-3.0 | | | | | | 2.5-4.72.5-3.6 | | | | | | 5.0-13.32.0-12.5 | | | | | | 10.010.0-11.3 | | | | | | 2.0-13.31.3-12.5 | | | Rate of price inflation | | | (%) | | | | | 2.01.3-2.0 | | | | | | 0.6-3.00.8-3.1 | | | | | | 3.5-9.72.6-11.3 | | | | | | 5.5-8.23.3-5.0 | | | | | | 0.6-9.70.8-11.3 | | | Life expectations on retirement at age 65 | | | (years) | | | | | 21-22 | | | | | | 22-2424-25 | | | | | | 13-1513-17 | | | | | | | | | | | | 13-2413-25 | | | 20162018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Discount rate | | | (%) | | | | | 1.0-2.01.5-1.9 | | | | | | 0.6-2.70.8-2.9 | | | | | | 3.5-17.53.7-18.0 | | | | | | 7.3-8.18.0-13.3 | | | | | | 0.6-17.50.8-18.0 | | | Rate of compensation increase | | | (%) | | | | | 1.0-3.01.5-3.0 | | | | | | 2.3-3.82.5-3.8 | | | | | | 5.0-15.05.0-16.5 | | | | | | 7.8-10.010.0-13.3 | | | | | | 1.0-15.01.5-16.5 | | | Rate of price inflation | | | (%) | | | | | 1.0-1.81.5-2.0 | | | | | | 0.6-3.40.8-3.3 | | | | | | 3.5-13.53.7-16.0 | | | | | | 5.0-5.53.5-5.0 | | | | | | 0.6-13.50.8-16.0 | | | Life expectations on retirement at age 65 | | | (years) | | | | | 21-22 | | | | | | 23-2423-25 | | | | | | 13-1513-17 | | | | | | | | | | | | 13-2413-25 | | | |
The discount rate used was determined on the base of corporate bond yields (rating AA) in countries with a significant market, or in the absence, of government bond yields. The demographic tables adopted are those used by each country for the assessments of IAS 19. The inflation rate is consistent with the discount rate adopted determined based on the inflation rate implicit in the securities financial markets.
The effects of a possible change in the main actuarial assumptions at the end of the year are listed below: | | | Discount rate | | | Rate of price inflation | | | Rate of increases in pensionable salaries | | | Healthcare cost trend rate | | | Rate of increases to pensions in payment | | (€ million) | | | 0.5% Increase | | | 0.5% Decrease | | | 0.5% Increase | | | 0.5% Increase | | | 0.5% Increase | | | 0.5% Increase | | December 31, 2015 | | | | | | | | Effect on DBO | | | | | | | | TFR | | | | | (17) | | | | | | 18 | | | | | | 12 | | | | | | Foreign defined benefit plans | | | | | (75) | | | | | | 84 | | | | | | 46 | | | | | | 26 | | | | | | | | | | | | 54 | | | FISDE and other foreign medical plans | | | | | (8) | | | | | | 9 | | | | | | | | | | | | | | | | | | 9 | | | | Other long-term benefit plans | | | | | (2) | | | | | | 2 | | | | | | 1 | | | | | | December 31, 2016 | | | | | | | | Effect on DBO | | | | | | | | TFR | | | | | (15) | | | | | | 16 | | | | | | 10 | | | | | | Foreign defined benefit plans | | | | | (57) | | | | | | 66 | | | | | | 33 | | | | | | 15 | | | | | | | | | | | | 23 | | | FISDE and other foreign medical plans | | | | | (7) | | | | | | 8 | | | | | | | | | | | | | | | | | | 8 | | | | Other long-term benefit plans | | | | | (2) | | | | | | 2 | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | |
| | | Discount rate | | | Rate of price inflation | | | Rate of increases in pensionable salaries | | | Healthcare cost trend rate | | | Rate of increases to pensions in payment | | (€ million) | | | 0.5% Increase | | | 0.5% Decrease | | | 0.5% Increase | | | 0.5% Increase | | | 0.5% Increase | | | 0.5% Increase | | December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Italian defined benefit plans | | | | | (12) | | | | | | 13 | | | | | | 8 | | | | | | | | | | | | | | | | | | | | | Foreign defined benefit plans | | | | | (67) | | | | | | 77 | | | | | | 31 | | | | | | 18 | | | | | | | | | | | | 34 | | | FISDE, foreign medical plans and other | | | | | (9) | | | | | | 10 | | | | | | | | | | | | | | | | | | 10 | | | | | | | | | Other benefit plans | | | | | (4) | | | | | | 1 | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Italian defined benefit plans | | | | | (12) | | | | | | 13 | | | | | | 8 | | | | | | | | | | | | | | | | | | | | | Foreign defined benefit plans | | | | | (58) | | | | | | 65 | | | | | | 23 | | | | | | 15 | | | | | | | | | | | | 18 | | | FISDE, foreign medical plans and other | | | | | (7) | | | | | | 8 | | | | | | | | | | | | | | | | | | 6 | | | | | | | | | Other benefit plans | | | | | (5) | | | | | | 3 | | | | | | 1 | | | | | | | | | | | | | | | | | | | | |
The sensitivity analysis was performed based on the results for each plan through assessments calculated considering modified parameters.
The amount of contributions expected to be paid for employee benefit plans in the next year amounted to €87€130 million, of which €52€57 million related to defined benefit plans. The following is an analysis by maturity date of the liabilities for employee benefit plans: (€ million) | | | TFR | | | Foreign defined benefit plans | | | FISDE and other foreign medical plans | | | Other long-term benefits | | December 31, 2015 | | | | | | 2016 | | | | | 4 | | | | | | 31 | | | | | | 5 | | | | | | 31 | | | 2017 | | | | | 5 | | | | | | 33 | | | | | | 5 | | | | | | 37 | | | 2018 | | | | | 6 | | | | | | 43 | | | | | | 5 | | | | | | 57 | | | 2019 | | | | | 8 | | | | | | 34 | | | | | | 5 | | | | | | 2 | | | 2020 | | | | | 10 | | | | | | 37 | | | | | | 6 | | | | | | 2 | | | 2021 and thereafter | | | | | 248 | | | | | | 355 | | | | | | 130 | | | | | | 47 | | | December 31, 2016 | | | | | | 2017 | | | | | 13 | | | | | | 31 | | | | | | 5 | | | | | | 37 | | | 2018 | | | | | 14 | | | | | | 44 | | | | | | 5 | | | | | | 59 | | | 2019 | | | | | 15 | | | | | | 33 | | | | | | 5 | | | | | | 52 | | | 2020 | | | | | 17 | | | | | | 33 | | | | | | 5 | | | | | | 3 | | | 2021 | | | | | 19 | | | | | | 38 | | | | | | 5 | | | | | | 3 | | | 2022 and thereafter | | | | | 220 | | | | | | 97 | | | | | | 99 | | | | | | 42 | | | |
Theplans and their relative weighted average duration of theduration:
(€ million) | | | Italian defined benefit plans | | | Foreign defined benefit plans | | | FISDE, foreign medical plans and other | | | Other benefit plans | | December 31, 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | 2020 | | | | | 17 | | | | | | 33 | | | | | | 9 | | | | | | 73 | | | 2021 | | | | | 16 | | | | | | 35 | | | | | | 8 | | | | | | 68 | | | 2022 | | | | | 12 | | | | | | 32 | | | | | | 7 | | | | | | 61 | | | 2023 | | | | | 10 | | | | | | 39 | | | | | | 7 | | | | | | 17 | | | 2024 | | | | | 15 | | | | | | 49 | | | | | | 7 | | | | | | 14 | | | 2025 and thereafter | | | | | 199 | | | | | | 224 | | | | | | 139 | | | | | | 45 | | | Weighted average duration (years) | | | | | 9.4 | | | | | | 18.1 | | | | | | 13.3 | | | | | | 3.0 | | | December 31, 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | 2019 | | | | | 15 | | | | | | 54 | | | | | | 9 | | | | | | 81 | | | 2020 | | | | | 16 | | | | | | 56 | | | | | | 7 | | | | | | 72 | | | 2021 | | | | | 18 | | | | | | 63 | | | | | | 6 | | | | | | 67 | | | 2022 | | | | | 14 | | | | | | 64 | | | | | | 6 | | | | | | 20 | | | 2023 | | | | | 11 | | | | | | 74 | | | | | | 6 | | | | | | 17 | | | 2024 and thereafter | | | | | 201 | | | | | | 74 | | | | | | 114 | | | | | | 57 | | | Weighted average duration (years) | | | | | 10.1 | | | | | | 17.4 | | | | | | 12.8 | | | | | | 2.6 | | |
22 Deferred tax assets and liabilities for employee benefit plans was the following: | | | | | | | | | TFR | | | Foreign defined benefit plans | | | FISDE and other foreign medical plans | | | Other long-term benefits | | 2015 | | | | | | | Weighted average duration | | | | | (years) | | | | | | 12.0 | | | | | | 16.5 | | | | | | 14.1 | | | | | | 4.3 | | | 2016 | | | | | | | Weighted average duration | | | | | (years) | | | | | | 10.3 | | | | | | 17.9 | | | | | | 13.9 | | | | | | 3.4 | | | |
(€ million) | | | December 31, 2019 | | | December 31, 2018 | | Deferred tax liabilities before offsetting | | | | | 9,583 | | | | | | 7,956 | | | Deferred tax assets available for offset | | | | | (4,663) | | | | | | (3,684) | | | Deferred tax liabilities | | | | | 4,920 | | | | | | 4,272 | | | Deferred tax assets before offsetting (net of accumulated write-down provisions) | | | | | 9,023 | | | | | | 7,615 | | | Deferred tax liabilities available for offset | | | | | (4,663) | | | | | | (3,684) | | | Deferred tax assets | | | | | 4,360 | | | | | | 3,931 | | | |
32 Deferred tax liabilities
Deferred tax liabilities were recognized net of the amounts of deferred tax assets which can be offset for €4,286 million (€3,355 million at December 31, 2015).
(€ million) | | | Amount at December 31, 2015 | | | Additions | | | Deductions | | | Currency translation differences | | | Other changes | | | Amount at December 31, 2016 | | | | | | | 7,425 | | | | | | 1,796 | | | | | | (1,486) | | | | | | 229 | | | | | | (1,297) | | | | | | 6,667 | | | |
Deferred tax assets and liabilities consisted of the following:
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Deferred tax liabilities | | | | | 10,780 | | | | | | 10,953 | | | Deferred tax assets available for offset | | | | | (3,355) | | | | | | (4,286) | | | | | | | | 7,425 | | | | | | 6,667 | | | Deferred tax assets not available for offset | | | | | (3,853) | | | | | | (3,790) | | | Net deferred tax liabilities | | | | | 3,572 | | | | | | 2,877 | | | |
Net deferred tax liabilities of €2,877 million (€3,572 million at December 31, 2015) included the recognition of the deferred tax effect against equity of: (i) the fair value measurement of derivatives designated as cash flow hedge (deferred tax liabilities for €57 million); (ii) the revaluation of defined benefit plans (deferred tax liabilities for €13 million); and (iii) the fair value measurement of available-for-sale securities (deferred tax liabilities for €1 million).
The most significant temporary differences giving rise to net deferred tax liabilities are disclosed below: (€ million) | | Carrying amount at December 31, 2015 | | Additions | | Deductions | | Currency translation differences | | Other changes | | Carrying amount at December 31, 2016 | | | Carrying amount at December 31, 2019 | | Carrying amount at December 31, 2018 | | Deferred tax liabilities | | | | | | | | | | | | | | Accelerated tax depreciation | | | | 8,424 | | | | | 1,527 | | | | | (583) | | | | | 168 | | | | | (637) | | | | | 8,899 | | | | | | 6,796 | | | | | 6,612 | | | Leasing | | | | | 1,375 | | | | | | | | Difference between the fair value and the carrying amount of assets acquired | | | | 1,150 | | | | | 114 | | | | | (207) | | | | | 42 | | | | | 170 | | | | | 1,269 | | | | | | 617 | | | | | 849 | | | Site restoration and abandonment (tangible assets) | | | | 644 | | | | | | | | | | (171) | | | | | 20 | | | | | (145) | | | | | 348 | | | | | | 126 | | | | | 85 | | | Application of the weighted average cost method in evaluation of inventories | | | | 46 | | | | | 41 | | | | | (7) | | | | | 1 | | | | | | | | | | 81 | | | | | | 97 | | | | | 44 | | | Capitalized interest expense | | | | 77 | | | | | | | | | | (9) | | | | | 1 | | | | | (53) | | | | | 16 | | | | Other | | | | 439 | | | | | 114 | | | | | (509) | | | | | (3) | | | | | 299 | | | | | 340 | | | | | | 572 | | | | | 366 | | | | | | | 10,780 | | | | | 1,796 | | | | | (1,486) | | | | | 229 | | | | | (366) | | | | | 10,953 | | | | | | 9,583 | | | | | 7,956 | | | Deferred tax assets, gross | | | | | | | | | | | | | | Carry-forward tax losses | | | | (3,598) | | | | | (1,377) | | | | | 95 | | | | | (88) | | | | | 246 | | | | | (4,722) | | | | | | (6,065) | | | | | (5,528) | | | Site restoration and abandonment (provisions for contingencies) | | | | (2,415) | | | | | (768) | | | | | 186 | | | | | 5 | | | | | 111 | | | | | (2,881) | | | | | | (2,242) | | | | | (1,986) | | | Timing differences on depreciation and amortization | | | | (2,195) | | | | | (253) | | | | | 140 | | | | | (63) | | | | | 111 | | | | | (2,260) | | | | | | (2,022) | | | | | (2,104) | | | Accruals for impairment losses and provisions for contingencies | | | | (1,380) | | | | | (370) | | | | | 337 | | | | | | | | | | | | | | | (1,413) | | | | | | (1,513) | | | | | (1,460) | | | Leasing | | | | | (1,385) | | | | | | | | Impairment losses | | | | (902) | | | | | (121) | | | | | 224 | | | | | (2) | | | | | (105) | | | | | (906) | | | | | | (946) | | | | | (792) | | | Over/Under lifting | | | | | (525) | | | | | (604) | | | Employee benefits | | | | (171) | | | | | (33) | | | | | 16 | | | | | | | | | | 25 | | | | | (163) | | | | | | (209) | | | | | (212) | | | Unrealized intercompany profits | | | | (257) | | | | | | | | | | 3 | | | | | 2 | | | | | 134 | | | | | (118) | | | | | | (120) | | | | | (124) | | | Other | | | | (1,389) | | | | | (72) | | | | | 207 | | | | | (39) | | | | | 58 | | | | | (1,235) | | | | | | (740) | | | | | (546) | | | | | | | (12,307) | | | | | (2,994) | | | | | 1,208 | | | | | (185) | | | | | 580 | | | | | (13,698) | | | | | | (15,767) | | | | | (13,356) | | | Impairments of deferred tax assets | | | | 5,099 | | | | | 667 | | | | | (254) | | | | | 80 | | | | | 30 | | | | | 5,622 | | | | Accumulated write-downs of deferred tax assets | | | | | 6,744 | | | | | 5,741 | | | Deferred tax assets, net | | | | (7,208) | | | | | (2,327) | | | | | 954 | | | | | (105) | | | | | 610 | | | | | (8,076) | | | | | | (9,023) | | | | | (7,615) | | | Net deferred tax liabilities | | | | 3,572 | | | | | (531) | | | | | (532) | | | | | 124 | | | | | 244 | | | | | 2,877 | | | | | |
The following table summarizes the changes in deferred tax liabilities and assets: (€ million) | | | Deferred tax liabilities, gross | | | Deferred tax assets, gross | | | Accumulated write-downs of deferred tax assets | | | Deferred tax assets, net of impairments | | Carrying amount at December 31, 2018 | | | | | 7,956 | | | | | | (13,356) | | | | | | 5,741 | | | | | | (7,615) | | | Changes in accounting policies (IFRS 16) | | | | | 1,470 | | | | | | (1,470) | | | | | | | | | | | | (1,470) | | | Carrying amount at January 1, 2019 | | | | | 9,426 | | | | | | (14,826) | | | | | | 5,741 | | | | | | (9,085) | | | Additions | | | | | 1,265 | | | | | | (2,091) | | | | | | 1,161 | | | | | | (930) | | | Deductions | | | | | (1,205) | | | | | | 1,407 | | | | | | (174) | | | | | | 1,233 | | | Currency translation differences | | | | | 194 | | | | | | (182) | | | | | | 34 | | | | | | (148) | | | Other changes | | | | | (97) | | | | | | (75) | | | | | | (18) | | | | | | (93) | | | Carrying amount at December 31, 2019 | | | | | 9,583 | | | | | | (15,767) | | | | | | 6,744 | | | | | | (9,023) | | | Carrying amount at December 31, 2017 | | | | | 10,169 | | | | | | (13,609) | | | | | | 5,262 | | | | | | (8,347) | | | Changes in accounting policies (IFRS 15) | | | | | 37 | | | | | | (237) | | | | | | | | | | | | (237) | | | Carrying amount at January 1, 2018 | | | | | 10,206 | | | | | | (13,846) | | | | | | 5,262 | | | | | | (8,584) | | | Additions | | | | | 1,147 | | | | | | (1,478) | | | | | | 253 | | | | | | (1,225) | | | Deductions | | | | | (802) | | | | | | 1,523 | | | | | | (43) | | | | | | 1,480 | | | Currency translation differences | | | | | 283 | | | | | | (278) | | | | | | 71 | | | | | | (207) | | | Change in the scope of consolidation | | | | | (2,778) | | | | | | 813 | | | | | | | | | | | | 813 | | | Other changes | | | | | (100) | | | | | | (90) | | | | | | 198 | | | | | | 108 | | | Carrying amount at December 31, 2018 | | | | | 7,956 | | | | | | (13,356) | | | | | | 5,741 | | | | | | (7,615) | | |
The first application of IFRS 16 is disclosed in note 3 — Changes in accounting policies. Carry-forward tax losses amounted to €21,360 million out of which €15,256 million can be carried forward indefinitely. Carry-forward tax losses were €12,039 million and €9,321 million at Italian
subsidiaries and foreign subsidiaries, respectively. Deferred tax assets recognized on these losses amounted to €2,936 million and €3,129 million, respectively. Italian taxation law allows the carry-forward of tax losses indefinitely. Foreign taxation laws generally allow the carry-forward of tax losses over a period longer than five years, and in many cases, indefinitely. An averageA tax rate of 24% was applied to tax losses of Italian subsidiaries to determine the portion of the carry-forwards tax losses, which will be utilized in future years to offset expected taxable profit. The corresponding average rate for foreign subsidiaries was 36%33.6%.
Carry-forward tax losses amounted to €16,478 million and can be used indefinitely for €13,083 million. Carry-forward tax losses regarded Italian companies for €9,889 million and foreign companies for €6,589 million. Deferred tax assets recognized on these losses amounted to €2,330 million and €2,392 million, respectively.
Provisions for impairmentsAccumulated write-downs of deferred tax assets of €5,622 million related to Italian companies for €4,020€5,329 million and foreignnon-Italian companies for €1,602€1,415 million.
33 Other non-current liabilities
(€ million) | | | December 31, 2015 | | | December 31, 2016 | | Fair value of derivatives financial instruments | | | | | 98 | | | | | | 161 | | | Current income tax liabilities | | | | | 23 | | | | | | 35 | | | Other payables towards tax authorities | | | | | 29 | | | | | | 9 | | | Cautionary deposits | | | | | 267 | | | | | | 265 | | | Other payables | | | | | 81 | | | | | | 51 | | | Other liabilities | | | | | 1,354 | | | | | | 1,247 | | | | | | | | 1,852 | | | | | | 1,768 | | | |
Fair value related to derivative financial instruments is disclosed in note 34 — Derivative financial instruments.
Cautionary deposits of €265 million (€267 million at December 31, 2015) related for €224 million (€232 million at December 31 2015) to deposits from retail customers for the supply of gas and electricity.
Other liabilities of €1,247 million (€1,354 million at December 31, 2015) included advances received from Suez following a long-term agreement for supplying natural gas and electricity of €664 million (€736 million at December 31, 2015). The current portion isTaxes are also described in note 2832 — Other current liabilities.Income taxes.
Liabilities with related parties are described in note 47 — Transactions with related parties.
3423 Derivative financial instruments and hedge accounting
| | December 31, 2015 | | December 31, 2016 | | | December 31, 2019 | | December 31, 2018 | | (€ million) | | Fair value asset | | Fair value liability | | Level of Fair value | | Fair value asset | | Fair value liability | | Level of Fair value | | | Fair value asset | | Fair value liability | | Level of Fair value | | Fair value asset | | Fair value liability | | Level of Fair value | | Non-hedging derivatives | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Derivatives on exchange rate | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Currency swap | | | | 223 | | | | | 311 | | | | | 2 | | | | | 188 | | | | | 268 | | | | | 2 | | | | | | 97 | | | | | 43 | | | | | 2 | | | | | 99 | | | | | 46 | | | | | 2 | | | - Interest currency swap | | | | 97 | | | | | 33 | | | | | 2 | | | | | 38 | | | | | 83 | | | | | 2 | | | | | | 26 | | | | | | | | | | 2 | | | | | 14 | | | | | 71 | | | | | 2 | | | - Outright | | | | 7 | | | | | 2 | | | | | 2 | | | | | 17 | | | | | 15 | | | | | 2 | | | | | | 8 | | | | | 5 | | | | | 2 | | | | | 3 | | | | | 5 | | | | | 2 | | | | | | | 327 | | | | | 346 | | | | | | | | | | 243 | | | | | 366 | | | | | | | 131 | | | | | 48 | | | | | | | | | | 116 | | | | | 122 | | | | | | | | Derivatives on interest rate | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Interest rate swap | | | | 30 | | | | | 20 | | | | | 2 | | | | | 10 | | | | | 12 | | | | | 2 | | | | | | 13 | | | | | 34 | | | | | 2 | | | | | 18 | | | | | 6 | | | | | 2 | | | | | | | 30 | | | | | 20 | | | | | | | | | | 10 | | | | | 12 | | | | | | | 13 | | | | | 34 | | | | | | | | | | 18 | | | | | 6 | | | | | | | | Derivatives on commodities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Future | | | | 1,586 | | | | | 1,483 | | | | | 1 | | | | | 624 | | | | | 611 | | | | | 2 | | | | | | 192 | | | | | 181 | | | | | 1 | | | | | 1,060 | | | | | 1,107 | | | | | 1 | | | - Over the counter | | | | 550 | | | | | 491 | | | | | 2 | | | | | 133 | | | | | 120 | | | | | 1 | | | | | | 89 | | | | | 58 | | | | | 2 | | | | | 306 | | | | | 284 | | | | | 2 | | | - Options | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | 2 | | | | - Other | | | | | | | | | | | | | | | | | | | 4 | | | | | 5 | | | | | 2 | | | | | | 12 | | | | | | | | | | 2 | | | | | 1 | | | | | 5 | | | | | 2 | | | | | | | 2,136 | | | | | 1,974 | | | | | | | | | | 761 | | | | | 737 | | | | | | | 293 | | | | | 239 | | | | | | | | | | 1,367 | | | | | 1,396 | | | | | | | | | | | | 2,493 | | | | | 2,340 | | | | | | | | | | 1,014 | | | | | 1,115 | | | | | | | 437 | | | | | 321 | | | | | | | | | | 1,501 | | | | | 1,524 | | | | | | | | Trading derivatives | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Derivatives on commodities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Over the counter | | | | 2,647 | | | | | 3,054 | | | | | 2 | | | | | 1,495 | | | | | 1,490 | | | | | 2 | | | | | | 2,387 | | | | | 1,953 | | | | | 2 | | | | | 992 | | | | | 1,031 | | | | | 2 | | | - Future | | | | 409 | | | | | 559 | | | | | 1 | | | | | 561 | | | | | 574 | | | | | 1 | | | | | | 348 | | | | | 313 | | | | | 1 | | | | | 367 | | | | | 263 | | | | | 1 | | | - Options | | | | 153 | | | | | 176 | | | | | 2 | | | | | 211 | | | | | 157 | | | | | 2 | | | | | | 21 | | | | | 22 | | | | | 2 | | | | | 80 | | | | | 71 | | | | | 2 | | | | | | | 3,209 | | | | | 3,789 | | | | | | | | | | 2,267 | | | | | 2,221 | | | | | | | 2,756 | | | | | 2,288 | | | | | | | | | | 1,439 | | | | | 1,365 | | | | | | | | Cash flow hedge derivatives | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Derivatives on commodities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Over the counter | | | | 19 | | | | | 614 | | | | | 2 | | | | | 309 | | | | | 150 | | | | | 2 | | | | | | 1 | | | | | 596 | | | | | 2 | | | | | 311 | | | | | 196 | | | | | 2 | | | - Future | | | | 107 | | | | | | | | | | 1 | | | | | 1 | | | | | 18 | | | | | 1 | | | | | | 34 | | | | | 148 | | | | | 1 | | | | | | | | | | | | | | | | | | - Options | | | | | | | | | | 2 | | | | | 2 | | | | | 26 | | | | | 15 | | | | | 1 | | | | | | | 126 | | | | | 614 | | | | | | | | | | 310 | | | | | 168 | | | | | | | 35 | | | | | 746 | | | | | | | | | | 337 | | | | | 211 | | | | | | | | Embedded derivatives | | | | 20 | | | | | | | | | | 2 | | | | | Option embedded in convertible bonds | | | | | | | | | 26 | | | | | 2 | | | | | 46 | | | | | 46 | | | | | 2 | | | | | | 11 | | | | | 11 | | | | | 2 | | | | | 21 | | | | | 21 | | | | | 2 | | | Gross amount | | | | 5,848 | | | | | 6,769 | | | | | | | | | | 3,637 | | | | | 3,550 | | | | | | | 3,239 | | | | | 3,366 | | | | | | | | | | 3,298 | | | | | 3,121 | | | | | | | | Offsetting | | | | (2,410) | | | | | (2,410) | | | | | | | | | | (1,281) | | | | | (1,281) | | | | | | | (612) | | | | | (612) | | | | | | | | | | (1,636) | | | | | (1,636) | | | | | | | | Net amount | | | | 3,438 | | | | | 4,359 | | | | | | | | | | 2,356 | | | | | 2,269 | | | | | | | 2,627 | | | | | 2,754 | | | | | | | | | | 1,662 | | | | | 1,485 | | | | | | | | Of which: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - current | | | | 3,220 | | | | | 4,261 | | | | | | | | | | 2,248 | | | | | 2,108 | | | | | | | 2,573 | | | | | 2,704 | | | | | | | | | | 1,594 | | | | | 1,445 | | | | | | | | - non-current | | | | 218 | | | | | 98 | | | | | | | | | | 108 | | | | | 161 | | | | | | | | | | | 54 | | | | | 50 | | | | | | | | | | 68 | | | | | 40 | | | | | | | | | |
Derivative fair values were estimated on the basis of market quotations provided by primary info-provider or, alternatively, appropriate valuation techniques generally adopted in the marketplace. Fair values of non-hedging derivatives consisted of derivatives that did not meet the formal criteria to be designated as hedges under IFRS because they were entered into in order to manage net exposures to foreign currency exchange rates, interest rates and commodity prices. Therefore, such derivatives did not relate to specific trade or financing transactions.IFRS.
Fair values of trading derivatives consisted of derivatives entered for trading purposes and proprietary trading. Fair value of cash flow hedge derivatives related to thecommodity hedges were entered into by the Gas & Power segment. These derivatives were entered into to hedge variability in future cash flows associated with highly probable future sale transactions of gas or electricity or on already contracted sales due to different indexation mechanismmechanisms of supply costs versus selling prices. A similar scheme applies to exchange rate hedging derivatives. The effects of the measurement at fair value of cash flow hedge derivatives are given in note 3625 — Shareholders’ equity and in note 4029 — Operating expenses.Costs. Information on hedged risks and hedging policies is disclosed in note 3827 — Guarantees, commitments and risks — Risk factors. Options embedded in convertible bonds of €46 million as of December 31, 2016, relatedrelate to equity-linked cash settled bonds. Options embedded in convertible bonds of €26 million as of December 31, 2015, related to the convertible bond into ordinary shares of Snam SpA expired on January 18, 2016.settled. More information is disclosed in note 2918 — Long-term debt and current portionFinance debts. The offsetting of long-term debt.financial derivatives related to the Gas & Power segment. During the 2016,2019, there were no transfers between the different hierarchy levels of fair value. Hedging derivative instruments are disclosed below: | | | December 31, 2019 | | | December 31, 2018 | | (€ million) | | | Nominal amount of the hedging instrument | | | Change in fair value (effective hedge) | | | Change in fair value (ineffective hedge) | | | Nominal amount of the hedging instrument | | | Change in fair value (effective hedge) | | | Change in fair value (ineffective hedge) | | Cash flow hedge derivatives | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Derivatives on commodity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Over the counter | | | | | 2,179 | | | | | | (1,357) | | | | | | (2) | | | | | | 3,528 | | | | | | 404 | | | | | | 2 | | | - Future | | | | | 1,245 | | | | | | (61) | | | | | | | | | | | | 71 | | | | | | (6) | | | | | | (2) | | | | | | | | 3,424 | | | | | | (1,418) | | | | | | (2) | | | | | | 3,599 | | | | | | 398 | | | | | | | | |
In 2019, the exposure to the exchange rate risk deriving from securities denominated in U.S. dollars included in the strategic liquidity portfolio amounting to €1,902 million was hedged by using, in a fair value hedge relationship, negative exchange differences for €21 million resulting on a portion of bonds denominated in U.S. dollars amounting to €1,844 million.
35 Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale
Discontinued operations
Saipem
On January 22, 2016, following the fulfillment of all the conditions precedent, among which the consensusThe breakdown of the Antitrust Authority,underlying asset or liability by type of risk hedged under cash flow hedge is provided below:
| | | December 31, 2019 | | | December 31, 2018 | | (€ million) | | | Change of the underlying asset used for the calculation of hedging ineffectiveness | | | CFH reserve | | | Reclassification adjustments | | | Change of the underlying asset used for the calculation of hedging ineffectiveness | | | CFH reserve | | | Reclassification adjustments | | Cash flow hedge derivatives | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Commodity price risk | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - Planned sales | | | | | 1,444 | | | | | | (656) | | | | | | (739) | | | | | | (389) | | | | | | (13) | | | | | | 642 | | | | | | | | 1,444 | | | | | | (656) | | | | | | (739) | | | | | | (389) | | | | | | (13) | | | | | | 642 | | |
Eni’s results of operations are affected by fluctuations in the price of commodities. To that end, Eni closedenters into commodities derivatives traded on organized markets (like MTF and OTF) and commodities derivatives traded over the sale transaction of 12.503%counter (swaps, forward, contracts for differences and options on commodities) with underlying commodities being crude oil, gas, refined products, electricity or emission certificates that are not settled through physical delivery of the share capital of Saipem SpA to CDP Equity SpA. The transaction referred to 55,176,364 Saipem shares atunderlying commodity but are designated as hedging instruments in a price of €8.3956 per share for a total consideration of €463 million. At the same date, a shareholder agreement between Eni and CDP Equity entered into force and established the joint control of the two shareholders over Saipem. Therefore, following the loss of control, Saipem was derecognized from Eni’s consolidated accounts and accounted for using the equity method. At the date of the loss of the control (January 22, 2016), the retained interest of 30.42% in the former subsidiary was aligned to the market price of €4.2 per share corresponding to a carrying amount of €564 million with a charge through profit and loss of €441 million (with respect to the carrying amount at the opening balance). Versalis
In 2016, Eni’s chemical segment ceased to be classified as a disposal group in accordance to IFRS 5 due to termination of the negations with US-based SK Capitalcash flow hedge fund, that had shown an interest in acquiring a 70% stake in Eni subsidiary Versalis SpA, the parent company of the chemical business. Therefore, Eni’s consolidated accounts as of and for the year 2016 have been prepared accounting this business as part of the continuing operations. Based on IFRS 5 provisions, in case of cessation of classification as held for sale, management is required to amend financial statements retrospectively to the date of initial classification as held for sale, December 31, 2015, as though the disposal group never qualified as held for sale. Accordingly, the opening balance of the consolidated accounts 2016 were amended to reinstate the criteria of the continuing use to evaluate Versalis by aligning its book value to the recoverable amount, given by the higher of fair value less cost to sell and value-in-use. Under IFRS 5, Versalis was measured at the lower of its carrying amount and fair value less cost to sell. Management estimated the value-in-use of the fixed assets of Versalis’ business units by identifying a single Cash Generating Unit consistently with Eni’s industrial plan for the four-year period 2016-2019 used at December 31, 2015 that considered Versalis as an integrated unit with a view to disposing or monetizing it as a whole. The value-in-use was estimated by discounting the future expected cash flows of the industrial plan of a standalone Versalis, which factored in the earnings volatility of a pool of chemical peers of Versalis, thus determining a beta parameter independent from Eni in the same manner as the Gas & Power segment. Further information is provided in note 16 — Property, plant and equipment. This amendment in Versalis evaluation marginally affected the opening balance of Eni’s consolidated net assets (an increase of €294 million) and was neutral to the Group’s net borrowings.relation.
The main economic and financial data of the discontinued operations net of intragroup transactions are provided below.
Saipem
(€ million) | | | 2014 | | | 2015 | | | 2016 | | Revenues | | | | | 11,644 | | | | | | 10,277 | | | | Operating expenses | | | | | 12,731 | | | | | | 12,199 | | | | Operating profit | | | | | (1,087) | | | | | | (1,922) | | | | Finance income (expense) | | | | | 116 | | | | | | 60 | | | | Income (expense) from investments | | | | | 24 | | | | | | 30 | | | | | | (413) | | | Profit before income taxes | | | | | (947) | | | | | | (1,832) | | | | | | (413) | | | Income taxes | | | | | (2) | | | | | | (142) | | | | Net profit | | | | | (949) | | | | | | (1,974) | | | | | | (413) | | | - attributable to Eni | | | | | (417) | | | | | | (826) | | | | | | (413) | | | - attributable to non-controlling interest | | | | | (532) | | | | | | (1,148) | | | | Earnings per share (€ per share) | | | | | (0.12) | | | | | | (0.23) | | | | | | (0.12) | | | Net cash provided by operating activities | | | | | 273 | | | | | | (1,226) | | | | Net cash flow from investing activities | | | | | (684) | | | | | | (456) | | | | Net cash used in financing activities | | | | | 126 | | | | | | (57) | | | | Capital expenditures | | | | | 694 | | | | | | 561 | | | | |
The existence of a relationship between the hedged item and the hedging derivative is checked at inception to verify eligibility for hedge accounting by observing the offset in changes of the fair values at both the underlying commodity and the derivative. The hedging relationship is also stress-tested against the level of credit risk of the counterparty in the derivative transaction. The hedge ratio is defined consistently with the Company’s risk management objectives, under a defined risk management strategy. The hedging relationship is discontinued when it ceases to meet the qualifying criteria and the risk management objectives on the basis of which hedge accounting has initially been applied. More information is reported in note 27 — Guarantees, Commitments and Risks — Financial risks. Effects recognized in other operating profit (loss) Other operating profit (loss) related to derivative financial instruments on commodity was as follows: (€ million) | | | 2019 | | | 2018 | | | 2017 | | Net income (loss) on cash flow hedging derivatives | | | | | (2) | | | | | | | | | | | | 12 | | | Net income (loss) on other derivatives | | | | | 289 | | | | | | 129 | | | | | | (44) | | | | | | | | 287 | | | | | | 129 | | | | | | (32) | | |
Net income (loss) on cash flow hedging derivatives related to the ineffective portion of the hedging relationship on commodity derivatives was recognized through profit and loss for 2016 included: (i) a loss from measurement atin the Gas & Power segment. Net income (loss) on other derivatives included the fair value measurement and settlement of commodity derivatives which could not be elected for hedge accounting under IFRS because they related to net exposure to commodity risk and derivatives for trading purposes and proprietary trading. Effects recognized in finance income (loss) Finance income (loss) on derivative financial instruments consisted of the retained interestfollowing: (€ million) | | | 2019 | | | 2018 | | | 2017 | | Derivatives on exchange rate | | | | | 9 | | | | | | (329) | | | | | | 809 | | | Derivatives on interest rate | | | | | (23) | | | | | | 22 | | | | | | 28 | | | | | | | | (14) | | | | | | (307) | | | | | | 837 | | |
Net financial income from derivative financial instruments was recognized in Saipem atconnection with the date of the loss of control (22 January 2016) for €441 million; (ii) a net gain from utilization of the reserve for exchange differences and of the reserve for the valuation at fair value valuation of cash flowcertain derivatives which lacked the formal criteria to be treated in accordance with hedge accounting under IFRS, as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. Exchange rate derivatives for €28 million.were entered into in order to manage exposures to foreign currency exchange rates arising from the pricing formulas of commodities in the Gas & Power segment. Finance income (expense) with related parties is disclosed in note 36 — Transactions with related parties.
24 Assets held for sale and liabilities directly associated with assets held for sale AssetsAs of December 31, 2019, assets held for sale amounted to €14 million and related to sales of tangible assets and investments.for €18 million.
In 2016,the course of 2019, Eni sold to MOL Group,finalized the sale of Agip Oil Ecuador BV, which retains a Hungarianservice contract for the development of Villano oil&gas company, field, and of a 100% stake of the subsidiaries Eni Slovenija doo and Eni Hungaria Zrt, two companies operating in the retail and wholesale marketing of fuels with activities in Slovenia and Hungary for a total consideration of €69 million.minority investment. More information is provided in note 37 — Other information — Supplemental cash flow information and note 42 — Income (expense) from investments.
3625 Shareholders’ equity
Non-controlling interest
| | | Net profit | | | Shareholders’ equity | | (€ million) | | | 2015 | | | 2016 | | | December 31, 2015 | | | December 31, 2016 | | Saipem SpA | | | | | (600) | | | | | | | | | | | | 1,872 | | | | Others | | | | | 5 | | | | | | 7 | | | | | | 44 | | | | | | 49 | | | | | | | | (595) | | | | | | 7 | | | | | | 1,916 | | | | | | 49 | | | |
Eni shareholders’ equity (€ million) | | December 31, 2015 | | December 31, 2016 | | | December 31, 2019 | | December 31, 2018 | | Share capital | | | | 4,005 | | | | | 4,005 | | | | | | 4,005 | | | | | 4,005 | | | Retained earnings | | | | | 37,436 | | | | | 36,702 | | | Cumulative currency translation differences | | | | | 7,209 | | | | | 6,605 | | | Legal reserve | | | | 959 | | | | | 959 | | | | | | 959 | | | | | 959 | | | Reserve for treasury shares | | | | 581 | | | | | 581 | | | | | | 981 | | | | | 581 | | | Reserve related to the fair value of cash flow hedging derivatives net of the tax effect | | | | (474) | | | | | 189 | | | | | | (465) | | | | | (9) | | | Reserve related to the fair value of available-for-sale securities net of the tax effect | | | | 8 | | | | | 4 | | | | Reserve related to the defined benefit plans net of tax effect | | | | (101) | | | | | (112) | | | | | | (173) | | | | | (130) | | | Other comprehensive income on equity-accounted investments | | | | | 60 | | | | | 66 | | | Other comprehensive income on other investments | | | | | 12 | | | | | 15 | | | Other reserves | | | | 180 | | | | | 211 | | | | | | 190 | | | | | 190 | | | Cumulative currency translation differences | | | | 9,129 | | | | | 10,319 | | | | Treasury shares | | | | (581) | | | | | (581) | | | | | | (981) | | | | | (581) | | | Retained earnings | | | | 51,985 | | | | | 40,367 | | | | Interim dividend | | | | (1,440) | | | | | (1,441) | | | | | | (1,542) | | | | | (1,513) | | | Net loss for the year | | | | (8,778) | | | | | (1,464) | | | | Other items of comprehensive income related to discontinued operations | | | | 20 | | | | | Net profit (loss) for the year | | | | | 148 | | | | | 4,126 | | | | | ��� | | | 55,493 | | | | | 53,037 | | | | | | 47,839 | | | | | 51,016 | | | | |
Share capital As of December 31, 2016,2019, the parent company’s issued share capital consisted of €4,005,358,876 represented by 3,634,185,330 ordinary shares without nominal value (same amounts as of December 31, 2015)2018). On May 12, 2016,14, 2019, Eni’s Shareholders’ Meeting declaredresolved: (i) to distribute a dividend of €0.40€0.41 per share, with the exclusion of treasury shares held at the ex-dividend date, in full settlement of the 20152018 dividend of €0.80€0.83 per share, of which €0.40€0.42 per share was already paid as interim dividend.dividend in September 2018. The balancefinal amount was paid on 22 May 25, 2016,2019, to shareholders on the register on May 23, 2016,20, 2019, record date on May 24, 2016.21, 2019; (ii) to authorise the Board of Directors — pursuant to and for the purposes of Article 2357 of the Italian Civil Code — to proceed, within a period of eighteen months from the date of the resolution, with the purchase of a maximum number of shares equal to 67,000,000 ordinary shares of the Company, representing about 1.84% of the share capital of Eni SpA, for a total outlay of up to €1,200 million. In execution of this resolution at December 31, 2019, 28,590,482 shares were acquired for a total consideration of €400 million.
Legal reserve This reserve represents earnings restricted from the payment of dividends pursuant to Article 2430 of the Italian Civil Code. The legal reserve has reached the maximum amount required by the Italian Law. Reserve for treasury shares The reserve for treasury shares of €581 million (same amount as of December 31, 2015) represents the reserve that was established in previous reporting period to repurchase the Company shares in accordance with resolutions at Eni’s Shareholders’ Meetings. Reserves related to the fair value measurement of cash flow hedging derivatives,F-75
Other Comprehensive Income reserves | | | Cash flow hedge derivatives | | | Defined benefit plans* | | | Other comprehensive income on equity-accounted investments | | | Investments valued at fair value | | (€ million) | | | Gross reserve | | | Deferred tax liabilities | | | Net reserve | | | Gross reserve | | | Deferred tax liabilities | | | Net reserve | | Reserve as of December 31, 2018 | | | | | (13) | | | | | | 4 | | | | | | (9) | | | | | | (143) | | | | | | 13 | | | | | | (130) | | | | | | 66 | | | | | | 15 | | | Changes of the year | | | | | (1,418) | | | | | | 411 | | | | | | (1,007) | | | | | | (49) | | | | | | 5 | | | | | | (44) | | | | | | (6) | | | | | | (3) | | | Foreign currency translation differences | | | | | | | | | | | | | | | | | | | | | | | (3) | | | | | | | | | | | | (3) | | | | | | | | | | | | | | | Change in scope of consolidation | | | | | | | | | | | | | | | | | | | | | | | 5 | | | | | | (1) | | | | | | 4 | | | | | | | | | | | | | | | Reversal to inventories adjustments | | | | | 36 | | | | | | (10) | | | | | | 26 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reclassification adjustments | | | | | 739 | | | | | | (214) | | | | | | 525 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserve as of December 31, 2019 | | | | | (656) | | | | | | 191 | | | | | | (465) | | | | | | (190) | | | | | | 17 | | | | | | (173) | | | | | | 60 | | | | | | 12 | | | Reserve as of December 31, 2017 | | | | | 240 | | | | | | (57) | | | | | | 183 | | | | | | (133) | | | | | | 19 | | | | | | (114) | | | | | | 90 | | | | | | | | | Changes of the year | | | | | 399 | | | | | | (116) | | | | | | 283 | | | | | | (15) | | | | | | (2) | | | | | | (17) | | | | | | (24) | | | | | | 15 | | | Foreign currency translation differences | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | | (1) | | | | | | | | | | | | | | | | | | | | | Change in scope of consolidation | | | | | | | | | | | | | | | | | | | | | | | 4 | | | | | | (3) | | | | | | 1 | | | | | | | | | | | | | | | Reversal to inventories adjustments | | | | | (10) | | | | | | 3 | | | | | | (7) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reclassification adjustments | | | | | (642) | | | | | | 174 | | | | | | (468) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserve as of December 31, 2018 | | | | | (13) | | | | | | 4 | | | | | | (9) | | | | | | (143) | | | | | | 13 | | | | | | (130) | | | | | | 66 | | | | | | 15 | | |
*
available-for-sale financial assets and OCI for defined benefit plans The reserves related to the valuation at fair value of cash flow hedging derivatives, available-for-sale financial instruments and defined benefit plans, net of the related tax effect, consisted of the following:
| | | Cash flow hedge derivatives | | | Available-for-sale financial instruments | | | Defined benefit plans | | | Total | | (€ million) | | | Gross reserve | | | Deferred tax liabilities | | | Net reserve | | | Gross reserve | | | Deferred tax liabilities | | | Net reserve | | | Gross reserve | | | Deferred tax liabilities | | | Net reserve | | | Gross reserve | | | Deferred tax liabilities | | | Net reserve | | Reserve as of December 31, 2014 | | | | | (384) | | | | | | 100 | | | | | | (284) | | | | | | 13 | | | | | | (2) | | | | | | 11 | | | | | | (154) | | | | | | 32 | | | | | | (122) | | | | | | (525) | | | | | | 130 | | | | | | (395) | | | Changes of the year 2015 | | | | | (439) | | | | | | 108 | | | | | | (331) | | | | | | (4) | | | | | | 1 | | | | | | (3) | | | | | | 34 | | | | | | (20) | | | | | | 14 | | | | | | (409) | | | | | | 89 | | | | | | (320) | | | Reclassification to discontinued operations | | | | | 5 | | | | | | (1) | | | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | 10 | | | | | | (2) | | | | | | 8 | | | | | | 15 | | | | | | (3) | | | | | | 12 | | | Foreign currency translation differences | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | (1) | | | | | | (1) | | | | | | | | | | | | (1) | | | Reversal of the year 2015 | | | | | 181 | | | | | | (44) | | | | | | 137 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 181 | | | | | | (44) | | | | | | 137 | | | Reserve as of December 31, 2015 | | | | | (637) | | | | | | 163 | | | | | | (474) | | | | | | 9 | | | | | | (1) | | | | | | 8 | | | | | | (111) | | | | | | 10 | | | | | | (101) | | | | | | (739) | | | | | | 172 | | | | | | (567) | | | Changes of the year 2016 | | | | | 360 | | | | | | (90) | | | | | | 270 | | | | | | (3) | | | | | | | | | | | | (3) | | | | | | 16 | | | | | | (35) | | | | | | (19) | | | | | | 373 | | | | | | (125) | | | | | | 248 | | | Foreign currency translation differences | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | 12 | | | | | | 8 | | | | | | (4) | | | | | | 12 | | | | | | 8 | | | Reversal of the year 2016 | | | | | 523 | | | | | | (130) | | | | | | 393 | | | | | | (1) | | | | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | | | | | | | 522 | | | | | | (130) | | | | | | 392 | | | Reserve as of December 31, 2016 | | | | | 246 | | | | | | (57) | | | | | | 189 | | | | | | 5 | | | | | | (1) | | | | | | 4 | | | | | | (99) | | | | | | (13) | | | | | | (112) | | | | | | 152 | | | | | | (71) | | | | | | 81 | | | |
Reserve for available-for-sale financial instruments net of tax effect of €4 million (€8 million at December 31, 2015) related2019 includes €7 million relating to the fair value valuation of securities.equity-accounted investments.
Other reserves Other reserves amounting to €211 million (€180 million at December 31, 2015) related to: •
(i) a reserve of €247€127 million representing the increase in Eni shareholders’ equity associated with a business combination under common control, whereby the parent company Eni SpA divested its subsidiary Snamprogetti SpA to Saipem Projects SpA (both merged into Saipem SpA) at a price higher than the book value of the interest transferred (same amount as of December 31, 2015);
•
subsidiaries; (ii) a reserve of €63 million deriving from Eni SpA’s equity (same amount as of December 31, 2015);
•
a reserve of €21 million relating to the share of “Other comprehensive income” on equity accounted entities (a negative reserve of €11 million at December 31, 2015);
•
a reserve of €4 million representing the impact on Eni shareholders’ equity associated with the acquisition of a non-controlling interest of 48.55% in the subsidiary Tigáz Zrt (€5 million for the acquisition of 47.60% at December 31, 2015);
•
a negative reserve of €124 million representing the impact on Eni shareholders’ equity associated with the acquisition of a non-controlling interest of 45.99% in the subsidiary Altergaz SA, now Eni Gas & Power France SA (same amount as of December 31, 2015).
equity.
Cumulative foreign currency translation differences The cumulative foreign currency translation differences arose from the translation of financial statements denominated in currencies other than euro.
Treasury shares A total of 33,045,19761,635,679 of Eni’s ordinary shares (same amount as of(33,045,197 at December 31, 2015)2018) were held in treasury for a total cost of €581€981 million (same amount as of(€581 million at December 31, 2015)2018). On April 13, 2017, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan 2017-2019 and empowered the Board of Directors to execute the Plan by authorizing it to dispose up to a maximum of 11 million of treasury shares in service of the Plan. Interim dividend The interim dividend for the year 20162019 amounted to €1,441€1,542 million corresponding to €0.40€0.43 per share, as resolved by the Board of Directors on 19 September 15, 2016,2019, in accordance with Article 2433-bis, paragraph 5 of the Italian Civil Code; the dividend was paid on 25 September 21, 2016, record date on September 19, 2016.2019. Distributable reserves As of December 31, 2016,2019, Eni shareholders’ equity included distributable reserves of approximately €48.2€43 billion.
Reconciliation of net profit and shareholders’ equity of the parent company Eni SpA to consolidated net profit and shareholders’ equity | | | Net profit | | | Shareholders’ equity | | (€ million) | | | 2015 | | | 2016 | | | December 31, 2015 | | | December 31, 2016 | | As recorded in Eni SpA’s Financial Statements | | | | | 2,183 | | | | | | 4,521 | | | | | | 39,562 | | | | | | 41,935 | | | Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company | | | | | (10,778) | | | | | | (5,480) | | | | | | 18,508 | | | | | | 12,384 | | | Consolidation adjustments: | | | | | | - difference between purchase cost and underlying carrying amounts of net equity | | | | | (58) | | | | | | (44) | | | | | | 308 | | | | | | 240 | | | - adjustments to comply with Group account policies | | | | | (523) | | | | | | (188) | | | | | | 1,137 | | | | | | 461 | | | - elimination of unrealized intercompany profits | | | | | 96 | | | | | | (56) | | | | | | (1,219) | | | | | | (801) | | | - deferred taxation | | | | | (270) | | | | | | (210) | | | | | | (880) | | | | | | (1,133) | | | - other adjustments | | | | | (23) | | | | | | | | | | | | (7) | | | | | | | | | | | | | | (9,373) | | | | | | (1,457) | | | | | | 57,409 | | | | | | 53,086 | | | Non-controlling interest | | | | | 595 | | | | | | (7) | | | | | | (1,916) | | | | | | (49) | | | As recorded in Consolidated Financial Statements | | | | | (8,778) | | | | | | (1,464) | | | | | | 55,493 | | | | | | 53,037 | | | |
| | | Net profit | | | Shareholders’ equity | | (€ million) | | | 2019 | | | 2018 | | | December 31, 2019 | | | December 31, 2018 | | As recorded in Eni SpA’s Financial Statements | | | | | 2,978 | | | | | | 3,173 | | | | | | 41,636 | | | | | | 42,615 | | | Excess of net equity stated in the separate accounts of consolidated subsidiaries over the corresponding carrying amounts of the parent company | | | | | (2,800) | | | | | | (134) | | | | | | 5,211 | | | | | | 7,183 | | | Consolidation adjustments: | | | | | | | | | | | | | | | | | | | | | | | | | | - difference between purchase cost and underlying carrying amounts of net equity | | | | | (6) | | | | | | | | | | | | 202 | | | | | | 153 | | | - adjustments to comply with Group accounting policies | | | | | (348) | | | | | | 862 | | | | | | 1,424 | | | | | | 2,000 | | | - elimination of unrealized intercompany profits | | | | | (74) | | | | | | 177 | | | | | | (593) | | | | | | (519) | | | - deferred taxation | | | | | 405 | | | | | | 59 | | | | | | 20 | | | | | | (359) | | | | | | | | 155 | | | | | | 4,137 | | | | | | 47,900 | | | | | | 51,073 | | | Non-controlling interest | | | | | (7) | | | | | | (11) | | | | | | (61) | | | | | | (57) | | | As recorded in Consolidated Financial Statements | | | | | 148 | | | | | | 4,126 | | | | | | 47,839 | | | | | | 51,016 | | |
3726 Other information
Supplemental cash flow information | | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Investment in consolidated subsidiaries and businesses | | | | | Current assets | | | | | 96 | | | | | Non-current assets | | | | | 265 | | | | | Net borrowings | | | | | (19) | | | | | Current and non-current liabilities | | | | | (291) | | | | | Net effect of investments | | | | | 51 | | | | | Fair value of investments held before the acquisition of control | | | | | (15) | | | | | Purchase price | | | | | 36 | | | | | less: | | | | | Cash and cash equivalents | | | | | Investment in consolidated subsidiaries and businesses net of cash and cash equivalent | | | | | 36 | | | | | Disposal of consolidated subsidiaries and businesses | | | | | Current assets | | | | | 5 | | | | | | 44 | | | | | | 6,526 | | | Non-current assets | | | | | 2 | | | | | | 125 | | | | | | 8,615 | | | Net borrowings | | | | | | | | | | | (77) | | | | | | (5,415) | | | Current and non-current liabilities | | | | | (2) | | | | | | (45) | | | | | | (6,334) | | | Net effect of disposals | | | | | 5 | | | | | | 47 | | | | | | 3,392 | | | Reclassification of foreign currency translation differences among other items of comprehensive income | | | | | | | | | | | (34) | | | | | | 7 | | | Fair value of share capital held after the sale of control | | | | | | | | | | | | | | | | | (1,006) | | | Gain (loss) on disposal | | | | | (5) | | | | | | 66 | | | | | | 11 | | | Non-controlling interest | | | | | | | | | | | | | | | | | (1,872) | | | Selling price | | | | | | | | | | | 79 | | | | | | 532 | | | less: | | | | | Cash and cash equivalents | | | | | | | | | | | (6) | | | | | | (894) | | | Disposal of consolidated subsidiaries and businesses net of cash and cash equivalent | | | | | | | | | | | 73 | | | | | | (362) | | | |
Cash flow from disposals of 2016 related to: (i) the consideration of €463 million received from the sale of 12.503% of Saipem to CDP Equity SpA, which was reported net of Saipem’s cash and cash equivalents disposed of for €889 million (as established by IAS 7). Due to the presentation of the Saipem Group as discontinued operations in 2015 Financial Statements, such cash and cash equivalents were included as reconciliation item in 2016 and 2015 Cash Flow Statement, in order to present the Group cash and cash equivalents net of those related to discontinued operations; (ii) the sale of a 100% stake in Eni Slovenija doo and Eni Hungaria Zrt for a total consideration of €69 million and cash and cash equivalents divested of €5 million.
38 Guarantees, commitments and risks
Guarantees
| | | December 31, 2015 | | | December 31, 2016 | | (€ million) | | | Unsecured guarantees | | | Other guarantees | | | Total | | | Unsecured guarantees | | | Other guarantees | | | Total | | Eni | | | | | | | | Consolidated subsidiaries | | | | | | | | | | | 7,929 | | | | | | 7,929 | | | | | | | | | | | | 5,869 | | | | | | 5,869 | | | Unconsolidated subsidiaries | | | | | | | | | | | 113 | | | | | | 113 | | | | | | | | | | | | 246 | | | | | | 246 | | | Consolidated joint operations | | | | | | | | | | | 6 | | | | | | 6 | | | | | | Joint ventures and associates | | | | | 6,122 | | | | | | 75 | | | | | | 6,197 | | | | | | 6,124 | | | | | | 2,112 | | | | | | 8,236 | | | Others | | | | | 7 | | | | | | 216 | | | | | | 223 | | | | | | | | | | | | 202 | | | | | | 202 | | | | | | | | 6,129 | | | | | | 8,339 | | | | | | 14,468 | | | | | | 6,124 | | | | | | 8,429 | | | | | | 14,553 | | | Engineering & Construction | | | | | | | | Consolidated subsidiaries | | | | | | | | | | | 3,349 | | | | | | 3,349 | | | | | | Joint ventures and associates | | | | | 150 | | | | | | 68 | | | | | | 218 | | | | | | | | | | | 150 | | | | | | 3,417 | | | | | | 3,567 | | | | | | | | | | | | | | | | | | | | | | | | | | 6,279 | | | | | | 11,756 | | | | | | 18,035 | | | | | | 6,124 | | | | | | 8,429 | | | | | | 14,553 | | | |
(€ million) | | | 2019 | | | 2018 | | | 2017 | | Investment in consolidated subsidiaries and businesses | | | | | | | | | | | | | | | | | | | | Current assets | | | | | 1 | | | | | | 44 | | | | | | | | | Non-current assets | | | | | 12 | | | | | | 198 | | | | | | | | | Net borrowings | | | | | | | | | | | 11 | | | | | | | | | Current and non-current liabilities | | | | | (6) | | | | | | (47) | | | | | | | | | Net effect of investments | | | | | 7 | | | | | | 206 | | | | | | | | | Fair value of investments held before the acquisition of control | | | | | | | | | | | (50) | | | | | | | | | Non-controlling interests | | | | | (2) | | | | | | | | | | | | | | | Gain on a bargain purchase | | | | | | | | | | | (8) | | | | | | | | | Purchase price | | | | | 5 | | | | | | 148 | | | | | | | | | less: | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | | | | | | | | | | (29) | | | | | | | | | Consolidated subsidiaries and businesses net of cash and cash equivalent acquired | | | | | 5 | | | | | | 119 | | | | | | | | | Disposal of consolidated subsidiaries and businesses | | | | | | | | | | | | | | | | | | | | Current assets | | | | | 77 | | | | | | 328 | | | | | | 166 | | | Non-current assets | | | | | 188 | | | | | | 5,079 | | | | | | 814 | | | Net borrowings | | | | | 11 | | | | | | 785 | | | | | | (252) | | | Current and non-current liabilities | | | | | (57) | | | | | | (3,470) | | | | | | (205) | | | Net effect of disposals | | | | | 219 | | | | | | 2,722 | | | | | | 523 | | | Reclassification of foreign currency translation differences among other items of comprehensive income | | | | | (24) | | | | | | 113 | | | | | | | | | Fair value of share capital held after the sale of control | | | | | | | | | | | (3,498) | | | | | | | | | Fair value valuation for business combination | | | | | | | | | | | 889 | | | | | | | | | Gain (loss) on disposal | | | | | 16 | | | | | | 13 | | | | | | 2,148 | | | Selling price | | | | | 211 | | | | | | 239 | | | | | | 2,671 | | | less: | | | | | | | | | | | | | | | | | | | | Cash and cash equivalents | | | | | (24) | | | | | | (286) | | | | | | (9) | | | Consolidated subsidiaries and businesses net of cash and cash equivalent disposed of | | | | | 187 | | | | | | (47) | | | | | | 2,662 | | | |
Investments in 2019 concerned: (i) the acquisition of a 60% stake of SEA SpA, which supplies services and solutions for energy efficiency in the residential and industrial segments in Italy; (ii) the acquisition of the residual 32% interest in the joint operation Petroven Srl, which operates storage facilities of petroleum products. Disposals in 2019 concerned the sale of 100% of the stake of Agip Oil Ecuador BV, which retains a service contract for the development of the Villano oil field. Investments in 2018 concerned: (i) the acquisition of the business by Versalis Spa of the “bio” activities of the Mossi & Ghisolfi Group, related to development, industrialization, licensing of bio-chemical technologies and processes based on use of renewable sources for €75 million; (ii) the acquisition of the remaining 51% stake in the Gas Supply Company of Thessaloniki – Thessalia SA which distributes and sells gas in Greece for €24 million, net of cash acquired of €28 million; (iii) the acquisition of the company Mestni Plinovodi distribucija plina doo, which distributes and sells gas in Slovenia for €15 million, net of cash acquired for €1 million. The gain from bargain purchase, recognized in Other income and revenues, was due to the obtainable synergies from the greater ability to recover the investments made by the acquired company due to the combination of customer portfolios. Disposals in 2018 concerned: (i) the loss of control of Eni Norge AS resulting from the business combination with Point Resources AS, with the establishment of the equity-accounted joint venture Vår Energi AS (Eni’s interest 69.60%), that will develop the project portfolio of the combined entities. The operation entailed the change in scope of consolidation of €2,486 million of net assets, of which cash and cash equivalents for €258 million, the recognition of the investment in Vår Energi AS for €3,498 million and a fair value gain of €889 million, net of negative exchange rate differences of €123 million; (ii) the sale of 98.99% (entire stake owned) of Tigáz Zrt and Tigáz Dso (100% Tigáz Zrt) operating in the gas distribution business in Hungary to the MET Holding AG group for €145 million net of cash divested of €13 million; (iii) the sale by Lasmo Sanga Sanga of the business relating to a 26.25% stake (entire stake owned) in the PSA of the Sanga Sanga gas and condensates field for €33 million; (iv) the sale of 100% of Eni Croatia BV, which owns shares of gas projects in Croatia to INA-Industrija Nafte dd for €20 million, net of cash divested of €15 million; (v) the sale of 100% of Eni Trinidad and Tobago Ltd, which holds a share of a gas project in Trinidad and Tobago for €10 million. 27 Guarantees, commitments and risks Guarantees (€ million) | | | December 31, 2019 | | | December 31, 2018 | | Consolidated subsidiaries | | | | | 4,323 | | | | | | 5,082 | | | Unconsolidated subsidiaries | | | | | 197 | | | | | | 196 | | | Joint ventures and associates | | | | | 4,075 | | | | | | 4,056 | | | Others | | | | | 267 | | | | | | 163 | | | | | | | | 8,862 | | | | | | 9,497 | | |
Guarantees include the guarantees issued by Eni SpA on behalf of third-party contractors and lenders who have a certain contractual obligations to build and finance the construction of an LNG Floating Production unit for the development of the Coral gas reserves discovered in Area 4 offshore Mozambique. The total value of the contract is €4,673 million. Eni is operator of the project with a 25% indirect interest through a 35.71% stake in the joint operation Mozambique Rovuma Venture SpA. The final investment decision (FID) for the Coral project was made on June 1, 2017. The FLNG plant is designed to treat approximately 3.37 million tonnes per year of LNG. A special purpose entity was established, Coral FLNG SA (Eni’s interest 25%). This entity will operate the vessel in accordance with a service agreement (EPCC) for the liquefaction, storage and loading of the LNG on behalf of the Concessionaires of Area 4 and of the other two partners of Mozambique Rovuma Venture SpA, CNPC and ExxonMobil in proportion to their participating interest in the Exploration and Production Concession Contract (EPCC) of Area 4, equal to 20% and 25%, respectively. The LNG will be supplied to BP under a long-term LNG sale and
purchase agreement with a take-or-pay clause and a twenty-year term, providing an option of extending the duration for up to ten consecutive years. Eni issued a parent company guarantee, whereby it irrevocably and unconditionally guarantees the Technip — JGC — Samsung Heavy Industries (TJS) consortium (the beneficiaries) for the due and proper performance of the obligations of Coral FLNG SA in connection with execution of the Engineering Procurement Construction Installation and Commissioning (EPCIC) contract, up to the maximum liability of €1,168 million equal to 25% of the value of the contract. The maximum liability will be automatically reduced by any amount paid to the beneficiaries in respect of the guaranteed obligations. The financing of the project is carried out partly through funds provided by the venturers and partly by a project financing with Export Credit Agencies and commercial banks for a total amount of €4,164 million. During the construction and the commissioning of the FLNG plant, the project financing agreement will be supported by a debt service undertaking (DSU), up to a maximum liability of €1,425 million in proportion to Eni’s participating interest equal to 25% in the industrial initiative. Subsequently, in the running phase of the plant, once the performance tests of the vessel have been validated by the lenders, that guarantee will be released and the financing facility will convert to non-recourse, terminating the obligations of the venturers of Area 4 towards the lenders. Once vessel operations start, the lenders will be guaranteed only by the cash flows of the sale of LNG volumes treated by the vessel and delivered to the buyer, excluding the gas reserves from the scope of the guarantee. The financing and any collateral costs will be reimbursed to the lenders through a “pay-when-paid” clause, whereby loan repayments will be made through the cash flows associated with the sale of the LNG arising from the project to the long-term buyer, without any obligations from Eni and Concessionaires to guarantee the performance of Coral FLNG SA towards the lenders. Furthermore, the Concessionaries opened a credit facility which committed each Concessionary to finance pro-quota: (i) the share of capital expenditures to be borne by the Mozambique State-owned company ENH up to a maximum liability of €123 million in Eni’s share; (ii) the share of the debt service undertaking by ENH up to a maximum liability of €158 million in Eni’s share. As a final point, as provided by the EPCC that regulates the petroleum activities in Area 4, Eni SpA in its capacity as parent company of the operator Mozambique Rovuma Venture SpA has provided concurrently with the approval of the initial development plan of the Area reserves, an irrevocable and unconditional parent company guarantee in respect of any possible claims or any contractual breaches in connection with the petroleum activities to be carried out in the contractual area, including those activities in charge of the special purpose entities like Coral FLNG SA, to the benefit of the Government of Mozambique and third parties. The obligations of the guarantor towards the Government of Mozambique are unlimited (non-quantifiable commitments), whereas they provide a maximum liability of €1,335 million in respect of third-parties claims. This guarantee will be effective until the completion of any decommissioning activity related to both the development plan of Coral as well as any development plan to be executed within Area 4 (particularly the Mamba project). This parent company guarantee issued by Eni covering 100% of the aforementioned obligations was taken over by the other concessionaires (Kogas, Galp and ENH) and by ExxonMobil and CNPC shareholders of the joint operation Mozambico Rovuma Venture SpA, in proportion to their respective participating interest in the EPCIC of Area 4. Guarantees issued on behalf of consolidated subsidiaries of €5,869€4,323 million (€7,9295,082 million at December 31, 2015)2018) primarily consisted of: (i)of guarantees given to third parties relating to bid bonds and performance bonds for €1,965€2,886 million (€4,3812,576 million at December 31, 2015)2018). The decrease of €2,416 million related to the reclassification to joint ventures and associates of the guarantees given on behalf of Saipem Group for €2,483 million as of December 31, 2015; (ii) VAT recoverable from tax authorities for €1,380 million (€1,310 million at December 31, 2015); (iii)In 2019 a bank guarantee of €1,010 million, issued on behalf of GasTerra in order to obtain the renunciationwaiver to a temporary seizure order onof Eni’s investment in Eni International BV, requested and obtainedwhich was ordered by a Netherlands Court in July 2016;2016, was settled. In July 2019, the arbitration proceeding, initiated by the parties to settle the dispute, issued an award favourable to Eni and (iv) insurance riskruled the claim of GasTerra for €141 million reinsured by Eni (€140 million at December 31, 2015).a price adjustment to the gas supplies to be without merit, which in the first partial award was the basis whereby GasTerra obtained the seizure order. On July��24, 2019 upon Eni’s request and GasTerra’s consent, the bank guarantee was terminated. GasTerra has reserved its rights of appeal. At December 31, 2016,2019, the underlying commitment issued on behalf of consolidated subsidiaries covered by such guarantees was €5,785€4,013 million (€7,8085,000 million at December 31, 2015)2018). Other guarantees issued on behalf of unconsolidated subsidiaries of €246 million (€113 million at December 31, 2015) consisted of letters of patronage and other guarantees issued to commissioning entities relating to bid bonds and performance bonds for €240 million (€102 million at December 31, 2015). At December 31, 2016, the underlying commitment covered by such guarantees was €53 million (€113 million at December 31, 2015).
Unsecured guarantees and other guaranteesGuarantees issued on behalf of joint ventures and associates of €8,236€4,075 million (€6,1974,056 million at December 31, 2015)2018) primarily consisted of: (i) unsecured guarantees and other guarantees for €1,676 million issued towards banks and other lending institutions in relation to loans and lines of credit received (€1,664 million at December 31, 2018), of which €1,425 million (€1,397 million at December 31, 2018) related to guarantees issued as part of the Coral development project in Area 4 offshore Mozambique on behalf of Coral South FLNG DMCC with respect to the financing agreements of the project with Export Credit Agencies and banks; and (ii) guarantees given to third parties relating to bid
bonds and performance bonds for €1,661 million (€1,644 million at December 31, 2018), of which €1,168 million (€1,147 million at December 31, 2018) related to guarantees issued towards the contractors who are building the FLNG vessel as part of the Coral development project offshore Mozambique; (iii) an unsecured guarantee of €6,122€499 million (same amount as of(€499 million at December 31, 2015)2018) given by Eni SpA on behalf of the participated Saipem joint-venture to Treno Alta Velocità — TAV SpA (now RFI — Rete Ferroviaria Italiana SpA) for the proper and timely completion of a project relating tofor the construction of the Milan-Bologna fast track railway by the CEPAV (Consorzio Eni per l’Alta Velocità) Uno (Saipem 50.36%); consortium members, excluding Saipem Group, gave Eni liability of surety letters and bank guarantees amounting to 10% of their respective portion of the work; (ii) guarantees given to third parties relating to bid bonds and performance bonds for €1,705 million given on behalf of Saipem Group; and (iii) unsecured guarantees and other guarantees given to banksUno; (iv) a guarantee issued in relation to loans and lines of credit received for €82 million (€12 million at December 31, 2015). At December 31, 2016, the underlying commitment covered by such guarantees was €2,109 million (€72 million at December 31, 2015). Unsecured and other guarantees given on behalf of third parties of €202 million (€223 million at December 31, 2015) primarily consisted of guarantees issued on behalffavor of Gulf LNG Energy and Gulf LNG Pipeline and on behalf of Angola LNG Supply Service Llc (Eni 13.6%(Eni’s interest 13.60%) as security against paymentto cover contractual commitments of paying re-gasification fees in connection with the regasification activity for €193€181 million (€187177 million at December 31, 2015)2018). At December 31, 2016,2019, the underlying commitment issued on behalf of joint ventures and associates covered by such guarantees was €202€2,109 million (€2142,159 million at December 31, 2015)2018).
Commitments and risks (€ million) | | December 31, 2015 | | December 31, 2016 | | | December 31, 2019 | | December 31, 2018 | | Commitments | | | | 21,241 | | | | | 20,682 | | | | | | 74,338 | | | | | 54,611 | | | Risks | | | | 422 | | | | | 605 | | | | | | 676 | | | | | 673 | | | | | | | 21,663 | | | | | 21,287 | | | | | | 75,014 | | | | | 55,284 | | | | |
Other commitments of €20,682 million (€21,241 million at December 31, 2015)Commitments related to: (i) parent company guarantees that were issued in connection with certain contractual commitments for hydrocarbon exploration and production activities and quantified, on the basis of the capital expenditures to be incurred, to €12,415be €65,374 million (€12,79452,397 million at December 31, 2015); (ii) commitments entered2018). The increase of €12,977 million was incurred in connection with: (a) the issuance of new parent company guarantees of €9,794 million of which €8,904 million issued on behalf of Eni Abu Dhabi BV in relation to the entry into the exploration permits of Blocks 1 and 2 and €890 million on behalf of Eni RAK BV in relation to the entry and the start of exploration activities in Block A in the United Arab Emirates. These parent company guarantees are in addition to those issued in 2018 as part of the transactions with the Abu Dhabi State oil company ADNOC, whereby Eni acquired participating interests in the two offshore concessions in production of Lower Zakum (Eni’s interest 5%) and Umm Shaif and Nasr (Eni’s interest 10%) for a period of 40 years and a maximum amount of €13,356 million and in the concession under development of Gasha (Eni’s interest 25%) for a period of 40 years and a maximum amount of €22,261 million. These guarantees were issued to cover the contractual obligations towards the State company, deriving from oil operations related to the Concession Agreements including, in particular, the achievement of some production targets and recovery factors of reserves in the medium and long term, an asset integrity plan and optimization and maintenance of the production after reaching the plateau, the transfer of technologies and the adoption of best-in-class operating standards in HSE. The guarantees do not cover any loss of profit or production deriving from failure to achieve the targets; (b) a new parent company guarantee of €445 million issued in relation to an asset swap with Lukoil involving Blocks 10 and 12 in the offshore of Mexico. This parent company guarantee is in addition to those issued in previous years for €9,194 million, of which €6,968 million issued in 2018 following the awarding of new exploration licenses in the offshore of Mexico and the final investment decision for the development of the offshore reserves in Area 1; (c) a new parent company guarantee for €1,781 million in relation to the acquisition of the upstream assets of ExxonMobil by the Explorationjoint venture Vår Energi AS intended to cover the decommissioning contractual obligations; (ii) two parent company guarantees for a total amount of €6,527 million given on behalf of Eni Abu Dhabi Refining & Production segment for leasing contracts (chartering, operationTrading BV following the Share Purchase Agreement to acquire from ADNOC a 20% equity interest in ADNOC Refining and maintenance)the set-up of FPSO vesselsADNOC Global Trading Ltd dedicated to be used for development projectsmarketing petroleum products. The first parent company guarantee of €2,965 million was issued to guarantee the obligations under the Share Purchase Agreement and will remain in Angolaplace until the payment of the Deferred Consideration expected by March 31, 2020. The second parent company guarantee of €3,562 million has been issued to guarantee the obligations set out in the Shareholders Agreements and Ghana. Total commitments amounted to approximately €4,344 million and have a duration ranging between 14 and 16 years (€4,364 million at December 31, 2015);will remain in force as long as the investment is maintained; (iii) commitments assumed by Eni USA Gas Marketing Llc towards Angola LNG Supply Service Llc for the acquisitionpurchase of volumes of regasified gas at the Pascagoula plant (United States) over a twenty-year period (until 2031) and towards Gulf LNG Energy for the acquisition of regasification capacity at the Pascagoula terminal (5.8 BCM/y) over a twenty-year period (until 2031). The expected commitments have beenwere estimated at €2,541€1,978 million and €1,156 million, respectively (€2,590 million and €1,1912,079 million at December 31, 2015, respectively)2018) and have been included in off-balance sheet contractual commitments in the followingtable “Future payments under contractual obligations” in the paragraph “Liquidity risk”; and (iv) a memorandum of intent signed withLiquidity risk. However, since the project has been abandoned by the partners, Eni does not expect to make any payment under those contractual obligations.
In 2018, the contractual commitment signed in December 2007 between Eni USA Gas Marketing Llc and Gulf LNG Energy Llc (GLE) and Gulf LNG Pipeline Llc (GLP) for the purchase of long-term regasification and transport services (until 2031) amounting at December 31, 2017 to €948 million (undiscounted) ceased due to an arbitration ruling. The jurors established that the commitment was resolved by March 1, 2016 and recognized to the counterparties an equitable compensation of €324 million to Eni’s counterparties. Despite the ruling of the arbitration court invalidating the contract, GLE and GLP filed a claim with the Supreme Court of New York against Eni SpA demanding the enforcement of the parent company guarantee issued by Eni for the payment of the regasification fees until the original due date of the contract (2031) for a maximum amount of €757 million. Eni believes that the claims by GLE and GLP have no merit and is defending the action. At the moment, the risk of losing the proceeding is considered unlikely; (iv) a memorandum of intent signed with the Basilicata Region, whereby Eni has agreed to invest €129€114 million (€133116 million at December 31, 2015)2018) in the future, also on account of Shell Italia E&P SpA, in connection with Eni’s development plan of oilfields in Val d’Agri. The commitment has been included in the off-balance sheet contractual commitments in the following paragraph “Liquidity risk”.; (v) the commitment of €105 million for the acquisition of a 70% stake of Evolvere SpA, a company leader in the distributed generation of energy from renewable sources; the acquisition was finalized in January 2020. Risks of €605 million (€422 million at December 31, 2015) primarily concernedrelate to potential risks associated withwith: (i) contractual assurances given to acquirers of certain investments and businesses of Eni for €334€248 million (€326244 million at December 31, 2015) and the value of2018); (ii) assets of third parties under the custody of Eni for €271€428 million (€96429 million at December 31, 2015)2018). Non-quantifiableOther commitments and risks
A parent company guarantee was issued on behalf of CARDÓNCardón IV SA (Eni’s interest 50%), a joint venture that is currently operating development activities at the Perla gas field located in Venezuela, for the supplyingsupply to PDVSA GAS of the volumes of gas produced by the field until 2036 (endthe end of the concession agreement)agreement (2036). This guarantee cannot be quantified because the penalty clause for unilateral anticipated resolution originally set for Eni and the relevant quantification became ineffective due to a revision of the contractual terms. In case of failure on part of the operator to deliver the contractual gas volumes out of production, the amount ofclaim under the guarantee execution will be determined by applying the local legislation. The EniEni’s share (50%) of the contractual volumes of gas to be delivered to PDVSA GAS amounted to a total of $16 billion (€15.2 billion).around €13 billion. Notwithstanding this amount does not properly represent the guarantee exposure, nonetheless such amount represents the maximum financial exposure at risk for Eni. A similar guarantee was issued to Eni by PDVSA relating toon behalf of Eni for the fulfillment of the purchase commitments relating toof the gas quantities to be collectedvolumes by PDVSA GAS. FollowingOther commitments also include the integration signed on April 19, 2011, Eni confirmedagreements entered into for forestry initiatives, implemented within the low carbon strategy defined by the Company, and in particular concerning the commitments for the purchase, up to RFI - Rete Ferroviaria Italiana SpA its commitment, previously assumed under the convention signed with Treno Alta Velocità — TAV SpA (now RFI — Rete Ferroviaria Italiana SpA) on October 15, 1991,2038, of carbon credits produced and certified according to guarantee a correct and timely execution of the section Milano-Brescia of the high-speed railway from Milan to Verona. Such integration provides for CEPAV (Consorzio Eni per l’Alta Velocità) Due to act as general contractor. In order to pledge the guarantee given, the regulation of CEPAV (Consorzio Eni per l’Alta Velocità) Due binds the associates to give proper sureties and guarantees on behalf of Eni.international standards by subjects specialized in forest conservation programs.
Eni is liable for certain non-quantifiable risks related to contractual assurances given to acquirers of certain Eni assets, including businesses and investments, against certain contingent liabilities deriving from tax, social security contributions, environmental issues and other matters applicable to periods during which such assets were operated by Eni. Eni believes such matters will not have a material adverse effect on Eni’s results of operations and liquidity.
Risk factors
Financial risks Financial risks are managed in respect of guidelines issued by the Board of Directors of Eni SpA in its role of directing and setting of the risk limits, targeting to align and centrally coordinate Group companies’ policies on financial risks (“Guidelines on financial risks management and control”). The “Guidelines” define for each financial risk the key components of the management and control process, such as the aim of the risk management, the valuation methodology, the structure of limits, the relationrelationship model and the hedging and mitigation instruments. Market risk Market risk is the possibility that changes in currency exchange rates, interest rates or commodity prices will adversely affect the value of the Group’s financial assets, liabilities or expected future cash flows. The Company actively manages market risk in accordance with a set of policies and guidelines that provide a centralized model of handling finance, treasury and risk management operationstransactions based on the
Company’s departments of operational finance: the parent company’s (Eni SpA) finance department, Eni Finance International SA, Eni Finance USA Inc and Banque Eni SA, which is subject to certain bank regulatory restrictions preventing the Group’s exposure to concentrations of credit risk, and Eni Trading & Shipping that is in charge to execute certain activities relating to commodity derivatives. In particular, Eni’sEni Corporate finance department, Eni Finance International SA and Eni Finance International SAUSA Inc manage subsidiaries’ financing requirements in and outside Italy and in the United States of America, respectively, covering funding requirements and using available surpluses. All transactions concerning currencies and derivative contracts on interest rates and currencies different from commodities are managed by the parent company. The commodity risk associated with commercial exposures of each business unit (Eni’s business line or subsidiaries) is pooled and managed by the Midstream business line, which manages the market risk component in a view of portfolio,company, while Eni Trading & Shipping SpA executes the negotiation of commodity derivatives over the market. Eni SpA and Eni Trading & Shipping SpA (also through its subsidiary Eni Trading & Shipping Inc) perform trading activities in financial derivatives on external trading venues, such as European and non-European regulated markets, Multilateral Trading Facility (MTF), Organized Trading Facility (OTF), or similar and brokerage platforms (i.e. SEF), and over the counter on a bilateral basis with external counterparties. Other legal entities belonging to Eni that require financial derivatives enter into these operationstransactions through Eni Trading & Shipping and Eni SpA based on the relevant asset class expertise. Eni uses derivative financial instruments (derivatives) in order to minimize exposure to market risks related to fluctuations in exchange rates relating to those transactions denominated in a currency other than the functional currency (the euro) and interest rates, as well as to optimize exposure to commodity prices fluctuations taking into account the currency in which commodities are quoted. Eni monitors every activity in derivatives classified as risk-reducing (in particular, back-to-back activities, flow hedging activities, asset-backed hedging activities and portfolio-management activities) directly or indirectly related to covered industrial assets, so as to effectively optimize the risk profile to which Eni is exposed or could be exposed. If the result of the monitoring shows those derivatives should not be considered as risk reducing, these derivatives are reclassified in proprietary trading. As the proprietary trading is considered separately from the other activities in specific portfolios of Eni Trading & Shipping, its exposure is subject to specific controls, both in terms of Value at Risk (VaR) and stop loss and in terms of nominal gross value. For Eni, the gross nominal value of proprietary trading activities is compared with the limits set by the relevant international standards. The framework defined by Eni’s policies and guidelines provides that the valuation and control of market risk is performed on the basis of maximum tolerable levels of risk exposure defined in terms of: (i) limits of stop loss, which expresses the maximum tolerable amount of losses associated with a certain portfolio of assets over a pre-defined time horizon; (ii) limits of revision strategy, which consist in the triggering of a revision process of the strategy in the event of exceeding the level of profit and loss given; and (iii) VaR which measures the maximum potential loss of the portfolio, given a certain confidence level and holding period, assuming adverse changes in market variables and taking into account of the correlation among the different positions held in the portfolio. Eni’s finance department defines the maximum tolerable levels of risk exposure to changes in interest rates and foreign currency exchange rates in terms of VaR, pooling Group companies’ risk positions maximizing, when possible, the benefits of the netting activity. Eni’s calculation and valuation techniques for interest rate and foreign currency exchange rate risks are in accordance with banking standards, as established by the Basel Committee for bank activities surveillance. Tolerable levels of risk are based on a conservative approach, considering the industrial nature of the Company. Eni’s guidelines prescribe that Eni Group companies minimize such kinds of market risks by transferring risk exposure to the parent company finance department. Eni’s guidelines define rules to manage the commodity risk
aiming at optimizing core activities and pursuing preset targets of stabilizing industrial and commercial margins. The maximum tolerable level of risk exposure is defined in terms of VaR, limits of revision strategy, stop loss and volumes in connection with exposure deriving from commercial activities, as well as exposure deriving from proprietary trading, exclusively managed by Eni Trading & Shipping. Internal mandates to manage the commodity risk provide for a mechanism of allocation of the Group maximum tolerable risk level to each business unit. In this framework, Eni Trading & Shipping, in addition to managing risk exposure associated with its own commercial activity and proprietary trading, pools the requests for negotiating commodity derivatives and executes them onin the marketplace. According to the targets of financial structure included in the financial plan approved by the Board of Directors, Eni has decided to retain a cash reserve to face any extraordinary requirement. Eni’s finance department, with the aim of optimizing the efficiency and ensuring maximum protection of the capital, manages such reserve and its immediate liquidity within the limits assigned. The management of strategic cash is part of the asset management pursued through transactions on own risk in view of optimizing financial returns, while respecting authorized risk levels, safeguarding the Company’s assets and retaining quick access to liquidity. The four different market risks, whose management and control have been summarized above, are described below.
Market risk -— Exchange rate Exchange rate risk derives from the fact that Eni’s operations are conducted in currencies other than the euro (mainly the U.S. dollar). Revenues and expenses denominated in foreign currencies may be significantly affected by exchange ratesrate fluctuations due to conversion differences on single transactions arising from the time lag existing between execution and definition of relevant contractual terms (economic risk) and conversion of foreign currency-denominated trade and financing payables and receivables (transactional risk). Exchange rate fluctuations affect the Group’s reported results and net equity as financial statements of subsidiaries denominated in currencies other than the euro are translated from their functional currency into euro. Generally, an appreciation of the U.S. dollar versus the euro has a positive impact on Eni’s results of operations, and vice versa. Eni’s foreign exchange risk management policy is to minimize transactional exposures arising from foreign currency movements and to optimize exposures arising from commodity risk. Eni does not undertake any hedging activity for risks deriving from the translation of foreign currency denominated profits or assets and liabilities of subsidiaries, which prepare financial statements in a currency other than the euro, except for single transactions to be evaluated on a case-by-case basis. Effective management of exchange rate risk is performed within Eni’s central finance department,departments, which poolspool Group companies’ positions, hedging the Group net exposure by using certain derivatives, such as currency swaps, forwards and options. Such derivatives are evaluated at fair value based on market prices provided by specialized info-providers. Changes in fair value of those derivatives are normally recognized through profit and loss, as they do not meet the formal criteria to be recognized as hedges. The VaR techniques are based on variance/covariance simulation models and are used to monitor the risk exposure arising from possible future changes in market values over a 24-hour period within a 99% confidence level and a 20-day holding period. Market risk -— Interest rate Changes in interest rates affect the market value of financial assets and liabilities of the Company and the level of finance charges. Eni’s interest rate risk management policy is to minimize risk with the aim to achieve financial structure objectives defined and approved in the management’s finance plans. The Group’s central finance department poolsdepartments pool borrowing requirements of the Group companies in order to manage net positions and fund portfolio developments consistent with management plans, thereby maintaining a level of risk exposure within prescribed limits. Eni enters into interest rate derivative transactions, in particular interest rate swaps, to manage effectively the balance between fixed and floating rate debt. Such derivatives are evaluated at fair value based on market prices provided from specialized sources. Changes in fair value of those derivatives are normally recognized through the profit and loss account, as they do not meet the formal criteria to be accounted for under the hedge accounting method. VaR deriving from interest rate exposure is measured daily based on a variance/covariance model, with a 99% confidence level and a 20-day holding period.
Market risk -— Commodity Eni’s results of operations are affected by changes in the prices of commodities. A decrease in oil&gas prices generally, has a negative impact on Eni’s results of operations and vice versa, and may jeopardize the achievement of the financial targets preset in the Company’s four-year plans and budget. The commodity price risk arises in connection with the following exposures: (i) strategic exposure: exposures directly identified by the Board of Directors as a result of strategic investment decisions or outside the planning horizon of risk. These exposures include those associated with the program for the production of proved and unproved oil&gas reserves, long-term gas supply contracts for the portion not balanced by ongoing or highly probable sale contracts, refining margins identified by the Board of Directors as of strategic nature (the remaining volumes can be allocated to the active management of the margin or to asset-backed hedging activities) and minimum compulsory stocks; (ii) commercial exposure: includes the exposures related to the components underlying the contractual arrangements of industrial and commercial activities and, if related to take-or-pay commitments, to the components related to the time horizon of the four-year plan and budget and the relevant activities of risk management. Commercial exposures are characterized by a systematic risk management activity conducted based on risk/return assumptions by implementing one or more strategies and subjected to specific risk limits (VaR, revision strategy limits and stop loss). In particular, the commercial exposures include exposures subjected to asset-backed hedging activities, arising from the flexibility/optionality of assets; and (iii) proprietary trading exposure: includes operations independently conducted for profit purposes in the short term, and normally not finalized tofor the purpose of delivery, both within the commodity and financial markets, with the aim to obtain a profit upon the occurrence of a favorable result in the market, in accordance with specific limits of authorized risk (VaR, stop loss). InOrigination activities are included in the proprietary trading exposures, are included the origination activities, if not connected to contractual or physical assets. Strategic risk is not subject to systematic activity of management/coverage that is eventually carried out only in case of specific market or business conditions. Because of the extraordinary nature, hedging
activities related to strategic risks are delegated to the top management. Strategic risk is subject to measuring and monitoring but is not subject to specific risk limits. If previously authorized by the Board of Directors, exposures related to strategic risk can be used in combination with other commercial exposures in order to exploit opportunities for natural compensation between the risks (natural hedge) and consequently reduce the use of derivatives (by activating logics of internal market). Eni manages exposure to commodity price risk arising in normal trading and commercial activities in view of achieving stable economic results. TheEni manages the commodity risk and the exposure to commodity prices fluctuations embedded in commodities quoted in currencies other than the euro at each business line (Eni’s Divisions or subsidiaries) is pooled and managed by the Portfolio Management unit for commodities, and by Eni’s finance department for exchange rate requirements. The Portfolio Management unit manages business lines’ risk exposures to commodities, pooling and optimizing Group companies’ exposures and hedging net exposures on the trading venues through the trading unit of Eni Trading & Shipping. In orderShipping and the exposure to manage commodity price risk, Eni usesprices through the Group’s finance departments by using derivatives traded on the organized markets MTF, OTF and derivatives traded over the counter (swaps, forward, contracts for differences and options on commodities) with the underlying commodities being crude oil, gas, refined products, electricitypower or emission certificates. Such derivatives are evaluatedvalued at fair value based on market prices provided from specialized sources or, absent market prices, on the basis of estimates provided by brokers or suitable valuation techniques. VaR deriving from commodity exposure is measured daily based on a historical simulation technique, with a 95% confidence level and a one-day holding period. Market risk -— Strategic liquidity Market risk deriving from liquidity management is identified as the possibility that changes in prices of financial instruments (bonds, money market instruments and mutual funds) would affect the value of these instruments when evaluatedvalued at fair value. The setting up and maintenance of the liquidity reserve is mainly aimed to guarantee a proper financial flexibility. Liquidity should allow Eni to fund any extraordinary need (such as difficulty in access to credit, exogenous shock, macroeconomic environment, as well as merger and acquisitions) and must be dimensioned to provide a coverage of short-term debts and a coverage of medium and long-term finance debts due within a time horizon of 24 months. In order to manage the investment activity of the strategic liquidity, Eni defined a specific investment policy with aims and constraints in terms of financial activities and operational boundaries, as well as Governancegovernance guidelines regulating management and control systems. The setting up and maintenance of the reserve ofIn particular, strategic liquidity is mainly aimed to: (i) guarantee of financial flexibility. Liquidity should allow Eni Group to fund any extraordinary need (such as difficulty in access to credit, exogenous shock, macroeconomic environment, as well as merger and acquisitions); and (ii) ensure a full coverage of short-term debts and a coverage of medium and long-term financial debts due within a time horizon of 24 months, even in case of restrictions to credit.
Strategic liquidity management is regulated in terms of VaR (measured based on a parametrical methodology with a one-day holding period and a 99% confidence level), stop loss and other operating limits in terms of concentration, issuing entity, business segment, country of emission, duration, ratings and type of investing instruments in portfolio, aimed to minimize market and liquidity and instruments to invest on.risks. Financial leverage or short selling is not allowed. Activities in terms of strategic liquidity management started in the second half of the year 2013 (Euro portfolio) and throughout the course of the years 2014 and 2015,year 2017 (U.S. dollar portfolio). In 2019, the Euro investment portfolio has maintained an average credit rating of A/A-/BBB+, accordinglywhereas the USD investment portfolio has maintained an average credit rating of A+/A, both in line with the decrease in the Company’s credit rating.
year 2018. The following table showstables show amounts in terms of VaR, recorded in 20162019 (compared with 2015)2018) relating to interest rate and exchange rate risks in the first section and commodity risk. Regarding the management of strategic liquidity, the sensitivity to changechanges of interest ratesrate is expressed by the values of “Dollar Valuevalue per Basis Point” (DVBP). (Value at risk — parametric method variance/covariance; holding period: 20 days; confidence level: 99%) | | | 2015 | | 2016 | | | 2019 | | 2018 | | (€ million) | | High | | Low | | Average | | At year end | | High | | Low | | Average | | At year end | | | High | | Low | | Average | | At year end | | High | | Low | | Average | | At year end | | Interest rate(a) | | | | 6.21 | | | | | 2.45 | | | | | 4.06 | | | | | 4.40 | | | | | 5.27 | | | | | 2.55 | | | | | 3.62 | | | | | 3.42 | | | | | | 5.19 | | | | | 2.44 | | | | | 3.80 | | | | | 3.00 | | | | | 3.65 | | | | | 1.80 | | | | | 2.73 | | | | | 2.99 | | | Exchange rate(a) | | | | 0.52 | | | | | 0.05 | | | | | 0.13 | | | | | 0.13 | | | | | 0.34 | | | | | 0.04 | | | | | 0.14 | | | | | 0.17 | | | | | | 0.41 | | | | | 0.07 | | | | | 0.17 | | | | | 0.15 | | | | | 0.57 | | | | | 0.09 | | | | | 0.28 | | | | | 0.25 | | | | |
(a)
Value at risk deriving from interest and exchange rates exposures include the following finance department:departments: Eni Corporate TreasuryFinance Department, Eni Finance International SA, Banque Eni SA and Eni Finance USA Inc.
(Value at risk — Historic simulation weighted method; holding period: 1 day; confidence level: 95%) | | | 2015 | | 2016 | | | 2019 | | 2018 | | (€ million) | | High | | Low | | Average | | At year end | | High | | Low | | Average | | At year end | | | High | | Low | | Average | | At year end | | High | | Low | | Average | | At year end | | Commercial exposures Management Portfolio(a) | | | | 61.91 | | | | | 3.37 | | | | | 26.82 | | | | | 3.37 | | | | | 19.03 | | | | | 4.23 | | | | | 10.24 | | | | | 9.41 | | | | Commercial exposures – Management Portfolio (a) | | | | | 23.03 | | | | | 7.74 | | | | | 11.22 | | | | | 9.11 | | | | | 18.60 | | | | | 6.79 | | | | | 11.04 | | | | | 7.50 | | | Trading(b) | | | | 4.07 | | | | | 0.40 | | | | | 1.38 | | | | | 0.55 | | | | | 2.58 | | | | | 0.27 | | | | | 0.87 | | | | | 1.35 | | | | | | 1.60 | | | | | 0.25 | | | | | 0.51 | | | | | 0.31 | | | | | 2.28 | | | | | 0.26 | | | | | 0.73 | | | | | 0.27 | | | | |
(a)
Refers to the Midstream DepartmentLNG Marketing & Power business line (risk exposure from Refining & Marketing Divisionbusiness line and Gas & Power Division), Versalis, Eni Trading & Shipping commercial portfolio, andoperating branches outside Italy pertaining to the Divisions.Divisions and from October 2016 the Gas e Luce business line. For the Midstream Department starting from 2014,Gas & Power business lines, following the approval of the Eni’s Board of Directors on December 12, 2013, VaR is calculated on the so-called Statutory view, with a time horizon that coincides with the year considering all the volumes delivered in the year and the relevant financial hedging derivatives. Consequently, induring the year the VaR pertaining to the Midstream DepartmentGLP and EGL presents a decreasing trend following the progressive reaching of the maturity of the positions within the annual horizon. (b)
Cross-commodity proprietary trading, both for commodity contracts and financial derivatives, refers to Eni Trading & Shipping SpA (London-Bruxelles-Singapore) and Eni Trading & Shipping Inc (Houston). (Sensitivity — Dollar value of 1 basis point — DVBP) | | | 2015 | | 2016 | | | 2019 | | 2018 | | (€ million) | | High | | Low | | Average | | At year end | | High | | Low | | Average | | At year end | | | High | | Low | | Average | | At year end | | High | | Low | | Average | | At year end | | Strategic liquidity(a) | | | | 0.31 | | | | | 0.25 | | | | | 0.29 | | | | | 0.25 | | | | | 0.42 | | | | | 0.23 | | | | | 0.35 | | | | | 0.35 | | | | | | 0.37 | | | | | 0.31 | | | | | 0.35 | | | | | 0.33 | | | | | 0.35 | | | | | 0.25 | | | | | 0.29 | | | | | 0.25 | | | | |
(a)
Management of strategic liquidity portfolio in € currency starting from July 2013. (Sensitivity — Dollar value of 1 basis point — DVBP) | | | | | | | | 2019 | | | 2018 | | ($ million) | | | High | | | Low | | | Average | | | At year end | | | High | | | Low | | | Average | | | At year end | | Strategic liquidity(b) | | | | | 0.05 | | | | | | 0.02 | | | | | | 0.04 | | | | | | 0.05 | | | | | | 0.04 | | | | | | 0.01 | | | | | | 0.02 | | | | | | 0.02 | | |
(b)
Management of strategic liquidity portfolio in $ currency starting from August 2017. Credit risk Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. The Group manages differentlyEni defined credit risk depending on whethermanagement policies consistent with the nature and characteristics of the counterparties of commercial and financial transactions with regard to the centralized finance model. The Company adopted a model to quantify and control the credit risk arisesbased on the evaluation of the expected loss which represents the probability of default and the capacity to recover credits in default that is estimated through the so-called Loss Given Default. In the credit risk management and control model, credit exposures are distinguished by commercial nature, in relation to the structured contracts on commodities related to Eni’s core business, and by financial nature, in relation to the financial instruments substantially used by Eni, such as deposits, derivatives and securities. Credit risk for commercial exposures Credit risk arising from exposure to financialcommercial counterparties or to customers relating to outstanding receivables. Individualis managed by the business units and Eni’sby the specialized corporate finance and administration departments and is operated on the basis of formal procedures for the assessment and assignment of commercial counterparties, the monitoring of credit exposures, credit recovery activities and disputes. At a corporate level, the general guidelines and methods for quantifying and controlling customer risk, in particular for commercial counterparties, are assessed through an internal rating model that combines different default factors deriving from economic variables, financial indicators, payment experiences and accounting units are responsible for managing creditinformation from primary info providers. The probability of default related to State Entities or their closely related counterparties (e.g. National Oil Company), essentially represented by the probability of late payments, is determined by using the country risk arising in the normal course of the business.
The Group has established formal credit systems and processespremiums adopted for the purposes of the determination of the WACCs for the impairment of non-financial assets. Furthermore, for retail positions without specific ratings, risk is determined by distinguishing customers in homogeneous risk clusters based on historical series of data relating to ensure that before trading with a new counterpart can start, its creditworthiness is assessed. In addition, credit litigation and receivable collection activities are assessed.payments, periodically updated.
Eni’s corporate units define directions and methodsCredit risk for quantifying and controlling customer’s reliability. financial exposures
With regard to credit risk arising from financial counterparties deriving from current and strategic use of liquidity, derivative contracts and transactions with underlying financial assets valued at fair value, Eni has established guidelines priorinternal policies providing exposure control and concentration through maximum credit risk limits corresponding to entering into cash management and derivative contracts to assess the counterparty’s financial soundness and rating in view of optimizing the risk profiledifferent classes of financial activities while pursuing operational targets. Maximum limits of risk exposure are set in terms of maximum amounts of credit exposures for categories of counterparties as defined by the Company’s Board of Directors taking into account the credit ratings provided by primary credit rating agencies on the marketplace. Credit risk arising from financial counterparties is managed by the GroupEni’s operating finance department, includingdepartments and Eni’s subsidiary Eni Trading & Shipping which specifically engages in commodity derivatives transactions and by Group companies and Divisions,business units, only in the case of physical transactions with financial counterparties consistently with the Group centralized finance model. Eligible financial counterparties are closely monitored by each counterpart and by group of belonging to check exposures against the limits assigned to each counterparty on a daily basis.basis and the expected loss analysis and the concentration periodically. Liquidity risk Liquidity risk is the risk that suitable sources of funding for the Group may not be available, or the Group is unable to sell its assets onin the marketplace in order to meet short-term finance requirements and to settle obligations. Such a situation would negatively affect Group results, as it would result in the Company incurring higher borrowing expenses to meet its obligations or under the worst of conditions the inability of the Company to continue as a going concern. As part of its financial planning process, Eni managesEni’s risk management targets include the liquidity risk by targeting such a capital structure as to allow the Company to maintain a level of liquidity adequate to the Group’s needs, optimizing the opportunity cost of maintaining liquidity reserves also achieving an efficient balance in terms of maturity and composition of finance debt in terms of: (i) maximum ratio between net financial debt and net equity (leverage); (ii) minimum incidence of medium and long-term debts over the total amount of financial debts; (iii) minimum amount of fixed-rate debts over the total amount of medium and long-term debts; and (iv) minimum level of liquidity reserve. For this purpose, Eni holds a significant amount of liquidity reserve (financial assets plus committed credit lines), which aims to: (i) ensure a full coverage of short-term debt and the coverage of medium and long-term debts with a maturity of 24 months, even in case of restrictions to the credit access; (ii) deal with identified risk factors that could significantly affect the cash flow expected in the Financial Plan (i.e. changes in the scenario and/or production volumes, delays in disposals); (iii) ensuring the availability of an adequate level of financialliquidity readily available to deal with external shocks (drastic changes in the scenario, restrictions on access to capital markets, etc.) or to ensure an adequate level of operational flexibility to supportfor the Group’s development plans; and (iv) maintaining/improvingprograms of the current credit rating.Company. The financial assetstrategic liquidity reserve is employed in short-term marketable financial instruments, favouring investments with very low risk profile. At present, the Group believes to have access to sufficient funding to meet the current foreseeable borrowing requirements as a consequence of the availability of financial assets and lines of credit and the access to a wide range of funding at competitive costs through the credit system and capital markets. Eni has in place a program for the issuance of Euro Medium Term Notes up to €20 billion, of which about €16.3€14.9 billion were drawn as of December 31, 2016.2019. The Group has credit ratings of BBB+A- outlook stable and A-2, respectively, for long and short-term debt, outlook stable, assigned by Standard & Poor’s andPoor’s; Baa1 outlook stable and P-2, respectively, for long and short-term debt, assigned by Moody’s.Moody’s; A- outlook stable and F1, respectively for long and short-term debt, assigned by Fitch. Eni’s credit rating is linked in addition to the Company’s industrial fundamentals and trends in the trading environment to the sovereign credit rating of Italy. Based on the methodologies used by Standard & Poor’s and Moody’s,the credit rating agencies, a downgrade of Italy’s credit rating may trigger a potential knock-on effect on the credit rating of Italian issuers such as Eni. During 2019, the rating of Eni remained unchanged. In the course of the 2016,2019, Eni issued bonds amounting to €3.0 billion related tofor €1,635 million, of which €746 million as part of the Euro Medium Term Notes Programprogram and equity-linked bonds€889 million through an issue amounting to €0.4 billion. $1 billion in the U.S. and international markets. As of December 31, 2016,2019, Eni maintained short-term unused borrowing facilities of €12,308 million, of which €41 million committed.€13,299 million. Long-term committed unused borrowing facilities amounted to €6,236€4,667 million, of which €700€450 million were due within 12 months. These facilities bore interest rates and fees for unused facilities that reflected prevailing market conditions.
Finance debt repayments including expectedExpected payments for interest chargesfinance debts and derivativeslease liabilities
The tabletables below summarizessummarize the Group main contractual obligations for finance debt and lease liability repayments, including expected payments for interest charges and derivatives. | | | Maturity year | | (€ million) | | | 2016 | | | 2017 | | | 2018 | | | 2019 | | | 2020 | | | 2021 and thereafter | | | Total | | December 31, 2015 | | | | | | | | | Non-current financial liabilities | | | | | 2,336 | | | | | | 3,013 | | | | | | 2,038 | | | | | | 3,827 | | | | | | 2,599 | | | | | | 8,001 | | | | | | 21,814 | | | Current financial liabilities | | | | | 5,720 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5,720 | | | Fair value of derivative instruments | | | | | 4,261 | | | | | | 56 | | | | | | 1 | | | | | | 33 | | | | | | | | | | | | 8 | | | | | | 4,359 | | | | | | | | 12,317 | | | | | | 3,069 | | | | | | 2,039 | | | | | | 3,860 | | | | | | 2,599 | | | | | | 8,009 | | | | | | 31,893 | | | Interest on finance debt | | | | | 737 | | | | | | 654 | | | | | | 525 | | | | | | 453 | | | | | | 354 | | | | | | 1,673 | | | | | | 4,396 | | | Financial guarantees | | | | | 169 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 169 | | | |
| | | Maturity year | | (€ million) | | | 2017 | | | 2018 | | | 2019 | | | 2020 | | | 2021 | | | 2022 and thereafter | | | Total | | December 31, 2016 | | | | | | | | | Non-current financial liabilities | | | | | 2,988 | | | | | | 2,090 | | | | | | 4,044 | | | | | | 2,914 | | | | | | 1,285 | | | | | | 10,332 | | | | | | 23,653 | | | Current financial liabilities | | | | | 3,396 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3,396 | | | Fair value of derivative instruments | | | | | 2,108 | | | | | | 36 | | | | | | 76 | | | | | | | | | | | | 46 | | | | | | 3 | | | | | | 2,269 | | | | | | | | 8,492 | | | | | | 2,126 | | | | | | 4,120 | | | | | | 2,914 | | | | | | 1,331 | | | | | | 10,335 | | | | | | 29,318 | | | Interest on finance debt | | | | | 696 | | | | | | 557 | | | | | | 486 | | | | | | 386 | | | | | | 277 | | | | | | 1,605 | | | | | | 4,007 | | | Financial guarantees | | | | | 84 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 84 | | | |
| | | Maturity year | | (€ million) | | | 2020 | | | 2021 | | | 2022 | | | 2023 | | | 2024 | | | 2025 and thereafter | | | Total | | December 31, 2019 | | | | | | | | | Non-current financial liabilities (including the current portion) | | | | | 2,908 | | | | | | 1,704 | | | | | | 1,259 | | | | | | 2,743 | | | | | | 1,785 | | | | | | 11,521 | | | | | | 21,920 | | | Current financial liabilities | | | | | 2,452 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,452 | | | Lease liabilities | | | | | 884 | | | | | | 632 | | | | | | 487 | | | | | | 434 | | | | | | 424 | | | | | | 2,761 | | | | | | 5,622 | | | Fair value of derivative instruments | | | | | 2,704 | | | | | | 2 | | | | | | 14 | | | | | | | | | | | | | | | | | | 34 | | | | | | 2,754 | | | | | | | | 8,948 | | | | | | 2,338 | | | | | | 1,760 | | | | | | 3,177 | | | | | | 2,209 | | | | | | 14,316 | | | | | | 32,748 | | | Interest on finance debt | | | | | 594 | | | | | | 452 | | | | | | 353 | | | | | | 342 | | | | | | 269 | | | | | | 1,667 | | | | | | 3,677 | | | Interest on lease liabilities | | | | | 341 | | | | | | 302 | | | | | | 263 | | | | | | 233 | | | | | | 206 | | | | | | 1,015 | | | | | | 2,360 | | | | | | | | 935 | | | | | | 754 | | | | | | 616 | | | | | | 575 | | | | | | 475 | | | | | | 2,682 | | | | | | 6,037 | | | Financial guarantees | | | | | 926 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 926 | | | |
| | | Maturity year | | (€ million) | | | 2019 | | | 2020 | | | 2021 | | | 2022 | | | 2023 | | | 2024 and thereafter | | | Total | | December 31, 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Non-current financial liabilities (including the current portion) | | | | | 3,301 | | | | | | 2,958 | | | | | | 1,541 | | | | | | 1,253 | | | | | | 2,714 | | | | | | 11,723 | | | | | | 23,490 | | | Current financial liabilities | | | | | 2,182 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2,182 | | | Fair value of derivative instruments | | | | | 1,445 | | | | | | 13 | | | | | | 1 | | | | | | 21 | | | | | | | | | | | | 5 | | | | | | 1,485 | | | | | | | | 6,928 | | | | | | 2,971 | | | | | | 1,542 | | | | | | 1,274 | | | | | | 2,714 | | | | | | 11,728 | | | | | | 27,157 | | | Interest on finance debt | | | | | 655 | | | | | | 545 | | | | | | 436 | | | | | | 330 | | | | | | 320 | | | | | | 1,677 | | | | | | 3,963 | | | Financial guarantees | | | | | 668 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 668 | | |
TradeLiabilities for leased assets including related interest for €2,953 million refer to the share pertaining to the partners of unincorporated joint operations operated by Eni which will be recovered through recharges of cash calls.
Expected payments for trade and other payables | | | Maturity year | | (€ million) | | | 2020 | | | 2021 – 2024 | | | 2025 and thereafter | | | Total | | December 31, 2019 | | | | | | Trade payables | | | | | 10,480 | | | | | | | | | | | | | | | | | | 10,480 | | | Other payables and advances | | | | | 5,065 | | | | | | 54 | | | | | | 100 | | | | | | 5,219 | | | | | | | | 15,545 | | | | | | 54 | | | | | | 100 | | | | | | 15,699 | | | |
| | | Maturity year | | (€ million) | | | 2019 | | | 2020 – 2023 | | | 2024 and thereafter | | | Total | | December 31, 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | Trade payables | | | | | 11,645 | | | | | | | | | | | | | | | | | | 11,645 | | | Other payables and advances | | | | | 5,102 | | | | | | 59 | | | | | | 96 | | | | | | 5,257 | | | | | | | | 16,747 | | | | | | 59 | | | | | | 96 | | | | | | 16,902 | | | |
The table below summarizes the GroupF-87
Expected payments under contractual obligations36 In addition to lease, financial, trade and other payables by maturity. | | | Maturity year | | (€ million) | | | 2016 | | | 2017-2020 | | | 2021 and thereafter | | | Total | | December 31, 2015 | | | | | | Trade payables | | | | | 9,605 | | | | | | | | | | | | | | | | | | 9,605 | | | Other payables and advances | | | | | 5,337 | | | | | | 58 | | | | | | 23 | | | | | | 5,418 | | | | | | | | 14,942 | | | | | | 58 | | | | | | 23 | | | | | | 15,023 | | | |
| | | Maturity year | | (€ million) | | | 2017 | | | 2018-2021 | | | 2022 and thereafter | | | Total | | December 31, 2016 | | | | | | Trade payables | | | | | 11,038 | | | | | | | | | | | | | | | | | | 11,038 | | | Other payables and advances | | | | | 5,665 | | | | | | 29 | | | | | | 22 | | | | | | 5,716 | | | | | | | | 16,703 | | | | | | 29 | | | | | | 22 | | | | | | 16,754 | | | |
Expected payments by period underliabilities represented in the balance sheet, the company is subject to non-cancellable contractual obligations
The Group has or obligations, the cancellation of which requires the payment of a penalty. These obligations will require cash settlements in place a numberfuture reporting periods. These liabilities are valued based on the net cost for the company to fulfill the contract, which consists of the lowest amount between the costs for the fulfillment of the contractual obligations arisingobligation and the contractual compensation/penalty in the normal courseevent of the business. To meet these commitments, the Group will have to make payments to third parties. non-performance.
The Company’s main contractual obligations pertain toat the balance sheet date comprise take-or-pay clauses contained in the Company’s gas supply contracts or shipping arrangements, whereby the Company obligations consist of off-taking minimum quantities of product or service or, in case of failure, paying the corresponding cash amount that entitles the Company the right to collect the product or the service in future years. Future obligations in connection with these contracts were calculated by applying the forecasted prices of energy or services included in the four-year business plan approved by the Company’s Board of Directors.
The table below summarizes the Group principal contractual obligations as of the balance sheet date, shown on an undiscounted basis. | | Maturity year | | | Maturity year | | (€ million) | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 and thereafter | | Total | | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 and thereafter | | Total | | Operating lease obligations(a) | | | | 593 | | | | | 353 | | | | | 257 | | | | | 231 | | | | | 199 | | | | | 785 | | | | | 2,418 | | | | Decommissioning liabilities(b) | | | | 253 | | | | | 580 | | | | | 417 | | | | | 400 | | | | | 184 | | | | | 14,447 | | | | | 16,281 | | | | Decommissioning liabilities(a) | | | | | 331 | | | | | 325 | | | | | 163 | | | | | 179 | | | | | 424 | | | | | 12,052 | | | | | 13,474 | | | Environmental liabilities | | | | 281 | | | | | 249 | | | | | 255 | | | | | 202 | | | | | 71 | | | | | 1,631 | | | | | 2,689 | | | | | | 403 | | | | | 368 | | | | | 319 | | | | | 238 | | | | | 198 | | | | | 1,065 | | | | | 2,591 | | | Purchase obligations(c) | | | | 10,891 | | | | | 9,265 | | | | | 9,511 | | | | | 8,839 | | | | | 7,961 | | | | | 73,758 | | | | | 120,225 | | | | Purchase obligations(b) | | | | | 9,938 | | | | | 9,912 | | | | | 9,467 | | | | | 9,530 | | | | | 9,722 | | | | | 77,914 | | | | | 126,483 | | | - Gas | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - take-or-pay contracts | | | | 8,429 | | | | | 7,912 | | | | | 8,277 | | | | | 7,916 | | | | | 7,312 | | | | | 70,851 | | | | | 110,697 | | | | | | 7,117 | | | | | 9,140 | | | | | 8,912 | | | | | 9,100 | | | | | 9,410 | | | | | 77,239 | | | | | 120,918 | | | - ship-or-pay contracts | | | | 1,569 | | | | | 1,053 | | | | | 943 | | | | | 724 | | | | | 478 | | | | | 1,853 | | | | | 6,620 | | | | | | 1,070 | | | | | 532 | | | | | 454 | | | | | 412 | | | | | 296 | | | | | 646 | | | | | 3,410 | | | - Other take-or-pay or ship-or-pay obligations | | | | 114 | | | | | 105 | | | | | 101 | | | | | 96 | | | | | 80 | | | | | 228 | | | | | 724 | | | | - Other purchase obligations(d) | | | | 779 | | | | | 195 | | | | | 190 | | | | | 103 | | | | | 91 | | | | | 826 | | | | | 2,184 | | | | - Other purchase obligations | | | | | 1,751 | | | | | 240 | | | | | 101 | | | | | 18 | | | | | 16 | | | | | 29 | | | | | 2,155 | | | Other obligations | | | | 9 | | | | | 3 | | | | | 2 | | | | | 2 | | | | | 2 | | | | | 111 | | | | | 129 | | | | | | 7 | | | | | 1 | | | | | | | | | | | | | | | | | | | | 106 | | | | | 114 | | | - Memorandum of intent relating Val d’Agri | | | | 9 | | | | | 3 | | | | | 2 | | | | | 2 | | | | | 2 | | | | | 111 | | | | | 129 | | | | | | | | 12,027 | | | | | 10,450 | | | | | 10,442 | | | | | 9,674 | | | | | 8,417 | | | | | 90,732 | | | | | 141,742 | | | | | | - Memorandum of intent – Val d’Agri | | | | | 7 | | | | | 1 | | | | | | | | | | | | | | | | | | | | 106 | | | | | 114 | | | Total | | | | | 10,679 | | | | | 10,606 | | | | | 9,949 | | | | | 9,947 | | | | | 10,344 | | | | | 91,137 | | | | | 142,662 | | |
(a)
Operating leases primarily regarded assets for drilling and production activities, time charter and long term rentals of vessels, lands, service stations and office buildings. Such leases generally did not include renewal options. There are no significant restrictions provided by these operating leases which limit the ability of the Company to pay dividend, use assets or to take on new borrowings.
(b)
Represents the estimated future costs for the decommissioning of oil and natural gas production facilities at the end of the producing lives of fields, well-plugging, abandonment and site restoration. (c)(b)
Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. (d)
Mainly refers to arrangements to purchase capacity entitlements at certain regasification facilities in the U.S. (€1,226 million).
Capital investment and capital expenditure commitments In the next four years, Eni expects capital investments and capital expenditures of €31.6€31.5 billion. The table below summarizes Eni’s capital expenditure commitments for property, plant and equipment and capital projects. Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. At this stage, procurement contracts to execute those projects have already been awarded or are being awarded to third parties. | | | Maturity year | | (€ million) | | | 2017 | | | 2018 | | | 2019 | | | 2020 | | | 2021 and thereafter | | | Total | | Committed projects | | | | | 6,733 | | | | | | 6,679 | | | | | | 4,218 | | | | | | 2,441 | | | | | | 3,685 | | | | | | 23,756 | | | |
The amounts shown in the table below include committed expenditures to execute certain environmental projects. | | | Maturity year | | (€ million) | | | 2020 | | | 2021 | | | 2022 | | | 2023 | | | 2024 and thereafter | | | Total | | Committed projects | | | | | 5,570 | | | | | | 4,054 | | | | | | 2,611 | | | | | | 1,544 | | | | | | 2,669 | | | | | | 16,448 | | |
36
Contractual obligations related to employee benefits are indicated in note 21 — Provisions for employee benefits.
Other information about financial instruments The carrying amount of financial instruments and the relevant economic and equity effect as of and for the years ended December 31, 2015 and 2016 consisted of the following: | | | 2015 | | 2016 | | | 2019 | | 2018 | | (€ million) | | Carrying amount | | | Finance income (expense) recognized in | | | Carrying amount | | | Finance income (expense) recognized in | | | Carrying amount | | | Finance income (expense) recognized in | | | Carrying amount | | | Finance income (expense) recognized in | | | Profit and loss account | | Other comprehensive income | | Profit and loss account | | Other comprehensive income | | | Profit and loss account | | Other comprehensive income | | Profit and loss account | | Other comprehensive income | | Held-for-trading financial instruments | | | | Securities(a) | | | | 5,028 | | | | | 3 | | | | | | | | | | 6,166 | | | | | (21) | | | | | Financial instruments at fair value with effects recognized in profit and loss acount | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Financial assets held for trading(a) | | | | | 6,760 | | | | | 127 | | | | | | | | | | 6,552 | | | | | 32 | | | | | | | | Non-hedging and trading derivatives(b) | | | | (921) | | | | | (327) | | | | | | | | | | 87 | | | | | (465) | | | | | | | (125) | | | | | 273 | | | | | | | | | | 177 | | | | | (178) | | | | | | | | Held-to-maturity financial instruments | | | | Securities(a) | | | | 77 | | | | | 1 | | | | | | | | | | 75 | | | | | Available-for-sale financial instruments | | | | Securities(a) | | | | 282 | | | | | 8 | | | | | (4) | | | | | 238 | | | | | 9 | | | | | (4) | | | | Investments valued at fair value | | | | | | | | | Non-current investments(c) | | | | 368 | | | | | 286 | | | | | Other investments valued at fair value(c) | | | | | 929 | | | | | 247 | | | | | (3) | | | | | 919 | | | | | 231 | | | | | 15 | | | Receivables and payables and other assets/liabilities valued at amortized cost | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Trade receivables and other(d) | | | | 19,946 | | | | | (716) | | | | | | | | | | 17,324 | | | | | (1,116) | | | | | | | 12,926 | | | | | (409) | | | | | | | | | | 14,145 | | | | | (343) | | | | | | | | Financing receivables(a) | | | | 3,256 | | | | | (118) | | | | | | | | | | 2,328 | | | | | 128 | | | | | Trade payables and other(e) | | | | 15,023 | | | | | 83 | | | | | | | | | | 16,754 | | | | | 287 | | | | | Financing payables(a) | | | | 27,793 | | | | | (812) | | | | | | | | | | 27,239 | | | | | (291) | | | | | Net assets (liabilities) for hedging derivatives(f) | | | | | | | | | (179) | | | | | (256) | | | | | | | | | | (524) | | | | | 883 | | | | | | Financing receivables(e) | | | | | 1,503 | | | | | 110 | | | | | | | | | | 1,489 | | | | | (139) | | | | | | | | Securities(a) | | | | | 55 | | | | | | | | | | | | | | | 64 | | | | | | | | | | | | | Trade payables and other(a) | | | | | 15,699 | | | | | 33 | | | | | | | | | | 16,902 | | | | | (28) | | | | | | | | Financing payables(f) | | | | | 24,518 | | | | | (802) | | | | | | | | | | 25,865 | | | | | (615) | | | | | | | | Net assets (liabilities) for hedging derivatives (g) | | | | | (2) | | | | | (739) | | | | | (679) | | | | | | | | | | 642 | | | | | (243) | | |
(a)
Income or expense were recognized in the profit and loss account within “Finance income (expense)”. (b)
In the profit and loss account, economic effects were recognized as income within “Other operating income (loss)” for €17€287 million (loss(income for €487€129 million in 2015)2018) and as loss within “Finance income (expense)” for €482€14 million (income(loss for €160€307 million in 2015)2018). (c)
InIncome or expense were recognized in the profit and loss account economic effects were recognized as income within “Income (expense) from investments”investments — Dividends”.
(d)
InIncome or expense were recognized in the profit and loss account economic effects were essentially recognized as expensenet impairment losses within “Purchase, services“Net (impairment losses) reversal of trade and other”other receivables” for €840€432 million (expense(net impairment losses for €641€415 million in 2015) (impairments net of reversal)2018) and as expense for €276 millionincome within “Finance income (expense)” (expense for €75€23 million (income for €69 million in 2015) (exchange2018), including interest income calculated on the basis of the effective interest rate differences at year-end and amortized cost)of €26 million (interest income for €38 million in 2018).
(e)
In the profit and loss account, exchange differences arising from accounts denominated in foreign currency and translated into euro at year-endincome or expense were primarily recognized as income within “Finance income (expense)”, including interest income calculated on the basis of the effective interest rate of €99 million (income for €129 million in 2018) and net revaluations for €4 million (net impairment losses for €275 million in 2018). (f)
In the profit and loss account, income or expense were recognized as expense within “Net sales“Finance income (expense)”, including interest expense calculated on the basis of the effective interest rate of €647 million (interest expense for €605 million in 2018). �� (g)
In the profit and loss account, income or expense were recognized within “Sales from operations” and “Purchase, services and other” as expense for €523 million (expense for €181 million in 2015) and as expense within “Finance income (expense)” for €1 million (income for €2 million in 2015) (time value component). Disclosures about the offsetting of financial instruments The table below summarizes the disclosures about the offsetting of financial instruments.
(€ million) | | Gross amount of financial assets and liabilities | | Gross amount of financial assets and liabilities subject to offsetting | | Net amount of financial assets and liabilities | | | Gross amount of financial assets and liabilities | | Gross amount of financial assets and liabilities subject to offsetting | | Net amount of financial assets and liabilities | | December 31, 2015 | | | | December 31, 2019 | | | | | | | | | | | | | | | | | | Financial assets | | | | | | | | | | | | | | | | | | | Trade and other receivables | | | | 22,351 | | | | | 711 | | | | | 21,640 | | | | | | 13,773 | | | | | 900 | | | | | 12,873 | | | Other current assets | | | | 6,052 | | | | | 2,410 | | | | | 3,642 | | | | | | 4,584 | | | | | 612 | | | | | 3,972 | | | Financial liabilities | | | | | | | | | | | | | | | | | | | Trade and other liabilities | | | | 15,653 | | | | | 711 | | | | | 14,942 | | | | | | 16,445 | | | | | 900 | | | | | 15,545 | | | Other current liabilities | | | | 7,122 | | | | | 2,410 | | | | | 4,712 | | | | | | 7,758 | | | | | 612 | | | | | 7,146 | | | December 31, 2016 | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | Financial assets | | | | | | | | | | | | | | | | | | | Trade and other receivables | | | | 18,489 | | | | | 896 | | | | | 17,593 | | | | | | 15,634 | | | | | 1,533 | | | | | 14,101 | | | Other current assets | | | | 3,872 | | | | | 1,281 | | | | | 2,591 | | | | | | 4,455 | | | | | 1,636 | | | | | 2,819 | | | Financial liabilities | | | | | | | | | | | | | | | | | | | Trade and other liabilities | | | | 17,599 | | | | | 896 | | | | | 16,703 | | | | | | 18,280 | | | | | 1,533 | | | | | 16,747 | | | Other current liabilities | | | | 3,880 | | | | | 1,281 | | | | | 2,599 | | | | | | 7,048 | | | | | 1,636 | | | | | 5,412 | | | |
The offsetting of financial assets and liabilities related to: (i) for €1,281 million (€2,410 million at December 31, 2015)to the offsetting assets and liabilities for current financial derivatives pertaining to Eni Trading & Shipping SpA for €1,145 million (€2,389 million at December 31, 2015) and Eni Trading & Shipping Inc for €136 million (€21 million at December 31, 2015); and (ii) for €896 million (€711 million at December 31, 2015) the offsetting ofof: (i) receivables and payables pertaining to the Exploration & Production segment towards state entities for €845€713 million (€6641,347 million at December 31, 2015)2018) and the offsetting of trade receivables and trade payables pertaining to Eni Trading & Shipping Inc for €51€187 million (€47186 million at December 31, 2015)2018); and (ii) other assets and liabilities for current financial derivatives of €612 million (€1,636 million at December 31, 2018). Legal Proceedings Eni is a party in a number of civil actions and administrative arbitral and other judicial proceedings arising in the ordinary course of business. Based on information available to date, and taking into account the existing risk provisions disclosed in note 3020 — Provisions for contingencies and that in some instances it is not possible to make a reliable estimate of contingency losses, Eni believes that the foregoing will likely not have a material adverse effect on the Group Consolidated Financial Statements. AIn addition to proceedings arising in the ordinary course of business referred to above, Eni is party to other proceedings, and a description of the most significant proceedings currently pending is provided in the following paragraph.paragraphs. Unless otherwise indicated, no provisions have been made for these legal proceedings as Eni believes that negative outcomes are not probable or because the amount of the provision cannot be estimated reliably.
1. Environment, health and safety 1.1 Criminal proceedings in the matters of environment, health and safety (i) Eni Rewind SpA (former Syndial SpASpA) (company incorporating EniChem Agricoltura SpA -— Agricoltura SpA in liquidation -— EniChem Augusta Industriale Srl -— Fosfotec Srl) — Proceeding about the industrial site of Crotone. A In 2010 a criminal proceeding is pendingstarted before the Public Prosecutor of Crotone relating to allegations of environmental disaster, poisoning of substances used in the food chain and omitted clean-up due to the activity at a landfill site which was taken over by Eni in 1991. Subsequently to Eni’s subsidiary in 1991 following the divestment of an industrial complex by Montedison (now Edison SpA). The landfill site had been filled with industrialtakeover, any activity for waste from Montedison activities until 1989 and then no additional wasteconferral was discharged there. Eni’s subsidiary carried out the clean-up of the landfill in 1999 through 2000.stopped. The defendants are certain managers at Eni’s subsidiariesof Eni Group companies, that have owned and managed the landfill since 1991. Independent consultants performed an assessment duringThe Municipality of Crotone is acting as plaintiff. In March 2019, the 2014. Oncepublic prosecutor requested the consultants completed their work, the acts returned toacquittal of all defendants. The proceeding is ongoing. In April 2017, the Public Prosecutor of Crotone started another criminal proceeding concerning the clean-up of the area called “Farina Trappeto”. The Company presented a new clean-up program already deemed approvable by the Ministry for the next step and possible indictment.Environment. Clean-up remediation activities have started. The proceeding continues withCompany has requested the examinationdismissal of the dismissal request submitted by the defense. The City of Crotone will act as offended party.second proceeding. (ii) Eni Rewind SpA (former Syndial SpA) and Versalis SpA — Industrial sitePorto Torres — Prosecuting body: Public Prosecutor of Praia a Mare.Sassari. Based on complaints filed by certain offended persons,In 2011, the Public Prosecutor of Paola started an enquiry about alleged diseases related to tumors that those persons contracted on the workplace. Those persons were employees at an industrial complex owned by a Group subsidiary many years ago. Based on the findings of independent appraisal reports, in the course of 2009 the Public Prosecutor resolvedSassari (Sardinia) determined that a numbermanager responsible for plant operations at the site of ex-manager of that industrial complex would stand trial. In the preliminary hearing held in November 2010, 189 persons entered the trial as plaintiff; while 107 persons were declared as having been offended by the alleged crime. The plaintiffs have requested that both Eni and Marzotto SpA would bear civil liability. However, compensation for damages suffered by the offended persons has yet to be determined. Upon conclusion of the preliminary hearing, the Public Prosecutor resolved that all defendants wouldPorto Torres should stand trial for culpable manslaughter, culpable injuries,alleged environmental disaster and poisoning of water and substances destined for food. The Province of Sassari, the Municipality of Porto Torres and other entities have been involved in the proceedings as civil parties seeking damages. In 2013, the Prosecutor of Sassari requested a new indictment for negligent conduct about safety measures onbehavior, replacing the workplace. Followingprevious allegation of willful conduct. The Third Instance Court has denied a settlement agreement with Eni, Marzotto SpA entered settlement agreements with all plaintiffs, except formotion to terminate the local administrations. In December 2014, the Tribunal issued an acquittal sentence for all defendants, as the indictment was found groundless.proceedings. The Public Prosecutor appealed againsthas re-submitted request that the sentence.defendants stand trial. The proceeding is underway. (iii) Eni Rewind SpA (former Syndial SpASpA) and Versalis SpA — Porto Torres dock. In July 2012, the Judge for the Preliminary Hearing, following a request of the Public Prosecutor of Sassari, requested the performancean Italian court ordered presentation of a probationary evidence relating to the functioning of the hydraulic barrier of Porto Torres site (ran by
Syndial Eni Rewind SpA) and its capacity to avoid the dispersion of contamination released by the site ininto the near portion ofnearby sea. SyndialEni Rewind SpA and Versalis SpA have beenwere notified that its chief executive officers and certain other managers arewere being investigated. The Public Prosecutor of the Municipality of Sassari requested that the above-mentionedthese individuals would stand trial. The Judgeplaintiffs, the Ministry for preliminary investigation authorized that the two Eni’s subsidiaries would be arraigned to compensate any possible damage in connection with the proceeding. The trial was held with an abbreviated procedure. The plaintiffs Ministry of Environment and the Sardinia Region claimed environmental damage in an amount of €1 billion and €500 million, respectively. On€1.5 billion. Other parties referred to the judge’s equitable assessment. At a hearing datedin July 22, 2016, the Judge pronounced an acquittal sentence for Syndialcourt acquitted all defendants of Eni Rewind and Versalis. CertainVersalis with respect to the crimes of Eni’s employeesenvironmental disaster. Three Eni Rewind managers were found guilty: the environmental managerguilty of the area, the environmental manager of Porto Torres site and the manager in charge of the Syndial’s groundwater treatment plant, who were all condemned to one year, with a suspended sentence, for environmental disaster which took place in the area inrelating to the period limited to August 2010 – January 2011. The provisional settlement awards compensation payment of €200,0002011 and sentenced to the Ministry, €100,000 to the Sardinia Region and €100,000 to the Municipality of Sassari. The Judge did not mention any possible malfunctioning of the hydraulic barrier of Porto Torres site or ineffective implementation of any emergency safety measure, as claimed by the Public Prosecutor. Syndial will fileone-year prison, with a suspended sentence. Eni Rewind filed an appeal against this decision. The proceeding is underway.
(iv) Eni Rewind SpA (former Syndial SpA -SpA) — The illegal landfill in Minciaredda area, Porto Torres site. On July 7, 2015, the Judge for the Preliminary Hearing of theThe Court of Sassari, on request of the Public Prosecutor, decided the seizure ofseized the Minciaredda landfill area, near the western border of the Porto Torres site.site (Minciaredda area). All the indicted have been served a notice of investigation for alleged crimes of carrying out illegal waste disposal and environmental disaster. The seizure provisionorder involved as well Syndial in accordance with thealso Eni Rewind pursuant to Legislative DegreeDecree No. 231 of 2001 that held231/01, whereby companies are liable for the crimes committed by their employees.employees when performing their duties. The investigations are underway. With a reference tocourt determined that Eni Rewind can be sued for civil liability and resolved that all defendants and the clean-up activities inEni subsidiary be put on trial before the Minciaredda area, on January 27, 2016 the administrative body responsible for sanctioning clean-up projects approved: i) the operative project “Nuraghe” which provides for the soil clean-up in the area “Peci” (depositCourt of pitch from dimethyl terephthalate – DMT) and in the area “Palte Fosfatiche” (phosphates deposit) in the Minciaredda area; and ii) an addendum to the operative project of clean-up of the groundwater in the Minciaredda area. Syndial obtained the necessary ministerial and judicial authorizations to start the remediation project. The investigations are underway.Sassari. (v) Eni Rewind SpA (former Syndial SpA -SpA) — The Phosphate deposit at Porto Torres site (1). On June 30,In 2015, the Judge for the Preliminary Hearing of the Court of Sassari, accepting a request of the Public Prosecutor of Sassari, sentenced to seizeseized — as a preventive measure — the area of “Palte Fosfatiche” (phosphates deposit) located on the territory of Porto Torres site, in relation to alleged crimes of environmental disaster, and carrying out anof unauthorized disposal of hazardous wastes. Subsequentlywastes and other environmental crimes. Eni Rewind SpA is being investigated pursuant to Legislative Decree No. 231/01. In November 2019, a specific request bothfor referral to trial was served on the Public security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari authorized to implement better delimitation of the landfill area, to provide the area with devices to monitor the level of environmental pollutants and meteoric waters. The investigations are underway.Eni subsidiary. (vi) Eni Rewind SpA (former Syndial SpA -SpA) — Phosphate deposit at Porto Torres site (2). On December 16,In 2015, the Public Prosecutor at the Court of Sassari sentenced to seizeseized — as a probative measure — the containment systems for the meteoric waters in the area “Palte Fosfatiche” (phosphates deposit). These waters are being collected by Syndial following authorizations, located on the territory of the Public security officer of Sassari and the Judge for the Preliminary Hearing of the Court of Sassari.Porto Torres site. The indicted have also been served a notice of investigation for alleged crimes of omitted clean-up and management of radioactive waste and spill of waters containing hazardous substances. The Public Prosecutor decided to suspendwaste. This investigation has been combined into the activities of collection, containment and preservation of the area, in spite that those activities have already been authorized. Syndial filed a request to continue conducting clean-up operations to the Judge for the Preliminary Hearing of the Court of Sassari. The investigations are underway.abovementioned one. (vii) Eni Rewind SpA (former Syndial SpA - Public Prosecutor of Gela. An investigation is pending before the Public Prosecutor of Gela regarding 17 former managers of the Eni Group. The proceeding regards alleged crimes of culpable manslaughter and grievous bodily harm related to the death of 12 former employees and alleged work-related diseases that those persons may have contracted at the plant of Clorosoda. Alleged crimes relate to the period from 1969, when the Clorosoda plant commenced operations till 1998 when the plant was shut down and clean-up activities were performed. The Public Prosecutor requested the performance of a medico-legal appraisal on over 100 people that were employed at the above-mentioned plant. This appraisal was performed by independent consultants designated by the Judge for preliminary investigation
and did not find any evidence that the various diseases which underwent the medical appraisal could be directly linked to the exposure to emissions related to the production of chlorine and caustic soda. The consultants also found that production activities were in compliance with applicable laws and regulations on health and safety. On January 23, 2015, the Judge for preliminary investigation declared that the gathering of evidence before a trial was concluded. The Public Prosecutor issued a notice of the conclusion of preliminary investigations deciding not to ask for dismiss of charges only in relation to the one specific case, which regards one former employee which in the meantime had died, compared to the initial complaint that concerned several (over a hundred) cases of personal injury and manslaughter. Therefore, the proceeding has been downsized compared to the initial claim. The rest of the accusatory assumptions, however, seems to be groundless in the light of the results of assessment performed by independent consultants appointed by the Judge for the preliminary investigation. The criminal proceeding is still pending.
(viii) Seizure of areas located in the Municipalities of Cassano allo Jonio and Cerchiara di CalabriaSpA) — Prosecuting body: Public Prosecutor of Castrovillari. Certain areas owned by Eni in the Municipalities of Cassano allo Jonio and Cerchiara di Calabria have been preventively seized by the Judicial Authority, following a pending investigation about an alleged improper handling of industrial waste from the processing of zinc ferrites at the industrial site of Pertusola Sud, alleged illegally stored. The circumstances under investigation are the same considered in a criminal action for alleged omitted clean-up that was concluded in 2008 without any negative outcome on part of Eni’s employees. Eni’s subsidiary Syndial SpA has removed any waste materials from the landfills. Besides that, Syndial defined an agreement with the Municipality of Cerchiara and the Municipality of Cassano to settle all claimsProceeding relating to alleged damages caused by the unauthorized waste disposal in the landfills on the territory of the two Municipalities. The criminal proceeding is still pending. The remediation activities have been completed and the company filed a memorandum to request the closing of the proceeding.
(ix) Syndial SpA - Proceeding on the asbestos at the Ravenna site. A criminal proceeding is pending before the Tribunal of Ravenna aboutrelating to the crimes of culpable manslaughter, injuries and environmental disaster, which would have been allegedly committed by former SyndialEni Rewind employees at the site of Ravenna. The site was taken overacquired by SyndialEni Rewind following a number of corporate mergers and acquisitions. The alleged crimes date back to 1991. In the proceeding there are 77 affected75 alleged victims. The plaintiffs include relatives of the alleged victims, various local administrations, and other institutional bodies, including local trade unions. The advocacy of Syndial claimedEni Rewind asserted the statute of limitation aboutas a defense to the instance of environmental disaster for certain instances of diseases and deaths. The Judge for the Preliminary Hearingcourt at Ravenna decided that all defendants would stand trial and ascertainedheld that the statute of limitation only applied with reference to certain instances of crime of culpable injury. Concluded the trial, the proceeding entered the hearing phase for the final discussion. Syndial has signedEni Rewind reached some settlements. OnIn November 24, 2016, the Judge liftedacquitted the reserve, acquitteddefendants in all the accusedcontested cases except for 76one, an asbestos case, for which a conviction was handed down. The defendants, the prosecutor and the plaintiffs appealed the decision. The second instance Judge ordered a complex report, and stated that they could not decide the appeal at that stage of the 77 contested casesproceedings, and sentenced 6 ofappointed three experts. The proceeding is ongoing before the 15 defendants for a single case of asbestosis.appeals Court.
(x)(viii) Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA -— Alleged environmental disaster.A criminal proceeding is pending in relation to crimes allegedly committed by the managers of the Raffineria di Gela SpA and EniMed SpA relating to environmental disaster, unauthorized waste disposal and unauthorized spill of industrial wastewater. Raffineria diThe Gela SpARefinery has been suedprosecuted for administrative offence in accordance with the Lawpursuant to Legislative Decree No. 231 of 2001.231/01. This criminal proceeding initially regarded soil pollution allegedly caused by spills from 14 tanks of the refinery storage, which had not been provided with double bottoms, in addition to theand pollution of the sea water near the coastcoastal area adjacent to the site due to the failure of the barrier system implemented as part of the clean-up activities conducted at the site. OnAt the closureclosing of the preliminary investigation, the Public Prosecutor of Gela reunited inmerged into this proceeding the other investigations related to the pollution that occurred at the other sites of the Gela refinery as well as hydrocarbon spills at facilities of EniMed. The proceeding is still pending.ongoing.
(xi) Proceeding(ix) Val d’Agri. The ItalianIn March 2016, the Public Prosecutor’s OfficeProsecutors of Potenza started a criminal investigation in order to ascertain existence of aninto alleged illegal handling of wasteswaste material produced at the Viggiano oil center (COVA), part of the Eni-operated Val d’Agri oil complex, and disposed at treatment plants in the national territory.complex. After a two-year investigation, the Prosecutors decided forordered the domiciliary detentionhouse arrest of 5 Eni employees and to put underthe seizure of certain plants functional to the production activity of the Val d’Agri complex which, as a consequences,consequently, was shut down (60 kboe/(loss of 60 KBOE/d net to Eni), to be then resumed on 10 August 2016.. From the commencement of the investigation, Eni has carried out several and in-depth
technical and environmental surveys, with the support of independent experts of international reach,standing, who recognizedfound a full compliance of the plant and the industrial process with the requirements of the applicable laws, as well as with best available
technologies and international best practices. The Company sought to obtain a repeal of the seizure before the jurisdictional authorities without an outcome. The Company studiedimplemented certain corrective measures to upgrade plants which although being not a structural solution, were intended to address the claims made by the public prosecutor about an alleged operation of blending which would have occurred during normal plant functioning. Those measures comprise building a gathering system of waters associated with the extraction of hydrocarbons at the gas lines. Those corrective measures were favourablyfavorably reviewed by the public prosecutor, who grantedPublic Prosecutor. The Company restarted the plant in August 2016. In relation to the criminal proceeding, the Public Prosecutor’s Office requested the indictment of all the defendants and the Company. The Prosecutor requested Eni a temporary repealand all the defendants be put on trial, pursuant to Legislative Decree No. 231/01. The trial started in November 2017 and is ongoing. (x) Eni SpA — Health investigation related to the COVA center. Beside the criminal proceeding for illegal trafficking of waste, the Public Prosecutor started another investigation in relation to alleged health violations. The Public Prosecutor requested the formal opening of an investigation with respect to nine people in relation to alleged violations of the seizurerules providing for the preparation of a Risk Assessment Document of the working conditions at the Val d’Agri Oil Center (COVA). In March 2017, following the request of the consultant of the Prosecutor, the Labor Inspectorate of Potenza issued a fine against the employers of the COVA for omitted and incomplete assessment of the chemical risks for the COVA center. In October 2017, the Prosecutor’s Office changed the criminal allegations to disaster, murder and negligent personal injury, also alleging breaches of health and safety regulations. The proceeding is ongoing. (xi) Proceeding Val d’Agri — Tank spill. In February 2017, the Italian police department of Potenza found a stream of water contaminated by hydrocarbon traces of unknown origin, flowing inside a small shaft located outside the COVA. Eni carried out activities at the COVA aimed at determining the origin of the contamination and identified the cause in a failure of a tank outside of the COVA, that presented a risk — currently averted — of extension of the contamination in the downstream area of the plant. In executing these activities, Eni performed all the communications provided for by Legislative Decree 152/06 and started certain emergency safe-keeping operations at the areas subject to potential contamination outside the COVA. Furthermore, the Company completed the arrangement plan for the internal and external areas of the COVA, whose final report was examined by the relevant authorities. Following this event, a criminal investigation was initiated in order to allowascertain whether there had been illegal environmental pollution by the Company performformer COVA officers, the works. The in-charge departmentOperation Managers in charge since 2011 and the HSE Manager in charge at the time of the accident, and also against Eni in relation to the same offense pursuant to Legislative Decree No. 231/01 as communicated in December 2018 following the notification of the extension of the terms for preliminary investigations and of some public officials belonging to local administrations for official misconduct, false and fraudulent public statements committed in 2014 and of the crime for environmental disaster and of culpable conduct committed in February 2017. Investigations are ongoing. The Company has paid damages of an immaterial amount to certain landlords of areas close to the COVA, which were affected by a spillover. Discussions are ongoing with other claimants. The likely disbursements relating to these transactions have been provisioned. In February 2018, Eni contested the reports presented in October and in December 2017 by the Italian MinistryFire Department stating that it does not consider itself obliged to carry out the integration required, considering that the data acquired in the area affected by the event indicate, according to Eni’s assessments, that the loss was promptly and efficiently controlled and there were no situations of Economic Development duly authorizedserious danger to human health and the worksenvironment. In April 2019, precautionary measures were ordered against three Eni employees at the COVA. In September 2019, the Public Prosecutor requested one of those employees to be put on trial with expedited proceeding, accepted by the Judge for preliminary investigations. (xii) Raffineria di Gela SpA and establishedEni Mediterranea Idrocarburi SpA — Waste management of the landfill Camastra. In June 2018, the Public Prosecutor of Palermo (Sicily) notified Eni’s subsidiaries Raffineria di Gela SpA and Eni Mediterranea Idrocarburi SpA of a strict schedulecriminal proceeding relating to executeallegations of unlawful disposal of industrial waste resulting from the reclaiming activities of soil, which were discharged at a landfill owned by a third party. The Prosecutor charged the then chief executive officers of the two subsidiaries, and the legal entities have been charged with the liability pursuant to Legislative Decree No. 231/01. The alleged wrongdoing related to the willful falsification of the waste certification for purpose of discharging at the landfill. The charge against the CEO of the Refinery of Gela SpA and of the company itself has been dismissed, while the CEO of Enimed SpA and the company were requested to be put on trial. The proceeding is ongoing. (xiii) Eni Rewind SpA (former Syndial SpA) — Environmental disaster at Ferrandina. In January 2018, the Public Prosecutor of Matera commenced a criminal proceeding against a manager of the Eni subsidiary Eni Rewind based on allegations of unlawful handling of waste and environmental disaster as part of the
reclaiming activities performed at an industrial site (Ferrandina/Pisticci in the south of Italy). The charge related to an alleged spillover of effluent in the subsoil and then in a nearby river due to a damaged pipe dedicated to the transportation of effluent to a disposal plant upgradingowned by a third party. At the preliminary hearing in October 2019, the Judge dismissed the case on the basis that the defendant did not commit any crime. (xiv) Versalis SpA — Preventive seizure at the Priolo Gargallo plant. In February 2019, the Court of Syracuse at the request of the Public Prosecutor ordered the seizure of the Priolo/Gargallo plant as part of an ongoing investigation concerning the offenses of dangerous disposal of materials and environmental pollution, by the former plant manager of Versalis, pursuant to Legislative Decree No. 231/01. The Public Prosecutor’s thesis, according to the consultants, is that the plants covered by the provision have points of emissions that do not comply with the Best Available Techniques (BAT), therefore resulting in violation of the applicable legislation. Versalis has already implemented certain plant upgrades designed to comply with measures requested by the public prosecutor. The plant modification works were completedPublic Prosecutor and his consultants. Based on July 10, 2016 and on July 20, 2016,this, an appeal was filed against the Carabinierimeasure of NOE, assisted by the Technical Consultant of the Prosecutor, conducted the inspection to verify the state of the site and the compliance of the correct execution of the plant upgrading. Following the report prepared by the Technical Consultant, as a consequence of the inspection conducted, the Prosecutor issued the decision for the definitive release fromprecautionary seizure of the plant whilebefore a review court, which revoked the Region took noteseizure of the measureplants on March 26, 2019. (xv) Eni SpA — Fatal accident Ancona offshore platform. On March 5, 2019, a fatal accident occurred at the Barbara F platform in the offshore of Ancona. During the unloading phase of a tank from the platform to a supply vessel, there was a sudden failure of a part of the structure on which a crane was installed, causing the death of an Eni employee who was inside the control cabin of the crane and injuries to two other workers. The Public Prosecutor of Ancona opened an investigation against unknown persons and ordered further technical appraisals relating to the crane. As part of the technical assessment of the incident, the Public Prosecutor resolved to put under investigation the Eni employees who were in charge of safety standards at the involved facility. Also the Company has been put under investigation pursuant to Legislative Decree No. 231/01, which holds companies liable for the partcrimes committed by employees in a number of competence. On August 10, 2016,matters, including the plant was restarted with re-injection into the well Costa Molina 2. Simultaneously with the restartviolations of laws about safety of the plant, the Company began the review procedure at AIA by presenting the documents within the deadline of 14 August 2016.workplace. The proceeding is ongoing. (xvi) Raffineria di Gela SpA and Eni Rewind SpA (former Syndial SpA) — Groundwater pollution survey and reclamation process of the Gela site. Following complaints made by former contractors, the Public Prosecutor’s Office of Gela issued an inspection and seizure of the area called Isola 32 within the refinery of Gela, where old and new monitored landfills are located. The proceeding concerns criminal allegations of environmental pollution, omitted clean-up, negligent personal injury and illegal waste management, as part of the execution of clean-up of soil and groundwater as well as decommissioning activities in the area currently managed by Eni Rewind SpA, also on behalf of the companies Raffineria di Gela SpA, ISAF SpA (in liquidation) and Versalis SpA (efficiency and efficacy of the barrier system). The Public Prosecutor acquired documents and evidence at the preliminary hearings.Syndial office in Gela and at the refinery of Gela, which, during the period January 1, 2017 – March 20, 2019, managed the facilities involved in cleaning up the groundwater area (TAF Syndial, site TAF-TAS and pumping wells and hydraulic barrier). Subsequently a decree was issued for the seizure of eleven (11) piezometers of the hydraulic barrier system with contextual guarantee notice, issued by the Public Prosecutor of Gela against nine employees of Gela Refinery and four employees of Syndial SpA. The proceedings are ongoing. (xvii) Eni Rewind SpA (former Syndial SpA) and Versalis — Mantua. Environmental crime investigation. The Public Prosecutor of Mantua has initiated a series of proceedings against companies of the Eni group and employees of Eni for alleged environmental crimes related to the Mantua industrial hub. Investigations, whose terms have been extended, are in progress. The Prosecutor of Mantua is proceeding for the crime of omitted clean-up, both according to the case foreseen by the Consolidated Environmental Text and for the hypothesis foreseen by the penal code “up to the present”. Eni companies are being investigated pursuant to Legislative Decree No. 231/01. 1.2 Civil and administrative proceedings in the matters of environment, health and safety (i) Eni Rewind SpA (former Syndial SpA -SpA) — Summon for alleged environmental damage caused by DDT pollution in the Lake Maggiore - Prosecuting body: Ministry of the Environment.Maggiore. In May 2003, the Ministry offor the Environment summoned Syndial to obtain a sentence condemning theclaimed compensation from Eni subsidiary to compensate anRewind for alleged environmental damage caused by the activity ofat the Pieve Vergonte plant in the years 1990 through 1996. With a temporarily executive sentence datedIn July 3, 2008, the District Court of Turin sentenced the subsidiary Syndial SpAordered Eni Rewind to compensatepay environmental damages amounting to €1,833.5 million, plus legal costs thatinterests accrued from the filing of the
decision. Syndial and Eni technical legal consultants have considered the decision and the amount of the compensation to be without factual and legal basis and have concluded that a negative outcome of this proceeding is unlikely. Particularly, Eni and its subsidiary deemdeemed the amount of the environmental damage to be absolutely groundless as the sentence lackslacked sufficient elements to support such a material amount of the liability charged to Eni and its subsidiary with respect tofrom the volume of pollutants ascertained by the Italian Environmental Minister. Based on these technical legal advices, which is also supported by external accounting consultants, no provisions have been made with respect to the proceeding. In July 2009, SyndialEni Rewind filed an appeal against the above-mentioned sentence, and consequently the proceeding continued before a Second Degree Court of Turin. In the hearing of June 15, 2012, before the Second DegreeInstance Court of Turin the Minister of the Environment, formalized trough the Board of State Lawyers its decision to not enforce the sentence until a final verdict on the matter is reached. The Second Degree Court requested Syndial to stand as defendant and thenthat requested a technical appraisal ofon the matter. This technical appraisal was favorable to Syndial; however, the Board of State Lawyers questioned such outcome. On July 8, 2015, the Court of Appeal of Turin requested the consultants appointed by the Court to perform again a technical appraisal of the matter with aim to identify adequate measures for environmental restoration of the external areas. On June 13, 2016, the consultants filed an integration to the technical appraisal. In brief, the consultants validated the technical review of the matter and other technical assessments which were carried out by the Company together with local and national technical entities. The consultants that undertook this appraisal concluded that: (i) no further measure for environmental restoration is required; (ii) there was no significant and measurable impact on the environment and the usability of the ecosystem, therefore no restoration or damage compensation should be claimed. Theclaimed; the only impact which could be recorded concernsseen concerned fishing activity, with an estimated damage of €7 million which cancould be already restored by means ofthrough the measures proposed by Syndial;Eni Rewind, and; (iii) the necessity and convenience of dredging should be definitely excluded, both from the legal and scientific point of view, while confirming technical and scientific correctness of the Syndial’sEni Rewind’s approach based on the monitoring of the process of natural recovery, which is estimated to require 20 years. OnIn March 6, 2017, a second-degree Court issued a sentence repealing the first-degree court verdict, which had sentenced Syndial to compensate environmental damage in excessSecond Instance Court: (i) excluded the application of compensation for monetary equivalent; (ii) annulled the monetary compensation of €1.8 billion. The second-degree Court reaffirmed that monetary compensation is no longer applicable and requested Syndialbillion requesting Eni Rewind to perform the already approved cleanupclean-up project of the polluted areas, which comprise groundwater, as well as compensatory remediation works. The
value of these compensatory works requestedrequired by the Court, in case of SyndialEni Rewind failure to perform or misperformance, is estimated at €9.5 million. The cleanupclean-up project was filed by Syndial,Eni Rewind was ratified by local and governmentalthe authorities and is currently being executed. Expenditures expected to be incurred by Syndial have been provisioned in the environmental provision. Any other claims filed by the Italian Minister for the Environment were rejected. (ii)rejected by the court (including compensation for non-material damage). In April 2018, the Ministry for the Environment filed an appeal to the Third Instance Court. In accordance with the law, the Company and its managers filed an appeal and a counter-appeal.
(ii) Eni Rewind SpA (former Syndial SpA) — Versalis SpA — Eni SpA (R&M) — Augusta harbor. The Italian Ministry for the Environment with various administrative acts required companies that were runningoperating plants in the petrochemical site of Priolo to perform safety and environmental remediation works in the Augusta harbor. Companies involved include Eni subsidiaries Versalis, Syndial and Eni Refining & Marketing Division. Pollution has been detected in this area primarily due to a high mercury concentration that is allegedly attributed to the industrial activity of the Priolo petrochemical site. The above mentionedabove-mentioned companies opposed saidcontested these administrative actions, objecting in particular to the way in whichnature of the remediation works have been designeddecided and modesthe methods whereby information on the pollutants concentration has been gathered. A number of administrative proceedings were started on this matter which were reunifiedsubsequently merged before the Regional Administrative Court of Catania.Court. In October 2012, saidthe Court ruled in favor of Eni’s subsidiaries against the Ministry prescriptions aboutMinistry’s requirements for the removal of the pollutants and the construction of a physical barrier. In September 2017, the Ministry notified all the companies involved of a formal notice for the start of remediation and environmental restoration of the Augusta harbor within 90 days. The proceedingact, contested by the co-owner companies in December 2017, constitutes a formal notice for environmental damage. The Administrative Council of the Sicilian Region ruled on the appeals pending against various decisions of the Regional Administrative Court and essentially confirmed the cancellation of all administrative provisions subject to the dispute. The annulment of the provisions had, inter alia, retroactive effect to the time of their adoption and therefore excludes the risk of claims of any possible breach of administrative provisions. In June 2019, the Italian Ministry for the Environment set up a permanent technical committee to review the matter of the clean-up and reclamation of the Augusta harbor. A report of the committee affirmed the 2017 warning of the Ministry and reaffirmed the State agencies and local administrations’ view as to the environmental liability to be charged to the companies operating in the area. In coordination with the other companies operating at the site, the report is still pending.being appealed and further technical analyses have been commenced for defensive purposes. Eni’s subsidiary proposed to the Italian Environmental Ministry to start a collaboration with other interested parties to find remediation measures based on new available environmental data collected by independent agencies. (iii) Eni SpA — Eni Rewind SpA (former Syndial SpA) — Raffineria di Gela SpA — Claim for preventive technical inquiry - Court of Gela.inquiry. In February 2012, Eni’s subsidiaries Raffineria di Gela SpA and SyndialEni Rewind SpA and the parent company Eni SpA (involved in this matter through the operations of the Refining & Marketing Division) were notified of a claim issued by 33the parents of children born malformedwith birth defects in the Municipality of Gela between 1992 and 2007. The claim called for preventive technicalan inquiry aimsaimed at verifying the relation ofdetermining any causality between the malformation pathologiesbirth defects suffered by thethese children of the plaintiffs and theany environmental pollution caused by the Gela site, (pollution deriving from the existence and activities at the industrial plants of Raffineria di Gela SpA and Syndial SpA), quantifying the alleged damages suffered and eventually identifying the terms and conditions to settle the claim. In any case, theThe same issue was the subject of previous criminal proceedings, of which one closed without ascertainment ofdetermining any illicitillegal behavior on the part of Eni or its subsidiaries, while a further criminal proceeding is still pending. The consultants appointed by the Court and those designated by the plaintiffs performed a technical appraisal of the matter, reaching however very different outcomes. Thus, parties failed to reach a settlement of the matter. OnIn December 22, 2015, the three involved Eni companies were sued following a claim of the parents of a girl, whose case was assessed by the above-mentioned technical appraisal. Subsequently, the Eni’s companiesinvolved were sued in relation to othera total
of 30 cases of compensation for damages in civil proceedings. In May 2018, the Court issued a first instance judgment concerning one case. The proceeding is pending.Judge rejected the claim for damages, acknowledging the arguments of the defendant companies in relation to the absence of evidence concerning the existence of a causal link between the birth defects and the alleged industrial pollution. The judgement has been appealed. (iv) Environmental claim relating to the Municipality of Cengio - Plaintiffs:Cengio. Since 2008 a proceeding is pending by the Court of Genoa, brought by the Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio. The Ministry for the Environment and the Delegated Commissioner for Environmental Emergency in the territory of the Municipality of Cengio Those parties summoned Eni’s subsidiary SyndialEni Rewind before a Civil Court and sentenced thedemanded Eni’s subsidiary to compensate for the environmental damage relating to the site of Cengio. The request for environmental damage amounted to €250 million to which was to be added health damage to be quantified during the proceeding. The plaintiffs accused SyndialEni Rewind of negligence in performing the clean-up and remediation of the site. On the contrary, Syndial believes they have executed the clean-up work properly and efficiently in accordance with the framework agreement signed with the involved administrations includingIn March 2019, the Ministry for the Environment presented a proposal to Syndial to settle the case. The Company responded with a counter-proposal in July 2019. The judge is verifying the progress and status of the Environment in 2000. On February 6, 2013, a Court in Genoa ruled the resumption of the proceeding and established a technical appraisal to verify the existence of the environmental damage. Following failed attempts to define a settlement agreement of the matter among the involved parties, the Judge resumed the trial. The next stop in the procedure is the performance of an independent appraisal of the matter by a consultant appointed by the Judge.negotiations. (v) Eni Rewind SpA (former Syndial SpA and Versalis SpA — Porto Torres — Prosecuting body: Public Prosecutor of Sassari. The Public Prosecutor of Sassari (Sardinia) resolved that a number of officers and senior managers of companies engaging in petrochemical operations at the site of Porto Torres, including the manager responsible for plant operations of the Company’s fully-owned subsidiary Syndial, would stand trial due to allegations of environmental damage and poisoning of water and crops. The Province of Sassari, the Municipality of Porto Torres and other entities have been acting as plaintiffs. The Judge for the Preliminary Hearing admitted as plaintiffs the above mentioned parts, but based on the exceptions issued by Syndial on the lack of connection between the action as plaintiff and the charge, denied that the claimants would act as plaintiff with regard to the serious pathologies related to the existence of poisoning agents in the marine
fauna of the industrial port of Porto Torres. The proceeding continues before the Prosecutor of Sassari. In February 2013, the Prosecutor of Sassari has notified the conclusion of preliminary investigations and requested a new imputation for negligent behaviour instead of illicit conduct. In the conclusions of the preliminary hearing, the GUP of Sassari dismissed the accusation because of the statute of limitations. The Public Prosecutor filed an appeal before a Third Instance Court. After a hearing on a question of constitutional legitimacy concerning the period for the statute of limitations for the crime of disaster, the Third Instance Court recognized its validity and therefore accepted the claim and sent all the acts to the Constitutional Court.
(vi) Syndial SpASpA) and Versalis SpA — Summon for alleged environmental damage caused by illegal waste disposal in the municipality of Melilli (Sicily). In May 2014, the Municipality of Melilli summoned Eni’s subsidiaries SyndialEni Rewind and Versalis for the environmental damage allegedly caused by carrying out illegal waste disposal activities and unauthorized landfill. In particular, the plaintiff claimed the responsibilities of Syndialalleged Eni Rewind and Versalis forwere responsible because they produced the production of waste and because they commissioned the waste disposal. The plaintiff stated that this illegal handling of waste was part of certain criminal proceedings dating back to 2001-20032001 – 2003 which would have allegedly traced the hazardous waste materials back to the Priolo and Gela industrial sites that are managed by the above mentionedabove-mentioned Eni’s subsidiaries (in particular, the waste with high mercury concentration and railway sleepers no longer in use). Such waste was allegedly handled and disposed illegally at an unauthorized landfill owned by a third party (this landfill is located about 2 kilometers from the townparty. Two subsidiaries of Melilli). The claim amountsEni and a third-party waste company were claimed to €500 million and refers to two Group’s subsidiaries and SMA.RI, the company that carries out activities of waste disposal, beingbe jointly and severally liable. On February 8, 2016,liable for damage amounting to €500 million. The third-party company executed waste disposal at the site. In June 2017, the Judge accepted an explanation of Eni’s subsidiaries stating that the request of municipality was not admissible, so that the request was rejected. The proceeding is still pending.
(vii) Summon for Eni, Raffineria di Gela SpA, EniMed SpA and Syndial SpA. 273 Gela residents filed an appeal to the Court of Gela requesting to halt all the production activities conducted by Eni’s subsidiaries at Gela site in order to put an end to environmental pollution affectingdefensive instances of Eni Rewind and Versalis, judging the healthrequests of the local population. The claimantsMunicipality to be inadmissible for lacking right to sue, also requestedconsidering the appointment of commissioners in charge of carrying out the plants shutdownrequests to be unfounded or unproved, and of continuing to implement clean-up activities in the area. Besides that, they requested the Court to order toordered the Municipality of Gela — as a competent body into refund the field of health protection — to adopt certain provisions aimed to preserve the health of the local population. This proceeding arose in connection with an alleged environmental damage caused by the industrial activities of the site and consequent necessity to protect the population from serious harm to the health. The initiative was underpinned by certain technical assessments performed by consultants appointed by the Court on the preliminary stage. The aim of these assessments was to establish cause-and-effect relationship between the industrial contamination and congenital anomalies reported in the town of Gela.
2. Court inquiries and of other Regulatory Authorities
(i) Reorganization procedure of Alitalia Linee Aeree Italiane SpA under extraordinary administration. On January 23, 2013, the Italian airline company Alitalia which was undergoing a reorganization procedure, summoned Eni, Exxon Italia and Kuwait Petroleum Italia SpA before the Court of Rome, to obtain a compensation for alleged damages caused by a presumed anti-competitive behavior on part of the three petroleum companies in the supply of jet fuel in the years 1998 through 2009. The claim was based on a deliberation filed by the Italian Antitrust Authority on June 14, 2006. The antitrust deliberation accused Eni and other five petroleum companies of anti-competitive agreements designed to split the market for jet fuel supplies and blocking the entrance of new players in the years 1998 through 2006. The antitrust findings were substantially endorsed by an administrative court. Alitalia has made a claim against the three petroleum companies jointly and severally presenting two alternative ways to assess the alleged damages. A first assessment of the overall damages amounted to €908 million. This was based on the presumption that the anti-competitive agreements among the defendants would have prevented Alitalia from autonomously purchasing supplies of jet fuel in the years when the existence of the anti-competitive agreements were ascertained by the Italian Antitrust Authority and in subsequent years until Alitalia ceased to operate airline activity. Alitalia asserts the incurrence of higher supply costs of jet fuel of €777 million excluding interest accrued and other items which add to the lower profitability caused by a reduced competitive position in the marketplace estimated at €131 million. An alternative assessment of the overall damage made by Alitalia stands at €395 million of which €334 million of higher purchase costs for jet fuel and €61
million of lower profitability due to the reduced competitive position on the marketplace. With a decision dated May 23, 2014, the Court of Rome declared the connection with a judgment previously proposed by Alitalia itself before the Court of Milan against other oil companies participating to an alleged cartel agreement. The case was thus summed up by Alitalia before the Court of Milan. The proceedings is still pending before the First Degree Court. Eni accrued a risk provision against this proceeding.
(ii) Eni’s arbitration with GasTerra. In 2013, Eni initiated an arbitration against GasTerra, as part of a long-term supply contract signed in 1986, to obtain a revision of the price charged by GasTerra to Eni for the gas supplied in the 2012-2015 period. On that occasion, Eni and GasTerra agreed to apply a provisional price, which was lower than the previous price, until the definition of a new contractual price based on an arrangement between parties or an arbitration award. An arbitration award of June 23, 2016 dismissed Eni’s claim for price revision, without however determining a new price applicable in the relevant period. GasTerra considers that, by dismissing Eni’s claim, the award restored the original contract price, based on which GasTerra now claims an additional amount to be paid by Eni which corresponds to the difference between the provisional price and the contractual price. Eni, relying also on the opinion of its external consultants, does not agree with GasTerra’s interpretation and regards GasTerra claim groundless. However, GasTerra, based on its own interpretation, commenced arbitration proceedings and obtained from a Dutch court the provisional seizure of Eni’s investment in its subsidiary Eni International BV, for the alleged trade receivable due by Eni (equal to €1.01 billion). This measure, which was granted after a summary review only and without Eni being heard, does not prejudice the outcome on the meritsexpenses of the proceeding. In order to obtainApril 2018, the dischargeFirst Instance Judge rejected the counterclaim filed by the Municipality. An appeal by the Municipality before a Third Instance Court is pending.
(vi) Val D’Agri — Eni / Vibac. In September 2019 a claim was brought in the Court of Potenza against Eni. The plaintiffs are eighty people, living in different municipalities of the seizureVal d’Agri area, who are complaining of economic, non-economic, biological and moral damages, all deriving from the presence of Eni’s investmentoil facilities in the territory. In particular, the claim refers to certain events which allegedly caused damage to the local community and the territory (such as a 2017 spill, flaring events since 2014, smelly and noisy emissions). The Judge has been asked to ascertain Eni’s responsibility for causing emissions of polluting substances into the atmosphere. The plaintiffs have also requested Eni International BV, Eni proposedbe ordered to GasTerrainterrupt any polluting activity and to replacebe allowed to resume industrial activities on condition that all the seizure with a bank guaranteenecessary remediation measures be implemented to eliminate all of the same amount asalleged dangerous situations. Finally, they are asking that Eni compensate all direct and indirect property damages, current and future, to an extent to be quantified during the GasTerra claim, which would remain effective untilproceedings. (vii) Eni Spa — Climate change. In 2017 and 2018, local government authorities and a fishing association brought in the arbitration final award. GasTerra accepted Eni’s offer. With the filingcourts of the StetementState of DefenseCalifornia seven proceedings against Eni Group companies and Counterclaim, Eni willother oil companies. These proceedings claim compensation for the damages attributable to the increase in sea level and temperature, as well as to the hydrogeological instability. The cases have been transferred, by request that the arbitration panel states the provisional price established in the Agreement Letter continues being applied until a new contractual price is defined with retroactive efficacy from 2012, based on trends recorded in the Italian market. Currently it not possible to estimate a time schedule of the arbitration procedure becausedefendants, from the panelState Courts to the Federal Courts. A specific request has yet to be appointed. Presumably, a decision aboutbeen filed, highlighting the first award interpretation or about the interpretationlack of jurisdiction of the Agreement Letter will not occur before the end of 2017 or the beginning of 2018. Eni will further seek compensationState Courts. The proceedings are currently suspended and waiting for any damages it incurs, due to GasTerra’s legal actions. At the present, there are no evidence to suggest that an upward revision of the provisional price is likely. Furthermore, Eni is part to another arbitration proceeding relating to the price revision of a long-term gas supply contract.jurisdictional competence. 3. Court inquiries on the matter of2. Proceedings concerning criminal/administrative corporate responsibility
(i) EniPower SpA. In June 2004, the Milan Public Prosecutor of Milan commenced inquiries into contracts awarded by Eni’s subsidiary EniPower SpA and onas to supplies fromprovided by other companies to EniPower.EniPower SpA. It emerged that illicit payments were made by EniPower SpA suppliers to a manager of EniPower SpA who was immediately dismissed.fired. The Court served EniPower SpA (the commissioning entity) and
Snamprogetti (nowSpA, now Saipem SpA)SpA (contractor of engineering and procurement services), with notices of investigation in accordance withpursuant to Legislative Decree No. 231/2001 that establishes that companies are liable for the crimes committed by their employees who acted on behalf of the employer.01. In August 2007, Eni was notified that the Public Prosecutor requested the dismissal of EniPower SpA and Snamprogetti SpA, while the proceeding continues against former employees of these companies and employees and managers of the suppliers under the provisions ofpursuant to Legislative Decree No. 231/2001. Eni SpA, EniPower and Snamprogetti presented themselves as plaintiffs in the preliminary hearing. In the preliminary hearing related to the main proceeding on April 27, 2009, the Judge for the Preliminary Hearings requested all the parties that have not requested the plea-bargain to stand in trial, excluding certain defendants as a result of the statute of limitations. During the hearing on March 2, 2010, the Court confirmed the admission as plaintiffs of01. Eni SpA, EniPower SpA and SaipemSnamprogetti SpA against the inquired parts under the provisions of Legislative Decree No. 231/2001. Further employees of the companies involved were identifiedpresented themselves as defendants to account for their civil responsibility.plaintiffs. In September 2011, the Court of Milan found that nine persons were guilty for the above-mentioned crimes. In addition, they were sentenced jointly and severally to the payment of all damages to be assessed through a dedicatedspecific proceeding and to the reimbursement of the proceeding expenses incurred by the plaintiffs. The Court also resolved to dismiss all the criminal indictments for 7 employees, representing some companies involved as a result of the statute of limitations, while the trial ended with an acquittal of 15 individuals.defendants. In relationreference to the companiesparts involved in the proceeding pursuant to Legislative Decree No. 231/01, the Court found that 7 companies are liable based onresponsible for the provisions of Legislative Decree No. 231/2001,
administrative offenses ascribed to them, imposing a fine and the disgorgement of profit. Eni SpA and its subsidiaries, EniPower and Saipem, which took over Snamprogetti, acted as plaintiffs in the proceeding also against the mentioned companies. The Court rejected the position as plaintiffs of the Eni Group companies, reversing athe prior decision made by the Court. This decision may have been made based on a pronouncement made by a SupremeThird Instance Court that stated the illegitimacy of the constitution as plaintiffs made against any legal entity, which isas indicted under the provisions ofpursuant to Legislative Decree No. 231/2001.01. The Court filed the ground of the judgment in December 19, 2011. The condemnedsentenced parties filed an appeal against the above-mentioned decision. The Appeal Court issued a ruling that substantially confirmed the first-degree judgment except for the fact that it ascertained the statute of limitation with regard to certain defendants. In 2015, the SupremeThe Third Instance Court successively annulled the judgment of the AppealSecond Instance Court of Milan ascribing the judgment to another section.section that, once more, confirmed the sentence of first instance, excepting the rulings of the previous appeal sentence not subject to annulment, including the statute of limitation. The grounds of the sentence have been filed confirming the motivations provided by the previous instance Courts. An appeal was filed at the Third Instance Court solely for the purposes of the civil proceeding. (ii) Algeria. Legal proceedings are pending in Italy and outside Italy in connection with an allegation of corruption relating to the award of certain contracts to itsEni’s former controlled companysubsidiary Saipem in Algeria. On February 4,In 2011, Eni received from the Public Prosecutor of Milan an information request pursuant to Article 248 ofin accordance with the Italian Code of Criminal Procedure. The request related to allegations of international corruption and pertained to certain activities performed by Saipem Group companies in Algeria (in particular the contract between Saipem SpA and Sonatrach relating to the construction of the GK3 gas pipeline and the contract between Galsi, Saipem SpA and Technip relating to the engineering of the ground section of a gas pipeline). For that reason, Eni forwarded the notification to Saipem. The crime of international corruption is among the offenses contemplated bypursuant to Legislative Decree of June 8, 2001, No. 231, relating to231/01, which provides for corporate responsibilityliability for crimes committed by employees which providesand prescribes punishments including fines and interdictions to the company and the disgorgement of profit. Saipem promptly began to collect documentation in responseEni also voluntarily provided to the requests of the Public Prosecutor. The documents were produced on February 16, 2011. Eni also filedProsecutor documentation relating to the MLE project (in which the Eni’s Exploration & Production Division participates) even if not required,, with respect to which investigations in Algeria are ongoing. OnIn November 22, 2012, the Public Prosecutor of Milan served Saipem a notice stating that it had commenced an investigation for alleged liability of the company for international corruption in accordancepursuant to Article 25, second and third paragraph of Legislative Decree No. 231/2001.01. Furthermore, the Public Prosecutor requested the production of certain documents relating to certain activities in Algeria. The proceeding was unified withSubsequently, the Iraq-Kazakhstan proceeding, concerning a different line of investigation, as it relatedPublic Prosecutor’s Office notified further measures and requests to the activities carried out by Eni in Iraq and Kazakhstan. Subsequently Saipem, was served a notice of seizure, then a request for documentation and finally a search warrant was issued, in order to acquireaimed at acquiring further documentation, in particular relating to certain intermediary contracts and sub-contracts entered into by Saipem in connection with its Algerian business. Several former Saipem employees were also involved in the proceeding, including the former CEO of Saipem SpA, who resigned from the office in December of 2012, and the former Chief Operating Officer of the Business Unit Engineering & Construction of Saipem, whothe employment of whom was firedterminated at the beginning of 2013. OnIn February 7, 2013, on mandate from the Public Prosecutor of Milan, the Italian Finance Police visited Eni’s headquarters in Rome and San Donato Milanese and executed searches and seized documents relating to Saipem’s activity in Algeria. On the same occasion, Eni was served a notice that an investigation had commenced in accordance with Article 25, third and fourth paragraph ofpursuant to Legislative Decree No. 231/200101 with respect to Eni, Eni’s former CEO, Eni’s former CFO and another senior manager. Eni’s former CFO had previously served as Saipem’s CFO, including during the period in which alleged corruption took place and before being appointed as CFO of Eni on August 1, 2008. Following receipt of this notice, Eni conducted an internal investigation with the assistance of external consultants, in addition to the review activities performed by its audit and internal control departments and a team dedicated team to the Algerian matters. During 2013, theThe external consultants reached the following results: (i) the review of the documents seized by the Milan prosecutors and the examination of internal records held by Eni’s global procurement department havedid not foundfind any evidence that Eni entered into intermediary or any other contractual arrangements with the third parties involved in the prosecutors’ investigation; the brokerage contracts that were identified, were signed by Saipem or its subsidiaries or predecessor companies; and (ii) the internal review made on a voluntary basis of the MLE project, the only project that Eni understands to be under the prosecutors’
investigation where the client is an Eni Group company hasdid not foundfind evidence that any Eni employee engaged in wrongdoing in connection with the award to Saipem of two main contracts to execute the project (EPC and Drilling). Furthermore, in 2014, with the assistance of external consultants, Eni completed a review of the extent of its operating control over Saipem with regard to both legal, and accounting and administrative issues. The findings of thethat review performed have confirmed the autonomy of Saipem from the parent company.company during the relevant periods. The findings of Eni’s internal review have been provided to the Judicial Authority in order to reaffirm Eni’s willingness to fully cooperate. On October 24, 2014, Eni SpA received a request of probationary evidence by the Prosecutor of Milan relating to for the examination of two defendants: the former Chief Operating Officer of the Business Unit
Engineering & Construction of Saipem and the former President and General Manager of Saipem Contracting Algérie SpA. OnIn January 14, 2015, the Public Prosecutor of Milan notified the conclusion of preliminary investigations towardsrelating to Eni, Saipem and eight persons (including, the former CEO and CFO of Eni SpA and the Chief Upstream Officer of Eni SpA who was responsible for Eni Exploration & Production activities in North Africa at the time of the events under investigation). The Public Prosecutor of Milan has issued a notice forof alleged international corruption against all defendantssuch persons (including Eni SpA and Saipem on the base of the provisions ofSpA pursuant to Legislative Decree No. 231/2001)01) in connection with the entry into intermediary contracts by Saipem in Algeria. Furthermore, some of the defendants (including the former CEO and CFO of Eni and the Chief Upstream Officer of Eni) were accused of tax offense for fraudulent misrepresentation in relation to the accounting treatment of these contracts for the fiscal years 2009 and 2010. Having acquired the actions of the court filed in relation to the request of probationary evidence, the minutes of the hearing and the documents filed for the conclusion of the preliminary investigation, Eni requested its consultants to perform additional analysis and investigation. As a result, Eni’s consultants reaffirmed their conclusions previously reported to the Company. In February 2015, the Public Prosecutor indictedrequested the indictment of all the investigated persons for above-mentioned crimes. On October 2,international corruption as well as for tax offenses. In 2015, the Judge for the Preliminary Hearing of the Court of Milan dismissed the case and granted an acquittal in favor of Eni SpA, former Chief Executive Officer and Chief Upstream Officer for all the alleged crimes. Onoffenses. In February 24, 2016, the Court of Third Instance Court, upholding an appeal presented by the Public Prosecutor, of Milan, reversed the dismissal annulled the verdict, and remanded the proceedings to another Judge for the Preliminary Hearing in the Court of Milan. As a result of thea new preliminary hearing dated 27in July 2016, the judgeJudge ordered the trial for all defendants, including Eni.Eni SpA. At a hearing in February, 2018, the Public Prosecutor, concluding his indictment, requested — among other things — the imposition on Eni SpA of a pecuniary sanction. In September 2018, the Court of Milan rejected in part the charges of the Public Prosecutor and issued an acquittal verdict for Eni, for the former CEO and for the Company’s Chief Upstream Officer in relation to all charges. The judgmentformer CFO of Eni was also acquitted of charges relating to Eni’s involvement. In December 2018 the court filed a written opinion setting forth the basis for its rulings. The Public Prosecutor and the parties who were convicted in the first instance is pending.trial have appealed under the terms of the law. On January 15, 2020, the second penal section of the Court of Appeal of Milan confirmed the first-degree acquittal sentence against the former Eni managers, declaring the appeal proposed by the Public Prosecutor inadmissible against the Company.
At the end ofIn 2012, Eni contacted the U.S. Authorities — the DoJDepartment of Justice (DoJ) and the U.S. SEC — in order to voluntaryvoluntarily inform them about this matter, and has kept them informed about the developments in the Italian prosecutors’ investigations.Prosecutors’ investigations and proceedings. Following Eni’s notification, in 2012, both the U.S. SEC and the DoJ have started their own investigations regarding this matter. Eni has furnished various information and documents, including the findings of its internal reviews, in response to formal and informal requests. In September 2019, the DoJ notified Eni that based on the information it currently possessed, the DoJ was closing its investigation of Eni in connection with Eni’s and Saipem’s businesses in Algeria without the filing of any charges. Eni is currently in advanced discussions with the SEC about a potential resolution of the SEC’s investigation.
(iii) IraqBlock OPL 245 — Kazakhstan.Nigeria. A criminal proceedingcase is pending before the Public ProsecutorCourt of Milan in relation to alleged crimes ofalleging international corruption involving Eni’s activities in Kazakhstan regarding the management of the Karachaganak plant and the Kashagan project, as well as handling of assignment procedures of work contracts by Agip KCO. The Company has filed the documents collected and is fully collaborating with the Public Prosecutor. A number of managers and a former manager are involved in the investigation. The above-mentioned proceeding has been combined with another (the so-called “Iraq proceeding”) regarding a parallel proceeding related to Eni’s activities in Iraq, disclosed in the following paragraphs. On June 21, 2011, Eni Zubair SpA and Saipem SpA in Fano (Italy) were searched by the Judicial Authorities. The search involved the offices of certain Group employees and of certain third parties in connection with alleged crimes of conspiracy and corruption as partthe acquisition in 2011 of the “Jurassic” project in Kuwait. Particularly, the alleged crimes would have been committed in order to illicitly influence the award of a construction contract outside Italy where Eni was the commissioning entity. Considering the claims of the Public Prosecutor, Eni and Saipem believed that they were damaged by the crimes committed by their employees. Eni considered those employees to have breached the Company’s Code of Ethics. In spite of this, Eni SpA and Saipem SpA were notified of being under investigation pursuant to the Legislative Decree No. 231/2001, which establishes the liability of entities for the crimes committed by their employees. Eni SpA was notified by the Public Prosecutor of a request of extension of the preliminary investigations that has led up to the involvement of another employee, as well as other suppliers in the proceeding. The Public Prosecutor of Milan requested Eni SpA to be debarred for one year and six months from performing any industrial activities involving the production sharing contract of 1997 with the Republic of Kazakhstan and in the subsequent administrative or commercial arrangements, or the prosecution of the mentioned activities under the supervision of a commissioner pursuant to Article 15 of the Legislative Decree No. 231 of 2001. On July 16, 2013, the Judge for Preliminary Investigation rejected the request for precautionary measures requested by the Public Prosecutor of Milan, because it considered the request groundless. The Public Prosecutor promptly appealed the decision before a higher degree court. After the appeal hearing, on October 21, 2013 such court rejected the appeal filed by the Public Prosecutor. The Re-examination Court rejected the appeal with judgment upon the merits due to the lack of serious evidence against Eni, accepting the defense arguments for which Eni suffered severe damages because of poor performances of some suppliers involved in the Kashagan project. In addition, the Court declared the lack of precautionary requirements considering the reorganization of the activities in Kazakhstan and taking into account of the initiatives of internal audit and control promptly adopted by Eni. The Public Prosecutor’s office did not appeal against the sentence of the Re-examination Court. Also based on this
decision, on March 13, 2014, the Eni legal team requested to the Public Prosecutor to dismiss the proceeding. The Prosecutor’s Office filed a request for dismissal of all the natural persons, and, on 5 January 2017, the judge for preliminary investigations who issued the relevant decree granted the above-mentioned filing request. A similar measure is expected for Eni that was involved at the same proceeding pursuant to Legislative Decree no. 231/01.
(iv) Block OPL 245 —exploration block in Nigeria. On In July 2, 2014, the Italian Public Prosecutor of Milan served Eni with a notice of investigation relating to potential liability on the part of Eni arising from alleged international corruption, pursuant to Italian Legislative Decree No. 231/2001 whereby companies are liable for the crimes committed by their employees when performing their tasks. As part of the proceeding, Eni was also subpoenaed for documents and other evidence. According to the subpoena, the01. The proceeding was commenced following a claim filed by NGO ReCommon NGO relating to alleged corruptive practices thatwhich, according to the Public Prosecutor, would have allegedly involved the Resolution Agreement made on April 29, 2011 relating to the so-called Oil Prospecting licenseLicense of the offshore oilfield that was discovered in Block 245 in Nigeria.OPL 245. Eni is fully cooperatingcooperated with the Public Prosecutor and has promptly filed the requested documentation. Furthermore, Eni has voluntarily reported the matter to the U.S. Department of Justice and the U.S. SEC. In July 2014, the Eni’s Board of Statutory Auditors jointly with the Eni Watch Structure resolved to engage an independent, US-based law firm, expert in anticorruption, to conduct a forensic, independent review of the matter, upon informing the Judicial Authorities. After reviewing the matter, the USU.S. lawyers concluded in summary that they detected no evidence of wrongdoing onby Eni side were detected in relation to the 2011 transaction with the Nigerian government for the acquisition of the OPL 245 license. The outcome of this review was transmitted to the judicial authorities. OnIn September 10, 2014, the Public Prosecutor of Milan notified Eni of a restraining order issued by a British judge who ruledordered the seizure of a bank account not pertaining to Eni domiciled at a British bank following a request from the Italian Public Prosecutor. The order wasSince the act had also been notified to certain individuals,some persons, including Eni’sthe CEO of Eni and the former Chief Development, OperationsOperation & Technology Officer of Eni and Technological Officer, as well as Eni’sthe former CEO. From the available documents,CEO of Eni, it was inferredassumed that such Eni’s officers and former officers are under investigation by the Italian Public Prosecutor.same had been registered in the register of suspects at the Milan Prosecutor’s office. During a hearing before a Court ofcourt in London onin September 15, 2014, Eni and its current executive officers stated their non-involvement in the matter regarding the seized bank account. Following the hearing, the Court
reaffirmed the seizure. OnIn December 22 2016, the Public Prosecutor of Milan notified Eni was notified of the conclusion of the preliminary investigation by the Italian Judicial Authorities. Following the request of the Public Prosecutor of Milan that theand requested Eni’s CEO, and the Chief Development, Operations and Technological Officer and the Executive Vice President for international negotiations to stand trial, as well as Eni’s former CEO would stand trial, as well asand Eni based onSpA, pursuant to Italian lawLegislative Decree No. 231/2001 on corporate entity responsibility, on February 14, 2017, Eni’s attorneys were notified of01. Upon the schedule of the preliminary hearing due on April 20, 2017. Upon notification to Eni of the conclusion of the preliminary investigation by the Public Prosecutor, of Milan, the independent US-based law firm was requested by Eni to assess whether the new documentation made available from Italian prosecutors could modify the conclusions of the law firm prior review. The USU.S. law firm was also provided with the documentation filed in the NigeriaNigerian proceeding mentioned below. The independent U.S. law firm concluded that the reappraisal of the matter in light of the new documentationsdocumentation available did not alter the outcome of the prior review. OnIn September 2019, the DoJ notified Eni that based on the information it currently possessed, the DoJ was closing its investigation of Eni in connection with OPL 245 without the filing of any charges. In December 2017, the Judge for preliminary investigation ordered the indictment of all the parties mentioned above, and other parties under investigation by the Public Prosecutor, before the Court of Milan. The request of the Federal Government of Nigeria (FGN) for admission as a civil claimant in the proceedings was granted in July 2018. The first instance trial of the Milan Prosecutor’s OPL 245 charges began before the Court of Milan on June 20, 2018 and is currently ongoing. In a separate criminal proceeding, two defendants, neither of whom is a current or former employee of the Company, chose to have their liability determined by the Judge for the Preliminary Hearing on the basis of the evidence presented by the Milan Prosecutor at the preliminary hearing. In September 2018, the Judge convicted these defendants and sentenced them both to four-year detention terms and the disgorgement of profits amounting to approximately €100 million. In December 2018, the Judge for the Preliminary Hearing filed a written opinion setting forth the basis for these rulings. The defendants filed an appeal against this sentence. In January 27, 2017, Eni’s subsidiary Nigerian Agip Exploration Ltd (“NAE”) became aware of an Interim Order of Attachment (“Order”) issued by the Nigerian Federal High Court sitting in Abuja, upon request from the Nigerian Economic and Financial CrimeCrimes Commission (EFCC), attaching OPL 245 temporarily the property known as Oil Prospecting License 245 (“OPL 245”) pending thea proceeding forin Nigeria relating to alleged corruption and money laundering started in Nigeria. NAE made anlaundering. After making this application, to discharge the Order (along with the Shell affiliate co-holder of the license). On March 17, 2017, the Nigerian Court discharged the Order. Recently, Eni became aware of a formal filing of charges by the EFCC.EFCC against NAE and other parties. In March 2017, the Nigerian Court revoked the Order. To NAE’s knowledge EFCC charges have not been dropped but none of the defendants were served nor arraigned. In November 2018, Eni has providedSpA and its subsidiaries NAE, NAOC and AENR (as well as some companies of the Shell Group) were notified of the intention of the FGN to bring a copy of charges filed bycivil claim before an English court to obtain compensation for damages allegedly deriving from the EFCC, to the US-based law firm engaged to review the OPL 245 transaction who upon review of such documents, did not modify their conclusion according to which no evidence of wrongdoing on Eni side was detectedthat resulted in relation to the acquisitionassignment of the OPL 245 license fromto NAE and Shell subsidiary SNEPCO (Shell subsidiary). On April 15, 2019 the Nigerian government.subsidiaries NAE, NAOC and AENR received formal notification of the commencement of the proceeding, while similar notification was received by Eni spa on May 16, 2019. In the introductory deeds of the proceeding, the claim is set at $1.092 billion or at any other amount that will be established during the proceedings. The FGN has based its assessment on an estimated fair value of the asset of $3.5 billion. Eni’s interest in the asset is 50%. As the FGN is also acting as claimant in the Italian proceeding before the Court of Milan, this claim appears to duplicate the claims made before the Milan’s Court against Eni employees. (v)(iv) Congo. In March 2017, the Italian Finance Police served Eni with an information request in accordance with the Italian Code of Criminal Procedure in connection with an investigative file opened by the Public Prosecutor of Milan against unknown persons. The request related in particular to the agreements signed by Eni Congo SA with the Ministry of Hydrocarbons of the Republic of Congo in 2013, 2014 and 2015 in relation to exploration, development and production activities concerning certain permits held by Eni Congo SA for Congolese projects and Eni’s relationships with Congolese companies that hold stakes in those projects. In July 2017, the Italian Financial Police, on behalf of the Public Prosecutor of Milan, served Eni with another information request and a notice of investigation pursuant to Legislative Decree No. 231/01 for alleged international corruption. The request expressly stated that it was based in part on the March 2017 information request and concerned the relationship of Eni and its subsidiaries with certain third-party companies from 2012 to the present. Eni produced all of the documentation requested in March and July 2017 and voluntarily disclosed this matter to the relevant U.S. authorities (SEC and DoJ). In April 2018, the Public Prosecutor of Milan served Eni SpA Refiningwith a further request for documentation and notified an Eni employee, who was the then Chief Development, Operation & Marketing DivisionTechnology Officer, of a search order stating that he and another Eni employee had been placed under investigation.
In December 2018 and subsequently in May and September 2019, Eni was notified by the Public Prosecutor of Milan for documents in accordance with the Italian Code of Criminal Procedure, concerning some economic transactions between Eni Group companies and certain third-party companies. All the required documentation has been produced to the Judge. In April 2018, the Board of Statutory Auditors, the Watch Structure and the Control and Risk Committee of Eni jointly appointed an independent law firm and a professional consulting company, knowledgeable in the matter of anti-corruption, to carry out a forensic review of facts relating to Eni’s work in Congo. Such review did not find any factual evidence as to the involvement of Eni, nor of any Eni employees and key managers, in the alleged crimes. The report resulting from this review was brought to the attention of the Public Prosecutor and the relevant US authorities (SEC and DoJ). In September 2019, the Company was informed that the Company’s CEO was served with a search decree and an investigation decree in connection with an alleged violation of article 2629 bis of the Italian Civil Code which penalizes directors of listed companies that fail to communicate conflicts of interest. The alleged omission relates to the supply of logistics and transportation services to certain Eni’s subsidiaries operating in Africa, among which Eni Congo SA, by third-party companies owned by Petroserve Holding BV, in the period 2007-2018. The accusation is based on the allegations that the wife of the Company’s CEO retained a shareholding of the above-mentioned holding company over part of the period of time under investigation. The Board of Directors of Eni spa has never been involved in any resolution concerning the suppliers under investigation. In November 2019, following the notification of further investigative documents, the Board of Statutory Auditors, the Control and Risk Committee and the Watch Structure of Eni asked the consultants, which had been engaged in 2018, also to review the conclusions reached, in the light of the documentation made available following the decree notified to the CEO in September 2019. The second report of the consultants, which was delivered in February 2020, still of a preliminary nature and subject to modifications and follow-up, updates the conclusions reached by the first report and indicated that: (i) it is probable that the CEO’s wife held a shareholding in the Petroserve Group for a few years starting from 2009 until 2012 and in any case no later than the date the CEO was appointed Board member; (ii) there is an absence of evidence to contradict the statements made by the CEO as to his lack of knowledge of his wife’s interests in the ownership of Petroserve Group. 3. Other proceedings concerning criminal matters (i) Eni SpA (R&M) — Criminal proceedings on fuel excise tax (Criminal proceeding N. 6159/10 RGNR the Italian Public Prosecutor in Frosinone and. A criminal proceeding No. 7320/14 RGNR the Italian Public Prosecutor in Rome). Two criminal proceedings areis currently pending, relating to alleged evasion of excise taxes in the context of the retail sales atin the fuel market. In particular, the claim states that the quantity of oil products marketed by Eni was larger than the quantity subjected to the excise tax. TheThis proceeding (No. 7320/2014 RGNR) concerns the combination of three distinct investigations: (i) A first proceeding, opened by the Public Prosecutor’s Office of Frosinone againstinvolved a third company (Turrizziani Petroli) purchaser of Eni’s fuel, is still pending in the phase of the preliminary investigation.fuel. This investigation was subsequently extended to Eni. The Company hasfully cooperated fully with the
proceeding and provided all data and information concerning the performance of the excise tax obligations for the quantities of fuel coming from the storage sites of Gaeta, Naples and Livorno. Eni ensured the best possible collaboration, handing in all the required documentation. Such proceeding referred to quantities of oil products sold by Eni, allegedly larger than the quantity subjected to the excise tax. After the ending of the investigation, the Fiscal Police from Frosinone, along with the local Customs Agency, in November 2013 issuedOn June 24, 2019, a claim related to the evasion of the payment of excise taxes in the 2007 2012 periods for €1.55 million. In May 2014,settlement agreement was signed between Eni and the Customs Agency, involving the determination of Rome issued a payment notice relatingthe excise tax of €73 thousand and the reimbursement to Eni of the exceeding amounts paid while the judgment was pending. Consequently, an application to cease the dispute was presented to the abovementioned claim that was filedTax Commission. (ii) A second proceeding, concerning an investigation by the Fiscal Police and Customs AgencyPublic Prosecutor’s Office of Frosinone. The Company immediately appealedPrato, commenced in regard to the Tributary Commission. The seconddeposit of Calenzano and relates to abduction of fuel through manipulation of the fuel dispensers, subsequently extended also to the Refinery of Stagno (Livorno); (iii) A third proceeding, opened by the Public Prosecutor’s Office of Rome, regardedconcerns alleged evasionmissing payment of excise tax payment on the surplus of the unloading products, as the quantity of such products was larger than the quantity reported in the supporting fiscal documents. This proceeding represents a development of the first proceeding mentioned above and substantially concerns similar facts withpresenting, however, some differences with regard to both the nature of the alleged crimes and the responsibility subjected to verification. In fact, theresponsibility.
The Public Prosecutor’s Office of Rome has alleged the existence of a criminal conspiracy aimed at the habitual subtractionabduction of oil products at all of the 22 storage sites which are operated by Eni over the national territory.in Italy. Eni is cooperating with prosecutorthe Prosecutor in order to defend the correctness of its operation. OnIn September 30, 2014, a
search was conducted at the office of the former chief operating officer of Eni’s Refining & Marketingthe R&M Division as ordered by the Rome’s Public Prosecutor.in Rome. The motivations of the search are the same as the above-mentioned proceeding as the ongoing investigations also relatesrelate to a period of time when hethe officer was in charge of thatat Eni’s R&M Division. OnIn March 5, 2015, the Prosecutor of Rome ordered a search at all the storage sites of Eni’s network in Italy as part of the same proceeding. The search was intended to verify the existence of fraudulent practices aimed at tampering with measuring systems functional to the tax compliance of excise duties in relation to fuel handling at the storage sites. The three criminal proceedings were united together at Public Prosecutor’s Office of Rome, which is still conducting preliminary investigations. Ultimately, the Customs Agency, in reply to a request of the national association of refiners solicited by Eni, published a dedicated Circular which provides the rules the operators in the sector should follow to determine the quantity of oil products subjected to the excise tax, so as to give clarification to regional customs agencies, the Revenue Agency and the Finance Police. According to this Circular, Eni and other oil companies followed the correct procedures in order to determine the quantity subjected to the excise tax. In September 2015, the Public Prosecutor of Rome requested a one-off technical appraisal aimed to verify the compliance of the software installed at certain metric heads previously seized with those lodged by the manufacturer toat the Ministry of Economic Development. The technical appraisal verified the compliance of the software tested. On this occasion, it became clear that theThe proceeding has beenwas then extended to a large number of employees and former employees of the company. TheCompany. Eni has continued to provide full cooperation to the authorities. During the course of 2018, as part of the general proceeding is atno. 7320/2014, the Public Prosecutor of Rome notified the conclusion of the preliminary investigations.investigations in relation to the criminal proceeding concerning the Calenzano, Pomezia, Naples, Gaeta and Ortona storage sites and the Livorno and Sannazzaro refineries. Based on the outcome of the investigations, as far as Eni is concerned, the proceeding involves former managers and directors of the logistic sites and refineries indicated above concerning alleged aggravated and continuous non-payment of excise duties, alteration and removal of seals, use and possession of false measures and weights instruments. In addition for the Calenzano site, three employees and their manager of the storage site were accused of alleged procedural fraud. (vi) Block Marine XII, Congo. On July 9, 2015,In September 2018, Eni received, fromas injured party, the U.S. Departmentnotification of Justicethe schedule of hearing issued by the Court of Rome, in relation to criminal association and other minor claims, against numerous persons under investigation — including over forty Eni employees — subject of a subpoena orderingseparated proceeding (No. 22066/17 RGNR), for which, in May 2017, the Company to produce documents in viewPublic Prosecutor’s Office had requested the dismissal. At the end of the hearing in December 2018, the Judge accepted the request for dismissal for several persons under investigation, including thirteen Eni employees. The Judge also initially rejected the request of indictment for criminal association relating twenty-eight Eni employees (including the former managers of the R&M Division).
As part of the separate proceeding no. 22066/2017 RGNR, following the re-filing by the Public Prosecutor of the indictment for criminal association, following a preliminary hearing, the judge resolved to dismiss the case against all of the defendants because allegations were found to be groundless. In April 2018 as part of the administrative proceeding intended to collect taxes allegedly unpaid by Eni, the tax police of Rome based on the findings of the investigations performed by the prosecutors of Frosinone, Prato and Rome issued a statement of objection against the Company claiming the missed payment of excise taxes due for the years 2008 up to 2017 for €34 million, as well as the related higher corporate profits before income taxes leading to the claim of additional taxes for €22 million related to income taxes and VAT. The Custom Agency that is in charge of issuing the notice of payment may also impose a fine and the recognition of interest expense. A part of the disputed amounts for excise taxes and other related taxes concerned the same litigation, which was successfully challenged by the Company following a recourse filed with the Tax Commission of Rome and in relation to which the Company agreed upon an extrajudicial transaction with the Tax Authorities. Following the documentation presented by the company, the Customs Agency determined the excise tax due in the amount of €8 million by issuing the payment notices in July 2019. Furthermore, the Agency estimated €6 million of other related taxes. The Company has paid the amounts determined by the Agency. (ii) Eni employee,SpA — Public Prosecutor of Milan — Criminal proceeding no. 12333/2017. In February 2018, Eni was notified of a search and seizure decree in relation to allegations of associative crime aimed at slander and at reporting false information to a Public Prosecutor. In the decree, the Prosecutor of Milan included, among the other persons under investigation, a former external lawyer and a former Eni manager, at the time of the facts holding strategic positions in the Company. According to the decree, the association is allegedly aimed at interfering with the judicial activity in certain criminal proceedings that are involving, among others, Eni and some of its directors and managers. Afterwards, the Control and Risks Committee, having consulted the Board of Statutory Auditors, and together with the Watch Structure, agreed to engage an auditing firm to perform an internal audit of all relevant facts and circumstances and all records and documentation relating to the assets “Marine XII” in Congo and relationshipsmatter with certain persons and companies. Accordingrespect to preliminary informal contacts between Eni’s U.S. lawyers and the Authority, this hearing is part of a broader investigation, which is currently being carried out with regard to third parties. Within such investigation, Eni is considered a witness and — potentially — a damaged party. The documents required by the Authority are currently being collected and filed with the Authority. 4. Tax Proceedings
Italy
(i) Eni SpA — municipal tax related to certain oil platforms located in the Italian territorial waters. Several tax proceedings are pending in Italy, as certain municipalities claimed Eni SpA omitted payments of a tax on property relating oil platforms located in the territorial waters under the municipality administration. After completing all degrees of judgment before Italian tax courts, on February 24, 2016, the Third Instance Court sentenced that: i) property taxes on platforms are due by Eni; ii) the taxable basis is to be defined by considering the platforms carrying amounts, insteadevents of the replacement cost; iii) sanctions are not applicable. Theaforementioned proceeding, continued with an indictment before a trial judge to determine the due amount. In a similar proceeding relating to another oil company, the Third Instance Court confirmed that these industrial installations might be subject to this local tax. Based on the outcomes
of these resolutions, Eni started an out of court procedure to reachincluding a settlement on the matter with the local authorities whoforensic review. The final report, submitted claims against the Company based on the taxability of oil platforms. This settlement will be pursued on condition that the local authorities agree with Eni a fair tax base and renounce any claim of sanctions as established by the Third Instance Court which resolved the inapplicability of any sanction to the matter inControl and Risk Committee, the case involving a local municipality. BasedWatch Structure and the Board of Statutory Auditors on September 12, 2018, concluded that following the expectation of managementreview carried out with respect to successfully conclude these settlements, Eni accrued a tax provision.
(ii) Eni SpA — Excise taxes. On May 31, 2016 the Customs Agency issued to Eni a payment notice for a total sum of €134 million (of which €114 million referring to excise taxes and €20 million referring to interests), in addition to fines amounting to €34 million. This followed a claim filed in 2011, referring to legal proceeding startedallegations made by the Court of Milan in 2010 pertaining to alleged culpable omission to pay excise taxes (for the period 2003 – 2008) due on 9.8 billion cubic meters of natural gas marketed by Eni in Italy. With a sentence dated June 28, 2012 the Public Prosecutor of Milan, there was not sufficient factual evidence to prove the Tribunal resolvedinvolvement of the aforementioned former manager of Eni in the alleged crimes. On April 19, 2018, the Board of Directors appointed two external consultants, a criminal lawyer and a civil lawyer to dismissprovide independent legal advice in relation to the proceeding against all defendants because the factfacts under investigation. Their report, dated November 22, 2018, did not constitute an offence. In addition,find facts which could suggest any involvement of any Eni employees in the appeal filedcrimes alleged by the Public ProsecutorProsecutor. On June 4, 2018, Consob, the Italian market regulator, requested to be informed about the above mentioned proceeding. The request was rejected by a final-degree Court with sentence dated July 3, 2013 and filed on January 7, 2014. With regardaddressed to the administrative proceeding, considering the documentation filed by Eni in the aftermath, the volumes allegedly subtractedCompany and to tax payment were reduced to 650 million cubic meters. Thus, the corresponding amountits Board of allegedly due excise taxes decreased from €1.7 billion, initially claimed by the Public Prosecutor, to €114 million. Like the initial claim, the residual claim appears to be groundless, taking into account the fact that the gas volumes input into the national grid by Eni and gas volumes off-taken at each delivery pointsStatutory Auditors.
Specifically, Consob asked for reselling to final customers have different calorific power. This was confirmed by the opinion of sector experts and acknowledged by the Customs Agency itself during the consultation process with the Italian association of gas resellers. Therefore, the Customs Agency issued a new administrative claim configuring erroneous compilation of the consumption declaration only. The Customs Agency reiterated the claim because — even if the incidence of the calorific value has been acknowledged from a technical and scientific point of view and shared by the Agency itself, — at the same time the matter has not been explicitly regulated by an administrative act. In order to safeguard the Company’s assets, Eni’s management commenced the following initiatives: (i) an administrative claim has been filed in order to suspend the tax collection, accepted by the Customs Agency; (ii) an appeal against the Agency’s claim before a Tax Judge has been filed whose discussion hearing is scheduled. Based on current information and taking into account the outcome of the criminal litigation, the objections presented are considered groundless and, therefore, the Company did not accrue any tax provision in the consolidated financial statements 2016. Outside Italy
(iii) Eni Angola Production BV. The tax Authorities of Angola filed a notice of tax assessment in which it claimed the improper deductibility of amortization charges recognized on assets in progress related to the payment of the Petroleum Income Tax that was made by Eni Angola Production BV as partner of the Cabinda concession. The company paid the higher taxes under contestation for the years 2002 – 2006, requiring the recognition of its position for subsequent years and, accordingly, filed an appeal against this decision. The judgment is still pending before the Supreme Court. The tax authorities also contested to Eni Angola Production BVforensic review and to Eni Angola Exploration BV the recovery of certain costs (cost oil) for the tax years from 2003 to 2009,be updated about any other audit action taken in relation to licenses regulatedthe matter by oil contracts in Production Sharing Agreements,the Company and that would result inby its Board of Statutory Auditors. The Board of Statutory Auditors was also requested to report about the findings of the additional audit program agreed with an external auditor regarding the matter and to keep Consob updated about any further initiatives adopted. The Company answered the request on June 11, 2018. Subsequently, the Company finalized its response by sending further documentation including the final report of the independent third party and the reports of the consultants of the Board of Directors. The Board of Statutory Auditors has periodically updated Consob of the initiatives taken as part of the Board’s monitoring responsibilities with several communications. On June 13, 2018, Eni was notified of a payment of further taxes on the higher profit oil resultingrequest from the lackProsecutor Office to transmit certain documentation in accordance with the Italian Code of Criminal Procedure. The request targeted evidence and documents relating to the recognition of such costs. The companies contested the legitimacy of the claim formulatedinternal audit performed by the Ministry of Finance either asCompany and any possible external review concerning certain tasks that had been assigned to the power to approve the cost oil (recoverable costs) and the shares of profit oil contract lies solely to Sonangol (first party in the oil contract), or the tax deductibility of such costs. The companies have presented an appeal that is waiting to be discussed. Eni accrued a tax provisionformer external lawyer with respect to Eni. This lawyer appears to be investigated as part of this proceeding. The reports of the independent third party and of the consultant of the Board of directors were also sent to the Public Prosecutor.
5. Settled proceedings
(i) Action commencedIn May and June 2019, in the context of the same proceeding, the Court of Milan notified Eni and three of its subsidiaries (ETS Spa, Versalis Spa, Ecofuel Spa) of various requests for documentation in accordance with the Italian Code of Criminal Procedure. At the same time, on May 23, 2019, Eni was served a notice that the Company is being investigated pursuant to Legislative Decree No. 231/01, with reference to the crime sanctioned by the Municipality of Carrara for the remediation and reestablishment of previous environmental conditions at the Avenza site and payment of environmental damage. In relationItalian Penal Code concerning “inducement not to make statements or to make false statements to the judicial authority”.
The object of the aforementioned requests particularly concerns the relations with two business partners, access to Eni offices of certain third parties, also on behalf of one of the above-mentioned business partners, the mailbox of some employees and former employees, the documentation concerning the relations (and the interruption of those relations) with the former external lawyer investigated in the proceeding, brought by the Municipality of Carrarainternal audit reports and the Ministry for the Environment against Syndial SpA for the compensation of alleged environmental damages at the Avenza site. The proceeding was closed without ascertaining any responsibilityreports of the company. Company’s bodies that dealt with assessing these relationships. Following internal audits, on June 21, 2019, the Company sued for fraud a former employee at its subsidiary ETS, who was fired on May 28, 2019, and also filed a complaint before the Judicial Authority to ascertain possible complicity in fraud of other third parties. On August 14, 2019, the Italian tax police sent a new request for information to Eni, concerning the economic relations between Eni Group companies and an external professional. In particularNovember 2019, Eni received a notice to extend the Minister indicated Syndialpreliminary investigations. The notice also covered the investigations of the alleged breach of certain provisions of Italian Law Decree 231/01 on part of Eni. Furthermore, it was ascertained that certain former Eni employees have been charged with various criminal allegations. Those employees were a former manager of Eni’s legal department, the former Chief Upstream Officer of Eni and an employee that was fired in 2013. A number of third parties have also been indicted, among them, two former legal consultants of Eni. On January 23, 2020, a search decree and an indictment were notified to the Company’s Chief Services & Stakeholder Relations Officer, the Senior Vice President for Security and to a manager of the legal department. Moreover, further procedural documentation became available following requests to review the aforementioned decree. The Board of Statutory Auditors, the Control Committee and the Watch Structure have instructed the same consultants appointed in 2018 to examine the aforementioned documentation, in order to review and summarize the facts underlying those allegations, as well as other factual elements and conduct to be examined in depth relating to the existence of any substantial issue or possible deficiency in the internal control and risk management system and in the organization and risk management model pursuant to Legislative Decree No. 231/01. The consultant’s activities are ongoing.
responsible(iii) Eni SpA — Public Prosecutor of Milan — Insider trading. In March 2019, a request for environmental damages onextending certain investigations was notified to Eni’s Chief Upstream Officer by the belief that: a) Syndialpublic prosecutor office of Milan. The commencement of those investigation was liableotherwise not notified. The investigations related to an alleged breach of Italian provisions that regulate insider trading and access to market-sensitive information. The breach was allegedly made from November 1 to December 1, 2016. There were no more informative details about the alleged breach in the notified document.
4. Tax proceedings (i) Dispute for omitted payment of a property tax for some oil offshore platforms located in territorial waters. A Third Instance Court in Italy with a ruling issued in 2016 established that oil&gas offshore platforms located within territorial boundaries were subject to a property tax, resolving a dispute that has been in progress for about a decade in favor of local authorities. Eni was a party to many of these disputes and has entered into settlement transactions with various local authorities. Currently, a risk provision €17 million has been set aside in the consolidated financial statements for the environmental damage as the Eni subsidiary took over the site from the previous owners assuming all existing liabilities; b) it was responsible for managing the plant and inadequately remediating the site after the occurrence of an incident in 1984; c) it was responsible for omitted clean-up. Syndial established itself as defendant. remaining pending litigations. The Third Instance Court sentenced that onlyruling applied to the first motivationlegislation in force until 2015. Since 2016 the regulatory framework has changed due to enactment of law no. 208/2015, which excluded from the scope of the appeal filedproperty tax the value of plants instrumental to specific production processes. To clarify the effects of this scope limitation of the property tax relating to above-mentioned offshore platforms, in 2016 the Italian association of oil&gas producers submitted a question to the Italian Finance Department. The Department recognized that offshore platforms met the requirements for classification as instrumental plants and consequently are excluded from the scope of the property tax (resolution no. 3/DF of June 1, 2016). The ruling of the Department of Finance, however, is not binding for local authorities with taxing powers and three of these have issued assessment notices for 2016 and subsequent years. The Company has challenged these notices in legal proceedings. To date two first instance judgments have been issued, one in favor of the Company and one against. A second instance judgement has also been issued with results unfavorable to the Company. Of the two unfavorable outcomes, only one applies penalties. One of the two unfavorable judgements concerns the dispute with the municipality of Ravenna for the years 2016 and 2017, that judgement confirmed the assessment made by the Ministry is valid, which relatedmunicipality for a total tax of €19 million, in addition to the statute of limitations forpenalties applicable by law. Based on the crime of disaster applicable exclusively to the previous ownersresolution of the site. Therefore,Department of Finance in 2016, Eni believes that the scope limitation of the tax property enacted in 2016 applies to offshore platforms located within territorial boundaries and based on this the Company intends to continue to contest the assessment. No risk provisions have been accrued in the consolidated financial statements. Law Decree 124/2019 (enacted with Law 157/2019) has established, starting from 2020, that marine platforms are subject to a new property tax that will replace and supersede any other ordinary local property tax eventually levied on these plants up to 2019. This rule has therefore sanctioned, starting from 2020, the existence of the tax requirement for these plants. 5. Settled Proceedings (i) Reorganization procedure of Alitalia Linee Aeree Italiane SpA under extraordinary administration. In January 2013, the Italian airline company Alitalia summoned Eni, Exxon Italia and Kuwait Petroleum Italia SpA before the Court has definitely confirmed that Syndial is not liable, neitherof Rome, to seek a compensation for activities directly conducted (including alleged delay/omissiondamages caused by alleged anti-competitive behavior on part of the clean-up activities claimed by the Ministry) nor for strict liability (as it took over the site from the previous owners). Particular attention should be paid to this second profilethree petroleum companies in the lightsupply of the fact that the Avenza site was transferred to Eni due to a law provision. (ii) Eni SpA — Investigation for alleged violations of the Consumer Codejet fuel in the matter of billing of gas and power consumptions. In relation to the proceeding broughtyears 1998 through 2009. The claim was based on a decision rendered by the Italian Antitrust Authority (AGCM) in regard of alleged unfair commercial practices under the Consumer Code in the billing of gas and power consumptions to retail customers, after the conclusion of the investigation, the AGCM notified Eni its final ruling by imposing to the company a sanction of €3.6 million.June 2006. The sanction has been paid. Eni appealed theantitrust decision to the Regional Administrative Court.
(iii) Fatal accident Truck Center Molfetta — Prosecuting body: Public Prosecutor of Trani. In relation to a fatal accident occurred in March 2008 that caused the death of four workers deputed to the cleaning of a tank car used for the transportation of liquid sulphur produced by Eni in the Refinery of Taranto, the Public Prosecutor of Trani accused Eni and eight employeesanother five petroleum companies of anti-competitive agreements designed to split the companymarket for alleged manslaughter, grievous bodily harmjet fuel supplies and illegal disposalblocking the entrance of waste materials. The decision of a first instance court which ruled acquittal fornew players in the years 1998 through 2006. In June 2019 the lawsuit was settled between all the defendants and forinvolved parties. The amount transacted by Eni SpA, as legal entity, with the wide formula “because the alleged fact does not exist” was upheldpreviously accrued in the subsequent degrees of judgments and became final on July 27, 2016.financial statements.
(iv)(ii) Eni SpA — Reorganization procedurePublic Prosecutor’s Office of Rome — Criminal Procedure No. 2711/2019 — VAT returns. On September 16, 2019, a notice of extension of the airlines companies Volare Group, Volare Airlinespreliminary investigations was notified to the former CEO and Air Europe — Prosecuting body: Delegated Commissioner. Inthe current CEO of Eni, in relation to the bankruptcy clawbacktax crime referred to in art. 4 of Legislative
Decree 74/2000 (unfaithful tax statement). From the first investigations carried out by the defense attorney, the allegations referred to the criminal proceedings on fuel excise taxes, disclosed in the previous section and derived from the alleged taxes due on the higher profit before taxation ascertained as a result of evading the owed amounts of excise taxes for fiscal years from 2011 to 2014. As a result of the defensive activities carried out and due to the transaction carried out with the Customs and Revenue Agency, in November 2019 the Prosecutor filed a request to dismiss the proceedings and on December 2, 2019 the Court of Rome issued an order of dismissal. (iii) Eni’s arbitration with GasTerra. In 2013, Eni initiated an arbitration against GasTerra, as part of a long-term supply contract signed in 1986, to obtain a revision of the reorganization procedure filedprice charged by GasTerra to Eni for the airlines companies Volare Group, Volare Airlinesgas supplied in the 2012 – 2015 period. On that occasion, Eni and Air EuropeGasTerra agreed to apply a provisional price, which was lower than the previous price, until the definition of a new contractual price based on an arrangement between parties or an arbitration award. The arbitration award dismissed Eni’s claim for price revision, without however determining a new price applicable in the relevant period. GasTerra considered that, by dismissing Eni’s claim, the award restored the original contract price, based on which GasTerra claimed an additional amount to be paid by Eni which corresponded to the difference between the provisional price and the request of override of all the payments made by those entities tocontractual price. Eni, in the year previous to the insolvency declaration from November 30, 2003 to November 29, 2004, the Court of Appeal of Milan ruled Eni to return a total amount of €9 million. The plaintiffs requested that the sentence against Eni would be reassessed to an amount of about €18 million. The proceeding is pending before a third-degree court. Eni accrued a provision in respect to this proceeding. The proceeding is no longer significant. (v) Investigation by the Italian Antitrust about Eni’s determination of Italian market share of the Italian gas wholesale market. With Resolution No. 25064 of August 1, 2014, the Italian Antitrust commenced an investigation to verify whether Eni controlled a bigger share of the domestic wholesale gas market than it had declared. Following the Legislative Decree No. 130 of 2010, which envisages a 55% ceiling to the wholesale market share for each Italian gas operator who inputs gas into the Italian backbone network, Eni declared that its market share was equal to 54%, therefore slightly below the established threshold. Eni calculated its market share by excluding certain sales of gas volumes. On the other hand, the Antitrust rejected this calculation method and therefore concluded that Eni’s market share was actually 56%. Nonetheless, the Antitrust decided not to impose any finerelying also on the Company as the violation was immaterial. The Antitrust considered the fact that in its declaration Eni explained clearly how its market share was calculated. Besides that, in the opinion of its external consultants, did not agree with GasTerra’s interpretation and considered GasTerra’s claim groundless. However, GasTerra, based on its own interpretation, commenced an arbitration and obtained from a Dutch court the Ministryprovisional seizure of Economic Development, expressed duringEni’s investment in its subsidiary Eni International BV for the investigation,alleged receivable due by Eni calculated(equal to €1.01 billion). With respect to the interim seizure measure obtained by GasTerra, Eni offered to GasTerra, who in turn accepted, a bank guarantee of the same amount of the GasTerra claim. On July 8, 2019, the Tribunal issued an award concluding the first phase of the procedure by which it decided, in particular, that the provisional price mentioned above continued to apply in the 2012 – 2015 period, and that therefore GasTerra was not entitled to any price adjustment, so the invoices issued after the rendering of the award in 2016 were invalid. The Tribunal referred to the second phase of the arbitral procedure the quantification of Eni’s claims for damages against GasTerra. On July 24, 2019, upon Eni’s request and GasTerra consent, the bank guarantee for €1.01 billion was terminated. GasTerra has reserved its market share correctly. Eni filed an appeal against the Antitrust’s decision before the Regional Administrative Courtrights of Lazio, asking for annulment. Management does not expect any liability in connection with this proceeding.appeal.
Assets under concession arrangements Eni operates under concession arrangements mainly in the Exploration & Production segment and the Refining & Marketing business line. In the Exploration & Production segment, contractual clauses governing mineral concessions, licenses and exploration permits regulate the access of Eni to hydrocarbon reserves. Such clauses can differ in each country. In particular, mineral concessions, licenses and permits are granted by the legal owners and, generally, entered into with government entities, State oil companies and,
in some legal contexts, private owners. Pursuant to the assignment of mineral concession,concessions, Eni sustains all the operational risks and costs related to the exploration and development activities and it is entitled to the productions realized. As a compensation for mineral concessions, Eni pays royalties and taxes in accordance with local tax legislation. In production sharing agreement and service contracts, realized productions are defined based on contractual agreements with State oil companies, which hold the concessions. Such contractual agreements regulate the recovery of costs incurred for the exploration, development and operating activities (Cost Oil) and give entitlement to the own portion of the realized productions (Profit Oil). In the Refining & Marketing business line, several service stations and other auxiliary assets of the distribution service are located in the motorway areas and they are granted by the motorway concession operators following a public tender for the sub-concession of the supplying of oil products distribution service and other auxiliary services. In exchange of the granting of the services described above, Eni provides to the motorway companies fixed and variable royalties based on the basis of quantities sold. At the end of the concession period, all non-removable assets are transferred to the grantor of the concession for no consideration. Environmental regulations Risks associated with the footprint of Eni’s activities on the environment, health and safety are described in the “Financial Review”, paragraph “Risk factors and uncertainties”. In the future, Eni will sustain significant expenses in relation to compliance with environmental, health and safety laws and regulations and for reclaiming, safety and remediation works of areas previously used for industrial production and dismantled sites. In particular, regarding the environmental risk, management
does not currently expect any material adverse effect upon Eni’s Consolidated Financial Statements, taking account of ongoing remediation actions, existing insurance policies and the environmental risk provision accrued in the Consolidated Financial Statements. However, management believes that it is possible that Eni may incur material losses and liabilities in future years in connection with environmental matters due to: (i) the possibility of as yet unknown contamination; (ii) the results of ongoing surveys and other possible effects of statements required by Legislative Decree No. 152/2006; (iii) new developments in environmental regulation (i.e. Law No. 68/2015 on crimes against the environment and European Directive 2015/2193 on medium combustion plants); (iv) the effect of possible technological changes relating to future remediation; and (v) the possibility of litigation and the difficulty of determining Eni’s liability, if any, as against other potentially responsible parties with respect to such litigation and the possible insurance recoveries. Emission trading From 2013, the third phase of the European Union Emissions Trading Scheme (EU-ETS) came in force. The new phase marked a significant change in the method of awarding emission allowance from a no-consideration scheme based on historical emissions to allocation through auctioning. For the period 2013 – 2020, the award of free emission allowances is performed based on European benchmarks specific to each industrial segment, except for the thermoelectric sector that is not eligible for allocations for no consideration. This regulatory scheme implies for Eni’s plants subjected to emission trading a lower assignment of emission permits respect to the emissions recorded in the relevant year and, consequently, the necessity of covering the amounts in excess by purchasing the relevant emission allowances on the open market. In 2016,2019, the emissions of carbon dioxide from Eni’s plants were higher than the free allowances assigned to Eni. Against emissions of carbon dioxide amounting to approximately 20.2219.30 million tonnes, Eni was awarded free emission allowances of 7.067.73 million tonnes, determining a deficit of 13.1611.57 million tonnes. This deficit was entirely covered through the purchase of emission allowances in the open market. 3928 Revenues and other income
Net salesSales from operations
| | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Revenues from sales and services | | | | | 98,256 | | | | | | 72,290 | | | | | | 55,764 | | | Change in contract work in progress | | | | | (38) | | | | | | (4) | | | | | | (2) | | | | | | | | 98,218 | | | | | | 72,286 | | | | | | 55,762 | | | |
| | | | | (€ million) | | | Exploration & Production | | | Gas & Power | | | Refining & Marketing and Chemical | | | Corporate and Other activities | | | Total | | 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales from operations | | | | | 10,499 | | | | | | 38,160 | | | | | | 21,017 | | | | | | 205 | | | | | | 69,881 | | | Products sales and service revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales of crude oil | | | | | 3,505 | | | | | | 17,334 | | | | | | 27 | | | | | | | | | | | | 20,866 | | | Sales of oil products | | | | | 1,189 | | | | | | 3,000 | | | | | | 16,615 | | | | | | | | | | | | 20,804 | | | Sales of natural gas and LNG | | | | | 5,454 | | | | | | 12,468 | | | | | | | | | | | | | | | | | | 17,922 | | | Sales of petrochemical products | | | | | | | | | | | 316 | | | | | | 3,772 | | | | | | 22 | | | | | | 4,110 | | | Sales of other products | | | | | 68 | | | | | | 2,502 | | | | | | 16 | | | | | | 7 | | | | | | 2,593 | | | Services | | | | | 283 | | | | | | 2,540 | | | | | | 587 | | | | | | 176 | | | | | | 3,586 | | | Total | | | | | 10,499 | | | | | | 38,160 | | | | | | 21,017 | | | | | | 205 | | | | | | 69,881 | | | Transfer of goods/services | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Goods/Services transferred in a specific moment | | | | | 9,946 | | | | | | 38,047 | | | | | | 20,768 | | | | | | 87 | | | | | | 68,848 | | | Goods/Services transferred over a period of time | | | | | 553 | | | | | | 113 | | | | | | 249 | | | | | | 118 | | | | | | 1,033 | | |
| | | | | (€ million) | | | Exploration & Production | | | Gas & Power | | | Refining & Marketing and Chemical | | | Corporate and Other activities | | | Total | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales from operations | | | | | 9,943 | | | | | | 43,109 | | | | | | 22,594 | | | | | | 176 | | | | | | 75,822 | | | Products sales and service revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales of crude oil | | | | | 3,982 | | | | | | 18,471 | | | | | | | | | | | | | | | | | | 22,453 | | | Sales of oil products | | | | | 1,133 | | | | | | 4,053 | | | | | | 17,213 | | | | | | | | | | | | 22,399 | | | Sales of natural gas and LNG | | | | | 4,554 | | | | | | 15,088 | | | | | | | | | | | | | | | | | | 19,642 | | | Sales of petrochemical products | | | | | | | | | | | 762 | | | | | | 4,777 | | | | | | 35 | | | | | | 5,574 | | | Sales of other products | | | | | 27 | | | | | | 2,363 | | | | | | 20 | | | | | | 11 | | | | | | 2,421 | | | Services | | | | | 247 | | | | | | 2,372 | | | | | | 584 | | | | | | 130 | | | | | | 3,333 | | | Total | | | | | 9,943 | | | | | | 43,109 | | | | | | 22,594 | | | | | | 176 | | | | | | 75,822 | | | Transfer of goods/services | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Goods/Services transferred in a specific moment | | | | | 9,676 | | | | | | 42,979 | | | | | | 22,535 | | | | | | 106 | | | | | | 75,296 | | | Goods/Services transferred over a period of time | | | | | 267 | | | | | | 130 | | | | | | 59 | | | | | | 70 | | | | | | 526 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales from operations | | | | | 7,131 | | | | | | 39,846 | | | | | | 19,771 | | | | | | 171 | | | | | | 66,919 | | | Products sales and service revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales of crude oil | | | | | 2,431 | | | | | | 17,693 | | | | | | 17 | | | | | | | | | | | | 20,141 | | | Sales of oil products | | | | | 1,030 | | | | | | 3,930 | | | | | | 14,615 | | | | | | | | | | | | 19,575 | | | Sales of natural gas and LNG | | | | | 3,470 | | | | | | 11,643 | | | | | | | | | | | | | | | | | | 15,113 | | | Sales of petrochemical products | | | | | | | | | | | 147 | | | | | | 4,591 | | | | | | 32 | | | | | | 4,770 | | | Sales of other products | | | | | 14 | | | | | | 2,021 | | | | | | 21 | | | | | | 12 | | | | | | 2,068 | | | Services | | | | | 186 | | | | | | 4,412 | | | | | | 527 | | | | | | 127 | | | | | | 5,252 | | | Total | | | | | 7,131 | | | | | | 39,846 | | | | | | 19,771 | | | | | | 171 | | | | | | 66,919 | | | |
(€ million) | | | 2019 | | | 2018 | | Revenues associated with contract liabilities at the beginning of the period | | | | | 747 | | | | | | 342 | | | Revenues associated with performance obligations totally or partially satisfied in previous years | | | | | 10 | | | | | | 11 | | |
Revenues from sales were stated net of the following items:
| | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Excise taxes | | | | | 12,289 | | | | | | 11,889 | | | | | | 11,913 | | | Exchanges of oil sales (excluding excise taxes) | | | | | 1,586 | | | | | | 1,154 | | | | | | 878 | | | Services recharged to joint venture partners | | | | | 5,191 | | | | | | 5,609 | | | | | | 4,441 | | | Sales to service station managers for sales billed to holders of credit cards | | | | | 1,804 | | | | | | 1,643 | | | | | | 1,553 | | | | | | | | 20,870 | | | | | | 20,295 | | | | | | 18,785 | | | |
Net salesSales from operations by industry segment and geographical area of destination are disclosed in note 4635 — InformationSegment information and information by industry segment and by geographicalgeographic area.
Net salesSales from operations with related parties are disclosed in note 4736 — Transactions with related parties.
Other income and revenues | | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Gains on price adjustments under overlifting/underlifting transactions | | | | | 390 | | | | | | 253 | | | | | | 238 | | | Compensation for damages | | | | | 43 | | | | | | 36 | | | | | | 122 | | | Lease and rental income | | | | | 92 | | | | | | 85 | | | | | | 81 | | | Contract penalties and other trade revenues | | | | | 37 | | | | | | 36 | | | | | | 72 | | | Gains from sale of assets | | | | | 84 | | | | | | 457 | | | | | | 14 | | | Other proceeds(*) | | | | | 433 | | | | | | 385 | | | | | | 404 | | | | | | | | 1,079 | | | | | | 1,252 | | | | | | 931 | | | |
| | | | | (€ million) | | | 2019 | | | 2018 | | | 2017 | | Gains from sale of assets and businesses | | | | | 152 | | | | | | 454 | | | | | | 3,288 | | | Other proceeds | | | | | 1,008 | | | | | | 662 | | | | | | 770 | | | | | | | | 1,160 | | | | | | 1,116 | | | | | | 4,058 | | |
In 2019, gains from the sale of assets and businesses related for €146 million to assets of the Exploration & Production segment.
Each individualIn 2018, gains from the sale of assets and businesses related to the divestment of a 10% stake in the Zohr project for €428 million. In 2017, the amount included herein was lower than €50 million.related to the divestment of a 25% stake in natural gas-rich Area 4 offshore Mozambique (€1,985 million) and of a 40% stake in the Zohr project (€1,281 million).
Compensations of €122Other proceeds include €368 million related to a loss in property value following an accident occurred at the EST conversion plant at the Sannazzaro refinery, which resulted in a write-offrecovery of the damaged units for €193 million and the recognitioncost share of a provision for removal and cleanupright-of-use assets pertaining to partners of €24 million. The portion of losses not covered by the insurance compensation (€95 million) corresponds to the risk retainednon-incorporated joint operations operated by Eni.
Other income and revenues with related parties are disclosed in note 4736 — Transactions with related parties. 40 Operating expenses29 Costs
Purchase, services and other charges | | | | | (€ 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 for contingencies | | | | | 340 | | | | | | 644 | | | | | | 505 | | | Expenses for price variation on overliftling and underlifting operations | | | | | 409 | | | | | | 278 | | | | | | 240 | | | Other expenses | | | | | 918 | | | | | | 1,135 | | | | | | 1,512 | | | | | | | | 77,723 | | | | | | 57,271 | | | | | | 44,439 | | | less: | | | | | - capitalized direct costs associated with self-constructed assets - tangible assets | | | | | (238) | | | | | | (323) | | | | | | (297) | | | - capitalized direct costs associated with self-constructed assets - intangible assets | | | | | (81) | | | | | | (100) | | | | | | (18) | | | | | | | | 77,404 | | | | | | 56,848 | | | | | | 44,124 | | | |
| | | | | (€ million) | | | 2019 | | | 2018 | | | 2017 | | Production costs - raw, ancillary and consumable materials and goods | | | | | 36,272 | | | | | | 41,125 | | | | | | 35,907 | | | Production costs - services | | | | | 11,589 | | | | | | 10,625 | | | | | | 12,228 | | | Lease expense and other | | | | | 1,478 | | | | | | 1,820 | | | | | | 1,684 | | | Net provisions for contingencies | | | | | 858 | | | | | | 1,120 | | | | | | 886 | | | Charges for price variation on overliftling and underlifting operations | | | | | | | | | | | | | | | | | 145 | | | Other expenses | | | | | 879 | | | | | | 1,130 | | | | | | 931 | | | | | | | | 51,076 | | | | | | 55,820 | | | | | | 51,781 | | | less: | | | | | | | | | | | | | | | | | | | | - capitalized direct costs associated with self-constructed assets - tangible assets | | | | | (197) | | | | | | (192) | | | | | | (224) | | | - capitalized direct costs associated with self-constructed assets - intangible assets | | | | | (5) | | | | | | (6) | | | | | | (9) | | | | | | | | 50,874 | | | | | | 55,622 | | | | | | 51,548 | | |
Service costsPurchase, services and other charges include geological and geophysical expenses related to thecosts of exploration activities of the Exploration & Production segment amounting to €204for €275 million (€368287 million and €254€273 million in 20142018 and 2015,2017, respectively). In 2018 and 2017, the item included operating leases for €872 million and €1,022 million, respectively.
Costs incurred in connection with research and development activity recognized inactivities expensed through profit and loss, as they did not meet the requirements to be recognized as long-lived assets, amounted to €161€194 million (€174197 million and €176€185 million in 20142018 and 2015,2017, respectively). Operating leases and other comprised operating leases for €566 million (€559 million and €635 million in 2014 and 2015, respectively) and royaltiesRoyalties on the extraction of hydrocarbons for €572amounted to €1,183 million (€1,2781,043 million and €865€674 million in 20142018 and 2015,2017, respectively).
Other expenses of €1,512 million (€918 million and €1,135 million in 2014 and 2015, respectively) included provisionsAdditions to the reserve of allowance for doubtful accounts of trade receivables of the Gas & Power segment, primarily in the retail business, for €399 million (€549 million in 2015).
Future minimum lease payments expected to be paid under non-cancelable operating leases are provided below:
| | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | To be paid: | | | | | - within 1 year | | | | | 522 | | | | | | 495 | | | | | | 593 | | | - between 2 and 5 years | | | | | 1,114 | | | | | | 1,061 | | | | | | 1,040 | | | - beyond 5 years | | | | | 726 | | | | | | 809 | | | | | | 785 | | | | | | | | 2,362 | | | | | | 2,365 | | | | | | 2,418 | | | |
Operating leases primarily regarded drilling rigs, time charter and long-term rentals of vessels, land, service stations and office buildings. Such leases generally did not include renewal options. There are no significant restrictions provided by these operating leases that may limit the ability of Eni to pay dividends, use assets or take on new borrowing.
Risk provisions net of reversal of unused provisions amounted to €505 million (€340 million and €644 million in 2014 and 2015, respectively) and mainly related to net addition for litigations amounting to €60 million (net provisions of €101 million and €375 million in 2018 and 2017, respectively) and net additions for environmental liabilities amounting to €198€329 million (net provisions of €177€266 million and €232€200 million in 20142018 and 2015, respectively) and net provisions for litigations amounting to €55 million (net provisions of €35 million and €179 in 2014 and 2015,2017, respectively). More information is provided in note 3020 — Provisions for contingencies. RiskProvisions. Net additions to provisions net of reversal of unused provisionsby segment are disclosed in note 4635 — Segment information and information by geographic area.
Information by industry segmentabout leases is disclosed in note 12 — Right-of-use assets and by geographical area.lease liabilities.
Payroll and related costs | (€ million) | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Wages and salaries | | | | 2,590 | | | | | 2,648 | | | | | 2,491 | | | | | | 2,417 | | | | | 2,409 | | | | | 2,447 | | | Social security contributions | | | | 445 | | | | | 453 | | | | | 445 | | | | | | 449 | | | | | 448 | | | | | 441 | | | Cost related to employee benefit plans | | | | 73 | | | | | 85 | | | | | 81 | | | | | | 85 | | | | | 220 | | | | | 113 | | | Other costs | | | | 160 | | | | | 182 | | | | | 202 | | | | | | 213 | | | | | 170 | | | | | 162 | | | | | | | 3,268 | | | | | 3,368 | | | | | 3,219 | | | | | | 3,164 | | | | | 3,247 | | | | | 3,163 | | | less: | | | | | | | | | | | | | | | | | | | - capitalized direct costs associated with self-constructed assets - tangible assets | | | | (278) | | | | | (203) | | | | | (215) | | | | | | (152) | | | | | (142) | | | | | (202) | | | - capitalized direct costs associated with self-constructed assets - intangible assets | | | | (61) | | | | | (46) | | | | | (10) | | | | | | (16) | | | | | (12) | | | | | (10) | | | | | | | 2,929 | | | | | 3,119 | | | | | 2,994 | | | | | | 2,996 | | | | | 3,093 | | | | | 2,951 | | | | |
Other costs of €202 million (€160 million and €182 million in 2014 and 2015, respectively) comprised provisions for redundancy incentives of €47€45 million (€537 million and €31€18 million in 20142018 and 2015,2017, respectively) and costs for defined contribution plans of €83€99 million (€8595 million and €86€90 million in 20142018 and 2015,2017, respectively).
Cost related to employee benefit plans are described in note 3121 — Provisions for employee benefits. Costs with related parties are disclosed in note 36 — Transactions with related parties. Average number of employees The Group average number and breakdown of employees by category is reported below: | | | | | | | | 2014 | | | 2015 | | | 2016 | | (number) | | | Subsidiaries | | | Joint operations | | | Subsidiaries | | | Joint operations | | | Subsidiaries | | | Joint operations | | Senior managers | | | | | 1,049 | | | | | | 25 | | | | | | 1,044 | | | | | | 17 | | | | | | 1,018 | | | | | | 18 | | | Junior managers | | | | | 8,912 | | | | | | 121 | | | | | | 9,091 | | | | | | 108 | | | | | | 9,160 | | | | | | 109 | | | Employees | | | | | 18,143 | | | | | | 595 | | | | | | 17,685 | | | | | | 379 | | | | | | 17,180 | | | | | | 384 | | | Workers | | | | | 6,358 | | | | | | 559 | | | | | | 5,895 | | | | | | 303 | | | | | | 5,703 | | | | | | 294 | | | | | | | | 34,462 | | | | | | 1,300 | | | | | | 33,715 | | | | | | 807 | | | | | | 33,061 | | | | | | 805 | | | |
The above Group average number do not include employees of discontinued operations (Saipem Group).
| | | | | (number) | | | 2019 | | | 2018 | | | 2017 | | | Subsidiaries | | | Joint operations | | | Subsidiaries | | | Joint operations | | | Subsidiaries | | | Joint operations | | Senior managers | | | | | 1,014 | | | | | | 16 | | | | | | 999 | | | | | | 17 | | | | | | 995 | | | | | | 17 | | | Junior managers | | | | | 9,267 | | | | | | 77 | | | | | | 9,095 | | | | | | 84 | | | | | | 9,089 | | | | | | 98 | | | Employees | | | | | 15,945 | | | | | | 361 | | | | | | 16,220 | | | | | | 361 | | | | | | 16,721 | | | | | | 371 | | | Workers | | | | | 4,910 | | | | | | 287 | | | | | | 5,259 | | | | | | 283 | | | | | | 5,659 | | | | | | 285 | | | | | | | | 31,136 | | | | | | 741 | | | | | | 31,573 | | | | | | 745 | | | | | | 32,464 | | | | | | 771 | | |
The average number of employees was calculated as the average between the number of employees at the beginning and the end of the period. The average number of senior managers included managers employed and operating in foreign countries, whose position is comparable to a senior manager’s status. Long-term monetary incentive plan for the managers of Eni On April 13, 2017, the Shareholders Meeting approved the Long-Term Monetary Incentive Plan 2017 – 2019 and empowered the Board of Directors to execute the Plan by authorizing it to dispose up to a maximum of 11 million of treasury shares in service of the Plan. The Long-Term Monetary Incentive Plan 2017-2019 provides for three annual awards for the years 2017, 2018 and 2019 and is intended for the Chief Executive Officer of Eni and for the managers of Eni and its subsidiaries who qualify as “senior managers deemed critical for the business”, selected among those who are in charge of tasks directly linked to the Group results or of strategic clout to the business. The Plan provides the granting of Eni shares for no consideration to eligible managers after a three-year vesting period under the condition that they would remain in office until vesting. Considering that this incentive falls within the category of employee compensation, in accordance with IFRS, the cost of the plan is determined based on the fair value of the financial instruments awarded to the beneficiaries and the number of shares that will be granted at the end of the vesting period; the cost is accruing along the vesting period.
The number of shares that will be granted at the end of the vesting period is conditioned on a 50-50 basis to actual results of two performance parameters against preset targets: (i) a market condition in terms of Total Shareholder Return (TSR) of the Eni share compared to the TSR of the FTSE Mib index of the Italian Stock Exchange Market, and to a group of Eni’s competitors (“Peers Group”)37 and the TSR of their corresponding stock exchange market38; (ii) growth in the Net Present Value (NPV) of proved reserves benchmarked against the Peer Group. Depending on the performance of the parameters mentioned above, the number of shares that will vest after three years may range between 0% and 180% of the initial award. Furthermore, 50% of the shares that will eventually vest is subject to a lock-up clause of one year after the vesting date. The number of shares awarded at the grant date was 1,759,273 in 2019, 1,517,975 in 2018 and 1,719,061 in 2017; the weighted average fair value of the shares at the same date was €9.88 per share in 2019, €11.73 per share in 2018 and €7.99 per share in 2017. The estimation of the fair value was calculated by adopting specific valuation techniques regarding the different performance parameters provided by the plan (the stochastic method for the market condition of the plan and the Black-Scholes model for the component related to the NPV of the reserves), taking into account the fair value of the Eni share at the grant date (€13.714 per share in 2019; €14.246 per share in 2018; €13.81 per share in 2017), reduced by dividends expected along the vesting period (6.1% of the share price at vesting date in 2019; 5.8% of the share price at vesting date in 2018; 5.8% of the share price at vesting date in 2017), the volatility of the stock (19% for attribution 2019; 20% for attribution 2018; 25% for attribution 2017), the forecasts for the performance parameters, as well as the lower value attributable to the shares considering the lock-up period at the end of the vesting period. In 2019, the costs related to the long-term monetary incentive plan 2017 – 2019, recognized as a component of the payroll cost, amounted to €9 million (€5 million in 2018; €0.4 million in 2017) with a contra-entry to equity reserves. Compensation of key management personnel Compensation, including contributions and collateral expenses, of personnel holding key positions in planning, directing and controlling the Eni Group subsidiaries, including executive and non-executive officers, general managers and managers with strategic responsibilities in office during the year (including contributions and ancillary costs) amounted to €43 million, €42 million and €44 million for 2014, 2015 and 2016, respectively, and consisted of the following: | (€ million) | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Wages and salaries | | | | 25 | | | | | 26 | | | | | 26 | | | | | | 28 | | | | | 27 | | | | | 25 | | | Post-employment benefits | | | | 2 | | | | | 2 | | | | | 2 | | | | | | 2 | | | | | 2 | | | | | 2 | | | Other long-term benefits | | | | 10 | | | | | 12 | | | | | 12 | | | | | | 12 | | | | | 10 | | | | | 9 | | | Indemnities upon termination of employment | | | | 6 | | | | | 2 | | | | | 4 | | | | | | 12 | | | | | | | | | | 7 | | | | | | | 43 | | | | | 42 | | | | | 44 | | | | | | 54 | | | | | 39 | | | | | 43 | | | | |
Compensation of Directors and Statutory Auditors Compensation of Directors amounted to €10.1€9.2 million, €6.7€9.6 million and €7.1€14.5 million for 2014, 20152019, 2018 and 2016,2017, respectively. Compensation of Statutory Auditors amounted to €0.419€0.613 million, €0.551€0.604 million and €0.738€0.760 million in 2014, 20152019, 2018 and 2016,2017, respectively. Compensation included emoluments and social security benefits due for the office as Director or Statutory Auditor held at the parent company Eni SpA or other Group subsidiaries, which was recognized as a cost to the Group, even if not subject to personal income tax. Other operating income (loss)37
The analysis of net income (loss) on commodity derivatives was as follows: | | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Net income (loss) on cash flow hedging derivatives | | | | | (133) | | | | | | 2 | | | | | | (1) | | | Net income (loss) on other derivatives | | | | | 278 | | | | | | (487) | | | | | | 17 | | | | | | | | 145 | | | | | | (485) | | | | | | 16 | | | |
Net income (loss) on cash flow hedging derivatives related to the ineffective portiongroup consists of the hedging relationship on commodity derivatives was recognized through profitfollowing oil companies: Anadarko, Apache, BP, Chevron, ConocoPhillips, ExxonMobil, Marathon Oil, Royal Dutch Shell, Statoil and lossTotal.
38
The performance condition connected with the TSR in accordance with the Gas & Power segment.international accounting standards represents a so-called market condition.
Net income (loss) on other derivatives included: (i) the fair value measurement and settlement of commodity derivatives which could not be elected for hedge accounting under IFRS because they related to net exposure to commodity risk and derivatives for trading purposes and proprietary trading amounting to a net income of €36 million (net income of €247 million in 2014 and net loss of €471 million in 2015); and (ii) the fair value valuation at certain derivatives embedded in the pricing formulas of long-term gas supply contracts of the Exploration & Production segment amounting to a net loss of €19 million (net income of €31 million in 2014 and net loss of €16 million in 2015).
Operating expenses with related parties are reported in note 47 — Transactions with related parties.
Depreciation and amortization
| | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Depreciation, depletion and amortization: | | | | | - tangible assets | | | | | 7,356 | | | | | | 8,646 | | | | | | 7,308 | | | - intangible assets | | | | | 326 | | | | | | 303 | | | | | | 253 | | | | | | | | 7,682 | | | | | | 8,949 | | | | | | 7,561 | | | less: | | | | | - capitalized direct costs associated with self-constructed assets - tangible assets | | | | | (6) | | | | | | (9) | | | | | | (2) | | | | | | | | 7,676 | | | | | | 8,940 | | | | | | 7,559 | | | |
Depreciation and amortization by industry segment are disclosed in note 46 – Information by industry segment and by geographical area.
Net impairment (reversal)
| | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Impairments: | | | | | - tangible assets | | | | | 1,196 | | | | | | 5,993 | | | | | | 1,067 | | | - intangible assets | | | | | 138 | | | | | | 544 | | | | | | | | | | | | | | 1,334 | | | | | | 6,537 | | | | | | 1,067 | | | less: | | | | | - reversal of impairments - tangible assets | | | | | (64) | | | | | | (3) | | | | | | (1,153) | | | - reversal of impairments - intangible assets | | | | | | | | | | | | | | | | | (389) | | | | | | | | 1,270 | | | | | | 6,534 | | | | | | (475) | | | |
Net impairment (reversal) by industry segment are disclosed in note 46 — Information by industry segment and by geographical area.
Write-off
| | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Write-off | | | | | - tangible assets | | | | | 936 | | | | | | 678 | | | | | | 289 | | | - intangible assets | | | | | 262 | | | | | | 10 | | | | | | 61 | | | | | | | | 1,198 | | | | | | 688 | | | | | | 350 | | | |
Write-off by industry segment are disclosed in note 46 — Information by industry segment and by geographical area.
4130 Finance income (expense)
| (€ million) | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Finance income (expense) | | | | | | | | | | | | | | | | | | | Finance income | | | | 5,701 | | | | | 8,635 | | | | | 5,850 | | | | | | 3,087 | | | | | 3,967 | | | | | 3,924 | | �� | Finance expense | | | | (7,057) | | | | | (10,104) | | | | | (6,232) | | | | | | (4,079) | | | | | (4,663) | | | | | (5,886) | | | Net finance income (expense) from financial assets held for trading | | | | 24 | | | | | 3 | | | | | (21) | | | | | | 127 | | | | | 32 | | | | | (111) | | | | | | | (1,332) | | | | | (1,466) | | | | | (403) | | | | Income (expense) from derivative financial instruments | | | | 165 | | | | | 160 | | | | | (482) | | | | | | (14) | | | | | (307) | | | | | 837 | | | | | | | (1,167) | | | | | (1,306) | | | | | (885) | | | | | | (879) | | | | | (971) | | | | | (1,236) | | | | |
The breakdown by lenders or typeanalysis of net finance income or expense is provided below:(expense) was as follows: | (€ million) | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Finance income (expense) related to net borrowings | | | | | | | | | | | | | | | | | | | Interest and other finance expense on ordinary bonds | | | | (759) | | | | | (740) | | | | | (639) | | | | | | (618) | | | | | (565) | | | | | (638) | | | Interest due to banks and other financial institutions | | | | (112) | | | | | (98) | | | | | (118) | | | | Interest and other income from financial receivables and securities held for non-operating purposes | | | | 26 | | | | | 2 | | | | | 37 | | | | Net finance income (expense) on financial assets held for trading | | | | | 127 | | | | | 32 | | | | | (111) | | | Interest and other expense due to banks and other financial institutions | | | | | (122) | | | | | (120) | | | | | (113) | | | Interest on lease liabilities | | | | | (378) | | | | | | | | | | | | | Interest from banks | | | | 19 | | | | | 19 | | | | | 15 | | | | | | 21 | | | | | 18 | | | | | 12 | | | Net finance income (expense) from financial assets held for trading | | | | 24 | | | | | 3 | | | | | (21) | | | | Interest and other income on financial receivables and securities held for non-operating purposes | | | | | 8 | | | | | 8 | | | | | 16 | | | | | | | (802) | | | | | (814) | | | | | (726) | | | | | | (962) | | | | | (627) | | | | | (834) | | | Exchange differences | | | | | | 250 | | | | | 341 | | | | | (905) | | | Positive exchange differences | | | | 5,430 | | | | | 8,400 | | | | | 5,579 | | | | Negative exchange differences | | | | (5,845) | | | | | (8,754) | | | | | (4,903) | | | | | | | | (415) | | | | | (354) | | | | | 676 | | | | Income (expense) from derivative financial instruments | | | | | (14) | | | | | (307) | | | | | 837 | | | Other finance income (expense) | | | | | | | | | | | | | | | | | | | Interest and other income on financing receivables and securities held for operating purposes | | | | | 112 | | | | | 132 | | | | | 128 | | | Capitalized finance expense | | | | 163 | | | | | 166 | | | | | 106 | | | | | | 93 | | | | | 52 | | | | | 73 | | | 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)(a) | | | | (293) | | | | | (291) | | | | | (312) | | | | | | (255) | | | | | (249) | | | | | (264) | | | Other finance (expense) | | | | (59) | | | | | (293) | | | | | (290) | | | | Other finance income (expense) | | | | | (103) | | | | | (313) | | | | | (271) | | | | | | | (115) | | | | | (298) | | | | | (353) | | | | | | (153) | | | | | (378) | | | | | (334) | | | | | | | (1,332) | | | | | (1,466) | | | | | (403) | | | | | | (879) | | | | | (971) | | | | | (1,236) | | | | |
(a)
The item related to the increase in provisions for contingencies that are shown at present value in non-current liabilities. FinanceInformation about leases is disclosed in note 12 — Right-of-use assets and lease liabilities.
The analysis of income (loss) on(expense) from derivative financial instruments consisted of the following: | | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Options | | | | | 68 | | | | | | 33 | | | | | | 24 | | | Derivatives on exchange rate | | | | | 51 | | | | | | 96 | | | | | | (494) | | | Derivatives on interest rate | | | | | 46 | | | | | | 31 | | | | | | (12) | | | | | | | | 165 | | | | | | 160 | | | | | | (482) | | | |
Net loss from derivatives of €482 million (net income of €165 million and €160 million in 2014 and 2015, respectively) was recognized in connection with fair value valuation of certain derivatives which lacked the formal criteria to be treated in accordance with hedge accounting under IFRS as they were entered into for amounts equal to the net exposure to exchange rate risk and interest rate risk, and as such, they cannot be referred to specific trade or financing transactions. Exchange rate derivatives were entered into in order to manage exposures to foreign currency exchange rates arising from the pricing formulas of commodities in the Gas & Power segment. The lack of formal requirements to qualify these derivatives as
hedges under IFRS also entailed the recognition in profit or loss of currency translation differences on assets and liabilities denominated in currencies other than functional currency, as this effect cannot be offset by changes in the fair value of the related instruments.
Net income on options of €24 million (net income of €68 million and €33 million in 2014 and 2015, respectively) related to: (i) the reversal through profit and loss of the fair value reserve relating to the embedded options of the bond convertible into ordinary shares of Snam SpA amounting to an income of €26 million (income of €23 million and €33 million in 2014 and 2015, respectively); (ii) the fair value of the option embedded in non-dilutive equity-linked convertible bond for a net loss of €2 million. In 2014, the measurement at fair value of the options embedded in the bond convertible into ordinary shares of Galp Energia SGPS SA resulted in an income of €45 million. More information is provideddisclosed in note 2923 — Long-term debtDerivative financial instruments and current portion of long-term debt.hedge accounting.
More information finance income (expense) is providedOperating expenses with related parties are disclosed in note 4736 — Transactions with related parties.
4231 Income (expense) from investments
Share of profit (loss) of equity-accounted investments | | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Share of profit from equity-accounted investments | | | | | 188 | | | | | | 150 | | | | | | 77 | | | Share of loss from equity-accounted investments | | | | | (77) | | | | | | (615) | | | | | | (370) | | | Decreases (increases) in the provision for losses on investments from equity accounted investments | | | | | (1) | | | | | | (6) | | | | | | (33) | | | | | | | | 110 | | | | | | (471) | | | | | | (326) | | | |
More information is provided in note 20 –15 — Investments. Share of profit (loss)or loss of equity accounted investments by industry segment is disclosed in note 4635 — InformationSegment information and information by industry segment and by geographicalgeographic area.
Other gain (loss) from investments | (€ million) | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Dividends | | | | 385 | | | | | 402 | | | | | 143 | | | | | | 247 | | | | | 231 | | | | | 205 | | | Net gain (loss) on disposals | | | | 160 | | | | | 164 | | | | | (14) | | | | | | 19 | | | ��� | | 22 | | | | | 163 | | | Other net income (expense) | | | | (179) | | | | | 10 | | | | | (183) | | | | | | 15 | | | | | 910 | | | | | (33) | | | | | | | 366 | | | | | 576 | | | | | (54) | | | | | | 281 | | | | | 1,163 | | | | | 335 | | | | |
In 2016, dividendDividend income of €143 million essentiallyprimarily related to Nigeria LNG Ltd for €76€186 million and to Saudi European Petrochemical Co for €45 million.€46 million (€187 million and €35 million in 2018 and €167 million and €21 million in 2017, respectively).
In 2015, dividend2018, other net income of €402 million primarily related to Nigeria LNG Ltd for €222 million, Snam SpA for €72 million, Saudi European Petrochemical Co for €69 million and Galp Energia SGPS SA for €21 million. In 2014, dividend income of €385 million related to the Nigeria LNG Ltd for €247 million, Saudi European Petrochemical Co for €57 million, Snam SpA for €43 million and Galp Energia SGPS SA for €22 million.
In 2016, net loss on disposals amounting to €14 million related to: (i) a loss of €32 million for the sale of 2.22% share capital (entire stake owned) of Snam SpA; (ii)included a gain of €11€889 million related toderiving from the salebusiness combination between Eni Norge AS and Point Resources AS, with the establishment of 100% share capital of Eni Hungaria Zrt and Eni Slovenjia doo; and (iii) a gain of €6 million related tojoint venture the
sale of 30% share capital (entire stake owned) of Pokrovskoe Petroleum BV and Vår Energi AS, determined by the saledifference between the book value of the 60% share capital (entire stake owned) of Zagoryanska Petroleum BV.
In 2015, net gains on disposals amountinginvestment corresponding to €164 million related to: (i) a gain of €98 million for the sale of an 8% stake in Galp Energia SGPS SA; (ii) a gain of €46 million for the sale of a 6.03% stake in Snam SpA; (iii) a gain of €32 million for the sale of 100% stake in Ceská Republika Sro; (iv) a gain of €31 million for the sale of a 100% stake of Eni Romania Srl; (v) a gain of €6 million for the sale of 32.445% stake (entire stake owned) in Ceská Rafinérská AS (CRC); (vi) a gain of €1 million of 100% stake in Eni Slovensko Spol Sro; and (vii) a loss of €47 million for the sale of a 76% stake in Inversora de Gas Cuyana SA (entire stake owned), a 6.84% stake in Distribudora de Gas Cuyana SA (entire stake owned), a 25% stake in Inversora de Gas del Centro SA (entire stake owned) and a 31.35% stake in Distribudora de Gas del Centro SA (entire stake owned).
In 2014, net gains on disposals amounting to €160 million related to: (i) €96 million for the sale of a 8.15% of the share capital of Galp Energia SGPS SA, of which €77 million related to the reversal of the reserve for fair value measurement; (ii) €54 million for the sale of a 20% (entire stake owned) of the share capital of South Stream Transport BV to Gazprom; and (iii) €9 million for the sale of a 50% (entire stake owned) of the share capital of EnBW Eni Verwaltungsgesellschaft mbH to EnBW Energie Baden-Württemberg AG.
In 2016, other net losses of €183 million included: (i) an impairment for €162 million relating to Unión Fenosa Gas SA (€84 million), PetroSucre (€65 million) and Genomatica Inc (€13 million).
In 2015, other net income of €10 million included: (i) a gain on the remeasurement at market fair value of 77.7 million shares of Snam SpA for €49 million to which the faircombined net assets and the book value option was applied as provided for by IAS 39; (ii) a reversal of unutilized provision for losses on investments of €10 million relating to Caspian Pipeline Consortium R — Closed Joint Stock Co; and (iii) an impairment for €49 million relating to Unión Fenosa Gas SA.
In 2014, other net expense of €179 million included the remeasurement at market fair value at the balance sheet date of 66.3 million shares of Galp Energia SGPS SA (loss for €231 million at the price of €8.43 per share) and of 288.7 million shares of Snam SpA (income for €10 million at the price of €4.1 per share). The valuation of the shares of these investments was based on the fair value option as underlying two convertible bonds.net assets sold.
More information is provided in note 20 – Investments.
4332 Income taxes
| (€ million) | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Current taxes: | | | | | | | | | | | | | | | | | | | - Italian subsidiaries | | | | (573) | | | | | 155 | | | | | 195 | | | | | | 347 | | | | | 301 | | | | | 712 | | | - subsidiaries of the Exploration & Production segment - outside Italy | | | | 6,512 | | | | | 4,015 | | | | | 2,671 | | | | | | 4,729 | | | | | 4,906 | | | | | 3,167 | | | - other subsidiaries - outside Italy | | | | 116 | | | | | 218 | | | | | 133 | | | | | | 152 | | | | | 163 | | | | | 142 | | | | | | | 6,055 | | | | | 4,388 | | | | | 2,999 | | | | | | 5,228 | | | | | 5,370 | | | | | 4,021 | | | Net deferred taxes: | | | | | | | | | | | | | | | | | | | - Italian subsidiaries | | | | 369 | | | | | 881 | | | | | (243) | | | | | | 599 | | | | | 130 | | | | | (464) | | | - subsidiaries of the Exploration & Production segment - outside Italy | | | | 79 | | | | | (2,156) | | | | | (813) | | | | | | (172) | | | | | 497 | | | | | (162) | | | - other subsidiaries - outside Italy | | | | (37) | | | | | 9 | | | | | (7) | | | | | | (64) | | | | | (27) | | | | | 72 | | | | | | | 411 | | | | | (1,266) | | | | | (1,063) | | | | | | 363 | | | | | 600 | | | | | (554) | | | | | | | 6,466 | | | | | 3,122 | | | | | 1,936 | | | | | | 5,591 | | | | | 5,970 | | | | | 3,467 | | | | |
Current income taxes payable by Italian subsidiaries amountedreferred to €195 million and were in respect of the Italian corporate taxation (IRES for €12 million and IRAP for €7 million) and foreign taxes on the share of profit earned outside Italy for €176€137 million.
The reconciliation between the statutory tax charge calculated by applying the Italian statutory tax rate of 27.5%24% (same amount in 20142018 and in 2015)2017) and the effective tax charge is the following: | (€ million) | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Profit (loss) before taxation | | | | 8,274 | | | | | (4,277) | | | | | 892 | | | | | | 5,746 | | | | | 10,107 | | | | | 6,844 | | | Tax rate (IRES) (%) | | | | 27.5 | | | | | 27.5 | | | | | 27.5 | | | | | | 24.0 | | | | | 24.0 | | | | | 24.0 | | | Statutory corporation tax charge (credit) on profit or loss | | | | 2,275 | | | | | (1,176) | | | | | 245 | | | | | | 1,379 | | | | | 2,426 | | | | | 1,643 | | | Increase (decrease) resulting from: | | | | | | | | | | | | | | | | | | | - higher tax charges related to subsidiaries outside Italy | | | | 4,065 | | | | | 2,576 | | | | | 1,152 | | | | | | 2,934 | | | | | 3,096 | | | | | 1,882 | | | - impact pursuant to the write-off of deferred tax assets and recalculation of tax rates | | | | 1,002 | | | | | 1,514 | | | | | 397 | | | | - impact pursuant to the write-down of deferred tax assets and recalculation of tax rates | | | | | 938 | | | | | 261 | | | | | (96) | | | - tax effects related to previous years | | | | | 147 | | | | | (24) | | | | | (1) | | | - impact pursuant to foreign tax effects of italian entities | | | | | 105 | | | | | 46 | | | | | 54 | | | - effect due to the tax regime provided for intercompany dividends | | | | 51 | | | | | 114 | | | | | 87 | | | | | | 65 | | | | | 47 | | | | | 1 | | | - Italian regional income tax (IRAP) | | | | 5 | | | | | 100 | | | | | 42 | | | | | | 25 | | | | | 50 | | | | | 77 | | | - impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law 7/2009 | | | | | | | | | | | | | | | 61 | | | - effect due to non-taxable gains/losses on sales of investments | | | | 25 | | | | | (39) | | | | | 8 | | | | | | | | | | | (1) | | | | | (177) | | | - impact pursuant to redetermination of the Italian Windfall Corporate tax as per Law 7/2009 | | | | (825) | | | | | - effect due to discontinued operations | | | | (97) | | | | | (288) | | | | | - other adjustments | | | | (35) | | | | | 321 | | | | | 5 | | | | | | (2) | | | | | 69 | | | | | 23 | | | | | | | 4,191 | | | | | 4,298 | | | | | 1,691 | | | | | | 4,212 | | | | | 3,544 | | | | | 1,824 | | | Effective tax charge | | | | 6,466 | | | | | 3,122 | | | | | 1,936 | | | | | | 5,591 | | | | | 5,970 | | | | | 3,467 | | | | |
In 2016, theThe higher tax charges at non-Italian subsidiaries of €1,152 million related to the Exploration & Production segment for €1,211 million. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €397€2,934 million was incurred at Italian subsidiaries and essentially related to a write-off at deferred tax assets due to projections of lower future taxable profit.
In 2015, the higher tax charges at non-Italian subsidiaries of €2,576 million related to the Exploration & Production segment for €2,410 million, including a write-off of deferred tax assets due to a reduced profitability outlook of €1,058 million. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €1,514 million was incurred at Italian subsidiaries and related to a write-off at deferred tax assets due to projections of lower future taxable profit and to a reduction due to a change in the statutory tax rate from 27.5% to 24%, starting from January 1, 2017. The effect due to the Italian regional income tax (IRAP) of €100 million included a write-off at deferred tax assets due to projections of lower future taxable profit for €54 million.
In 2014, the higher tax charges at non-Italian subsidiaries of €4,065 million essentially related to the Exploration & Production segment. The impact pursuant to the write-off of deferred tax assets and recalculation of tax rates of €1,002 million was incurred at Italian subsidiaries and related to a write-off at deferred tax assets due to projections of lower future taxable profit for €526(€3,014 million and to a lower prospective tax rate€1,811 million in relation to the windfall tax (the so-called Robin Tax) provided by Article 81 of the Legislative Decree No. 112/2008 which was assessed to be no more recoverable as,2018 and in February 2015, by the Third Instance Court for €476 million. This sentence stated the illegitimacy of a tax rule prospectively, denying any reimbursement rights.2017, respectively).
4433 Earnings per share
| | | | | | | | | | | | | | 2014 | | | 2015 | | | 2016 | | Weighted average number of shares used for the calculation of the basic and diluted earnings per share | | | | | | | | 3,610,387,582 | | | | | | 3,601,140,133 | | | | | | 3,601,140,133 | | | Eni’s net profit | | | (€ million) | | | | | 1,303 | | | | | �� | (8,778) | | | | | | (1,464) | | | Basic and diluted earning (loss) per share | | | (euro per share) | | | | | 0.36 | | | | | | (2.44) | | | | | | (0.41) | | | Eni’s net profit - Continuing operations | | | (€ million) | | | | | 1,720 | | | | | | (7,952) | | | | | | (1,051) | | | Basic and diluted earning (loss) per share | | | (euro per share) | | | | | 0.48 | | | | | | (2.21) | | | | | | (0.29) | | | Eni’s net profit - Discontinued operations | | | (€ million) | | | | | (417) | | | | | | (826) | | | | | | (413) | | | Basic and diluted earning (loss) per share | | | (euro per share) | | | | | (0.12) | | | | | | (0.23) | | | | | | (0.12) | | | |
Basic earnings per ordinary share are calculated by dividing net profit for the period attributable to Eni’s shareholders by the weighted average number of ordinary shares issued and outstanding during the period, excluding treasury shares.
The average number of ordinary shares used for the calculation of the basic earnings per share outstanding atin 2019 was 3,592,249,603 (3,601,140,133 in 2018 and 2017). Diluted earnings per share are calculated by dividing the net profit of the period attributable to Eni’s shareholders by the weighted average number of shares fully-diluted, excluding treasury shares, and including the number of potential shares to be issued in connection with stock-based compensation plans. As of December 31, 2014, 2015 and 2016 was 3,610,387,582, 3,601,140,133 and 3,601,140,133, respectively. There were no pending issues2019, the shares that could be potentially issued related the estimation of new shares that could dilutewill vest in connection with the 2017-2019 long-term monetary incentive plan.
Reconciliation of the weighted average number of shares used for the calculation for both basic and diluted earnings at the reporting date.per share was as follows: | | | | | | | | | | | | | | 2019 | | | 2018 | | | 2017 | | Weighted average number of shares used for basic earnings per share | | | | | | | | 3,592,249,603 | | | | | | 3,601,140,133 | | | | | | 3,601,140,133 | | | Potential shares to be issued for ILT incentive plan | | | | | | | | 2,251,406 | | | | | | 2,782,584 | | | | | | 1,691,413 | | | Weighted average number of shares used for diluted earnings per share | | | | | | | | 3,594,501,009 | | | | | | 3,603,922,717 | | | | | | 3,602,831,546 | | | Eni’s net profit | | | (€million) | | | | | 148 | | | | | | 4,126 | | | | | | 3,374 | | | Basic earnings per share | | | (€ per share) | | | | | 0.04 | | | | | | 1.15 | | | | | | 0.94 | | | Diluted earnings per share | | | (€ per share) | | | | | 0.04 | | | | | | 1.15 | | | | | | 0.94 | | | |
34 Exploration andfor evaluation of oil&gas resources | (€ million) | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Revenues related to exploration activity and evaluation | | | | 1 | | | | | 68 | | | | | 4 | | | | | | 34 | | | | | 17 | | | | | 9 | | | Exploration activity and evaluation costs | | | | | | | | | | | | | | | | | | | - write-off of exploration and evaluation costs | | | | 1,110 | | | | | 617 | | | | | 170 | | | | | | 214 | | | | | 93 | | | | | 252 | | | - other exploration costs | | | | 368 | | | | | 254 | | | | | 204 | | | | - costs of geological and geophysical studies | | | | | 275 | | | | | 287 | | | | | 273 | | | Exploration expense for the year | | | | 1,478 | | | | | 871 | | | | | 374 | | | | | | 489 | | | | | 380 | | | | | 525 | | | Intangible assets: proved and unproved exploration licence and leasehold property acquisition costs | | | | 1,081 | | | | | 735 | | | | | 1,092 | | | | | | 1,031 | | | | | 1,081 | | | | | 995 | | | Tangible assets: capitalized exploration and evaluation costs | | | | 2,577 | | | | | 2,637 | | | | | 2,818 | | | | | | 1,563 | | | | | 1,267 | | | | | 1,371 | | | Total tangible and intangible assets | | | | 3,658 | | | | | 3,372 | | | | | 3,910 | | | | | | 2,594 | | | | | 2,348 | | | | | 2,366 | | | Provision for decommissioning related to exploration activity and evaluation | | | | 126 | | | | | 131 | | | | | 118 | | | | | | 109 | | | | | 77 | | | | | 81 | | | Exploration expenditure (net cash used in investing activities) | | | | 1,030 | | | | | 566 | | | | | 417 | | | | Exploration expenditure (net cash used in investing activivties) | | | | | 586 | | | | | 463 | | | | | 442 | | | Geological and geophysical costs (cash flow from operating activities) | | | | 368 | | | | | 254 | | | | | 204 | | | | | | 275 | | | | | 287 | | | | | 273 | | | Total exploration effort | | | | 1,398 | | | | | 820 | | | | | 621 | | | | | | 861 | | | | | 750 | | | | | 715 | | | | |
46 Segmental analysis35 Segment information and information by geographic area
Reportable segmentsSegment information
Eni’s segmental reporting reflects the Group’s operating segments, whose results are regularly reviewed by the chief operating decision maker (the CEO) to make decisions about resources to be allocated to each segment and to assess segment performance. Segment performance is evaluated based on operating profit or loss. Other segment information presented to the CEO include segment revenues and directly attributable assets and liabilities. Due to cessation of classification of the Chemical business as held for sale and the requirements that financial statements must be amended retrospectively to the date of initial classification (December 31, 2015) as though this disposal group never qualified as held for sale, the Group segmental reporting has been restated accordingly. The results of the Chemical business were aggregated with Refining & Marketing in a single reportable segment because these two operating segments exhibit similar economic characteristics. Furthermore, results of the E&P segment were restated following adoption of the Successful Efforts Method (SEM) (see note 1 – Basis of preparation).
As of December 31, 2016,2019, Eni had the following reportable segments: •
Exploration & Production:Production is engaged: engages in exploring forthe research, development and recoveringproduction of crude oil and natural gas, including participationprojects to projects for thebuild and operate liquefaction plants of natural gas;LNG; •
Gas & Power: is engagedengages in supply and marketing of natural gas at wholesale and retail markets, supply and marketing of LNG and supply, production and marketing of power at retail and wholesale markets. Gas & Power is also engaged in supply and marketing of crude oil and oil products targeting the operational requirements of Eni’s refining business and in energy commodity trading (including crude oil, natural gas, oil products, power, emission allowances, etc.) targeting to both hedge and stabilize the GroupGroup’s industrial and commercial margins according to an integrated view and to optimize margins.
•
Refining & Marketing and Chemical:Chemical is engaged: engages in the manufacturing, supply and distribution and marketing activities forof oil products and chemical products. The results of the Chemicals business have been aggregated to those of the Refining & Marketing business in a single reportable segment, because these two operating segments exhibit similar economic characteristics. •
Corporate and other activities:Other activities represents: include the key supportcosts of the Group HQ functions which provide services to the operating subsidiaries, comprising holdingsholding, financing and treasury, headquarters, central functions like IT, HR, real estate, legal assistance, captive insurance, activities, as well as the results of the Group environmental cleanupclean-up and remediation activities performed by the subsidiary Syndial.Eni Rewind SpA (former Syndial SpA). The Energy Solutions Department, which engages in developing the business of renewable energy business, is an operating segment, which is reported within Corporate and otherOther activities because it does not meet the materiality threshold set by IFRS 8 for separate segment reporting.
Information by segmental reportingsegment is the following:as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Discontinued operations | | | | | | | | | | | | | | | (€ million) | | | Exploration & Production | | | Gas & Power | | | Refining & Marketing and Chemical | | | Engineering & Construction | | | Corporate and other activities | | | Adjustments of intragroup profits | | | Total | | | Engineering & Construction | | | Intragroup eliminations | | | Continuing operations | | | | | | | | 2014 | | | | | | | | | | | | | | | | | | Net sales from operations(a) | | | | | 28,488 | | | | | | 73,434 | | | | | | 28,994 | | | | | | 12,873 | | | | | | 1,429 | | | | | | 54 | | | | | | | | | | | | | Less: intersegment sales | | | | | (16,618) | | | | | | (14,251) | | | | | | (2,042) | | | | | | (1,244) | | | | | | (1,270) | | | | | | | | | | | | | | Net sales to customers | | | | | 11,870 | | | | | | 59,183 | | | | | | 26,952 | | | | | | 11,629 | | | | | | 159 | | | | | | 54 | | | | | | 109,847 | | | | | | (11,629) | | | | | | | | | | | | 98,218 | | | | | | | | | Operating profit | | | | | 10,727 | | | | | | 64 | | | | | | (2,811) | | | | | | 18 | | | | | | (518) | | | | | | 398 | | | | | | 7,878 | | | | | | (18) | | | | | | 1,105 | | | | | | 8,965 | | | | | | | | | Net provisions for contingencies | | | | | 29 | | | | | | (26) | | | | | | 152 | | | | | | 154 | | | | | | 188 | | | | | | (3) | | | | | | 494 | | | | | | (154) | | | | | | | | | | | | 340 | | | | | | | | | Depreciation and amortization | | | | | 6,916 | | | | | | 335 | | | | | | 381 | | | | | | 737 | | | | | | 70 | | | | | | (26) | | | | | | 8,413 | | | | | | (737) | | | | | | | | | | | | 7,676 | | | | | | | | | Net Impairments/reversal | | | | | 851 | | | | | | 25 | | | | | | 380 | | | | | | 420 | | | | | | 14 | | | | | | | | | | | | 1,690 | | | | | | (420) | | | | | | | | | | | | 1,270 | | | | | | | | | Write-off | | | | | 1,197 | | | | | | | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | 1,198 | | | | | | | | | | | | | | | | | | 1,198 | | | | | | | | | Share of profit (loss) of equity-accounted investments | | | | | 62 | | | | | | 42 | | | | | | 4 | | | | | | 21 | | | | | | 2 | | | | | | | | | | | | 131 | | | | | | (21) | | | | | | | | | | | | 110 | | | | | | | | | Identifiable assets(b) | | | | | 72,917 | | | | | | 19,342 | | | | | | 13,313 | | | | | | 14,210 | | | | | | 1,300 | | | | | | (486) | | | | | | 120,596 | | | | | | | | | | | | | | | | | | | | | | | | | | | Unallocated assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 29,770 | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity-accounted investments | | | | | 2,016 | | | | | | 772 | | | | | | 228 | | | | | | 120 | | | | | | 36 | | | | | | | | | | | | 3,172 | | | | | | | | | | | | | | | | | | | | | | | | | | | Identifiable liabilities(c) | | | | | 19,152 | | | | | | 12,141 | | | | | | 4,093 | | | | | | 6,171 | | | | | | 3,903 | | | | | | (165) | | | | | | 45,295 | | | | | | | | | | | | | | | | | | | | | | | | | | | Unallocated liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 39,430 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital expenditure | | | | | 10,156 | | | | | | 172 | | | | | | 819 | | | | | | 694 | | | | | | 113 | | | | | | (82) | | | | | | 11,872 | | | | | | | | | | | | | | | | | | | | | | | | | | | 2015 | | | | | | | | | | | | | | | | | | Net sales from operations(a) | | | | | 21,436 | | | | | | 52,096 | | | | | | 22,639 | | | | | | 11,507 | | | | | | 1,468 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Less: intersegment sales | | | | | (12,115) | | | | | | (9,917) | | | | | | (2,007) | | | | | | (1,243) | | | | | | (1,314) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net sales to customers | | | | | 9,321 | | | | | | 42,179 | | | | | | 20,632 | | | | | | 10,264 | | | | | | 154 | | | | | | | | | | | | 82,550 | | | | | | (10,264) | | | | | | | | | | | | 72,286 | | | | | | | | | Operating profit | | | | | (959) | | | | | | (1,258) | | | | | | (1,567) | | | | | | (694) | | | | | | (497) | | | | | | (23) | | | | | | (4,998) | | | | | | 694 | | | | | | 1,228 | | | | | | (3,076) | | | | | | | | | Net provisions for contingencies | | | | | 221 | | | | | | 41 | | | | | | 148 | | | | | | 104 | | | | | | 226 | | | | | | 8 | | | | | | 748 | | | | | | (104) | | | | | | | | | | | | 644 | | | | | | | | | Depreciation and amortization | | | | | 8,080 | | | | | | 363 | | | | | | 454 | | | | | | 618 | | | | | | 71 | | | | | | (28) | | | | | | 9,558 | | | | | | (618) | | | | | | | | | | | | 8,940 | | | | | | | | | Net Impairments/reversal | | | | | 5,212 | | | | | | 152 | | | | | | 1,150 | | | | | | 590 | | | | | | 20 | | | | | | | | | | | | 7,124 | | | | | | (590) | | | | | | | | | | | | 6,534 | | | | | | | | | Write-off | | | | | 686 | | | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 688 | | | | | | | | | | | | | | | | | | 688 | | | | | | | | | Share of profit (loss) of equity-accounted investments | | | | | (446) | | | | | | (2) | | | | | | (20) | | | | | | 17 | | | | | | (3) | | | | | | | | | | | | (454) | | | | | | (17) | | | | | | | | | | | | (471) | | | | | | | | | Identifiable assets(b) | | | | | 73,073 | | | | | | 14,290 | | | | | | 10,483 | | | | | | 13,608 | | | | | | 1,117 | | | | | | (543) | | | | | | 112,028 | | | | | | | | | | | | | | | | | | | | | | | | | | | Unallocated assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 26,973 | | | | | | | | | | | | Equity-accounted investments | | | | | 1,884 | | | | | | 690 | | | | | | 243 | | | | | | 134 | | | | | | 36 | | | | | | | | | | | | 2,987 | | | | | | (134) | | | | | | | | | | | | 2,853 | | | | | | | | | Identifiable liabilities(c) | | | | | 17,742 | | | | | | 9,313 | | | | | | 3,657 | | | | | | 5,861 | | | | | | 3,824 | | | | | | (199) | | | | | | 40,198 | | | | | | | | | | | | | | | | | | | | | | | | | | | Unallocated liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 41,394 | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital expenditure | | | | | 9,980 | | | | | | 154 | | | | | | 628 | | | | | | 561 | | | | | | 64 | | | | | | (85) | | | | | | 11,302 | | | | | | | | | | | | | | | | | | | | | | 2016 | | | | | | | | | | | | | | | | | | Net sales from operations(a) | | | | | 16,089 | | | | | | 40,961 | | | | | | 18,733 | | | | | | | | | | | | 1,343 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Less: intersegment sales | | | | | (9,711) | | | | | | (8,898) | | | | | | (1,605) | | | | | | | | | | | | (1,150) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net sales to customers | | | | | 6,378 | | | | | | 32,063 | | | | | | 17,128 | | | | | | | | | | | | 193 | | | | | | | | | | | | 55,762 | | | | | | | | | | | | | | | | | | 55,762 | | | | | | | | | Operating profit | | | | | 2,567 | | | | | | (391) | | | | | | 723 | | | | | | | | | | | | (681) | | | | | | (61) | | | | | | 2,157 | | | | | | | | | | | | | | | | | | 2,157 | | | | | | | | | Net provisions for contingencies | | | | | 123 | | | | | | 50 | | | | | | 171 | | | | | | | | | | | | 438 | | | | | | (277) | | | | | | 505 | | | | | | | | | | | | | | | | | | 505 | | | | | | | | | Depreciation and amortization | | | | | 6,772 | | | | | | 354 | | | | | | 389 | | | | | | | | | | | | 72 | | | | | | (28) | | | | | | 7,559 | | | | | | | | | | | | | | | | | | 7,559 | | | | | | | | | Net Impairments/reversal | | | | | (700) | | | | | | 81 | | | | | | 104 | | | | | | | | | | | | 40 | | | | | | | | | | | | (475) | | | | | | | | | | | | | | | | | | (475) | | | | | | | | | Write-off | | | | | 153 | | | | | | 2 | | | | | | 195 | | | | | | | | | | | | | | | | | | | | | | | | 350 | | | | | | | | | | | | | | | | | | 350 | | | | | | | | | Share of profit (loss) of equity-accounted investments | | | | | (198) | | | | | | 19 | | | | | | (3) | | | | | | | | | | | | (144) | | | | | | | | | | | | (326) | | | | | | | | | | | | | | | | | | (326) | | | | | | | | | Identifiable assets(b) | | | | | 75,716 | | | | | | 12,014 | | | | | | 10,712 | | | | | | | | | | | | 1,146 | | | | | | (520) | | | | | | 99,068 | | | | | | | | | | | | | | | | | | | | | | | | | | | Unallocated assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 25,477 | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity-accounted investments | | | | | 1,626 | | | | | | 592 | | | | | | 289 | | | | | | | | | | | | 1,533 | | | | | | | | | | | | 4,040 | | | | | | | | | | | | | | | | | | | | | | | | | | | Identifiable liabilities(c) | | | | | 17,433 | | | | | | 8,923 | | | | | | 3,968 | | | | | | | | | | | | 3,939 | | | | | | (332) | | | | | | 33,931 | | | | | | | | | | | | | | | | | | | | | | | | | | | Unallocated liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 37,528 | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital expenditure | | | | | 8,254 | | | | | | 120 | | | | | | 664 | | | | | | | | | | | | 55 | | | | | | 87 | | | | | | 9,180 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(€ million) | | | Exploration & Production | | | Gas & Power | | | Refining & Marketing and Chemical | | | Corporate and Other activities | | | Adjustments of intragroup profits | | | Total | | 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales from operations including intersegment sales | | | | | 23,572 | | | | | | 50,015 | | | | | | 23,334 | | | | | | 1,681 | | | | | | | | | | | | | | | Less: intersegment sales | | | | | (13,073) | | | | | | (11,855) | | | | | | (2,317) | | | | | | (1,476) | | | | | | | | | | | | | | | Sales from operations | | | | | 10,499 | | | | | | 38,160 | | | | | | 21,017 | | | | | | 205 | | | | | | | | | | | | 69,881 | | | Operating profit | | | | | 7,417 | | | | | | 699 | | | | | | (854) | | | | | | (710) | | | | | | (120) | | | | | | 6,432 | | | Net provisions for contingencies | | | | | 97 | | | | | | 232 | | | | | | 273 | | | | | | 307 | | | | | | (51) | | | | | | 858 | | | Depreciation and amortization | | | | | (7,060) | | | | | | (447) | | | | | | (485) | | | | | | (146) | | | | | | 32 | | | | | | (8,106) | | | Impairments of tangible and intangible assets and right-of-use assets | | | | | (1,347) | | | | | | (83) | | | | | | (1,127) | | | | | | (13) | | | | | | | | | | | | (2,570) | | | Reversals of tangible and intangible assets | | | | | 130 | | | | | | 46 | | | | | | 205 | | | | | | 1 | | | | | | | | | | | | 382 | | | Write-off of tangible and intangible assets | | | | | (292) | | | | | | (1) | | | | | | (6) | | | | | | (1) | | | | | | | | | | | | (300) | | | Share of profit (loss) of equity-accounted investments | | | | | 7 | | | | | | (11) | | | | | | (63) | | | | | | (21) | | | | | | | | | | | | (88) | | | Identifiable assets(a) | | | | | 68,915 | | | | | | 9,176 | | | | | | 12,336 | | | | | | 1,860 | | | | | | (492) | | | | | | 91,795 | | | Unallocated assets(b) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 31,645 | | | Equity-accounted investments | | | | | 4,108 | | | | | | 487 | | | | | | 3,107 | | | | | | 1,333 | | | | | | | | | | | | 9,035 | | | Identifiable liabilities(c) | | | | | 20,164 | | | | | | 7,852 | | | | | | 4,599 | | | | | | 3,927 | | | | | | (141) | | | | | | 36,401 | | | Unallocated liabilities(d) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 39,139 | | | Capital expenditure in tangible and intangible assets and prepaid right-of-use assets | | | | | 6,996 | | | | | | 230 | | | | | | 933 | | | | | | 231 | | | | | | (14) | | | | | | 8,376 | | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales from operations including intersegment sales | | | | | 25,744 | | | | | | 55,690 | | | | | | 25,216 | | | | | | 1,589 | | | | | | | | | | | | | | | Less: intersegment sales | | | | | (15,801) | | | | | | (12,581) | | | | | | (2,622) | | | | | | (1,413) | | | | | | | | | | | | | | | Sales from operations | | | | | 9,943 | | | | | | 43,109 | | | | | | 22,594 | | | | | | 176 | | | | | | | | | | | | 75,822 | | | Operating profit | | | | | 10,214 | | | | | | 629 | | | | | | (380) | | | | | | (691) | | | | | | 211 | | | | | | 9,983 | | | Net provisions for contingencies | | | | | 235 | | | | | | 53 | | | | | | 274 | | | | | | 579 | | | | | | (21) | | | | | | 1,120 | | | Depreciation and amortization | | | | | (6,152) | | | | | | (408) | | | | | | (399) | | | | | | (59) | | | | | | 30 | | | | | | (6,988) | | | Impairments of tangible and intangible assets | | | | | (1,025) | | | | | | (56) | | | | | | (193) | | | | | | (18) | | | | | | | | | | | | (1,292) | | | Reversals of tangible and intangible assets | | | | | 299 | | | | | | 127 | | | | | | | | | | | | | | | | | | | | | | | | 426 | | | Write-off of tangible and intangible assets | | | | | (97) | | | | | | (1) | | | | | | (2) | | | | | | | | | | | | | | | | | | (100) | | | Share of profit (loss) of equity-accounted investments | | | | | 158 | | | | | | 9 | | | | | | (67) | | | | | | (168) | | | | | | | | | | | | (68) | | | Identifiable assets(a) | | | | | 63,051 | | | | | | 9,989 | | | | | | 11,692 | | | | | | 1,171 | | | | | | (420) | | | | | | 85,483 | | | Unallocated assets(b) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 32,890 | | | Equity-accounted investments | | | | | 4,972 | | | | | | 494 | | | | | | 275 | | | | | | 1,303 | | | | | | | | | | | | 7,044 | | | Identifiable liabilities(c) | | | | | 18,110 | | | | | | 8,314 | | | | | | 4,319 | | | | | | 4,072 | | | | | | (275) | | | | | | 34,540 | | | Unallocated liabilities(d) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 32,760 | | | Capital expenditure in tangible and intangible assets | | | | | 7,901 | | | | | | 215 | | | | | | 877 | | | | | | 143 | | | | | | (17) | | | | | | 9,119 | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sales from operations including intersegment sales | | | | | 19,525 | | | | | | 50,623 | | | | | | 22,107 | | | | | | 1,462 | | | | | | | | | | | | | | | Less: intersegment sales | | | | | (12,394) | | | | | | (10,777) | | | | | | (2,336) | | | | | | (1,291) | | | | | | | | | | | | | | | Sales from operations | | | | | 7,131 | | | | | | 39,846 | | | | | | 19,771 | | | | | | 171 | | | | | | | | | | | | 66,919 | | | Operating profit | | | | | 7,651 | | | | | | 75 | | | | | | 981 | | | | | | (668) | | | | | | (27) | | | | | | 8,012 | | | Net provisions for contingencies | | | | | 479 | | | | | | (20) | | | | | | 182 | | | | | | 245 | | | | | | | | | | | | 886 | | | Depreciation and amortization | | | | | (6,747) | | | | | | (345) | | | | | | (360) | | | | | | (60) | | | | | | 29 | | | | | | (7,483) | | | Impairments of tangible and intangible assets | | | | | (650) | | | | | | (56) | | | | | | (131) | | | | | | (25) | | | | | | | | | | | | (862) | | | Reversals of tangible and intangible assets | | | | | 808 | | | | | | 202 | | | | | | 77 | | | | | | | | | | | | | | | | | | 1,087 | | | Write-off of tangible and intangible assets | | | | | (260) | | | | | | (2) | | | | | | (1) | | | | | | | | | | | | | | | | | | (263) | | | Share of profit (loss) of equity-accounted investments | | | | | (99) | | | | | | (10) | | | | | | (57) | | | | | | (101) | | | | | | | | | | | | (267) | | | Identifiable assets(a) | | | | | 66,661 | | | | | | 11,058 | | | | | | 11,599 | | | | | | 1,108 | | | | | | (610) | | | | | | 89,816 | | | Unallocated assets(b) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 25,112 | | | Equity-accounted investments | | | | | 1,234 | | | | | | 509 | | | | | | 321 | | | | | | 1,447 | | | | | | | | | | | | 3,511 | | | Identifiable liabilities(c) | | | | | 17,273 | | | | | | 8,851 | | | | | | 4,005 | | | | | | 4,053 | | | | | | (306) | | | | | | 33,876 | | | Unallocated liabilities(d) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 32,973 | | | Capital expenditure in tangible and intangible assets | | | | | 7,739 | | | | | | 142 | | | | | | 729 | | | | | | 87 | | | | | | (16) | | | | | | 8,681 | | |
(a)
Before eliminationInclude assets directly associated with the generation of intersegment sales.operating profit.
(b)
IncludesInclude assets not directly associated with the generation of operating profit.
(c)
IncludesInclude liabilities directly associated with the generation of operating profit.
(d)
Include liabilities not directly associated with the generation of operating profit.
Financial informationInformation by geographical area
Identifiable assets and investments by geographical area of origin (€ million) | | Italy | | Other European Union | | Rest of Europe | | Americas | | Asia | | Africa | | Other areas | | Total | | | Italy | | Other European Union | | Rest of Europe | | Americas | | Asia | | Africa | | Other areas | | Total | | 2014 | | | | 2019 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Identifiable assets(a) | | | | | 19,346 | | | | | 7,237 | | | | | 1,151 | | | | | 5,230 | | | | | 17,898 | | | | | 40,021 | | | | | 912 | | | | | 91,795 | | | Capital expenditure in tangible and intangible assets and prepaid right-of-use assets | | | | | 1,402 | | | | | 306 | | | | | 9 | | | | | 1,017 | | | | | 1,685 | | | | | 3,902 | | | | | 55 | | | | | 8,376 | | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Identifiable assets(a) | | | | 26,722 | | | | | 15,254 | | | | | 9,099 | | | | | 8,559 | | | | | 21,105 | | | | | 37,976 | | | | | 1,881 | | | | | 120,596 | | | | | | 18,646 | | | | | 7,086 | | | | | 1,031 | | | | | 4,546 | | | | | 16,910 | | | | | 36,155 | | | | | 1,109 | | | | | 85,483 | | | Capital expenditure in tangible and intangible assets | | | | 1,757 | | | | | 827 | | | | | 1,378 | | | | | 1,165 | | | | | 1,904 | | | | | 4,689 | | | | | 152 | | | | | 11,872 | | | | | | 1,424 | | | | | 267 | | | | | 538 | | | | | 534 | | | | | 1,782 | | | | | 4,533 | | | | | 41 | | | | | 9,119 | | | 2015 | | | | 2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Identifiable assets(a) | | | | 21,360 | | | | | 12,370 | | | | | 7,937 | | | | | 7,442 | | | | | 22,359 | | | | | 38,927 | | | | | 1,633 | | | | | 112,028 | | | | | | 18,449 | | | | | 7,706 | | | | | 6,160 | | | | | 4,406 | | | | | 16,527 | | | | | 35,385 | | | | | 1,183 | | | | | 89,816 | | | Capital expenditure in tangible and intangible assets | | | | 1,320 | | | | | 708 | | | | | 1,151 | | | | | 727 | | | | | 2,326 | | | | | 5,020 | | | | | 50 | | | | | 11,302 | | | | | | 1,090 | | | | | 316 | | | | | 387 | | | | | 278 | | | | | 898 | | | | | 5,699 | | | | | 13 | | | | | 8,681 | | | 2016 | | | | Identifiable assets(a) | | | | 18,769 | | | | | 7,370 | | | | | 6,960 | | | | | 5,397 | | | | | 19,471 | | | | | 39,812 | | | | | 1,289 | | | | | 99,068 | | | | Capital expenditure in tangible and intangible assets | | | | 1,163 | | | | | 331 | | | | | 460 | | | | | 233 | | | | | 1,978 | | | | | 5,004 | | | | | 11 | | | | | 9,180 | | | | | |
(a)
IncludesInclude assets directly associated with the generation of operating profit.
Sales from operations by geographical area of destination | (€ million) | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | Italy | | | | 29,234 | | | | | 24,405 | | | | | 21,280 | | | | | | 23,312 | | | | | 25,279 | | | | | 21,925 | | | Other European Union | | | | 29,298 | | | | | 20,730 | | | | | 15,808 | | | | | | 18,567 | | | | | 20,408 | | | | | 19,791 | | | Rest of Europe | | | | 11,975 | | | | | 7,125 | | | | | 4,804 | | | | | | 6,931 | | | | | 7,052 | | | | | 5,911 | | | Americas | | | | 5,763 | | | | | 4,217 | | | | | 3,212 | | | | | | 3,842 | | | | | 5,051 | | | | | 5,154 | | | Asia | | | | 12,840 | | | | | 9,086 | | | | | 5,619 | | | | | | 8,102 | | | | | 9,585 | | | | | 7,523 | | | Africa | | | | 8,786 | | | | | 6,482 | | | | | 4,865 | | | | | | 8,998 | | | | | 8,246 | | | | | 6,428 | | | Other areas | | | | 322 | | | | | 241 | | | | | 174 | | | | | | 129 | | | | | 201 | | | | | 187 | | | | | | | 98,218 | | | | | 72,286 | | | | | 55,762 | | | | | | 69,881 | | | | | 75,822 | | | | | 66,919 | | | | |
4736 Transactions with related parties
In the ordinary course of its business, Eni enters into transactions regarding: (a)
exchangePurchase/supply of goods and services and the provision of services and financing withto joint ventures, associates and non-consolidated subsidiaries;
(b)
exchangePurchase/supply of goods and provision of services withto entities controlled by the Italian Government;
(c)
relations with Vodafone Italia SpAPurchase/supply of goods and services to companies related to Eni SpA through a membermembers of the Board of Directors. TheseMost of these transactions mainly involve costs for mobile communication services for €7 million, awarded following a competitive procedure, and therefore exemptedare exempt from the application of the Eni internal procedure of Eni “Transactions involving interests of Directors and Statutory Auditors and transactions with related parties” pursuant to the Consob Regulation, since they relate to ordinary transactions conducted at market or if not exempted,standard conditions, or because they fall below the materiality threshold provided for by the procedure. The solely non-exempted transaction, that was positively evaluatedexamined and valued in accordanceapplication of the procedure, concerned the remote monitoring of cars in the “enjoy” initiative (for an amount of about €1 million) conducted with such procedure;Vodafone Italia SpA related to Eni SpA through of a member of the Board of Directors; and
(d)
contributions to non-profit entities with a non-company form referablecorrelated to Eni with the aim to develop solidarity, culture and research initiatives. In particular these related to: (i) Eni Foundation, established by Eni as a non-profit entity with the aim of pursuing exclusively solidarity initiatives in the fields of social assistance, health, education, culture and environment, as well as researchscientific and development;technological research; and (ii) Eni Enrico Mattei Foundation, established by Eni with the aim of enhancing, through studies, research and training initiatives, knowledge enrichment in the fields of economics, energy and environment, both at the national and international level. Transactions with related parties were conducted in the interest of Eni companies and, with exception of those with entities whose aim is to develop charitable, cultural and research initiatives, are related to the ordinary course of Eni’s business.
TradeTransactions and other transactionsbalances with related parties
(€ million) | | December 31, 2014 | | 2014 | | | December 31, 2019 | | 2019 | | | | Receivables and other assets | | Payables and other liabilities | | Guarantees | | Costs | | Revenues | | | Other operating (expense) income | | | Name | | | | | | | | | | | | | | | | | Goods | | Services | | Other | | Goods | | Services | | Other | | | Receivables and other assets | | Payables and other liabilities | | Guarantees | | Revenues | | Costs | | Other operating (expense) income | | Continuing operations | | | | Joint ventures and associates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Agiba Petroleum Co | | | | 2 | | | | | 60 | | | | | | | | | | | | | | | 169 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3 | | | | | 71 | | | | | | | | | | | | | | | 229 | | | | | | | | CEPAV (Consorzio Eni per l’Alta Velocità) Due | | | | 120 | | | | | 152 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | CEPAV (Consorzio Eni per l’Alta Velocità) Uno | | | | 23 | | | | | 12 | | | | | 6,122 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | EnBW Eni Verwaltungsgesellschaft mbH | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 134 | | | | | 2 | | | | | | | | | | | | | | InAgip doo | | | | 52 | | | | | 11 | | | | | | | | | | | | | | | 44 | | | | | | | | | | 1 | | | | | 7 | | | | | | | | | | | | | | Angola LNG Supply Services Llc | | | | | | | | | | | | | | | 181 | | | | | | | | | | | | | | | | | | Coral FLNG SA | | | | | 15 | | | | | | | | | | 1,168 | | | | | 71 | | | | | | | | | | | | | Gas Distribution Company of Thessaloniki - Thessaly SA | | | | | | | | | | 13 | | | | | | | | | | | | | | | 53 | | | | | | | | Saipem Group | | | | | 75 | | | | | 227 | | | | | 510 | | | | | 27 | | | | | 503 | | | | | | | | Karachaganak Petroleum Operating BV | | | | 43 | | | | | 233 | | | | | | | | | | 1,246 | | | | | 320 | | | | | 22 | | | | | | | | | | 20 | | | | | | | | | | | | | | | | 33 | | | | | 198 | | | | | | | | | | 1 | | | | | 1,134 | | | | | | | | KWANDA - Suporte Logistico Lda | | | | 68 | | | | | 15 | | | | | Mellitah Oil & Gas BV | | | | 98 | | | | | 58 | | | | | | | | | | 10 | | | | | 235 | | | | | | | | | | | | | | | 7 | | | | | | | | | | | | | | | | 57 | | | | | 171 | | | | | | | | | | 3 | | | | | 365 | | | | | | | | Petrobel Belayim Petroleum Co | | | | 32 | | | | | 375 | | | | | | | | | | | | | | | 603 | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | | | | | 50 | | | | | 1,130 | | | | | | | | | | 7 | | | | | 1,590 | | | | | | | | Petromar Lda | | | | 93 | | | | | 4 | | | | | 21 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | South Stream Transport BV | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | Unión Fenosa Gas Comercializadora SA | | | | 15 | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | 157 | | | | | | | | | | | | | | | | | | | Unión Fenosa Gas SA | | | | | | | | | | | | | | 57 | | | | | | | | | | 1 | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | 8 | | | | | 1 | | | | | 57 | | | | | 1 | | | | | 6 | | | | | 63 | | | Vår Energi AS | | | | | 32 | | | | | 143 | | | | | 482 | | | | | 63 | | | | | 1,481 | | | | | (64) | | | Other(*) | | | | 122 | | | | | 67 | | | | | | | | | | 17 | | | | | 132 | | | | | 18 | | | | | 95 | | | | | 61 | | | | | 15 | | | | | | | 106 | | | | | 29 | | | | | 1 | | | | | 112 | | | | | 87 | | | | | | | | | | | | 668 | | | | | 988 | | | | | 6,200 | | | | | 1,273 | | | | | 1,504 | | | | | 41 | | | | | 387 | | | | | 99 | | | | | 16 | | | | | | | 379 | | | | | 1,983 | | | | | 2,399 | | | | | 285 | | | | | 5,448 | | | | | (1) | | | Unconsolidated entities controlled by Eni | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Agip Kazakhstan North Caspian Operating Co NV | | | | | | | | | | | | | | | | | | | | | | | | 342 | | | | | 7 | | | | | | | | | | 32 | | | | | 2 | | | | | | | | | Eni BTC Ltd | | | | | | | | | | | | | | 167 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 180 | | | | | | | | | | | | | | | | | | Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) | | | | 61 | | | | | 1 | | | | | 10 | | | | | | | | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | | | | | 101 | | | | | 1 | | | | | 3 | | | | | 14 | | | | | | | | | | | | | Other(*) | | | | 13 | | | | | 52 | | | | | 1 | | | | | | | | | | 11 | | | | | | | | | | 4 | | | | | 2 | | | | | 4 | | | | | Other | | | | | 5 | | | | | 25 | | | | | 14 | | | | | 6 | | | | | 18 | | | | | | | | | | | | 74 | | | | | 53 | | | | | 178 | | | | | | | | | | 353 | | | | | 7 | | | | | 4 | | | | | 37 | | | | | 6 | | | | | | | 106 | | | | | 26 | | | | | 197 | | | | | 20 | | | | | 18 | | | | | | | | | | | | 742 | | | | | 1,041 | | | | | 6,378 | | | | | 1,273 | | | | | 1,857 | | | | | 48 | | | | | 391 | | | | | 136 | | | | | 22 | | | | | | | 485 | | | | | 2,009 | | | | | 2,596 | | | | | 305 | | | | | 5,466 | | | | | (1) | | | Entities controlled by the Government | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Enel Group | | | | 156 | | | | | 122 | | | | | | | | | | | | | | | 933 | | | | | | | | | | 181 | | | | | 133 | | | | | 1 | | | | | 183 | | | | | | 185 | | | | | 284 | | | | | | | | | | 105 | | | | | 602 | | | | | (8) | | | Italgas Group | | | | | 3 | | | | | 154 | | | | | | | | | | 1 | | | | | 677 | | | | | | | | Snam Group | | | | 147 | | | | | 585 | | | | | 7 | | | | | 155 | | | | | 1,867 | | | | | 5 | | | | | 235 | | | | | 33 | | | | | | | | | | 13 | | | | | | 278 | | | | | 229 | | | | | | | | | | 71 | | | | | 1,208 | | | | | | | | Terna Group | | | | 33 | | | | | 65 | | | | | | | | | | 89 | | | | | 154 | | | | | 7 | | | | | 120 | | | | | 35 | | | | | 44 | | | | | 12 | | | | | | 40 | | | | | 45 | | | | | | | | | | 171 | | | | | 223 | | | | | 17 | | | GSE - Gestore Servizi Energetici | | | | 88 | | | | | 124 | | | | | | | | | | 580 | | | | | 2 | | | | | 60 | | | | | 172 | | | | | 14 | | | | | | | | | | | | | | | | 26 | | | | | 24 | | | | | | | | | | 549 | | | | | 468 | | | | | 11 | | | Other(*) | | | | 44 | | | | | 93 | | | | | | | | | | 8 | | | | | 98 | | | | | 3 | | | | | 45 | | | | | 2 | | | | | 2 | | | | | | Other | | | | | 10 | | | | | 19 | | | | | | | | | | 12 | | | | | 35 | | | | | | | | | | | | 468 | | | | | 989 | | | | | 7 | | | | | 832 | | | | | 3,054 | | | | | 75 | | | | | 753 | | | | | 217 | | | | | 47 | | | | | 208 | | | | | | 542 | | | | | 755 | | | | | | | | | | 909 | | | | | 3,213 | | | | | 20 | | | Pension funds and foundations | | | | | | | | | 2 | | | | | | | | | | | | | | | 4 | | | | | 60 | | | | | Other related parties | | | | | 2 | | | | | 3 | | | | | | | | | | 5 | | | | | 37 | | | | | | | | Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP» | | | | | 75 | | | | | 74 | | | | | | | | | | 33 | | | | | 457 | | | | | | | | | | | | 1,210 | | | | | 2,032 | | | | | 6,385 | | | | | 2,105 | | | | | 4,915 | | | | | 183 | | | | | 1,144 | | | | | 353 | | | | | 69 | | | | | 208 | | | | | | 1,104 | | | | | 2,841 | | | | | 2,596 | | | | | 1,252 | | | | | 9,173 | | | | | 19 | | | Discontinued operations | | | | | | | | | | | | | | | | | | | | | | | | Joint ventures and associates | | | | CEPAV (Consorzio Eni per l’Alta Velocità) Due | | | | | | | | | | | | | | | | | | | | | | | | 159 | | | | | | | | | | | | | | | 216 | | | | | | | | | | | | | | CEPAV (Consorzio Eni per l’Alta Velocità) Uno | | | | | | | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | | | | 14 | | | | | | | | | | | | | | KWANDA - Suporte Logistico Lda | | | | | | | | | | | | | | | | | | | | | | | | 10 | | | | | | | | | | | | | | | 9 | | | | | | | | | | | | | | Petrobel Belayim Petroleum Co | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 83 | | | | | Petromar Lda | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | 1 | | | | | | | | | | 61 | | | | | | | | | | | | | | South Stream Transport BV | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 495 | | | | | | | | | | | | | | Other(*) | | | | | | | | | | | | | | | | | | | | | | | | 50 | | | | | | | | | | | | | | | 31 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 223 | | | | | 1 | | | | | | | | | | 909 | | | | | | | | | | | | | | Unconsolidated entities controlled by Eni | | | | Agip Kazakhstan North Caspian Operating Co NV | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 155 | | | | | | | | | | | | | | Other(*) | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | | | | 155 | | | | | | | | | | | | | | Entities controlled by the Government | | | | Snam Group | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 39 | | | | | Other(*) | | | | | | | | | | | | | | | | | | | | | | | | 13 | | | | | | | | | | | | | | | 4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 13 | | | | | | | | | | | | | | | 43 | | | | | | | | | | | | | | Pension funds and foundations | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 238 | | | | | 2 | | | | | | | | | | 1,107 | | | | | | | | | | | | | | | | | | 1,210 | | | | | 2,032 | | | | | 6,385 | | | | | 2,105 | | | | | 5,153 | | | | | 185 | | | | | 1,144 | | | | | 1,460 | | | | | 69 | | | | | 208 | | | | | |
(*)
Each individual amount included herein was lower than €50 million. (€ million) | | | December 31, 2018 | | | 2018 | | Name | | | Receivables and other assets | | | Payables and other liabilities | | | Guarantees | | | Revenues | | | Costs | | | Other operating (expense) income | | Joint ventures and associates | | | | | | �� | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Agiba Petroleum Co | | | | | 1 | | | | | | 96 | | | | | | | | | | | | | | | | | | 156 | | | | | | | | | Angola LNG Supply Services Llc | | | | | | | | | | | | | | | | | 177 | | | | | | | | | | | | | | | | | | | | | Coral FLNG SA | | | | | 14 | | | | | | | | | | | | 1,147 | | | | | | 62 | | | | | | | | | | | | | | | Gas Distribution Company of Thessaloniki - Thessaly SA | | | | | 1 | | | | | | 18 | | | | | | | | | | | | | | | | | | 51 | | | | | | | | | Saipem Group | | | | | 75 | | | | | | 171 | | | | | | 793 | | | | | | 30 | | | | | | 420 | | | | | | | | | Karachaganak Petroleum Operating BV | | | | | 27 | | | | | | 134 | | | | | | | | | | | | 1 | | | | | | 998 | | | | | | | | | Mellitah Oil & Gas BV | | | | | 1 | | | | | | 268 | | | | | | | | | | | | 1 | | | | | | 502 | | | | | | | | | Petrobel Belayim Petroleum Co | | | | | 56 | | | | | | 2,029 | | | | | | | | | | | | 7 | | | | | | 2,282 | | | | | | | | | Unión Fenosa Gas SA | | | | | 4 | | | | | | 7 | | | | | | 57 | | | | | | 123 | | | | | | | | | | | | 37 | | | Vår Energi AS | | | | | 13 | | | | | | 100 | | | | | | 218 | | | | | | | | | | | | | | | | | | | | | Other(*) | | | | | 44 | | | | | | 25 | | | | | | | | | | | | 111 | | | | | | 104 | | | | | | (26) | | | | | | | | 236 | | | | | | 2,848 | | | | | | 2,392 | | | | | | 335 | | | | | | 4,513 | | | | | | 11 | | | Unconsolidated entities controlled by Eni | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni BTC Ltd | | | | | | | | | | | | | | | | | 177 | | | | | | | | | | | | | | | | | | | | | Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) | | | | | 87 | | | | | | 1 | | | | | | 5 | | | | | | 11 | | | | | | | | | | | | | | | Other | | | | | 6 | | | | | | 23 | | | | | | 14 | | | | | | 7 | | | | | | 13 | | | | | | | | | | | | | | 93 | | | | | | 24 | | | | | | 196 | | | | | | 18 | | | | | | 13 | | | | | | | | | | | | | | 329 | | | | | | 2,872 | | | | | | 2,588 | | | | | | 353 | | | | | | 4,526 | | | | | | 11 | | | Entities controlled by the Government | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Enel Group | | | | | 134 | | | | | | 151 | | | | | | | | | | | | 118 | | | | | | 514 | | | | | | 227 | | | Italgas Group | | | | | 5 | | | | | | 146 | | | | | | | | | | | | 23 | | | | | | 667 | | | | | | | | | Snam Group | | | | | 237 | | | | | | 289 | | | | | | | | | | | | 109 | | | | | | 1,184 | | | | | | (1) | | | Terna Group | | | | | 26 | | | | | | 47 | | | | | | | | | | | | 150 | | | | | | 231 | | | | | | 8 | | | GSE - Gestore Servizi Energetici | | | | | 67 | | | | | | 85 | | | | | | | | | | | | 555 | | | | | | 588 | | | | | | 74 | | | Other | | | | | 25 | | | | | | 18 | | | | | | | | | | | | 45 | | | | | | 34 | | | | | | | | | | | | | | 494 | | | | | | 736 | | | | | | | | | | | | 1,000 | | | | | | 3,218 | | | | | | 308 | | | Other related parties | | | | | 1 | | | | | | 2 | | | | | | | | | | | | 4 | | | | | | 32 | | | | | | | | | Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP» | | | | | 40 | | | | | | 140 | | | | | | | | | | | | 34 | | | | | | 229 | | | | | | | | | | | | | | 864 | | | | | | 3,750 | | | | | | 2,588 | | | | | | 1,391 | | | | | | 8,005 | | | | | | 319 | | |
(*)
Each individual amount included herein was lower than €50 million.
(€ million) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2015 | | | 2015 | | | | | Receivables and other assets | | | Payables and other liabilities | | | Guarantees | | | Costs | | | Revenues | | | Other operating (expense) income | | Name | | | | | | | | | | | | | | | | | | | | | Goods | | | Services | | | Other | | | Goods | | | Services | | | Other | | Continuing operations | | | | | | | | | | | | Joint ventures and associates | | | | | | | | | | | | Agiba Petroleum Co | | | | | 6 | | | | | | 60 | | | | | | | | | | | | | | | | | | 187 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | CEPAV (Consorzio Eni per l’Alta Velocità) Due | | | | | | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | CEPAV (Consorzio Eni per l’Alta Velocità) Uno | | | | | | | | | | | | | | | | | 6,122 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Karachaganak Petroleum Operating BV | | | | | 48 | | | | | | 171 | | | | | | | | | | | | 748 | | | | | | 403 | | | | | | 8 | | | | | | | | | | | | 10 | | | | | | | | | | | | | | | Mellitah Oil & Gas BV | | | | | 8 | | | | | | 16 | | | | | | | | | | | | 46 | | | | | | 339 | | | | | | | | | | | | | | | | | | 19 | | | | | | | | | | | | | | | Petrobel Belayim Petroleum Co | | | | | 16 | | | | | | 183 | | | | | | | | | | | | | | | | | | 543 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Petromar Lda | | | | | 2 | | | | | | | | | | | | 6 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unión Fenosa Gas SA | | | | | 1 | | | | | | | | | | | | 57 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | Other(*) | | | | | 118 | | | | | | 42 | | | | | | | | | | | | 27 | | | | | | 124 | | | | | | 1 | | | | | | 60 | | | | | | 70 | | | | | | 37 | | | | | | (2) | | | | | | | | 199 | | | | | | 473 | | | | | | 6,185 | | | | | | 821 | | | | | | 1,596 | | | | | | 9 | | | | | | 60 | | | | | | 99 | | | | | | 37 | | | | | | (6) | | | Unconsolidated entities controlled by Eni | | | | | | | | | | | | Eni México S. de RL de CV | | | | | | | | | | | | | | | | | 101 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) | | | | | 65 | | | | | | 1 | | | | | | 9 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | Other(*) | | | | | 17 | | | | | | 19 | | | | | | 3 | | | | | | 2 | | | | | | 2 | | | | | | | | | | | | 4 | | | | | | 2 | | | | | | 2 | | | | | | | | | | | | | | 82 | | | | | | 20 | | | | | | 113 | | | | | | 2 | | | | | | 2 | | | | | | | | | | | | 4 | | | | | | 5 | | | | | | 2 | | | | | | | | | | | | | | 281 | | | | | | 493 | | | | | | 6,298 | | | | | | 823 | | | | | | 1,598 | | | | | | 9 | | | | | | 64 | | | | | | 104 | | | | | | 39 | | | | | | (6) | | | Entities controlled by the Government | | | | | | | | | | | | Enel Group | | | | | 138 | | | | | | 203 | | | | | | | | | | | | | | | | | | 1,063 | | | | | | | | | | | | 196 | | | | | | 134 | | | | | | | | | | | | 90 | | | Snam Group | | | | | 144 | | | | | | 522 | | | | | | 3 | | | | | | 137 | | | | | | 2,014 | | | | | | 5 | | | | | | 249 | | | | | | 24 | | | | | | 1 | | | | | | | | | Terna Group | | | | | 18 | | | | | | 42 | | | | | | | | | | | | 109 | | | | | | 125 | | | | | | 14 | | | | | | 77 | | | | | | 19 | | | | | | 29 | | | | | | 12 | | | GSE - Gestore Servizi Energetici | | | | | 44 | | | | | | 63 | | | | | | | | | | | | 419 | | | | | | 5 | | | | | | 35 | | | | | | 307 | | | | | | 43 | | | | | | | | | | | | | | | Other(*) | | | | | 22 | | | | | | 38 | | | | | | | | | | | | | | | | | | 56 | | | | | | 6 | | | | | | 29 | | | | | | 1 | | | | | | | | | | | | | | | | | | | | 366 | | | | | | 868 | | | | | | 3 | | | | | | 665 | | | | | | 3,263 | | | | | | 60 | | | | | | 858 | | | | | | 221 | | | | | | 30 | | | | | | 102 | | | Pension funds and foundations | | | | | 1 | | | | | | 2 | | | | | | | | | | | | | | | | | | 4 | | | | | | 50 | | | | | | | | | | | | | | | | | | | | | | | | | | | Groupement Sonatrach - Agip and Organe Conjoint des Opérations | | | | | 185 | | | | | | 300 | | | | | | | | | | | | | | | | | | 453 | | | | | | 12 | | | | | | 35 | | | | | | 60 | | | | | | | | | | 833 | | | | | | 1,663 | | | | | | 6,301 | | | | | | 1,488 | | | | | | 5,318 | | | | | | 131 | | | | | | 957 | | | | | | 385 | | | | | | 69 | | | | | | 96 | | | Discontinued operations | | | | | | | | | | | | Joint ventures and associates | | | | | | | | | | | | CEPAV (Consorzio Eni per l’Alta Velocità) Due | | | | | 60 | | | | | | 99 | | | | | | 68 | | | | | | | | | | | | 101 | | | | | | | | | | | | | | | | | | 145 | | | | | | | | | | | | | | | CEPAV (Consorzio Eni per l’Alta Velocità) Uno | | | | | 9 | | | | | | 3 | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | | | | KWANDA - Suporte Logistico Lda | | | | | 69 | | | | | | 10 | | | | | | | | | | | | | | | | | | | | | | | | 5 | | | | | | | | | | | | 8 | | | | | | | | | | | | | | | Mellitah Oil & Gas BV | | | | | 9 | | | | | | | | | | | | | | | | | | | | | | | | 7 | | | | | | | | Petrobel Belayim Petroleum Co | | | | | 19 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 86 | | | | | Petromar Lda | | | | | 97 | | | | | | 16 | | | | | | | | | | | | | | | | | | 16 | | | | | | | | | | | | | | | | | | 45 | | | | | Other(*) | | | | | 14 | | | | | | 27 | | | | | | | | | | | | 10 | | | | | | 54 | | | | | | | | | | | | 1 | | | | | | 21 | | | | | | 1 | | | | | | | | | 277 | | | | | | 155 | | | | | | 68 | | | | | | 10 | | | | | | 181 | | | | | | 5 | | | | | | 1 | | | | | | 306 | | | | | | 1 | | | | Unconsolidated entities controlled by Eni | | | | | | | | | | | | Other(*) | | | | | 1 | | | | | | 1 | | | | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | | 1 | | | | | | 1 | | | | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Entities controlled by the Government | | | | | | | | | | | | Snam Group | | | | | 25 | | | | | | 46 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 36 | | | | | | | | | | | | | | | Other(*) | | | | | | | | | | | 5 | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 25 | | | | | | 51 | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | | | | | | | 36 | | | | | | | | | | | | | | | Pension funds and foundations | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | 303 | | | | | | 207 | | | | | | 68 | | | | | | 10 | | | | | ��� | 186 | | | | | | 6 | | | | | | 1 | | | | | | 342 | | | | | | 1 | | | | | | | | | 1,136 | | | | | | 1,870 | | | | | | 6,369 | | | | | | 1,498 | | | | | | 5,504 | | | | | | 137 | | | | | | 958 | | | | | | 727 | | | | | | 70 | | | | | | 96 | | | |
(*)
Each individual amount included herein was lower than €50 million.
(€ million) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2017 | | 2017 | | | | December 31, 2016 | | 2016 | | | | | Receivables and other assets | | Payables and other liabilities | | Guarantees | | Costs | | Revenues | | | Other operating (expense) income | | | Name | | | | | | | | | | | | | | | | | Goods | | Services | | Other | | Goods | | Services | | Other | | | Receivables and other assets | | Payables and other liabilities | | Guarantees | | Revenues | | Costs | | Other operating (expense) income | | Joint ventures and associates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Agiba Petroleum Co | | | | 1 | | | | | 50 | | | | | | | | | | | | | | | 156 | | | | | | | 1 | | | | | 83 | | | | | | | | | | | | | | | 142 | | | | | | | | Saipem Group | | | | 64 | | | | | 224 | | | | | 8,094 | | | | | | | | | | 775 | | | | | 6 | | | | | 9 | | | | | 37 | | | | | 5 | | | | | Coral FLNG SA | | | | | 20 | | | | | 4 | | | | | 1,094 | | | | | 28 | | | | | | | | | | | | | Karachaganak Petroleum Operating BV | | | | 47 | | | | | 187 | | | | | | | | | | 573 | | | | | 333 | | | | | 12 | | | | | 7 | | | | | 1 | | | | | 19 | | | | | | | 36 | | | | | 121 | | | | | | | | | | | | | | | 951 | | | | | | | | Mellitah Oil & Gas BV | | | | 7 | | | | | 134 | | | | | | | | | | 5 | | | | | 472 | | | | | | | 5 | | | | | 220 | | | | | | | | | | 2 | | | | | 495 | | | | | | | | Petrobel Belayim Petroleum Co | | | | 225 | | | | | 532 | | | | | | | | | | | | | | | 1,940 | | | | | | | | | | | | | | | | | | | | 2 | | | | | | | 86 | | | | | 1,205 | | | | | | | | | | 8 | | | | | 3,168 | | | | | | | | Saipem Group | | | | | 63 | | | | | 76 | | | | | 7,270 | | | | | 44 | | | | | 450 | | | | | | | | Unión Fenosa Gas SA | | | | | | | | | | | | | | 57 | | | | | | | | | | | | | | | | | | | | 93 | | | | | | | | | | 1 | | | | | | | | | | | | | | | | | 57 | | | | | 202 | | | | | 3 | | | | | 28 | | | Other(*) | | | | 114 | | | | | 25 | | | | | 1 | | | | | 32 | | | | | 113 | | | | | | | | | | 86 | | | | | 44 | | | | | 13 | | | | | 47 | | | | | | 84 | | | | | 22 | | | | | | | | | | 128 | | | | | 140 | | | | | | | | | | | | 458 | | | | | 1,152 | | | | | 8,152 | | | | | 610 | | | | | 3,789 | | | | | 18 | | | | | 195 | | | | | 82 | | | | | 40 | | | | | 47 | | | | | | 295 | | | | | 1,731 | | | | | 8,421 | | | | | 412 | | | | | 5,349 | | | | | 28 | | | Unconsolidated entities controlled by Eni | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni BTC Ltd | | | | | | | | | | | | | | 192 | | | | | | | | | | | | | | | | | 169 | | | | | | | | | | | | | | | | | | Industria Siciliana Acido Fosforico - ISAF SpA (in liquidation) | | | | 69 | | | | | 1 | | | | | 3 | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | | | | 77 | | | | | 1 | | | | | 5 | | | | | 7 | | | | | | | | | | | | | Other(*) | | | | 9 | | | | | 16 | | | | | 51 | | | | | 4 | | | | | 4 | | | | | | | | | | 6 | | | | | 2 | | | | | 2 | | | | | Other | | | | | 20 | | | | | 23 | | | | | 7 | | | | | 7 | | | | | 14 | | | | | | | | | | | | 78 | | | | | 17 | | | | | 246 | | | | | 4 | | | | | 4 | | | | | | | | | | 6 | | | | | 4 | | | | | 2 | | | | | | | 97 | | | | | 24 | | | | | 181 | | | | | 14 | | | | | 14 | | | | | | | | | | | | 536 | | | | | 1,169 | | | | | 8,398 | | | | | 614 | | | | | 3,793 | | | | | 18 | | | | | 201 | | | | | 86 | | | | | 42 | | | | | 47 | | | | | | 392 | | | | | 1,755 | | | | | 8,602 | | | | | 426 | | | | | 5,363 | | | | | 28 | | | Entities controlled by the Government | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Enel Group | | | | 151 | | | | | 254 | | | | | | | | | | 28 | | | | | 780 | | | | | | | | | | 88 | | | | | 95 | | | | | 18 | | | | | 182 | | | | | | 123 | | | | | 187 | | | | | | | | | | 164 | | | | | 622 | | | | | 285 | | | GSE - Gestore Servizi Energetici | | | | | 69 | | | | | 219 | | | | | | | | | | 702 | | | | | 506 | | | | | 2 | | | Italgas Group | | | | | 14 | | | | | 180 | | | | | 1 | | | | | 18 | | | | | 681 | | | | | | | | Snam Group | | | | 44 | | | | | 541 | | | | | 1 | | | | | 125 | | | | | 1,902 | | | | | 5 | | | | | 99 | | | | | 14 | | | | | | | 187 | | | | | 351 | | | | | | | | | | 85 | | | | | 1,221 | | | | | | | | Terna Group | | | | 33 | | | | | 46 | | | | | | | | | | 60 | | | | | 165 | | | | | 7 | | | | | 61 | | | | | 56 | | | | | | | | | | 13 | | | | | | 35 | | | | | 31 | | | | | | | | | | 154 | | | | | 212 | | | | | 15 | | | GSE - Gestore Servizi Energetici | | | | 58 | | | | | 32 | | | | | | | | | | 206 | | | | | 5 | | | | | 32 | | | | | 344 | | | | | 68 | | | | | 2 | | | | | 5 | | | | Italgas Group | | | | 54 | | | | | 1 | | | | | | | | | | | | | | | 4 | | | | | Other(*) | | | | 43 | | | | | 24 | | | | | | | | | | | | | | | 37 | | | | | | | | | | 62 | | | | | 6 | | | | | | | | | | | | | | | | 50 | | | | | 21 | | | | | | | | | | 16 | | | | | 38 | | | | | 1 | | | | | | | 383 | | | | | 898 | | | | | 1 | | | | | 419 | | | | | 2,893 | | | | | 44 | | | | | 654 | | | | | 239 | | | | | 20 | | | | | 200 | | | | | | 478 | | | | | 989 | | | | | 1 | | | | | 1,139 | | | | | 3,280 | | | | | 303 | | | Pension funds and foundations | | | | | | | | | 2 | | | | | | | | | | | | | | | 4 | | | | | 28 | | | | | Groupement Sonatrach - Agip and Organe Conjoint des Opérations | | | | 176 | | | | | 331 | | | | | | | | | | 5 | | | | | 413 | | | | | 5 | | | | | | | | | | 58 | | | | | 12 | | | | | Other related parties | | | | | 1 | | | | | 2 | | | | | | | | | | 1 | | | | | 25 | | | | | | | | Groupement Sonatrach - Agip «GSA» and Organe Conjoint des Opérations «OC SH/FCP» | | | | | 39 | | | | | 145 | | | | | | | | | | 42 | | | | | 530 | | | | | | | | | | | | 1,095 | | | | | 2,400 | | | | | 8,399 | | | | | 1,038 | | | | | 7,103 | | | | | 95 | | | | | 855 | | | | | 383 | | | | | 74 | | | | | 247 | | | | | | 910 | | | | | 2,891 | | | | | 8,603 | | | | | 1,608 | | | | | 9,198 | | | | | 331 | | | | |
(*)
Each individual amount included herein was lower than €50 million. The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned: •
Eni’s share of expenses incurred to develop oil fields from Agiba Petroleum Co, Karachaganak Petroleum Operating BV, Mellitah Oil & Gas BV, Petrobel Belayim Petroleum Co, Groupement Sonatrach — Agip «GSA», Organe Conjoint des Opérations «OC SH/FCP» and, only for Karachaganak Petroleum Operating BV, purchase of crude oil products by Eni Trading & Shipping SpA; services charged to Eni’s associates are invoiced on the basis of incurred costs; •
a guarantee issued on behalf of Angola LNG Supply Services Llc to cover the commitments relating to the payment of the regasification fee; •
supply of upstream specialist services and a guarantee issued on a pro-quota basis granted to Coral FLNG SA on behalf of the Consortium TJS for the contractual obligations assumed following the award of the EPCIC contract for the construction of a floating gas liquefaction plant (for more information see note 27 — Guarantees, commitments and risks); •
the acquisition of transport and distribution services from the Gas Distribution Company of Thessaloniki-Thessaly SA; •
engineering, construction and drilling services by the Saipem Group mainly for the Exploration & Production segment and residual guarantees issued by Eni SpA relating to bid bonds and performance bonds; •
a performance guaranteesguarantee given on behalf of Unión Fenosa Gas SA in relation to contractual commitments related to the results of operations and salesfair value of LNG;derivative financial instruments; •
a guarantee issued in compliance with contractual agreements in the interest of Vår Energi AS, the supply of upstream specialist services, the purchase of crude oil, condensates and gas and fair value of derivative financial instruments; •
a guarantee issued in relation to the construction of an oil pipeline on behalf of Eni BTC Ltd; and •
services for environmental restoration to Industria Siciliana Acido Fosforico –— ISAF SpA (in liquidation).
The most significant transactions with entities controlled by the Italian Government concerned: •
sale of diesel fuel, and fuel through payment cards, sale and purchase of gas, environmental certificates, transmissionacquisition of power distribution services and fair value of derivative financial instruments with Enel Group; •
acquisition of natural gas transportation, distribution and storage services with the Snam Group and the Italgas Group on the basis of tariffs set by the Italian Regulatory Authority for Electricity, GasEnergy, Networks and WaterEnvironment and purchase and sale with Snam Group of natural gas for granting the system balancing of the system on the basis of prices referred to the quotations of the main energy commodities; •
sale and purchase of electricity, the acquisition of domestic electricity transmission service and sale and purchase of electricity for granting the system balancing on the basis of prices referred to the quotations of the main energy commodities, and derivatives on commodities entered to hedge the price risk related to the utilization of transport capacity rights with the Terna Group;
•
sale and purchase of electricity, andgas, environmental certificates, fair value of derivative financial instruments, sale of oil products and storage capacity with GSE –— Gestore Servizi Energetici for the setting-up of a specific stock held by the Organismo Centrale di Stoccaggio Italiano (OCSIT) according to the Legislative Decree No. 249/2012. Transactions with pension funds and foundationother related parties concerned: •
provisions to pension funds of €24€30 million; and •
contributions and service provisions to Eni Enrico Mattei Foundation of €4for €6 million and to Eni Enrico Mattei Foundation for €4€1 million. Financing transactions and balances with related parties (€ million) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | | 2014 | | Name | | | Receivables | | | Payables | | | Guarantees | | | Charges | | | Gains | | Continuing operations | | | | | | | Joint ventures and associates | | | | | | | CARDÓN IV SA | | | | | 621 | | | | | | | | | | | | | | | | | | | | | | | | 29 | | | CEPAV (Consorzio Eni per l’Alta Velocità) Due | | | | | | | | | | | | | | | | | 150 | | | | | | | | | | | | 6 | | | Matrìca SpA | | | | | 200 | | | | | | | | | | | | | | | | | | | | | | | | 5 | | | Shatskmorneftegaz Sàrl | | | | | 56 | | | | | | | | | | | | | | | | | | 13 | | | | Société Centrale Electrique du Congo SA | | | | | 84 | | | | | | | | | | | | 2 | | | | | Unión Fenosa Gas SA | | | | | | | | | | | 90 | | | | | | Other(*) | | | | | 48 | | | | | | 13 | | | | | | 19 | | | | | | 28 | | | | | | 4 | | | | | | | | 1,009 | | | | | | 103 | | | | | | 171 | | | | | | 41 | | | | | | 44 | | | Unconsolidated entities controlled by Eni | | | | | | | Other(*) | | | | | 68 | | | | | | 73 | | | | | | 2 | | | | | | | | | | | | 1 | | | | | | | | 68 | | | | | | 73 | | | | | | 2 | | | | | | | | | | | | 1 | | | Entities controlled by the Government | | | | | | | Other(*) | | | | | | | | | | | 5 | | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | | | 5 | | | | | | | | | | | | | | | | | | 1 | | | | | | | | 1,077 | | | | | | 181 | | | | | | 173 | | | | | | 41 | | | | | | 46 | | | |
(*)
Each individual amount included herein was lower than €50 million.
(€ million) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2015 | | | 2015 | | Name | | | Receivables | | | Payables | | | Guarantees | | | Charges | | | Gains | | Continuing operations | | | | | | | Joint ventures and associates | | | | | | | CARDÓN IV SA | | | | | 1,112 | | | | | | | | | | | | | | | | | | | | | | | | 65 | | | Matrìca SpA | | | | | 209 | | | | | | | | | | | | | | | | | | 10 | | | | | | 11 | | | Shatskmorneftegaz Sàrl | | | | | 63 | | | | | | | | | | | | | | | | | | 21 | | | | Société Centrale Electrique du Congo SA | | | | | 94 | | | | | | | Unión Fenosa Gas SA | | | | | | | | | | | 90 | | | | | | Other(*) | | | | | 52 | | | | | | 7 | | | | | | 12 | | | | | | 19 | | | | | | 5 | | | | | | | | 1,530 | | | | | | 97 | | | | | | 12 | | | | | | 50 | | | | | | 81 | | | Unconsolidated entities controlled by Eni | | | | | | | Other(*) | | | | | 51 | | | | | | 111 | | | | | | | | | | | | | | | | | �� | 1 | | | | | | | | 51 | | | | | | 111 | | | | | | | | | | | | | | | | | | 1 | | | Entities controlled by the Government | | | | | | | Other(*) | | | | | 27 | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | | | | 27 | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | | | | 1,608 | | | | | | 208 | | | | | | 12 | | | | | | 50 | | | | | | 83 | | | Discontinued operations | | | | | | | Joint ventures and associates | | | | | | | CEPAV (Consorzio Eni per l’Alta Velocità) Due | | | | | | | | | | | | | | | | | 150 | | | | | Other(*) | | | | | 5 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5 | | | | | | | | | | | | 150 | | | | | | | | | | | | | | | | | | | | 1,613 | | | | | | 208 | | | | | | 162 | | | | | | 50 | | | | | | 83 | | | |
(*)
Each individual amount included herein was lower than €50 million.
(€ million) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2019 | | | 2019 | | Name | | | Receivables | | | Payables | | | Guarantees | | | Gains | | | Charges | | | Joint ventures and associates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Angola LNG Ltd | | | | | | | | | | | | | | | | | 249 | | | | | | | | | | | | | | | | Cardón IV SA | | | | | 563 | | | | | | 5 | | | | | | | | | | | | 77 | | | | | | | | | | Coral FLNG SA | | | | | 253 | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | Coral South FLNG DMCC | | | | | | | | | | | | | | | | | 1,425 | | | | | | | | | | | | | | | | Société Centrale Electrique du Congo SA | | | | | 85 | | | | | | | | | | | | | | | | | | | | | | | | 20 | | | | Other | | | | | 18 | | | | | | 14 | | | | | | 2 | | | | | | 18 | | | | | | 14 | | | | | | | | | 919 | | | | | | 19 | | | | | | 1,676 | | | | | | 95 | | | | | | 36 | | | | Unconsolidated entities controlled by Eni | | | | | 48 | | | | | | 28 | | | | | | | | | | | | 1 | | | | | | | | | | | | | | | 48 | | | | | | 28 | | | | | | | | | | | | 1 | | | | | | | | | | Entities controlled by the Government | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other | | | | | 4 | | | | | | 12 | | | | | | | | | | | | | | | | | | | | | | | | | | | 4 | | | | | | 12 | | | | | | | | | | | | | | | | | | | | | | | | | | | 971 | | | | | | 59 | | | | | | 1,676 | | | | | | 96 | | | | | | 36 | | | | |
(€ million) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | | | 2018 | | Name | | | Receivables | | | Payables | | | Guarantees | | | Gains | | | Charges | | Joint ventures and associates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Angola LNG Ltd | | | | | | | | | | | | | | | | | 245 | | | | | | | | | | | | | | | Cardón IV SA | | | | | 705 | | | | | | 36 | | | | | | | | | | | | 95 | | | | | | | | | Coral FLNG SA | | | | | 108 | | | | | | | | | | | | | | | | | | | | | | | | | | | Coral South FLNG DMCC | | | | | | | | | | | | | | | | | 1,397 | | | | | | | | | | | | | | | Shatskmorneftegaz Sàrl | | | | | | | | | | | | | | | | | | | | | | | 7 | | | | | | 267 | | | Société Centrale Electrique du Congo SA | | | | | 64 | | | | | | 30 | | | | | | | | | | | | | | | | | | 5 | | | Vår Energi AS | | | | | | | | | | | 494 | | | | | | | | | | | | | | | | | | | | | Other | | | | | 38 | | | | | | 4 | | | | | | 22 | | | | | | 13 | | | | | | 9 | | | | | | | | 915 | | | | | | 564 | | | | | | 1,664 | | | | | | 115 | | | | | | 281 | | | Unconsolidated entities controlled by Eni | | | | | 49 | | | | | | 25 | | | | | | | | | | | | | | | | | | | | | Entities controlled by the Government | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Enel Group | | | | | | | | | | | 64 | | | | | | | | | | | | | | | | | | | | | Other | | | | | | | | | | | 8 | | | | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | | | 72 | | | | | | | | | | | | | | | | | | 2 | | | | | | | | 964 | | | | | | 661 | | | | | | 1,664 | | | | | | 115 | | | | | | 283 | | | |
(€ million) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2016 | | 2016 | | | December 31, 2017 | | 2017 | | Name | | Receivables | | Payables | | Guarantees | | Charges | | Gains | | Income from equity instruments | | | Receivables | | Payables | | Guarantees | | Gains | | Charges | | Continuing operations | | | | Joint ventures and associates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | CARDÓN IV SA | | | | 1,054 | | | | | | | | | | | | | | | | | | | | 96 | | | | | Matrìca SpA | | | | 125 | | | | | | | | | | | | | | | 93 | | | | | 9 | | | | | Angola LNG Ltd | | | | | | | | | | | | | | | 233 | | | | | | | | | | | | | Coral South FLNG D MCC | | | | | | | | | | | | | | | 1,334 | | | | | | | | | | | | | Cardón IV SA | | | | | 955 | | | | | | | | | | | | | | | 86 | | | | | | | | Shatskmorneftegaz Sarl | | | | 69 | | | | | | | | | | | | | | | 13 | | | | | 4 | | | | | | | 101 | | | | | | | | | | | | | | | 6 | | | | | | | | Société Centrale Electrique du Congo SA | | | | 78 | | | | | | | | | | | | | | | 18 | | | | | | | 66 | | | | | 43 | | | | | | | | | | | | | | | | | | Unión Fenosa Gas SA | | | | | | | | | 85 | | | | | Saipem Group | | | | | | | | | | | | | | 82 | | | | | | | | | | 43 | | | | | 27 | | | | | | | | | | | 3 | | | | | 56 | | | | | 13 | | | | | | | | Other(*) | | | | 52 | | | | | | | | | | 2 | | | | | 17 | | | | | 4 | | | | | | | | | Coral FLNG SA | | | | | 56 | | | | | | | | | | | | | | | 71 | | | | | | | | Other | | | | | 48 | | | | | 49 | | | | | 2 | | | | | 14 | | | | | 1 | | | | | | | 1,378 | | | | | 85 | | | | | 84 | | | | | 141 | | | | | 156 | | | | | 27 | | | | | | 1,226 | | | | | 95 | | | | | 1,625 | | | | | 190 | | | | | 1 | | | Unconsolidated entities controlled by Eni | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni BTC Ltd | | | | | | | | | 54 | | | | | Servizi Fondo Bombole Metano SpA | | | | | 60 | | | | | 9 | | | | | | | | | | 1 | | | | | | | | Other(*) | | | | 46 | | | | | 52 | | | | | | | | | | 1 | | | | | 1 | | | | | | | 1 | | | | | 52 | | | | | | | | | | | | | | | | | | | | | | 46 | | | | | 106 | | | | | | | | | | 1 | | | | | 1 | | | | | | | 61 | | | | | 61 | | | | | | | | | | 1 | | | | | | | | Entities controlled by the Government | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other(*) | | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | | | Other | | | | | | | | | | 8 | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | | | | | | | | | | 8 | | | | | | | | | | | | | | | 3 | | | | | | | 1,424 | | | | | 191 | | | | | 84 | | | | | 145 | | | | | 157 | | | | | 27 | | | | | | 1,287 | | | | | 164 | | | | | 1,625 | | | | | 191 | | | | | 4 | | | | |
(*)
Each individual amount included herein was lower than €50 million. The most significant transactions with joint ventures, associates and unconsolidated subsidiaries concerned: •
bank debt guarantees issued on behalf of Angola LNG Ltd; •
the financing loansloan granted to CARDÓNCardón IV SA for the exploration and development activities of a gas field in Venezuela; •
the financing loansloan granted to Matrìca SpACoral FLNG SA for the construction of a floating gas liquefaction plant in relation to the “Green Chemistry” project at the Porto Torres plant;Area 4 offshore Mozambique (for more information see note 27 — Guarantees, commitments and risks); •
a bank debt guarantee issued on behalf of Coral South FLNG DMCC as part of the project financing loansof the Coral FLNG development project (for more information see note 27 — Guarantees, commitments and risks); •
the loan granted to Shatskmorneftegaz Sàrl for the exploration activity of in the Black Sea and to Société Centrale Electrique du Congo SA for the construction of an electrica power plant in Congo;Congo. •
a cash deposit at Eni’s financial companies on behalf of Unión Fenosa Gas SA and Eni BTC Ltd;
•
derivative financial instruments relating to the settlement of derivatives on exchange rate entered into by the Saipem Group with Eni in previous years.
On January 22, 2016, Eni closed the sale transaction of 12.503% of the share capital of Saipem to CDP Equity SpA (former Fondo Strategico Italiano SpA) for a total consideration of €463 million. More information is reported in note 35 — Discontinued operations, assets held for sale and liabilities directly associated with assets held for sale.
Impact of transactions and positions with related parties on the balance sheet, profit and loss account and statement of cash flows The impact of transactions and positions with related parties on the balance sheet accounts consisted of the following: (€ million) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | December 31, 2015 | | December 31, 2016 | | | December 31, 2019 | | December 31, 2018 | | (€ million) | | Total | | Related parties | | Impact % | | Total | | Related parties | | Impact % | | Total | | Related parties | | Impact % | | | | | | Total | | Related parties | | Impact % | | Total | | Related parties | | Impact % | | Other current financial assets | | | | | 384 | | | | | 60 | | | | | 15.63 | | | | | 300 | | | | | 49 | | | | | 16.33 | | | Trade and other receivables | | | | 28,601 | | | | | 1,973 | | | | | 6.90 | | | | | 21,640 | | | | | 1,985 | | | | | 9.17 | | | | | 17,593 | | | | | 1,100 | | | | | 6.25 | | | | | | 12,873 | | | | | 704 | | | | | 5.47 | | | | | 14,101 | | | | | 633 | | | | | 4.49 | | | Other current assets | | | | 4,385 | | | | | 43 | | | | | 0.98 | | | | | 3,642 | | | | | 50 | | | | | 1.37 | | | | | 2,591 | | | | | 57 | | | | | 2.20 | | | | | | 3,972 | | | | | 219 | | | | | 5.51 | | | | | 2,819 | | | | | 71 | | | | | 2.52 | | | Other non-current financial assets | | | | 1,042 | | | | | 259 | | | | | 24.86 | | | | | 1,026 | | | | | 396 | | | | | 38.60 | | | | | 1,860 | | | | | 1,349 | | | | | 72.53 | | | | | | 1,174 | | | | | 911 | | | | | 77.60 | | | | | 1,253 | | | | | 915 | | | | | 73.02 | | | Other non-current assets | | | | 2,773 | | | | | 12 | | | | | 0.43 | | | | | 1,758 | | | | | 10 | | | | | 0.57 | | | | | 1,348 | | | | | 13 | | | | | 0.96 | | | | | | 871 | | | | | 181 | | | | | 20.78 | | | | | 624 | | | | | 160 | | | | | 25.64 | | | Discontinued operations and assets held for sale | | | | 456 | | | | | | | | | | | | | | | 15,533 | | | | | 308 | | | | | 1.98 | | | | | 14 | | | | | Current financial liabilities | | | | 2,716 | | | | | 181 | | | | | 6.66 | | | | | 5,720 | | | | | 208 | | | | | 3.64 | | | | | 3,396 | | | | | 191 | | | | | 5.62 | | | | Short-term debt | | | | | 2,452 | | | | | 46 | | | | | 1.88 | | | | | 2,182 | | | | | 661 | | | | | 30.29 | | | Current portion of long-term lease liabilities | | | | | 889 | | | | | 5 | | | | | 0.56 | | | | | | | | | | | | | | | | | | Trade and other payables | | | | 23,703 | | | | | 1,954 | | | | | 8.24 | | | | | 14,942 | | | | | 1,544 | | | | | 10.33 | | | | | 16,703 | | | | | 2,289 | | | | | 13.70 | | | | | | 15,545 | | | | | 2,663 | | | | | 17.13 | | | | | 16,747 | | | | | 3,664 | | | | | 21.88 | | | Other current liabilities | | | | 4,489 | | | | | 58 | | | | | 1.29 | | | | | 4,712 | | | | | 96 | | | | | 2.04 | | | | | 2,599 | | | | | 88 | | | | | 3.39 | | | | | | 7,146 | | | | | 155 | | | | | 2.17 | | | | | 5,412 | | | | | 63 | | | | | 1.16 | | | Long-term lease liabilities | | | | | 4,759 | | | | | 8 | | | | | 0.17 | | | | | | | | | | | | | | | | | | Other non-current liabilities | | | | 2,285 | | | | | 20 | | | | | 0.88 | | | | | 1,852 | | | | | 23 | | | | | 1.24 | | | | | 1,768 | | | | | 23 | | | | | 1.30 | | | | | | 1,611 | | | | | 23 | | | | | 1.43 | | | | | 1,475 | | | | | 23 | | | | | 1.56 | | | Discontinued operations and liabilities directly associated to assets held for sale | | | | 165 | | | | | | | | | | | | | | | 6,485 | | | | | 207 | | | | | 3.19 | | | | | | | | | | | | | | | | | | | | |
The impact of transactions with related parties on the profit and loss accounts consisted of the following: | | | | | | | | 2014 | | | 2015 | | | 2016 | | (€ million) | | | Total | | | Related parties | | | Impact % | | | Total | | | Related parties | | | Impact % | | | Total | | | Related parties | | | Impact % | | Continuing operations | | | | | | | | | | | Net sales from operations | | | | | 98,218 | | | | | | 1,497 | | | | | | 1.52 | | | | | | 72,286 | | | | | | 1,342 | | | | | | 1.86 | | | | | | 55,762 | | | | | | 1,238 | | | | | | 2.22 | | | Other income and revenues | | | | | 1,079 | | | | | | 69 | | | | | | 6.39 | | | | | | 1,252 | | | | | | 69 | | | | | | 5.51 | | | | | | 931 | | | | | | 74 | | | | | | 7.95 | | | Purchases, services and other | | | | | 77,404 | | | | | | 7,143 | | | | | | 9.23 | | | | | | 56,848 | | | | | | 6,882 | | | | | | 12.11 | | | | | | 44,124 | | | | | | 8,212 | | | | | | 18.61 | | | Payroll and related costs | | | | | 2,929 | | | | | | 60 | | | | | | 2.05 | | | | | | 3,119 | | | | | | 55 | | | | | | 1.76 | | | | | | 2,994 | | | | | | 24 | | | | | | 0.80 | | | Other operating (expense) income | | | | | 145 | | | | | | 208 | | | | | | — | | | | | | (485) | | | | | | 96 | | | | | | — | | | | | | 16 | | | | | | 247 | | | | | | — | | | Financial income | | | | | 5,701 | | | | | | 46 | | | | | | 0.81 | | | | | | 8,635 | | | | | | 83 | | | | | | 0.96 | | | | | | 5,850 | | | | | | 157 | | | | | | 2.69 | | | Financial expense | | | | | (7,057) | | | | | | (41) | | | | | | 0.58 | | | | | | (10,104) | | | | | | (50) | | | | | | 0.49 | | | | | | (6,232) | | | | | | (145) | | | | | | 2.33 | | | Derivative financial instruments | | | | | 165 | | | | | | | | | | | | | | | | | | 160 | | | | | | | | | | | | | | | | | | (482) | | | | | | 27 | | | | | | — | | | Discontinued operations | | Total revenues | | | | | 11,644 | | | | | | 1,107 | | | | | | 9.51 | | | | | | 10,277 | | | | | | 344 | | | | | | 3.35 | | | | | | Operating costs | | | | | 12,731 | | | | | | 240 | | | | | | 1.89 | | | | | | 12,199 | | | | | | 202 | | | | | | 1.66 | | | | | | | | | | |
| | | | | | | | 2019 | | | 2018 | | | 2017 | | (€million) | | | Total | | | Related parties | | | Impact % | | | Total | | | Related parties | | | Impact % | | | Total | | | Related parties | | | Impact % | | Sales from operations | | | | | 69,881 | | | | | | 1,248 | | | | | | 1.79 | | | | | | 75,822 | | | | | | 1,383 | | | | | | 1.82 | | | | | | 66,919 | | | | | | 1,567 | | | | | | 2.34 | | | Other income and revenues | | | | | 1,160 | | | | | | 4 | | | | | | 0.34 | | | | | | 1,116 | | | | | | 8 | | | | | | 0.72 | | | | | | 4,058 | | | | | | 41 | | | | | | 1.01 | | | Purchases, services and other | | | | | (50,874) | | | | | | (9,173) | | | | | | 18.03 | | | | | | (55,622) | | | | | | (8,009) | | | | | | 14.40 | | | | | | (51,548) | | | | | | (9,164) | | | | | | 17.78 | | | Net (impairment losses) reversals of trade and other receivables | | | | | (432) | | | | | | 28 | | | | | | — | | | | | | (415) | | | | | | 26 | | | | | | — | | | | | | (913) | | | | | | | | | | | | | | | Payroll and related costs | | | | | (2,996) | | | | | | (28) | | | | | | 0.93 | | | | | | (3,093) | | | | | | (22) | | | | | | 0.71 | | | | | | (2,951) | | | | | | (34) | | | | | | 1.15 | | | Other operating income (expense) | | | | | 287 | | | | | | 19 | | | | | | 6.62 | | | | | | 129 | | | | | | 319 | | | | | | — | | | | | | (32) | | | | | | 331 | | | | | | — | | | Finance income | | | | | 3,087 | | | | | | 96 | | | | | | 3.11 | | | | | | 3,967 | | | | | | 115 | | | | | | 2.90 | | | | | | 3,924 | | | | | | 191 | | | | | | 4.87 | | | Finance expense | | | | | (4,079) | | | | | | (36) | | | | | | 0.88 | | | | | | (4,663) | | | | | | (283) | | | | | | 6.07 | | | | | | (5,886) | | | | | | (4) | | | | | | 0.07 | | |
Main cash flows with related parties are provided below: | | | | | (€ million) | | | 2014 | | | 2015 | | | 2016 | | Revenues and other income | | | | | 1,566 | | | | | | 1,411 | | | | | | 1,312 | | | Costs and other expenses | | | | | (6,022) | | | | | | (5,786) | | | | | | (5,623) | | | Other operating income (loss) | | | | | 208 | | | | | | 96 | | | | | | 247 | | | Net change in trade and other receivables and liabilities | | | | | 164 | | | | | | 105 | | | | | | 182 | | | Net interests | | | | | 46 | | | | | | 82 | | | | | | 133 | | | Net cash provided from operating activities — Continuing operations | | | | | (4,038) | | | | | | (4,092) | | | | | | (3,749) | | | Net cash provided from operating activities — Discontinued operations | | | | | 835 | | | | | | 126 | | | | | | | | | Net cash provided from operating activities | | | | | (3,203) | | | | | | (3,966) | | | | | | (3,749) | | | Capital expenditure in tangible and intangible assets | | | | | (1,181) | | | | | | (1,151) | | | | | | (2,613) | | | Disposal of investments | | | | | | | | | | | | | | | | | 463 | | | Net change in accounts payable and receivable in relation to investments | | | | | (114) | | | | | | (238) | | | | | | 252 | | | Change in financial receivables | | | | | (163) | | | | | | (194) | | | | | | 5,650 | | | Net cash used in investing activities | | | | | (1,458) | | | | | | (1,583) | | | | | | 3,752 | | | Change in financial liabilities | | | | | (99) | | | | | | 13 | | | | | | (192) | | | Net cash used in financing activities | | | | | (99) | | | | | | 13 | | | | | | (192) | | | Total financial flows to related parties | | | | | (4,760) | | | | | | (5,536) | | | | | | (189) | | | |
| | | | | (€ million) | | | 2019 | | | 2018 | | | 2017 | | Revenues and other income | | | | | 1,252 | | | | | | 1,391 | | | | | | 1,608 | | | Costs and other expenses | | | | | (6,869) | | | | | | (5,210) | | | | | | (5,360) | | | Other operating income (expense) | | | | | 19 | | | | | | 319 | | | | | | 331 | | | Net change in trade and other receivables and payables | | | | | (839) | | | | | | 683 | | | | | | 391 | | | Net interests | | | | | 81 | | | | | | 110 | | | | | | 187 | | | Net cash provided from operating activities | | | | | (6,356) | | | | | | (2,707) | | | | | | (2,843) | | | Capital expenditure in tangible and intangible assets | | | | | (2,332) | | | | | | (2,768) | | | | | | (3,838) | | | Net change in accounts payable and receivable in relation to investments | | | | | (339) | | | | | | 20 | | | | | | 425 | | | Change in financial receivables | | | | | (241) | | | | | | (566) | | | | | | 298 | | | Net cash used in investing activities | | | | | (2,912) | | | | | | (3,314) | | | | | | (3,115) | | | Change in financial and lease liabilities | | | | | (817) | | | | | | 16 | | | | | | (16) | | | Net cash used in financing activities | | | | | (817) | | | | | | 16 | | | | | | (16) | | | Total financial flows to related parties | | | | | (10,085) | | | | | | (6,005) | | | | | | (5,974) | | |
The impact of cash flows with related parties consisted of the following: | | | 2014 | | 2015 | | 2016 | | | 2019 | | 2018 | | 2017 | | (€ million) | | Total | | Related parties | | Impact % | | Total | | Related parties | | Impact % | | Total | | Related parties | | Impact % | | | Total | | Related parties | | Impact % | | Total | | Related parties | | Impact % | | Total | | Related parties | | Impact % | | Cash provided from operating activities | | | | 14,742 | | | | | (3,203) | | | | | — | | | | | 11,649 | | | | | (3,966) | | | | | — | | | | | 7,673 | | | | | (3,749) | | | | | — | | | | Cash used in investing activities | | | | (8,575) | | | | | (1,458) | | | | | 17.00 | | | | | (10,923) | | | | | (1,583) | | | | | 14.49 | | | | | (4,443) | | | | | 3,752 | | | | | — | | | | Cash used in financing activities | | | | (5,062) | | | | | (99) | | | | | 1.96 | | | | | (1,351) | | | | | 13 | | | | | — | | | | | (3,651) | | | | | (192) | | | | | 5.26 | | | | | | Net cash provided by operating activities | | | | | 12,392 | | | | | (6,356) | | | | | — | | | | | 13,647 | | | | | (2,707) | | | | | — | | | | | 10,117 | | | | | (2,843) | | | | | — | | | Net cash used in investing activities | | | | | (11,413) | | | | | (2,912) | | | | | 25.51 | | | | | (7,536) | | | | | (3,314) | | | | | 43.98 | | | | | (3,768) | | | | | (3,115) | | | | | 82.67 | | | Net cash used in financing activities | | | | | (5,841) | | | | | (817) | | | | | 13.99 | | | | | (2,637) | | | | | 16 | | | | | — | | | | | (4,595) | | | | | (16) | | | | | 0.35 | | |
37 Other information about investments Information on Eni’s investments as of December 31, 20162019 The following section provides the information about Eni’s subsidiaries, joint arrangements, associates and other significant investments as of December 31, 2016.2019. Unless otherwise indicated, share capital is represented by ordinary shares directly held by the Group, while ownership interest corresponds to voting rights. Parent company Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | Eni SpA(#) | | | | | Rome | | | | | | Italy | | | | EUR | | | | | 4,005,358,876 | | | | Cassa Depositi e Prestiti SpA | | | | | 25.76 | | | | | | | | | | | | | | | | | | | | | | | | | | | Ministero dell’Economia e delle Finanze | | | | | 4.34 | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni SpA | | | | | 0.91 | | | | | | | | | | | | | | | | | | | | | | | | | | | Other shareholders | | | | | 68.99 | | |
Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | Eni SpA(#) | | | Rome | | | Italy | | | EUR | | | | | 4,005,358,876 | | | | Cassa Depositi e Prestiti SpA Ministero dell’Economia e delle Finanze Eni SpA Other shareholders | | | 25.76 4.34 1.70 68.20 | |
Subsidiaries Exploration & Production In Italy Company name | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | Eni Angola SpA | | San Donato Milanese (MI) | | Angola | | EUR | | | | 20,200,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | San Donato Milanese (MI) | | Angola | | EUR | | | | 20,200,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Mediterranea Idrocarburi SpA | | Gela (CL) | | Italy | ��� | | EUR | | | | 5,200,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Gela (CL) | | Italy | | EUR | | | | 5,200,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Mozambico SpA | | San Donato Milanese (MI) | | Mozambique | | EUR | | | | 200,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | San Donato Milanese (MI) | | Mozambique | | EUR | | | | 200,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Timor Leste SpA | | San Donato Milanese (MI) | | Timor Leste | | EUR | | | | 6,841,517 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | San Donato Milanese (MI) | | East Timor | | EUR | | | | 6,841,517 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni West Africa SpA | | San Donato Milanese (MI) | | Angola | | EUR | | | | 10,000,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | San Donato Milanese (MI) | | Angola | | EUR | | | | 10,000,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Zubair SpA (in liquidation) | | San Donato Milanese (MI) | | Italy | | EUR | | | | 120,000 | | | Eni SpA | | 100.00 | | | | | | | | | Co. | | | | EniProgetti SpA | | | Venezia Marghera (VE) | | Italy | | EUR | | | | 2,064,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Floaters SpA | | San Donato Milanese (MI) | | Italy | | EUR | | | | 200,120,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | San Donato Milanese (MI) | | Italy | | EUR | | | | 200,120,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Ieoc SpA | | San Donato Milanese (MI) | | Egypt | | EUR | | | | 18,331,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | San Donato Milanese (MI) | | Egypt | | EUR | | | | 7,518,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Società Petrolifera Italiana SpA | | San Donato Milanese (MI) | | Italy | | EUR | | | | 24,103,200 | | | Eni SpA Third parties | | 99.96 0.04 | | | | 99.96 | | | | | F.C. | | | | San Donato Milanese (MI) | | Italy | | EUR | | | | 13,877,600 | | | Eni SpA Third parties | | 99.96 0.04 | | | | 99.96 | | | | | F.C. | | | Tecnomare - Società per lo Sviluppo delle Tecnologie Marine SpA | | Venezia Marghera (VE) | | Italy | | EUR | | | | 2,064,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (#)
Company with shares quoted in the regulated market of Italy or of other EU countries
Outside Italy Company name | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | Agip Caspian Sea BV | | Amsterdam (Netherlands) | | Kazakhstan | | EUR | | | | 20,005 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Kazakhstan | | EUR | | | | 20,005 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Agip Energy and Natural Resources (Nigeria) Ltd | | Abuja (Nigeria) | | Nigeria | | NGN | | | | 5,000,000 | | | Eni International BV Eni Oil Holdings BV | | 95.00 5.00 | | | | 100.00 | | | | | F.C. | | | | Abuja (Nigeria) | | Nigeria | | NGN | | | | 5,000,000 | | | Eni International BV Eni Oil Holdings BV | | 95.00 5.00 | | | | 100.00 | | | | | F.C. | | | Agip Karachaganak BV | | Amsterdam (Netherlands) | | Kazakhstan | | EUR | | | | 20,005 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Kazakhstan | | EUR | | | | 20,005 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Agip Oil Ecuador BV | | Amsterdam (Netherlands) | | Ecuador | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Agip Oleoducto de Crudos Pesados BV | | Amsterdam (Netherlands) | | Ecuador | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | | Burren (Cyprus) Holdings Ltd (in liquidation) | | Nicosia (Cyprus) | | Cyprus | | EUR | | | | 1,710 | | | Burren En.(Berm)Ltd | | 100.00 | | | | | | | | | Co. | | | | Agip Oleoducto de Crudos Pesados BV (in liquidation) | | | Amsterdam (Netherlands) | | Ecuador | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Co. | | | Burren Energy (Bermuda) Ltd | | Hamilton (Bermuda) | | United Kingdom | | USD | | | | 12,002 | | | Burren Energy Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Hamilton (Bermuda) | | United Kingdom | | USD | | | | 12,002 | | | Burren Energy Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Burren Energy (Egypt) Ltd | | | London (United Kingdom) | | Egypt | | GBP | | | | 2 | | | Burren Energy Plc | | 100.00 | | | | | | | | | Eq. | | | Burren Energy Congo Ltd | | Tortola (British Virgin Islands) | | Republic of the Congo | | USD | | | | 50,000 | | | Burren En.(Berm)Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Tortola (British Virgin Islands) | | Republic of the Congo | | USD | | | | 50,000 | | | Burren En.(Berm)Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Burren Energy (Egypt) Ltd | | London (United Kingdom) | | Egypt | | GBP | | | | 2 | | | Burren Energy Plc | | 100.00 | | | | | | | | | Eq. | | | | Burren Energy India Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 2 | | | Burren Energy Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 2 | | | Burren Energy Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Burren Energy Ltd (in liquidation) | | Nicosia (Cyprus) | | Cyprus | | EUR | | | | 3,420 | | | Burren En.(Berm)Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Burren Energy Plc | | London (United Kingdom) | | United Kingdom | | GBP | | | | 28,819,023 | | | Eni UK Holding Plc Eni UK Ltd | | 99.99 (—) | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 28,819,023 | | | Eni UK Holding Plc Eni UK Ltd | | 99.99 (..) | | | | 100.00 | | | | | F.C. | | | Burren Energy (Services) Ltd (in liquidation) | | London (United Kingdom) | | United Kingdom | | GBP | | | | 2 | | | Burren Energy Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Burren Energy Ship Management Ltd (in liquidation) | | Nicosia (Cyprus) | | Cyprus | | EUR | | | | 3,420 | | | Burren(Cyp)Hold.Ltd (L) Burren En.(Berm)Ltd | | 50.00 50.00 | | | | | | | | | Co. | | | | Burren Energy Shipping and Transportation Ltd (in liquidation) | | Nicosia (Cyprus) | | Cyprus | | EUR | | | | 3,420 | | | Burren(Cyp)Hold.Ltd (L) Burren En.(Berm)Ltd | | 50.00 50.00 | | | | | | | | | Co. | | | | Burren Shakti Ltd | | Hamilton (Bermuda) | | United Kingdom | | USD | | | | 65,300,000 | | | Burren En. India Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Hamilton (Bermuda) | | United Kingdom | | USD | | | | 213,138 | | | Burren En. India Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Abu Dhabi BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | | Amsterdam (Netherlands) | | United Arab Emirates | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni AEP Ltd | | London (United Kingdom) | | Pakistan | | GBP | | | | 73,471,000 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Pakistan | | GBP | | | | 13,471,000 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Albania BV | | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | Eni Algeria Exploration BV | | Amsterdam (Netherlands) | | Algeria | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Algeria | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Algeria Ltd Sàrl | | Luxembourg (Luxembourg) | | Algeria | | USD | | | | 20,000 | | | Eni Oil Holdings BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Luxembourg (Luxembourg) | | Algeria | | USD | | | | 20,000 | | | Eni Oil Holdings BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Algeria Production BV | | Amsterdam (Netherlands) | | Algeria | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Algeria | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Ambalat Ltd | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni America Ltd | | Dover, Delaware (USA) | | USA | | USD | | | | 72,000 | | | Eni UHL Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Dover, Delaware (USA) | | USA | | USD | | | | 72,000 | | | Eni UHL Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Angola Exploration BV | | Amsterdam (Netherlands) | | Angola | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Angola | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Angola Production BV | | | Amsterdam (Netherlands) | | Angola | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Argentina Exploración y Explotación SA | | | Buenos Aires (Argentina) | | Argentina | | ARS | | | | 24,136,336 | | | Eni International BV Eni Oil Holdings BV | | 95.00 5.00 | | | | 100.00 | | | | | F.C. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Company name | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | %Equity ratio | | Consolidation or valutation method(*) | | Eni Angola Production BV | | Amsterdam (Netherlands) | | Angola | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni Argentina Exploración y Explotación SA | | Buenos Aires (Argentina) | | Argentina | | ARS | | | | 24,136,336 | | | Eni International BV Eni Oil Holdings BV | | 95.00 5.00 | | | | | | | | | Eq. | | | | Eni Arguni I Ltd | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Australia BV | | Amsterdam (Netherlands) | | Australia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Australia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Australia Ltd | | London (United Kingdom) | | Australia | | GBP | | | | 20,000,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Australia | | GBP | | | | 20,000,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Bahrain BV | | | Amsterdam (Netherlands) | | Bahrain | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni BB Petroleum Inc | | Dover, Delaware (USA) | | USA | | USD | | | | 1,000 | | | Eni Petroleum Co Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Dover, Delaware (USA) | | USA | | USD | | | | 1,000 | | | Eni Petroleum Co Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni BTC Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 34,000,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 1 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | Eni Bukat Ltd | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Bulungan BV | | Amsterdam (Netherlands) | | Indonesia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni Bulungan BV (in liquidation) | | | Amsterdam (Netherlands) | | Indonesia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Co. | | | Eni Canada Holding Ltd | | Calgary (Canada) | | Canada | | USD | | | | 1,453,200,001 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Calgary (Canada) | | Canada | | USD | | | | 1,453,200,001 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni CBM Ltd | | London (United Kingdom) | | Indonesia | | USD | | | | 2,210,728 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | USD | | | | 2,210,728 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni China BV | | Amsterdam (Netherlands) | | China | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | China | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Congo SA | | Pointe - Noire (Republic of the Congo) | | Republic of the Congo | | USD | | | | 17,000,000 | | | Eni E&P Holding BV Eni Int. NA NV Sàrl Eni International BV | | 99.99 (—) (—) | | | | 100.00 | | | | | F.C. | | | | Pointe - Noire (Republic of the Congo) | | Republic of the Congo | | USD | | | | 17,000,000 | | | Eni E&P Holding BV Eni Int. NA NV Sàrl Eni International BV | | 99.99 (..) (..) | | | | 100.00 | | | | | F.C. | | | Eni Côte d’Ivoire Ltd (former Eni Ivory Coast Ltd) | | London (United Kingdom) | | Ivory Coast | | GBP | | | | 1 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni Croatia BV | | Amsterdam (Netherlands) | | Croatia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni Côte d’Ivoire Ltd | | | London (United Kingdom) | | Ivory Coast | | GBP | | | | 1 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Cyprus Ltd | | Nicosia (Cyprus) | | Cyprus | | EUR | | | | 2,004 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Nicosia (Cyprus) | | Cyprus | | EUR | | | | 2,006 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Dación BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 90,000 | | | Eni Oil Holdings BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni Denmark BV | | Amsterdam (Netherlands) | | Greenland | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Greenland | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | Eni do Brasil Investimentos em Exploração e Produção de Petróleo Ltda | | Rio De Janeiro (Brazil) | | Brazil | | BRL | | | | 1,593,415,000 | | | Eni International BV Eni Oil Holdings BV | | 99.99 (—) | | | | | | | | | Eq. | | | | Rio de Janeiro (Brazil) | | Brazil | | BRL | | | | 1,593,415,000 | | | Eni International BV Eni Oil Holdings BV | | 99.99 (..) | | | | | | | | | Eq. | | | Eni East Ganal Ltd | | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni East Sepinggan Ltd | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Elgin/Franklin Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 100 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 100 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Energy Russia BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Engineering E&P Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 40,000,001 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni Exploration & Production Holding BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 29,832,777.12 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 29,832,777.12 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Gabon SA | | Libreville (Gabon) | | Gabon | | XAF | | | | 13,132,000,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Libreville (Gabon) | | Gabon | | XAF | | | | 13,132,000,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Ganal Ltd | | London (United Kingdom) | | Indonesia | | GBP | | | | 2 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | GBP | | | | 2 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Company name | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | Eni Gas & Power LNG Australia BV | | Amsterdam (Netherlands) | | Australia | | EUR | | | | 10,000,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Australia | | EUR | | | | 10,000,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Ghana Exploration and Production Ltd | | Accra (Ghana) | | Ghana | | GHS | | | | 21,412,500 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Accra (Ghana) | | Ghana | | GHS | | | | 21,412,500 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Hewett Ltd | | Aberdeen (United Kingdom) | | United Kingdom | | GBP | | | | 3,036,000 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Aberdeen (United Kingdom) | | United Kingdom | | GBP | | | | 3,036,000 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Hydrocarbons Venezuela Ltd | | London (United Kingdom) | | Venezuela | | GBP | | | | 8,050,500 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Venezuela | | GBP | | | | 8,050,500 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni India Ltd | | London (United Kingdom) | | India | | GBP | | | | 44,000,000 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | India | | GBP | | | | 44,000,000 | | | Eni Lasmo Plc | | 100.00 | | | | | | | | | Eq. | | | Eni Indonesia Ltd | | London (United Kingdom) | | Indonesia | | GBP | | | | 100 | | | Eni ULX Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | GBP | | | | 100 | | | Eni ULX Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Indonesia Ots 1 Ltd | | Grand Cayman (Cayman Islands) | | Indonesia | | USD | | | | 1.01 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Grand Cayman (Cayman Islands) | | Indonesia | | USD | | | | 1.01 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni International NA NV Sàrl | | Luxembourg (Luxembourg) | | United Kingdom | | USD | | | | 25,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Luxembourg (Luxembourg) | | United Kingdom | | USD | | | | 25,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Investments Plc | | London (United Kingdom) | | United Kingdom | | GBP | | | | 750,050,000 | | | Eni SpA Eni UK Ltd | | 99.99 (—) | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 750,050,000 | | | Eni SpA Eni UK Ltd | | 99.99 (..) | | | | 100.00 | | | | | F.C. | | | Eni Iran BV | | Amsterdam (Netherlands) | | Iran | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Iran | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | Eni Iraq BV | | Amsterdam (Netherlands) | | Iraq | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Iraq | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Ireland BV | | Amsterdam (Netherlands) | | Ireland | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Ireland | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Isatay BV | | Amsterdam (Netherlands) | | Kazakhstan | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Kazakhstan | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni JPDA 03-13 Ltd | | London (United Kingdom) | | Australia | | GBP | | | | 250,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Australia | | GBP | | | | 250,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni JPDA 06-105 Pty Ltd | | Perth (Australia) | | Australia | | AUD | | | | 80,830,576 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Perth (Australia) | | Australia | | AUD | | | | 80,830,576 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni JPDA 11-106 BV | | Amsterdam (Netherlands) | | Australia | | EUR | | | | 50,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Australia | | EUR | | | | 50,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Kenya BV | | Amsterdam (Netherlands) | | Kenya | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Kenya | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Krueng Mane Ltd | | London (United Kingdom) | | Indonesia | | GBP | | | | 2 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | GBP | | | | 2 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Lasmo Plc | | London (United Kingdom) | | United Kingdom | | GBP | | | | 337,638,724.25 | | | Eni Investments Plc Eni UK Ltd | | 99.99 (—) | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 337,638,724.25 | | | Eni Investments Plc Eni UK Ltd | | 99.99 (..) | | | | 100.00 | | | | | F.C. | | | Eni Lebanon BV | | | Amsterdam (Netherlands) | | Lebanon | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Liberia BV | | Amsterdam (Netherlands) | | Liberia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Liberia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | Eni Liverpool Bay Operating Co Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 5,001,000 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 1 | | | Eni UK Ltd | | 100.00 | | | | | | | | | Eq. | | | Eni LNS Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 80,400,000 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 80,400,000 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Marketing Inc | | Dover, Delaware (USA) | | USA | | USD | | | | 1,000 | | | Eni Petroleum Co Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Dover, Delaware (USA) | | USA | | USD | | | | 1,000 | | | Eni Petroleum Co Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Maroc BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Morocco | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Company name | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | Eni México S. de RL de CV | | Lomas De Chapultepec, Mexico City (Mexico) | | Mexico | | MXN | | | | 3,000 | | | Eni International BV Eni Oil Holdings BV | | 99.90 0.10 | | | | 100.00 | | | | | F.C. | | | | Lomas De Chapultepec, Mexico City (Mexico) | | Mexico | | MXN | | | | 3,000 | | | Eni International BV Eni Oil Holdings BV | | 99.90 0.10 | | | | 100.00 | | | | | F.C. | | | Eni Middle East BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | | Eni Middle East Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 1 | | | Eni ULT Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 1 | | | Eni ULT Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni MOG Ltd (in liquidation) | | London (United Kingdom) | | United Kingdom | | GBP | | | | 220,711,147.50 | | | Eni Lasmo Plc Eni LNS Ltd | | 99.99 (—) | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 220,711,147.50 | | | Eni Lasmo Plc Eni LNS Ltd | | 99.99 (..) | | | | 100.00 | | | | | F.C. | | | Eni Montenegro BV | | Amsterdam (Netherlands) | | Montenegro | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | | Amsterdam (Netherlands) | | Montenegro | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Mozambique Engineering Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 1 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 1 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Mozambique LNG Holding BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Muara Bakau BV | | Amsterdam (Netherlands) | | Indonesia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Indonesia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Myanmar BV | | Amsterdam (Netherlands) | | Myanmar | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Myanmar | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Norge AS | | Forus (Norway) | | Norway | | NOK | | | | 278,000,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni North Africa BV | | Amsterdam (Netherlands) | | Libya | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Libya | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni North Ganal Ltd | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Oil & Gas Inc | | Dover, Delaware (USA) | | USA | | USD | | | | 100,800 | | | Eni America Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Dover, Delaware (USA) | | USA | | USD | | | | 100,800 | | | Eni America Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Oil Algeria Ltd | | London (United Kingdom) | | Algeria | | GBP | | | | 1,000 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Algeria | | GBP | | | | 1,000 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Oil Holdings BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 450,000 | | | Eni ULX Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 450,000 | | | Eni ULX Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Oman BV | | | Amsterdam (Netherlands) | | Oman | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Pakistan Ltd | | London (United Kingdom) | | Pakistan | | GBP | | | | 90,087 | | | Eni ULX Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Pakistan | | GBP | | | | 90,087 | | | Eni ULX Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Pakistan (M) Ltd Sàrl | | Luxembourg (Luxembourg) | | Pakistan | | USD | | | | 20,000 | | | Eni Oil Holdings BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Luxembourg (Luxembourg) | | Pakistan | | USD | | | | 20,000 | | | Eni Oil Holdings BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Petroleum Co Inc | | Dover, Delaware (USA) | | USA | | USD | | | | 156,600,000 | | | Eni SpA Eni International BV | | 63.86 36.14 | | | | 100.00 | | | | | F.C. | | | | Dover, Delaware (USA) | | USA | | USD | | | | 156,600,000 | | | Eni SpA Eni International BV | | 63.86 36.14 | | | | 100.00 | | | | | F.C. | | | Eni Petroleum US Llc | | Dover, Delaware (USA) | | USA | | USD | | | | 1,000 | | | Eni BB Petroleum Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Dover, Delaware (USA) | | USA | | USD | | | | 1,000 | | | Eni BB Petroleum Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Portugal BV | | Amsterdam (Netherlands) | | Portugal | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Portugal | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | Eni RAK BV | | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Rapak Ltd | | London (United Kingdom) | | Indonesia | | GBP | | | | 2 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | GBP | | | | 2 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni RD Congo SA | | Kinshasa (Democratic Republic of Congo) | | Democratic Republic of Congo | | CDF | | | | 750,000,000 | | | Eni International BV Eni Oil Holdings BV | | 99.99 (—) | | | | 100.00 | | | | | F.C. | | | | Kinshasa (Democratic Republic of the Congo) | | Democratic Republic of the Congo | | CDF | | | | 750,000,000 | | | Eni International BV Eni Oil Holdings BV | | 99.99 (..) | | | | | | | | | Eq. | | | Eni Rovuma Basin BV | | | Amsterdam (Netherlands) | | Mozambique | | EUR | | | | 20,000 | | | Eni Mozambique LNG H. BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Sharjah BV | | | Amsterdam (Netherlands) | | United Arab Emirates | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni South Africa BV | | Amsterdam (Netherlands) | | Republic of South Africa | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Republic of South Africa | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni South China Sea Ltd Sàrl | | Luxembourg (Luxembourg) | | China | | USD | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Company name | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | Eni South China Sea Ltd Sàrl | | | Luxembourg (Luxembourg) | | China | | USD | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | Eni TNS Ltd | | Aberdeen (United Kingdom) | | United Kingdom | | GBP | | | | 1,000 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Aberdeen (United Kingdom) | | United Kingdom | | GBP | | | | 1,000 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Togo BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | | | | | | Eq. | | | | Eni Trinidad and Tobago Ltd | | Port Of Spain (Trinidad and Tobago) | | Trinidad and Tobago | | TTD | | | | 1,181,880 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni Tunisia BV | | Amsterdam (Netherlands) | | Tunisia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Tunisia | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Turkmenistan Ltd | | Hamilton (Bermuda) | | Turkmenistan | | USD | | | | 20,000 | | | Burren En.(Berm)Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Hamilton (Bermuda) | | Turkmenistan | | USD | | | | 20,000 | | | Burren En.(Berm)Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni UHL Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 1 | | | Eni ULT Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 1 | | | Eni ULT Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni UKCS Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 100 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni UK Holding Plc | | London (United Kingdom) | | United Kingdom | | GBP | | | | 424,050,000 | | | Eni Lasmo Plc Eni UK Ltd | | 99.99 (—) | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 424,050,000 | | | Eni Lasmo Plc Eni UK Ltd | | 99.99 (..) | | | | 100.00 | | | | | F.C. | | | Eni UK Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 250,000,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 250,000,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni UKCS Ltd | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 100 | | | Eni UK Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Ukraine Holdings BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Ukraine Llc | | Kiev (Ukraine) | | Ukraine | | UAH | | | | 42,004,757.64 | | | Eni Ukraine Hold.BV Eni International BV | | 99.99 0.01 | | | | 100.00 | | | | | F.C. | | | | Kiev (Ukraine) | | Ukraine | | UAH | | | | 42,004,757.64 | | | Eni Ukraine Hold.BV Eni International BV | | 99.99 0.01 | | | | | | | | | Eq. | | | Eni Ukraine Shallow Waters BV | | Amsterdam (Netherlands) | | Ukraine | | EUR | | | | 20,000 | | | Eni Ukraine Hold.BV | | 100.00 | | | | | | | | | Eq. | | | | Amsterdam (Netherlands) | | Ukraine | | EUR | | | | 20,000 | | | Eni Ukraine Hold.BV | | 100.00 | | | | | | | | | Eq. | | | Eni ULT Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 93,215,492.25 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 93,215,492.25 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni ULX Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 200,010,000 | | | Eni ULT Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 200,010,000 | | | Eni ULT Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni US Operating Co Inc | | | Dover, Delaware (USA) | | USA | | USD | | | | 1,000 | | | Eni Petroleum Co Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni USA Gas Marketing Llc | | Dover, Delaware (USA) | | USA | | USD | | | | 10,000 | | | Eni Marketing Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Dover, Delaware (USA) | | USA | | USD | | | | 10,000 | | | Eni Marketing Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni USA Inc | | Dover, Delaware (USA) | | USA | | USD | | | | 1,000 | | | Eni Oil & Gas Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Dover, Delaware (USA) | | USA | | USD | | | | 1,000 | | | Eni Oil & Gas Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni US Operating Co Inc | | Dover, Delaware (USA) | | USA | | USD | | | | 1,000 | | | Eni Petroleum Co Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni Venezuela BV | | Amsterdam (Netherlands) | | Venezuela | | EUR | | | | 20,000 | | | Eni Venezuela E&P H | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Venezuela | | EUR | | | | 20,000 | | | Eni Venezuela E&P Holding | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Venezuela E&P Holding SA | | Bruxelles (Belgium) | | Belgium | | USD | | | | 963,800,000 | | | Eni International BV Eni Oil Holdings BV | | 99.99 (—) | | | | 100.00 | | | | | F.C. | | | | Bruxelles (Belgium) | | Belgium | | USD | | | | 254,443,200 | | | Eni International BV Eni Oil Holdings BV | | 99.99 (..) | | | | 100.00 | | | | | F.C. | | | Eni Ventures Plc (in liquidation) | | London (United Kingdom) | | United Kingdom | | GBP | | | | 278,050,000 | | | Eni International BV Eni Oil Holdings BV | | 99.99 (—) | | | | | | | | | Co. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 278,050,000 | | | Eni International BV Eni Oil Holdings BV | | 99.99 (..) | | | | | | | | | Co. | | | Eni Vietnam BV | | Amsterdam (Netherlands) | | Vietnam | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Vietnam | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni West Ganal Ltd | | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni West Timor Ltd | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | Indonesia | | GBP | | | | 1 | | | Eni Indonesia Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Yemen Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 1,000 | | | Burren Energy Plc | | 100.00 | | | | | | | | | Eq. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 1,000 | | | Burren Energy Plc | | 100.00 | | | | | | | | | Eq. | | | EniProgetti Egypt Ltd | | | Cairo (Egypt) | | Egypt | | EGP | | | | 50,000 | | | EniProgetti SpA Eni SpA | | 99.00 1.00 | | | | | | | | | Eq. | | | Eurl Eni Algérie | | Algiers (Algeria) | | Algeria | | DZD | | | | 1,000,000 | | | Eni Algeria Ltd Sàrl | | 100.00 | | | | | | | | | Eq. | | | | Algiers (Algeria) | | Algeria | | DZD | | | | 1,000,000 | | | Eni Algeria Ltd Sàrl | | 100.00 | | | | | | | | | Eq. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Company name | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | First Calgary Petroleums LP | | Wilmington (USA) | | Algeria | | USD | | | | 1 | | | Eni Canada Hold. Ltd FCP Partner Co ULC | | 99.99 0.01 | | | | 100.00 | | | | | F.C. | | | | Wilmington (USA) | | Algeria | | USD | | | | 1 | | | Eni Canada Hold. Ltd FCP Partner Co ULC | | 99.99 0.01 | | | | 100.00 | | | | | F.C. | | | First Calgary Petroleums Partner Co ULC | | Calgary (Canada) | | Canada | | CAD | | | | 10 | | | Eni Canada Hold. Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Calgary (Canada) | | Canada | | CAD | | | | 10 | | | Eni Canada Hold. Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | Ieoc Exploration BV | | Amsterdam (Netherlands) | | Egypt | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Egypt | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Ieoc Production BV | | Amsterdam (Netherlands) | | Egypt | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Egypt | | EUR | | | | 20,000 | | | Eni International BV | | 100.00 | | | | 100.00 | | | | | F.C. | | | Lasmo Sanga Sanga Ltd | | Hamilton (Bermuda) | | Indonesia | | USD | | | | 12,000 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Hamilton (Bermuda) | | Indonesia | | USD | | | | 12,000 | | | Eni Lasmo Plc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Liverpool Bay Ltd | | London (United Kingdom) | | United Kingdom | | USD | | | | 29,075,343 | | | Eni ULX Ltd | | 100.00 | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | USD | | | | 1 | | | Eni ULX Ltd | | 100.00 | | | | | | | | | Eq. | | | Mizamtec Operating Company S. de RL de CV | | | Mexico City (Mexico) | | Mexico | | MXN | | | | 3,000 | | | Eni US Op. Co Inc Eni Petroleum Co Inc | | 99.90 0.10 | | | | | | | | | Eq. | | | Nigerian Agip CPFA Ltd | | Lagos (Nigeria) | | Nigeria | | NGN | | | | 1,262,500 | | | NAOC Ltd Agip En Nat Res.Ltd Nigerian Agip E. Ltd | | 98.02 0.99 0.99 | | | | | | | | | Co. | | | | Lagos (Nigeria) | | Nigeria | | NGN | | | | 1,262,500 | | | NAOC Ltd Agip En Nat Res.Ltd Nigerian Agip E. Ltd | | 98.02 0.99 0.99 | | | | | | | | | Co. | | | Nigerian Agip Exploration Ltd | | Abuja (Nigeria) | | Nigeria | | NGN | | | | 5,000,000 | | | Eni International BV Eni Oil Holdings BV | | 99.99 0.01 | | | | 100.00 | | | | | F.C. | | | | Abuja (Nigeria) | | Nigeria | | NGN | | | | 5,000,000 | | | Eni International BV Eni Oil Holdings BV | | 99.99 0.01 | | | | 100.00 | | | | | F.C. | | | Nigerian Agip Oil Co Ltd | | Abuja (Nigeria) | | Nigeria | | NGN | | | | 1,800,000 | | | Eni International BV Eni Oil Holdings BV | | 99.89 0.11 | | | | 100.00 | | | | | F.C. | | | | Abuja (Nigeria) | | Nigeria | | NGN | | | | 1,800,000 | | | Eni International BV Eni Oil Holdings BV | | 99.89 0.11 | | | | 100.00 | | | | | F.C. | | | OOO ‘Eni Energhia’ | | Moscow (Russia) | | Russia | | RUB | | | | 2,000,000 | | | Eni Energy Russia BV Eni Oil Holdings BV | | 99.90 0.10 | | | | 100.00 | | | | | F.C. | | | | Moscow (Russia) | | Russia | | RUB | | | | 2,000,000 | | | Eni Energy Russia BV Eni Oil Holdings BV | | 99.90 0.10 | | | | 100.00 | | | | | F.C. | | | Tecnomare Egypt Ltd | | Cairo (Egypt) | | Egypt | | EGP | | | | 50,000 | | | Tecnomare SpA Eni SpA | | 99.00 1.00 | | | | | | | | | Eq. | | | | Zetah Congo Ltd | | Nassau (Bahamas) | | Republic of the Congo | | USD | | | | 300 | | | Eni Congo SA Burren En.Congo Ltd | | 66.67 33.33 | | | | | | | | | Co. | | | | Nassau (Bahamas) | | Republic of the Congo | | USD | | | | 300 | | | Eni Congo SA Burren En.Congo Ltd | | 66.67 33.33 | | | | | | | | | Co. | | | Zetah Kouilou Ltd | | Nassau (Bahamas) | | Republic of the Congo | | USD | | | | 2,000 | | | Eni Congo SA Burren En.Congo Ltd Third parties | | 54.50 37.00 8.50 | | | | | | | | | Co. | | | | Nassau (Bahamas) | | Republic of the Congo | | USD | | | | 2,000 | | | Eni Congo SA Burren En.Congo Ltd Third parties | | 54.50 37.00 8.50 | | | | | | | | | Co. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Gas & Power Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | Eni Gas e Luce SpA (former Eni Medio Oriente SpA) | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 6,655,992 | | | | Eni SpA | | | 100.00 | | | | | | | | | | | Co. | | | Eni Gas Transport Services Srl | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 120,000 | | | | Eni SpA | | | 100.00 | | | | | | | | | | | Co. | | | Eni Trading & Shipping SpA | | | Rome | | | Italy | | | EUR | | | | | 60,036,650 | | | | Eni SpA Eni Gas & Power NV | | | 94.73 5.27 | | | | | 100.00 | | | | | | F.C. | | | EniPower Mantova SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 144,000,000 | | | | EniPower SpA Third parties | | | 86.50 13.50 | | | | | 86.50 | | | | | | F.C. | | | EniPower SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 944,947,849 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | LNG Shipping SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 240,900,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Servizi Fondo Bombole Metano SpA | | | Rome | | | Italy | | | EUR | | | | | 13,580,000.20 | | | | Eni SpA | | | 100.00 | | | | | | | | | | | Co. | | | Trans Tunisian Pipeline Co SpA | | | San Donato Milanese (MI) | | | Tunisia | | | EUR | | | | | 1,098,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Outside Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana | | | Ljubljana (Slovenia) | | | Slovenia | | | EUR | | | | | 12,956,935 | | | | Eni SpA Third parties | | | 51.00 49.00 | | | | | 51.00 | | | | | | F.C. | | | Distrigas LNG Shipping SA | | | Bruxelles (Belgium) | | | Belgium | | | EUR | | | | | 788,579.55 | | | | LNG Shipping SpA Eni Gas & Power NV | | | 99.99 (—) | | | | | 100.00 | | | | | | F.C. | | | Eni G&P France BV | | | Amsterdam (Netherlands) | | | France | | | EUR | | | | | 20,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni G&P Trading BV | | | Amsterdam (Netherlands) | | | Turkey | | | EUR | | | | | 70,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Gas & Power France SA | | | Levallois Perret (France) | | | France | | | EUR | | | | | 29,937,600 | | | | Eni G&P France BV Third parties | | | 99.87 0.13 | | | | | 99.87 | | | | | | F.C. | | | Eni Gas & Power NV | | | Vilvoorde (Belgium) | | | Belgium | | | EUR | | | | | 31,925,264 | | | | Eni SpA Eni International BV | | | 99.99 (—) | | | | | 100.00 | | | | | | F.C. | | | Eni Trading & Shipping Inc | | | Dover, Delaware (USA) | | | USA | | | USD | | | | | 36,000,000 | | | | Ets SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Wind Belgium NV | | | Vilvoorde (Belgium) | | | Belgium | | | EUR | | | | | 5,494,500 | | | | Eni Gas & Power NV Eni International BV | | | 99.77 0.23 | | | | | 100.00 | | | | | | F.C. | | | Société de Service du Gazoduc Transtunisien SA - Sergaz SA | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 99,000 | | | | Eni International BV Third parties | | | 66.67 33.33 | | | | | 66.67 | | | | | | F.C. | | | Société pour la Construction du Gazoduc Transtunisien SA - Scogat SA | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 200,000 | | | | Eni International BV Eni SpA Eni Gas & Power NV Trans Tunis.P.Co SpA | | | 99.85 0.05 0.05 0.05 | | | | | 100.00 | | | | | | F.C. | | | Tigáz Gepa Kft (in liquidation) | | | Hajdúszoboszló (Hungary) | | | Hungary | | | HUF | | | | | 52,780,000 | | | | Tigáz Zrt | | | 100.00 | | | | | | | | | | | Eq. | | | Tigáz-Dso Földgázelosztó kft | | | Hajdúszoboszló (Hungary) | | | Hungary | | | HUF | | | | | 62,066,000 | | | | Tigáz Zrt | | | 100.00 | | | | | 98.99 | | | | | | F.C. | | | Tigáz Tiszántúli Gázszolgáltató Zártkörûen Mûködõ Részvénytársaság | | | Hajdúszoboszló (Hungary) | | | Hungary | | | HUF | | | | | 8,486,070,500 | | | | Eni SpA Third parties | | | 98.99 1.01 | | | | | 98.99 | | | | | | F.C. | | |
Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni gas e luce SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 750,000,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Gas Transport Services Srl | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 120,000 | | | | Eni SpA | | | 100.00 | | | | | | | | | | | Co. | | | Eni Trading & Shipping SpA | | | Rome | | | Italy | | | EUR | | | | | 60,036,650 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | EniPower Mantova SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 144,000,000 | | | | EniPower SpA Third parties | | | 86.50 13.50 | | | | | 86.50 | | | | | | F.C. | | | EniPower SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 944,947,849 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | LNG Shipping SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 240,900,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | SEA SpA | | | L’Aquila (AQ) | | | Italy | | | EUR | | | | | 100,000 | | | | Eni gas e luce SpA Third parties | | | 60.00 40.00 | | | | | 60.00 | | | | | | F.C. | | | Trans Tunisian Pipeline Co SpA | | | San Donato Milanese (MI) | | | Tunisia | | | EUR | | | | | 1,098,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Outside Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Adriaplin Podjetje za distribucijo zemeljskega plina doo Ljubljana | | | Ljubljana (Slovenia) | | | Slovenia | | | EUR | | | | | 12,956,935 | | | | Eni gas e luce SpA Third parties | | | 51.00 49.00 | | | | | 51.00 | | | | | | F.C. | | | Eni G&P Trading BV | | | Amsterdam (Netherlands) | | | Turkey | | | EUR | | | | | 70,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Gas & Power France SA | | | Levallois Perret (France) | | | France | | | EUR | | | | | 29,937,600 | | | | Eni gas e luce SpA Third parties | | | 99.87 0.13 | | | | | 99.87 | | | | | | F.C. | | | Eni Trading & Shipping Inc | | | Dover, Delaware (USA) | | | USA | | | USD | | | | | 36,000,000 | | | | ETS SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Transporte y Suministro México, S. de RL de CV | | | Mexico City (Mexico) | | | Mexico | | | MXN | | | | | 3,000 | | | | Eni International BV Eni Oil Holdings BV | | | 99.90 0.10 | | | | | | | | | | | Eq. | | | Gas Supply Company Thessaloniki – Thessalia SA | | | Thessaloniki (Greece) | | | Greece | | | EUR | | | | | 13,761,788 | | | | Eni gas e luce SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Société de Service du Gazoduc Transtunisien SA – Sergaz SA | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 99,000 | | | | Eni International BV Third parties | | | 66.67 33.33 | | | | | 66.67 | | | | | | F.C. | | | Société pour la Construction du Gazoduc Transtunisien SA – Scogat SA | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 200,000 | | | | Eni International BV Eni SpA LNG Shipping SpA Trans Tunis.P.Co SpA | | | 99.85 0.05 0.05 0.05 | | | | | 100.00 | | | | | | F.C. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Refining & Marketing and Chemical Refining & Marketing Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | Consorzio AgipGas Sabina (in liquidation) | | | Cittaducale (RI) | | | Italy | | | EUR | | | | | 5,160 | | | | Eni Fuel SpA | | | 100.00 | | | | | | | | | | | Co. | | | Ecofuel SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 52,000,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Fuel SpA (former Eni Rete oil&nonoil SpA) | | | Rome | | | Italy | | | EUR | | | | | 58,944,310 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Raffineria di Gela SpA | | | Gela (CL) | | | Italy | | | EUR | | | | | 15,000,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Outside Italy | | | | | | | | | | Eni Austria GmbH | | | Wien (Austria) | | | Austria | | | EUR | | | | | 78,500,000 | | | | Eni International BV Eni Deutsch.GmbH | | | 75.00 25.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Benelux BV | | | Rotterdam (Netherlands) | | | Netherlands | | | EUR | | | | | 1,934,040 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Deutschland GmbH | | | Munich (Germany) | | | Germany | | | EUR | | | | | 90,000,000 | | | | Eni International BV Eni Oil Holdings BV | | | 89.00 11.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Ecuador SA | | | Quito (Ecuador) | | | Ecuador | | | USD | | | | | 103,142.08 | | | | Eni International BV Esain SA | | | 99.93 0.07 | | | | | 100.00 | | | | | | F.C. | | | Eni France Sàrl | | | Lyon (France) | | | France | | | EUR | | | | | 56,800,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Iberia SLU | | | Alcobendas (Spain) | | | Spain | | | EUR | | | | | 17,299,100 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Lubricants Trading (Shanghai) Co Ltd | | | Shanghai (China) | | | China | | | EUR | | | | | 5,000,000 | | | | Eni International BV | | | 100.00 | | | | | | | | | | | Eq. | | | Eni Marketing Austria GmbH | | | Wien (Austria) | | | Austria | | | EUR | | | | | 19,621,665.23 | | | | Eni Mineralölh.GmbH Eni International BV | | | 99.99 (—) | | | | | 100.00 | | | | | | F.C. | | | Eni Mineralölhandel GmbH | | | Wien (Austria) | | | Austria | | | EUR | | | | | 34,156,232.06 | | | | Eni Austria GmbH | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Schmiertechnik GmbH | | | Wurzburg (Germany) | | | Germany | | | EUR | | | | | 2,000,000 | | | | Eni Deutsch.GmbH | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Suisse SA | | | Lausanne (Switzerland) | | | Switzerland | | | CHF | | | | | 102,500,000 | | | | Eni International BV Third parties | | | 99.99 (—) | | | | | 100.00 | | | | | | F.C. | | | Eni USA R&M Co Inc | | | Wilmington (USA) | | | USA | | | USD | | | | | 11,000,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Esacontrol SA | | | Quito (Ecuador) | | | Ecuador | | | USD | | | | | 60,000 | | | | Eni Ecuador SA Third parties | | | 87.00 13.00 | | | | | | | | | | | Eq. | | | Esain SA | | | Quito (Ecuador) | | | Ecuador | | | USD | | | | | 30,000 | | | | Eni Ecuador SA Tecnoesa SA | | | 99.99 (—) | | | | | 100.00 | | | | | | F.C. | | | Oléoduc du Rhône SA | | | Valais (Switzerland) | | | Switzerland | | | CHF | | | | | 7,000,000 | | | | Eni International BV | | | 100.00 | | | | | | | | | | | Eq. | | | OOO ‘‘Eni-Nefto’’ | | | Moscow (Russia) | | | Russia | | | RUB | | | | | 1,010,000 | | | | Eni International BV Eni Oil Holdings BV | | | 99.01 0.99 | | | | | | | | | | | Eq. | | | Tecnoesa SA | | | Quito (Ecuador) | | | Ecuador | | | USD | | | | | 36,000 | | | | Eni Ecuador SA Esain SA | | | 99.99 (—) | | | | | | | | | | | Eq. | | |
In Italy Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | Ecofuel SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 52,000,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Fuel SpA | | | Rome | | | Italy | | | EUR | | | | | 58,944,310 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Petroven Srl | | | Genova | | | Italy | | | EUR | | | | | 918,520 | | | | Ecofuel SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Raffineria di Gela SpA | | | Gela (CL) | | | Italy | | | EUR | | | | | 15,000,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | SeaPad SpA | | | Genova | | | Italy | | | EUR | | | | | 12,400,000 | | | | Ecofuel SpA Third parties | | | 80.00 20.00 | | | | | | | | | | | Eq. | | | Servizi Fondo Bombole Metano SpA | | | Rome | | | Italy | | | EUR | | | | | 13,580,000.20 | | | | Eni SpA | | | 100.00 | | | | | | | | | | | Co. | | | Outside Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Eni Abu Dhabi Refining & Trading BV | | | Amsterdam (Netherlands) | | | Netherlands | | | EUR | | | | | 20,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Abu Dhabi Refining & Trading Services BV | | | Amsterdam (Netherlands) | | | Netherlands | | | EUR | | | | | 20,000 | | | | Eni Abu Dhabi R&T BV | | | 100.00 | | | | | | | | | | | Eq. | | | Eni Austria GmbH | | | Wien (Austria) | | | Austria | | | EUR | | | | | 78,500,000 | | | | Eni International BV Eni Deutsch.GmbH | | | 75.00 25.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Benelux BV | | | Rotterdam (Netherlands) | | | Netherlands | | | EUR | | | | | 1,934,040 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Deutschland GmbH | | | Munich (Germany) | | | Germany | | | EUR | | | | | 90,000,000 | | | | Eni International BV Eni Oil Holdings BV | | | 89.00 11.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Ecuador SA | | | Quito (Ecuador) | | | Ecuador | | | USD | | | | | 103,142.08 | | | | Eni International BV Esain SA | | | 99.93 0.07 | | | | | 100.00 | | | | | | F.C. | | | Eni France Sàrl | | | Lyon (France) | | | France | | | EUR | | | | | 56,800,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Iberia SLU | | | Alcobendas (Spain) | | | Spain | | | EUR | | | | | 17,299,100 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Lubricants Trading (Shanghai) Co Ltd | | | Shanghai (China) | | | China | | | EUR | | | | | 5,000,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Marketing Austria GmbH | | | Wien (Austria) | | | Austria | | | EUR | | | | | 19,621,665.23 | | | | Eni Mineralölh.GmbH Eni International BV | | | 99.99 (..) | | | | | 100.00 | | | | | | F.C. | | | Eni Mineralölhandel GmbH | | | Wien (Austria) | | | Austria | | | EUR | | | | | 34,156,232.06 | | | | Eni Austria GmbH | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Schmiertechnik GmbH | | | Wurzburg (Germany) | | | Germany | | | EUR | | | | | 2,000,000 | | | | Eni Deutsch.GmbH | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Suisse SA | | | Lausanne (Switzerland) | | | Switzerland | | | CHF | | | | | 102,500,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni USA R&M Co Inc | | | Wilmington (USA) | | | USA | | | USD | | | | | 11,000,000 | | | | Eni International BV | | | 100.00 | | | | | | | | | | | Eq. | | | Esacontrol SA | | | Quito (Ecuador) | | | Ecuador | | | USD | | | | | 60,000 | | | | Eni Ecuador SA Third parties | | | 87.00 13.00 | | | | | | | | | | | Eq. | | | Esain SA | | | Quito (Ecuador) | | | Ecuador | | | USD | | | | | 30,000 | | | | Eni Ecuador SA Tecnoesa SA | | | 99.99 (..) | | | | | 100.00 | | | | | | F.C. | | | Oléoduc du Rhône SA | | | Valais (Switzerland) | | | Switzerland | | | CHF | | | | | 7,000,000 | | | | Eni International BV | | | 100.00 | | | | | | | | | | | Eq. | | | OOO “Eni-Nefto” | | | Moscow (Russia) | | | Russia | | | RUB | | | | | 1,010,000 | | | | Eni International BV Eni Oil Holdings BV | | | 99.01 0.99 | | | | | | | | | | | Eq. | | | Tecnoesa SA | | | Quito (Ecuador) | | | Ecuador | | | USD | | | | | 36,000 | | | | Eni Ecuador SA Esain SA | | | 99.99 (..) | | | | | | | | | | | Eq. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Chemical Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | Versalis SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 1,364,790,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | In Italy | | | | | | | | | | Consorzio Industriale Gas Naturale (in liquidation) | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 124,000 | | | | Versalis SpA Raff. di Gela SpA Eni SpA Syndial SpA Raff. Milazzo ScpA | | | 53.55 18.74 15.37 0.76 11.58 | | | | | | | | | | | Eq. | | | Outside Italy | | | | | | | | | | Dunastyr Polisztirolgyártó Zártkoruen Mukodo Részvénytársaság | | | Budapest (Hungary) | | | Hungary | | | HUF | | | | | 8,092,160,000 | | | | Versalis SpA Versalis Deutsc.GmbH Versalis Int.SA | | | 96.34 1.83 1.83 | | | | | 100.00 | | | | | | F.C. | | | Eni Chemicals Trading (Shanghai) Co Ltd (in liquidation) | | | Shanghai (China) | | | China | | | USD | | | | | 5,000,000 | | | | Versalis SpA | | | 100.00 | | | | | | | | | | | Eq. | | | Versalis Americas Inc | | | Dover, Delaware (USA) | | | USA | | | USD | | | | | 100,000 | | | | Versalis International SA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Versalis Congo Sarlu | | | Pointe-Noire (Republic of Congo) | | | Republic of Congo | | | CDF | | | | | 1,000,000 | | | | Versalis International SA | | | 100.00 | | | | | | | | | | | Eq. | | | Versalis Deutschland GmbH | | | Eschborn (Germany) | | | Germany | | | EUR | | | | | 100,000 | | | | Versalis SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Versalis France SAS | | | Mardyck (France) | | | France | | | EUR | | | | | 126,115,582.90 | | | | Versalis SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Versalis International SA | | | Bruxelles (Belgium) | | | Belgium | | | EUR | | | | | 15,449,173.88 | | | | Versalis SpA Versalis Deutsc.GmbH Dunastyr Zrt Versalis France | | | 59.00 23.71 14.43 2.86 | | | | | 100.00 | | | | | | F.C. | | | Versalis Kimya Ticaret Limited Sirketi | | | Istanbul (Turkey) | | | Turkey | | | TRY | | | | | 20,000 | | | | Versalis Int.SA | | | 100.00 | | | | | | | | | | | Eq. | | | Versalis Pacific (India) Private Ltd | | | Mumbai (India) | | | India | | | INR | | | | | 238,700 | | | | Versalis Pacific Trading Third parties | | | 99.99 (—) | | | | | | | | | | | Eq. | | | Versalis Pacific Trading (Shanghai) Co Ltd | | | Shanghai (China) | | | China | | | CNY | | | | | 1,000,000 | | | | Versalis SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Versalis UK Ltd | | | Lyndhurst, Hampshire (United Kingdom) | | | United Kingdom | | | GBP | | | | | 4,004,042 | | | | Versalis SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | |
Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Versalis SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 1,364,790,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Outside Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dunastyr Polisztirolgyártó Zártkörûen Mûködõ Részvénytársaság | | | Budapest (Hungary) | | | Hungary | | | HUF | | | | | 8,092,160,000 | | | | Versalis SpA Versalis Deutsc.GmbH Versalis Int.SA | | | 96.34 1.83 1.83 | | | | | 100.00 | | | | | | F.C. | | | Versalis Americas Inc | | | Dover, Delaware (USA) | | | USA | | | USD | | | | | 100,000 | | | | Versalis International SA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Versalis Congo Sarlu | | | Pointe-Noire (Republic of the Congo) | | | Republic of the Congo | | | XAF | | | | | 1,000,000 | | | | Versalis International SA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Versalis Deutschland GmbH | | | Eschborn (Germany) | | | Germany | | | EUR | | | | | 100,000 | | | | Versalis SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Versalis France SAS | | | Mardyck (France) | | | France | | | EUR | | | | | 126,115,582.90 | | | | Versalis SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Versalis International SA | | | Bruxelles (Belgium) | | | Belgium | | | EUR | | | | | 15,449,173.88 | | | | Versalis SpA Versalis Deutsc.GmbH Dunastyr Zrt Versalis France | | | 59.00 23.71 14.43 2.86 | | | | | 100.00 | | | | | | F.C. | | | Versalis Kimya Ticaret Limited Sirketi | | | Istanbul (Turkey) | | | Turkey | | | TRY | | | | | 20,000 | | | | Versalis Int.SA | | | 100.00 | | | | | | | | | | | Eq. | | | Versalis México S. de R.L. de CV | | | Mexico City (Mexico) | | | Mexico | | | MXN | | | | | 1,000 | | | | Versalis Int. SA Versalis SpA | | | 99.00 1.00 | | | | | | | | | | | Eq. | | | Versalis Pacific (India) Private Ltd | | | Mumbai (India) | | | India | | | INR | | | | | 238,700 | | | | Versalis Sing. P. Ltd Third parties | | | 99.99 (..) | | | | | | | | | | | Eq. | | | Versalis Pacific Trading (Shanghai) Co Ltd | | | Shanghai (China) | | | China | | | CNY | | | | | 1,000,000 | | | | Versalis SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Versalis Singapore Pte Ltd | | | Singapore (Singapore) | | | Singapore | | | SGD | | | | | 80,000 | | | | Versalis SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Versalis UK Ltd | | | London (United Kingdom) | | | United Kingdom | | | GBP | | | | | 4,004,042 | | | | Versalis SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Corporate and otherOther activities Corporate and financial companies Company name | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | | Registered office | | Country of operation | | Currency | | Share Capital | | Shareholders | | % Ownership | | % Equity ratio | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | | | | | | | | | | | | | | | In Italy | | In Italy | | Agenzia Giornalistica Italia SpA | | Rome | | Italy | | EUR | | | | 2,000,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Rome | | Italy | | EUR | | | | 2,000,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Adfin SpA | | Rome | | Italy | | EUR | | | | 85,537,498.80 | | | Eni SpA Third parties | | 99.65 0.35 | | | | 99.65 | | | | | F.C. | | | | D-Service Media Srl (in liquidation) | | | Milan | | Italy | | EUR | | | | 75,000 | | | D-Share SpA | | 100.00 | | | | | | | | | | | | D-Share SpA | | | Milan | | Italy | | EUR | | | | 121,719.25 | | | Agi SpA Third parties | | 55.21 44.79 | | | | | | | | | Co. | | | Eni Corporate University SpA | | San Donato Milanese (MI) | | Italy | | EUR | | | | 3,360,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | San Donato Milanese (MI) | | Italy | | EUR | | | | 3,360,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | EniServizi SpA | | San Donato Milanese (MI) | | Italy | | EUR | | | | 13,427,419.08 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | San Donato Milanese (MI) | | Italy | | EUR | | | | 13,427,419.08 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Serfactoring SpA | | San Donato Milanese (MI) | | Italy | | EUR | | | | 5,160,000 | | | Eni Adfin SpA Third parties | | 49.00 51.00 | | | | 48.83 | | | | | F.C. | | | | San Donato Milanese (MI) | | Italy | | EUR | | | | 5,160,000 | | | Eni SpA Third parties | | 49.00 51.00 | | | | 49.00 | | | | | F.C. | | | Servizi Aerei SpA | | San Donato Milanese (MI) | | Italy | | EUR | | | | 79,817,238 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | San Donato Milanese (MI) | | Italy | | EUR | | | | 79,817,238 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Outside Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | Outside Italy | | Outside Italy | | Banque Eni SA | | Bruxelles (Belgium) | | Belgium | | EUR | | | | 50,000,000 | | | Eni International BV Eni Oil Holdings BV | | 99.90 0.10 | | | | 100.00 | | | | | F.C. | | | | Bruxelles (Belgium) | | Belgium | | EUR | | | | 50,000,000 | | | Eni International BV Eni Oil Holdings BV | | 99.90 0.10 | | | | 100.00 | | | | | F.C. | | | D-Share USA Corp. | | | New York (USA) | | USA | | USD | | | | 0(a) | | | D-Share SpA | | 100.00 | | | | | | | | | | | | Eni Finance International SA | | Bruxelles (Belgium) | | Belgium | | USD | | | | 2,474,225,632 | | | Eni International BV Eni SpA | | 66.39 33.61 | | | | 100.00 | | | | | F.C. | | | | Bruxelles (Belgium) | | Belgium | | USD | | | | 1,480,365,336 | | | Eni International BV Eni SpA | | 66.39 33.61 | | | | 100.00 | | | | | F.C. | | | Eni Finance USA Inc | | Dover, Delaware (USA) | | USA | | USD | | | | 15,000,000 | | | Eni Petroleum Co Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Dover, Delaware (USA) | | USA | | USD | | | | 15,000,000 | | | Eni Petroleum Co Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni Insurance Designated Activity Company (former Eni Insurance Ltd) | | Dublin (Ireland) | | Ireland | | EUR | | | | 500,000,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Eni Insurance DAC | | | Dublin (Ireland) | | Ireland | | EUR | | | | 500,000,000 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni International BV | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 641,683,425 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | | Amsterdam (Netherlands) | | Netherlands | | EUR | | | | 641,683,425 | | | Eni SpA | | 100.00 | | | | 100.00 | | | | | F.C. | | | Eni International Resources Ltd | | London (United Kingdom) | | United Kingdom | | GBP | | | | 50,000 | | | Eni SpA Eni UK Ltd | | 99.99 (—) | | | | 100.00 | | | | | F.C. | | | | London (United Kingdom) | | United Kingdom | | GBP | | | | 50,000 | | | Eni SpA Eni UK Ltd | | 99.99 (..) | | | | 100.00 | | | | | F.C. | | | Eni Next Llc | | | Houston (USA) | | USA | | USD | | | | 100 | | | Eni Petroleum Co Inc | | 100.00 | | | | 100.00 | | | | | F.C. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (a)
Shares without nominal value.
Other Activitiesactivities Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | Anic Partecipazioni SpA (in liquidation) | | | Gela (CL) | | | Italy | | | EUR | | | | | 23,519,847.16 | | | | Syndial SpA Third parties | | | 99.96 0.04 | | | | | | | | | | | Eq. | | | Eni New Energy SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 5,000,000.00 | | | | Eni SpA | | | 100.00 | | | | | | | | | | | Co. | | | Industria Siciliana Acido Fosforico - ISAF - SpA (in liquidation) | | | Gela (CL) | | | Italy | | | EUR | | | | | 1,300,000 | | | | Syndial SpA Third parties | | | 52.00 48.00 | | | | | | | | | | | Eq. | | | Ing. Luigi Conti Vecchi SpA | | | Assemini (CA) | | | Italy | | | EUR | | | | | 5,518,620.64 | | | | Syndial SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Syndial Servizi Ambientali SpA (former Syndial SpA – Attività Diversificate) | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 422,269,480.70 | | | | Eni SpA Third parties | | | 99.99 (—) | | | | | 100.00 | | | | | | F.C. | | | Outside Italy | | | | | | | | | | Oleodotto del Reno SA | | | Coira (Switzerland) | | | Switzerland | | | CHF | | | | | 1,550,000 | | | | Syndial SpA | | | 100.00 | | | | | | | | | | | Eq. | | |
Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | In Italy | | Anic Partecipazioni SpA (in liquidation) | | | Gela (CL) | | | Italy | | | EUR | | | | | 23,519,847.16 | | | | Eni Rewind SpA Third parties | | | 99.97 0.03 | | | | | | | | | | | Eq. | | | Eni Energia Srl | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 10,000 | | | | Eni SpA | | | 100.00 | | | | | | | | | | | Co. | | | Eni Energy Activities Srl | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 50,000 | | | | Eni SpA | | | 100.00 | | | | | | | | | | | Co. | | | Eni New Energy SpA | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 9,296,000 | | | | Eni SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Rewind SpA (former Syndial Servizi Ambientali SpA) | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 425,343,731.50 | | | | Eni SpA Third parties | | | 99.99 (..) | | | | | 100.00 | | | | | | F.C. | | | Industria Siciliana Acido Fosforico-ISAF-SpA (in liquidation) | | | Gela (CL) | | | Italy | | | EUR | | | | | 1,300,000 | | | | Eni Rewind SpA Third parties | | | 52.00 48.00 | | | | | | | | | | | Eq. | | | Ing. Luigi Conti Vecchi SpA | | | Assemini (CA) | | | Italy | | | EUR | | | | | 5,518,620.64 | | | | Eni Rewind SpA | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Outside Italy | | Arm Wind Llp | | | Nur-Sultan (Kazakhstan) | | | Kazakhstan | | | KZT | | | | | 7,963,200,000 | | | | Windirect BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni Energy Solutions BV | | | Amsterdam (Netherlands) | | | Netherlands | | | EUR | | | | | 20,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | | Eni New Energy Egypt SAE | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 250,000 | | | | Eni International BV Ieoc Exploration BV Ieoc Production BV | | | 99.98 0.01 0.01 | | | | | | | | | | | Eq. | | | Eni New Energy Pakistan (Private) Ltd | | | Saddar Town-Karachi (Pakistan) | | | Pakistan | | | PKR | | | | | 136,000,000 | | | | Eni International BV Eni Oil Hold. BV Eni Pakistan Ltd (M) | | | 99.98 0.01 0.01 | | | | | 100.00 | | | | | | F.C. | | | Eni New Energy US Inc | | | Dover, Delaware (USA) | | | USA | | | USD | | | | | 100 | | | | Eni Petroleum Co Inc | | | 100.00 | | | | | | | | | | | Eq. | | | Eni Rewind International BV | | | Amsterdam (Netherlands) | | | Netherlands | | | EUR | | | | | 20,000 | | | | Eni International BV | | | 100.00 | | | | | | | | | | | Eq. | | | Oleodotto del Reno SA | | | Coira (Switzerland) | | | Switzerland | | | CHF | | | | | 1,550,000 | | | | Eni Rewind SpA | | | 100.00 | | | | | | | | | | | Eq. | | | Windirect BV | | | Amsterdam (Netherlands) | | | Netherlands | | | EUR | | | | | 10,000 | | | | Eni International BV | | | 100.00 | | | | | 100.00 | | | | | | F.C. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Joint arrangements and associates Exploration & Production Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | Eni East Africa SpA(†) | | | San Donato Milanese (MI) | | | Mozambique | | | EUR | | | | | 20,000,000 | | | | Eni SpA Third parties | | | 71.43 28.57 | | | | | 71.43 | | | | | | J.O. | | | Società Oleodotti Meridionali - SOM SpA(†) | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 3,085,000 | | | | Eni SpA Third parties | | | 70.00 30.00 | | | | | 70.00 | | | | | | J.O. | | | Outside Italy | | | | | | | | | | Agiba Petroleum Co(†) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | Angola LNG Ltd | | | Hamilton (Bermuda) | | | Angola | | | USD | | | | | 11,277,000,000 | | | | Eni Angola Prod.BV Third parties | | | 13.60 86.40 | | | | | | | | | | | Eq. | | | Ashrafi Island Petroleum Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 25.00 75.00 | | | | | | | | | | | Co. | | | Barentsmorneftegaz Sàrl(†) | | | Luxembourg (Luxembourg) | | | Russia | | | USD | | | | | 20,000 | | | | Eni Energy Russia BV Third parties | | | 33.33 66.67 | | | | | | | | | | | Eq. | | | Cabo Delgado Gas Development Limitada(†) | | | Maputo (Mozambique) | | | Mozambique | | | MZN | | | | | 2,500,000 | | | | Eni Mozam.LNG H. BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | CARDÓN IV SA(†) | | | Caracas (Venezuela) | | | Venezuela | | | VEF | | | | | 17,210,000 | | | | Eni Venezuela BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | Compañia Agua Plana SA | | | Caracas (Venezuela) | | | Venezuela | | | VEF | | | | | 100 | | | | Eni Venezuela BV Third parties | | | 26.00 74.00 | | | | | | | | | | | Co. | | | East Delta Gas Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 37.50 62.50 | | | | | | | | | | | Co. | | | East Kanayis Petroleum Co(†) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | East Obaiyed Petroleum Company(†) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | El-Fayrouz Petroleum Co(†) (in liquidation) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Exploration BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | El Temsah Petroleum Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 25.00 75.00 | | | | | | | | | | | Co. | | | Enstar Petroleum Ltd | | | Calgary (Canada) | | | Canada | | | CAD | | | | | 0.10 | | | | Unimar Llc | | | 100.00 | | | | Fedynskmorneftegaz Sàrl(†) | | | Luxembourg (Luxembourg) | | | Russia | | | USD | | | | | 20,000 | | | | Eni Energy Russia BV Third parties | | | 33.33 66.67 | | | | | | | | | | | Eq. | | | InAgip doo(†) | | | Zagreb (Croatia) | | | Croatia | | | HRK | | | | | 54,000 | | | | Eni Croatia BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | Karachaganak Petroleum Operating BV | | | Amsterdam (Netherlands) | | | Kazakhstan | | | EUR | | | | | 20,000 | | | | Agip Karachag.BV Third parties | | | 29.25 70.75 | | | | | | | | | | | Co. | | | Karachaganak Project Development Ltd (KPD) | | | Reading, Berkshire (United Kingdom) | | | United Kingdom | | | GBP | | | | | 100 | | | | Agip Karachag.BV Third parties | | | 38.00 62.00 | | | | | | | | | | | Eq. | | | Khaleej Petroleum Co Wll | | | Safat (Kuwait) | | | Kuwait | | | KWD | | | | | 250,000 | | | | Eni Middle E. Ltd Third parties | | | 49.00 51.00 | | | | | | | | | | | Eq. | | | Liberty National Development Co Llc | | | Wilmington (USA) | | | USA | | | USD | | | | | 0(a) | | | | Eni Oil & Gas Inc Third parties | | | 32.50 67.50 | | | | | | | | | | | Eq. | | | Llc ‘Westgasinvest’(†) | | | Lviv (Ukraine) | | | Ukraine | | | UAH | | | | | 2,000,000 | | | | Eni Ukraine Hold.BV Third parties | | | 50.01 49.99 | | | | | | | | | | | Eq. | | |
In Italy Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method (*) | | Mozambique Rovuma Venture SpA (†) | | | San Donato Milanese (MI) | | | Mozambique | | | EUR | | | | | 20,000,000 | | | | Eni SpA Third parties | | | 35.71 64.29 | | | | | 35.71 | | | | | | J.O. | | | Outside Italy | | Agiba Petroleum Co (†) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | Angola LNG Ltd | | | Hamilton (Bermuda) | | | Angola | | | USD | | | | | 9,952,000,000 | | | | Eni Angola Prod.BV Third parties | | | 13.60 86.40 | | | | | | | | | | | Eq. | | | Ashrafi Island Petroleum Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 25.00 75.00 | | | | | | | | | | | Co. | | | Barentsmorneftegaz Sàrl (†) | | | Luxembourg (Luxembourg) | | | Russia | | | USD | | | | | 20,000 | | | | Eni Energy Russia BV Third parties | | | 33.33 66.67 | | | | | | | | | | | Eq. | | | Cabo Delgado Gas Development Limitada (†) | | | Maputo (Mozambique) | | | Mozambique | | | MZN | | | | | 2,500,000 | | | | Eni Mozam.LNG H. BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | Cardón IV SA (†) | | | Caracas (Venezuela) | | | Venezuela | | | VES | | | | | 172.1 | | | | Eni Venezuela BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | Compañia Agua Plana SA | | | Caracas (Venezuela) | | | Venezuela | | | VES | | | | | 0.001 | | | | Eni Venezuela BV Third parties | | | 26.00 74.00 | | | | | | | | | | | Co. | | | Coral FLNG SA | | | Maputo (Mozambique) | | | Mozambique | | | MZN | | | | | 100,000,000 | | | | Eni Mozam.LNG H. BV Third parties | | | 25.00 75.00 | | | | | | | | | | | Eq. | | | Coral South FLNG DMCC | | | Dubai (United Arab Emirates) | | | United Arab Emirates | | | AED | | | | | 500,000 | | | | Eni Mozam.LNG H. BV Third parties | | | 25.00 75.00 | | | | | | | | | | | Eq. | | | East Delta Gas Co (in liquidation) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 37.50 62.50 | | | | | | | | | | | Co. | | | East Kanayis Petroleum Co (†) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | East Obaiyed Petroleum Co (†) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | El Temsah Petroleum Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 25.00 75.00 | | | | | | | | | | | Co. | | | El-Fayrouz Petroleum Co (†) (in liquidation) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Exploration BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | Fedynskmorneftegaz Sàrl (†) | | | Luxembourg (Luxembourg) | | | Russia | | | USD | | | | | 20,000 | | | | Eni Energy Russia BV Third parties | | | 33.33 66.67 | | | | | | | | | | | Eq. | | | Isatay Operating Company Llp (†) | | | Nur-Sultan (Kazakhstan) | | | Kazakhstan | | | KZT | | | | | 400,000 | | | | Eni Isatay BV Third parties | | | 50.00 50.00 | | | | | | | | | | | Co. | | | Karachaganak Petroleum Operating BV | | | Amsterdam (Netherlands) | | | Kazakhstan | | | EUR | | | | | 20,000 | | | | Agip Karachag.BV Third parties | | | 29.25 70.75 | | | | | | | | | | | Co. | | | Karachaganak Project Development Ltd (KPD) | | | Reading, Berkshire (United Kingdom) | | | United Kingdom | | | GBP | | | | | 100 | | | | Agip Karachag.BV Third parties | | | 38.00 62.00 | | | | | | | | | | | Eq. | | | Khaleej Petroleum Co Wll | | | Safat (Kuwait) | | | Kuwait | | | KWD | | | | | 250,000 | | | | Eni Middle E. Ltd Third parties | | | 49.00 51.00 | | | | | | | | | | | Eq. | | | Liberty National Development Co Llc | | | Wilmington (USA) | | | USA | | | USD | | | | | 0(a) | | | | Eni Oil & Gas Inc Third parties | | | 32.50 67.50 | | | | | | | | | | | Eq. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (†)
Jointly controlled entity. (a)
Shares without nominal value.
Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | Mediterranean Gas Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 25.00 75.00 | | | | | | | | Co. | | | Meleiha Petroleum Company (†) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 50.00 50.00 | | | | | | | | Co. | | | Mellitah Oil & Gas BV(†) | | | Amsterdam (Netherlands) | | | Libya | | | EUR | | | | | 20,000 | | | | Eni North Africa BV Third parties | | | 50.00 50.00 | | | | | | | | Co. | | | Nile Delta Oil Co Nidoco | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 37.50 62.50 | | | | | | | | Co. | | | Norpipe Terminal Holdco Ltd | | | London (United Kingdom) | | | Norway | | | GBP | | | | | 55.69 | | | | Eni SpA Third parties | | | 14.20 85.80 | | | | | | | | Eq. | | | North Bardawil Petroleum Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Exploration BV Third parties | | | 30.00 70.00 | | | | | | | | Co. | | | North El Burg Petroleum CompanyCo | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc SpA Third parties | | | 25.00 75.00 | | | | | | | | Co. | | | Petrobel Belayim Petroleum Co(†) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 50.00 50.00 | | | | | | | | Co. | | | PetroBicentenario SA(†) | | | Caracas (Venezuela) | | | Venezuela | | | VEFVES | | | | | 410,500,0003,790 | | | | Eni Lasmo Plc Third parties | | | 40.00 60.00 | | | | | | | | Eq. | | | PetroJunín SA(†) | | | Caracas (Venezuela) | | | Venezuela | | | VEFVES | | | | | 2,591,100,00024,021 | | | | Eni Lasmo Plc Third parties | | | 40.00 60.00 | | | | | | | | Eq. | | | PetroSucre SA | | | Caracas (Venezuela) | | | Venezuela | | | VEFVES | | | | | 220,300,0002,203 | | | | Eni Venezuela BV Third parties | | | 26.00 74.00 | | | | | | | | Eq. | | | Pharaonic Petroleum Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 25.00 75.00 | | | | | | | | Co. | | | Point Resources FPSO AS | | | Sandnes (Norway) | | | Norway | | | NOK | | | | | 150,100,000 | | | | PR FPSO Holding AS | | | 100.00 | | | | | | | | | | | Point Resources FPSO Holding AS | | | Sandnes (Norway) | | | Norway | | | NOK | | | | | 60,000 | | | | Vår Energi AS | | | 100.00 | | | | | | | | | | | Port Said Petroleum Co(†) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 50.00 50.00 | | | | | | | | Co. | | | PR Jotun DA | | | Sandnes (Norway) | | | Norway | | | NOK | | | | | 0(a) | | | | PR FPSO AS PR FPSO Holding AS | | | 95.00 5.00 | | | | | | | | | | | Raml Petroleum Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 22.50 77.50 | | | | | | | | Co. | | | Ras Qattara Petroleum Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 37.50 62.50 | | | | | | | | Co. | | | Rovuma Basin LNG Land Limitada(†) | | | Maputo (Mozambique) | | | Mozambique | | | MZN | | | | | 140,000 | | | | Eni East AfricaMozamb. Rov. V. SpA Third parties | | | 33.33 66.67 | | | | | | | | Co. | | | Shatskmorneftegaz Sàrl(†) Rovuma LNG Investments (DIFC) Ltd | | | LuxembourgMaputo
(Luxembourg)(Mozambique) | | | RussiaMozambique | | | USD | | | | | 20,00050,000 | | | | Eni Energy RussiaMoz. LNG H. BV Third parties | | | 33.3325.00
66.6775.00 | | | | | | | | Eq. | | | Rovuma LNG SA | | | Maputo (Mozambique) | | | Mozambique | | | MZN | | | | | 100,000,000 | | | | Eni Moz. LNG H. BV Third parties | | | 25.00 75.00 | | | | | | | | Eq. | | | Shorouk Petroleum Company(†) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 50.0025.00
50.0075.00 | | | | | | | | Co. | | | Société Centrale Electrique du Congo SA | | | Pointe-Noire (Republic of the Congo) | | | Republic of the Congo | | | XAF | | | | | 44,732,000,000 | | | | Eni Congo SA Third parties | | | 20.00 80.00 | | | | | | | | Eq. | | | Société Italo Tunisienne d’Exploitation Pétrolière SA(†) | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 5,000,000 | | | | Eni Tunisia BV Third parties | | | 50.00 50.00 | | | | | | | | Eq. | | | Sodeps - Société de Developpement et d’Exploitation du Permis du Sud SA(†) | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 100,000 | | | | Eni Tunisia BV Third parties | | | 50.00 50.00 | | | | | | | | Co. | | | Tapco Petrol Boru
Hatti
Sanayi ve Ticaret AS(†)
| | | Istanbul
(Turkey) | | | Turkey | | | TRY | | | | | 7,850,000 | | | | Eni International BV
Third parties | | | 50.00
50.00 | | | | | | | | Eq. | | | Tecninco Engineering Contractors Llp(†) | | | Aksai (Kazakhstan) | | | Kazakhstan | | | KZT | | | | | 29,478,455 | | | | TecnomareEniProgetti SpA Third parties | | | 49.00 51.00 | | | | | | | | Eq. | | | Thekah Petroleum Co (in liquidation) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Exploration BV Third parties | | | 25.00 75.00 | | | | | | | | Co. | | | Unimar Llc(†)
| | | Houston
(USA) | | | USA | | | USD | | | | | 0(a) | | | | Eni America Ltd
Third parties | | | 50.00
50.00 | | | | | | | | Eq. | | | United Gas Derivatives Co | | | New Cairo (Egypt) | | | Egypt | | | USD | | | | | 285,000,000153,000,000 | | | | Eni International BV Third parties | | | 33.33 66.67 | | | | | | | | Eq. | | | Vår Energi AS(†) | | | Forus (Norway) | | | Norway | | | NOK | | | | | 399,425,000 | | | | Eni International BV Third parties | | | 69.60 30.40 | | | | | | | | Eq. | | | Vår Energi Marine AS | | | Sandnes (Norway) | | | Norway | | | NOK | | | | | 61,000,000 | | | | Vår Energi AS | | | 100.00 | | | | | | | | | | | VIC CBM Ltd(†) | | | London (United Kingdom) | | | Indonesia | | | USD | | | | | 1,315,91252,315,912 | | | | Eni Lasmo Plc Third parties | | | 50.00 50.00 | | | | | | | | Eq. | | | Virginia Indonesia Co CBM Ltd(†) | | | London (United Kingdom) | | | Indonesia | | | USD | | | | | 631,64025,631,640 | | | | Eni Lasmo Plc Third parties | | | 50.00 50.00 | | | | | | | | Eq. | | | Virginia Indonesia Co
Llc | | | Wilmington
(USA) | | | Indonesia | | | USD | | | | | 10 | | | | Unimar Llc | | | 100.00 | | | | Virginia International
Co Llc | | | Wilmington
(USA) | | | Indonesia | | | USD | | | | | 10 | | | | Unimar Llc | | | 100.00 | | | | West Ashrafi Petroleum Co(†) (in liquidation) | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Exploration BV Third parties | | | 50.00 50.00 | | | | | | | | Co. | | | Zetah Noumbi Ltd | | | Nassau
(Bahamas) | | | Republic of
the Congo | | | USD | | | | | 100 | | | | Burren En.Congo Ltd
Third parties | | | 37.00
63.00 | | | | | | | | Co. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (†)
Jointly controlled entity. (a)
Shares without nominal value.
Gas & Power Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mariconsult SpA(†) | | | Milan | | | Italy | | | EUR | | | | | 120,000 | | | | Eni SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | Società EniPower Ferrara Srl(†) | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 170,000,000 | | | | EniPower SpA Third parties | | | 51.00 49.00 | | | | | 51.00 | | | | | | J.O. | | | Transmed SpA(†) | | | Milan | | | Italy | | | EUR | | | | | 240,000 | | | | Eni SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | Outside Italy | | | | | | | | | | Blue Stream Pipeline Co BV(†) | | | Amsterdam (Netherlands) | | | Russia | | | USD | | | | | 22,000 | | | | Eni International BV Third parties | | | 50.00 50.00 | | | | | 50.00 | | | | | | J.O. | | | Egyptian International Gas Technology Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 100,000,000 | | | | Eni International BV Third parties | | | 40.00 60.00 | | | | | | | | | | | Co. | | | Gas Distribution Company of Thessaloniki - Thessaly SA(†) (former Eteria Parohis Aeriou Thessalonikis AE) | | | Ampelokipi- Menemeni (Greece) | | | Greece | | | EUR | | | | | 266,309,200 | | | | Eni SpA Third parties | | | 49.00 51.00 | | | | | | | | | | | Eq. | | | GreenStream BV(†) | | | Amsterdam (Netherlands) | | | Libya | | | EUR | | | | | 200,000,000 | | | | Eni North Africa BV Third parties | | | 50.00 50.00 | | | | | 50.00 | | | | | | J.O. | | | Premium Multiservices SA | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 200,000 | | | | Sergaz SA Third parties | | | 49.99 50.01 | | | | | | | | | | | Eq. | | | SAMCO Sagl | | | Lugano (Switzerland) | | | Switzerland | | | CHF | | | | | 20,000 | | | | Eni International BV Transmed.Pip.Co Ltd Third parties | | | 5.00 90.00 5.00 | | | | | | | | | | | Eq. | | | Transmediterranean Pipeline Co Ltd(†) | | | St. Helier (Jersey) | | | Jersey | | | USD | | | | | 10,310,000 | | | | Eni SpA Third parties | | | 50.00 50.00 | | | | | 50.00 | | | | | | J.O. | | | Turul Gázvezeték Építõ es Vagyonkezelõ Részvénytársaság(†) | | | Tatabànya (Hungary) | | | Hungary | | | HUF | | | | | 404,000,000 | | | | Tigáz Zrt Third parties | | | 58.42 41.58 | | | | | | | | | | | Eq. | | | Unión Fenosa Gas SA(†) | | | Madrid (Spain) | | | Spain | | | EUR | | | | | 32,772,000 | | | | Eni SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | |
In Italy Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method (*) | | Mariconsult SpA (†) | | | Milan | | | Italy | | | EUR | | | | | 120,000 | | | | Eni SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | Società EniPower Ferrara Srl (†) | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 140,000,000 | | | | EniPower SpA Third parties | | | 51.00 49.00 | | | | | 51.00 | | | | | | J.O. | | | Transmed SpA (†) | | | Milan | | | Italy | | | EUR | | | | | 240,000 | | | | Eni SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | Outside Italy | | | | | | | | | | Angola LNG Supply Services Llc | | | Wilmington (USA) | | | USA | | | USD | | | | | 19,278,782 | | | | Eni USA Gas M. Llc Third parties | | | 13.60 86.40 | | | | | | | | | | | Eq. | | | Blue Stream Pipeline Co BV (†) | | | Amsterdam (Netherlands) | | | Russia | | | USD | | | | | 22,000 | | | | Eni International BV Third parties | | | 50.00 50.00 | | | | | 74.62(a) | | | | | | J.O. | | | Gas Distribution Company of Thessaloniki - Thessaly SA (†) | | | Ampelokipi- Menemeni (Greece) | | | Greece | | | EUR | | | | | 247,127,605 | | | | Eni gas e luce SpA Third parties | | | 49.00 51.00 | | | | | | | | | | | Eq. | | | GreenStream BV (†) | | | Amsterdam (Netherlands) | | | Libya | | | EUR | | | | | 200,000,000 | | | | Eni North Africa BV Third parties | | | 50.00 50.00 | | | | | 50.00 | | | | | | J.O. | | | Premium Multiservices SA | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 200,000 | | | | Sergaz SA Third parties | | | 49.99 50.01 | | | | | | | | | | | Eq. | | | SAMCO Sagl | | | Lugano (Switzerland) | | | Switzerland | | | CHF | | | | | 20,000 | | | | Eni International BV Transmed.Pip.Co Ltd Third parties | | | 5.00 90.00 5.00 | | | | | | | | | | | Eq. | | | Transmediterranean Pipeline Co Ltd (†) | | | St. Helier (Jersey) | | | Jersey | | | USD | | | | | 10,310,000 | | | | Eni SpA Third parties | | | 50.00 50.00 | | | | | 50.00 | | | | | | J.O. | | | Unión Fenosa Gas SA (†) | | | Madrid (Spain) | | | Spain | | | EUR | | | | | 32,772,000 | | | | Eni SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (†)
Jointly controlled entity. (a)
Equity ratio equal to the Eni’s working interest.
Refining & Marketing and Chemical Refining & Marketing In Italy Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | Arezzo Gas SpA(†) | | | Arezzo | | | Italy | | | EUR | | | | | 394,000 | | | | Eni Fuel SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | CePIM Centro Padano Interscambio Merci SpA | | | Fontevivo (PR) | | | Italy | | | EUR | | | | | 6,642,928.32 | | | | Ecofuel SpA Third parties | | | 44.78 55.22 | | | | | | | | | | | Eq. | | | Consorzio Operatori GPL di Napoli | | | Napoli | | | Italy | | | EUR | | | | | 102,000 | | | | Eni Fuel SpA Third parties | | | 25.00 75.00 | | | | | | | | | | | Co. | | | Costiero Gas Livorno SpA(†) | | | Livorno | | | Italy | | | EUR | | | | | 26,000,000 | | | | Eni Fuel SpA Third parties | | | 65.00 35.00 | | | | | 65.00 | | | | | | J.O. | | | Disma SpA | | | Segrate (MI) | | | Italy | | | EUR | | | | | 2,600,000 | | | | Eni Fuel SpA Third parties | | | 25.00 75.00 | | | | | | | | | | | Eq. | | | Livorno LNG Terminal SpA | | | Livorno | | | Italy | | | EUR | | | | | 200,000 | | | | Costiero Gas Liv. SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | Porto Petroli di Genova SpA | | | Genova | | | Italy | | | EUR | | | | | 2,068,000 | | | | Ecofuel SpA Third parties | | | 40.50 59.50 | | | | | | | | | | | Eq. | | | Raffineria di Milazzo ScpA(†) | | | Milazzo (ME) | | | Italy | | | EUR | | | | | 171,143,000 | | | | Eni SpA Third parties | | | 50.00 50.00 | | | | | 50.00 | | | | | | J.O. | | | Seram SpA | | | Fiumicino (RM) | | | Italy | | | EUR | | | | | 852,000 | | | | Eni SpA Third parties | | | 25.00 75.00 | | | | | | | | | | | Co. | | | Sigea Sistema Integrato Genova Arquata SpA | | | Genova | | | Italy | | | EUR | | | | | 3,326,900 | | | | Ecofuel SpA Third parties | | | 35.00 65.00 | | | | | | | | | | | Eq. | | | Società Oleodotti Meridionali - SOM SpA(†) | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 3,085,000 | | | | Eni SpA Third parties | | | 70.00 30.00 | | | | | 70.00 | | | | | | J.O. | | | Termica Milazzo Srl(†) | | | Milazzo (ME) | | | Italy | | | EUR | | | | | 100,000 | | | | Raff. Milazzo ScpA | | | 100.00 | | | | | 50.00 | | | | | | J.O. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (†)
Jointly controlled entity.
Refining & Marketing and ChemicalOutside Italy
Refining & Marketing
Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Arezzo Gas SpA(†) | | | Arezzo | | | Italy | | | EUR | | | | | 394,000 | | | | Eni Fuel SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | CePIM Centro Padano Interscambio Merci SpA | | | Fontevivo (PR) | | | Italy | | | EUR | | | | | 6,642,928.32 | | | | Ecofuel SpA Third parties | | | 34.93 65.07 | | | | | | | | | | | Eq. | | | Consorzio Operatori GPL di Napoli | | | Napoli | | | Italy | | | EUR | | | | | 102,000 | | | | Eni Fuel SpA Third parties | | | 25.00 75.00 | | | | | | | | | | | Co. | | | Costiero Gas Livorno SpA(†) | | | Livorno | | | Italy | | | EUR | | | | | 26,000,000 | | | | Eni Fuel SpA Third parties | | | 65.00 35.00 | | | | | 65.00 | | | | | | J.O. | | | Disma SpA | | | Segrate (MI) | | | Italy | | | EUR | | | | | 2,600,000 | | | | Eni Fuel SpA Third parties | | | 25.00 75.00 | | | | | | | | | | | Eq. | | | PETRA SpA(†) | | | Ravenna | | | Italy | | | EUR | | | | | 723,100 | | | | Ecofuel SpA Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | Petrolig Srl(†) | | | Genova | | | Italy | | | EUR | | | | | 104,000 | | | | Ecofuel SpA Third parties | | | 70.00 30.00 | | | | | 70.00 | | | | | | J.O. | | | Petroven Srl(†) | | | Genova | | | Italy | | | EUR | | | | | 156,000 | | | | Ecofuel SpA Third parties | | | 68.00 32.00 | | | | | 68.00 | | | | | | J.O. | | | Porto Petroli di Genova SpA | | | Genova | | | Italy | | | EUR | | | | | 2,068,000 | | | | Ecofuel SpA Third parties | | | 40.50 59.50 | | | | | | | | | | | Eq. | | | Raffineria di Milazzo ScpA(†) | | | Milazzo (ME) | | | Italy | | | EUR | | | | | 171,143,000 | | | | Eni SpA Third parties | | | 50.00 50.00 | | | | | 50.00 | | | | | | J.O. | | | SeaPad SpA(†) | | | Genova | | | Italy | | | EUR | | | | | 12,400,000 | | | | Ecofuel SpA Third parties | | | 80.00 20.00 | | | | | | | | | | | Eq. | | | Seram SpA | | | Fiumicino (RM) | | | Italy | | | EUR | | | | | 852,000 | | | | Eni SpA Third parties | | | 25.00 75.00 | | | | | | | | | | | Co. | | | Servizi Milazzo Srl(†) | | | Milazzo (ME) | | | Italy | | | EUR | | | | | 100,000 | | | | Raff. Milazzo ScpA | | | 100.00 | | | | | 50.00 | | | | | | J.O. | | | Sigea Sistema Integrato Genova Arquata SpA | | | Genova | | | Italy | | | EUR | | | | | 3,326,900 | | | | Ecofuel SpA Third parties | | | 35.00 65.00 | | | | | | | | | | | Eq. | | | Termica Milazzo Srl(†) | | | Milazzo (ME) | | | Italy | | | EUR | | | | | 100,000 | | | | Raff. Milazzo ScpA | | | 100.00 | | | | | 50.00 | | | | | | J.O. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
(†)
Jointly controlled entity.
Refining & Marketing
Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | Outside Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | AET - Raffineriebeteiligungs gesellschaft mbH | | | Schwedt (Germany) | | | Germany | | | EUR | | | | | 27,000 | | | | Eni Deutsch.GmbH Third parties | | | 33.33 66.67 | | | | | | | | | | | Eq. | | | Bayernoil Raffineriegesellschaft mbH(†) | | | Vohburg (Germany) | | | Germany | | | EUR | | | | | 10,226,000 | | | | Eni Deutsch.GmbH Third parties | | | 20.00 80.00 | | | | | 20.00 | | | | | | J.O. | | | City Carburoil SA(†) | | | Rivera (Switzerland) | | | Switzerland | | | CHF | | | | | 6,000,000 | | | | Eni Suisse SA Third parties | | | 49.91 50.09 | | | | | | | | | | | Eq. | | | ENEOS Italsing Pte Ltd | | | Singapore (Singapore) | | | Singapore | | | SGD | | | | | 12,000,000 | | | | Eni International BV Third parties | | | 22.50 77.50 | | | | | | | | | | | Eq. | | | FSH Flughafen Schwechat Hydranten-Gesellschaft OG | | | Wien (Austria) | | | Austria | | | EUR | | | | | 7,098,752.57 | | | | Eni Market.A.GmbH Eni Mineralölh.GmbH Eni Austria GmbH Third parties | | | 14.29 14.29 14.28 57.14 | | | | | | | | | | | Co. | | | Fuelling Aviation Services GIE | | | Tremblay en France (France) | | | France | | | EUR | | | | | 1 | | | | Eni France Sàrl Third parties | | | 25.00 75.00 | | | | | | | | | | | Co. | | | Mediterranée Bitumes SA | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 1,000,000 | | | | Eni International BV Third parties | | | 34.00 66.00 | | | | | | | | | | | Eq. | | | Routex BV | | | Amsterdam (Netherlands) | | | Netherlands | | | EUR | | | | | 67,500 | | | | Eni International BV Third parties | | | 20.00 80.00 | | | | | | | | | | | Eq. | | | Saraco SA | | | Meyrin (Switzerland) | | | Switzerland | | | CHF | | | | | 420,000 | | | | Eni Suisse SA Third parties | | | 20.00 80.00 | | | | | | | | | | | Co. | | | Supermetanol CA(†) | | | Jose Puerto La Cruz (Venezuela) | | | Venezuela | | | VEF | | | | | 12,086,744.84 | | | | Ecofuel SpA Supermetanol CA Third parties | | | 34.51(a) 30.07 35.42 | | | | | 50.00 | | | | | | J.O. | | | TBG Tanklager Betriebsgesellschaft GmbH(†) | | | Salzburg (Austria) | | | Austria | | | EUR | | | | | 43,603.70 | | | | Eni Market.A.GmbH Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | Weat Electronic Datenservice GmbH | | | Düsseldorf (Germany) | | | Germany | | | EUR | | | | | 409,034 | | | | Eni Deutsch.GmbH Third parties | | | 20.00 80.00 | | | | | | | | | | | Eq. | | |
Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | Abu Dhabi Oil Refining Company (TAKREER) | | | Abu Dhabi (United Arab Emirates) | | | United Arab Emirates | | | AED | | | | | 500,000,000 | | | | Eni Abu Dhabi R&T BV Third parties | | | 20.00 80.00 | | | | | | | | | | | Eq. | | | ADNOC Global Trading Ltd | | | Abu Dhabi (United Arab Emirates) | | | United Arab Emirates | | | USD | | | | | 1,000 | | | | Eni Abu Dhabi R&T BV Third parties | | | 20.00 80.00 | | | | | | | | | | | Eq. | | | AET - Raffinerie beteiligungs gesellschaft mbH(†) | | | Schwedt (Germany) | | | Germany | | | EUR | | | | | 27,000 | | | | Eni Deutsch.GmbH Third parties | | | 33.33 66.67 | | | | | | | | | | | Eq. | | | Bayernoil Raffinerie gesellschaft mbH(†) | | | Vohburg (Germany) | | | Germany | | | EUR | | | | | 10,226,000 | | | | Eni Deutsch.GmbH Third parties | | | 20.00 80.00 | | | | | 20.00 | | | | | | J.O. | | | City Carburoil SA(†) | | | Rivera (Switzerland) | | | Switzerland | | | CHF | | | | | 6,000,000 | | | | Eni Suisse SA Third parties | | | 49.91 50.09 | | | | | | | | | | | Eq. | | | Egyptian International Gas Technology Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 100,000,000 | | | | Eni International BV Third parties | | | 40.00 60.00 | | | | | | | | | | | Co. | | | ENEOS Italsing Pte Ltd | | | Singapore (Singapore) | | | Singapore | | | SGD | | | | | 12,000,000 | | | | Eni International BV Third parties | | | 22.50 77.50 | | | | | | | | | | | Eq. | | | Fuelling Aviation Services GIE | | | Tremblay en France (France) | | | France | | | EUR | | | | | 1 | | | | Eni France Sàrl Third parties | | | 25.00 75.00 | | | | | | | | | | | Co. | | | Mediterranée Bitumes SA | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 1,000,000 | | | | Eni International BV Third parties | | | 34.00 66.00 | | | | | | | | | | | Eq. | | | Routex BV | | | Amsterdam (Netherlands) | | | Netherlands | | | EUR | | | | | 67,500 | | | | Eni International BV Third parties | | | 20.00 80.00 | | | | | | | | | | | Eq. | | | Saraco SA | | | Meyrin (Switzerland) | | | Switzerland | | | CHF | | | | | 420,000 | | | | Eni Suisse SA Third parties | | | 20.00 80.00 | | | | | | | | | | | Co. | | | Supermetanol CA(†) | | | Jose Puerto La Cruz (Venezuela) | | | Venezuela | | | VES | | | | | 120.867 | | | | Ecofuel SpA Supermetanol CA Third parties | | | 34.51(a) 30.07 35.42 | | | | | 50.00 | | | | | | J.O. | | | TBG Tanklager Betriebs gesellschaft GmbH(†) | | | Salzburg (Austria) | | | Austria | | | EUR | | | | | 43,603.70 | | | | Eni Market.A.GmbH Third parties | | | 50.00 50.00 | | | | | | | | | | | Eq. | | | Weat Electronic Datenservice GmbH | | | Düsseldorf (Germany) | | | Germany | | | EUR | | | | | 409,034 | | | | Eni Deutsch.GmbH Third parties | | | 20.00 80.00 | | | | | | | | | | | Eq. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (†)
Jointly controlled entity. | (a)
Controlling interest: | | | Ecofuel SpA Third parties | | | 50.00 50.00 | |
Chemical Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Brindisi Servizi Generali Scarl | | | Brindisi | | | Italy | | | EUR | | | | | 1,549,060 | | | | Versalis SpA
SyndialEni Rewind SpA EniPower SpA Third parties | | | 49.00 20.20 8.90 21.90 | | | | | | | | Eq. | | | IFM Ferrara ScpA | | | Ferrara | | | Italy | | | EUR | | | | | 5,270,466 | | | | Versalis SpA
SyndialEni Rewind SpA S.E.F. Srl Third parties | | | 19.74 11.58 10.70 57.98 | | | | | | | | Eq. | | | Matrìca SpA(†) | | | Porto Torres (SS) | | | Italy | | | EUR | | | | | 37,500,000 | | | | Versalis SpA Third parties | | | 50.00 50.00 | | | | | | | | Eq. | | | Newco Tech SpA(†)
| | | Novara | | | Italy | | | EUR | | | | | 500,000 | | | | Versalis SpA
Genomatica Inc. | | | 80.00
20.00 | | | | | | | | Eq. | | | Novamont SpA | | | Novara | | | Italy | | | EUR | | | | | 13,333,500 | | | | Versalis SpA Third parties | | | 25.00 75.00 | | | | | | | | Eq. | | | Priolo Servizi ScpA | | | Melilli (SR) | | | Italy | | | EUR | | | | | 28,100,000 | | | | Versalis SpA
SyndialEni Rewind SpA Third parties | | | 33.1633.11
4.384.61
62.4662.28 | | | | | | | | Eq. | | | Ravenna Servizi Industriali ScpA | | | Ravenna | | | Italy | | | EUR | | | | | 5,597,400 | | | | Versalis SpA EniPower SpA Ecofuel SpA Third parties | | | 42.13 30.37 1.85 25.65 | | | | | | | | Eq. | | | Servizi Porto Marghera Scarl | | | Porto Marghera (VE) | | | Italy | | | EUR | | | | | 8,695,718 | | | | Versalis SpA
SyndialEni Rewind SpA Third parties | | | 48.44 38.39 13.17 | | | | | | | | Eq. | | | Outside Italy | | | | | | | | | | Lotte Versalis Elastomers Co
Co Ltd(†) | | | Yeosu (South Korea) | | | South Korea | | | KRW | | | | | 192,000,010,000401,800,000,000 | | | | Versalis SpA Third parties | | | 50.00 50.00 | | | | | | | | Eq. | | | Versalis Zeal Ltd (†) | | | Takoradi (Ghana) | | | Ghana | | | GHS | | | | | 5,650,000 | | | | Versalis Intern. SA Third parties | | | 80.00 20.00 | | | | | | | | Eq. | | | VPM Oilfield Specialty Chemicals Llc(†) | | | Abu Dhabi (United Arab Emirates) | | | United Arab Emirates | | | AED | | | | | 1,000,000 | | | | Versalis SpA Third parties | | | 49.00 51.00 | | | | | | | | Eq. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (†)
Jointly controlled entity.
Corporate and otherOther activities Other activitiesCorporate and financial companies
Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity ratio | | | Consolidation or valutation method(*) | | Outside Italy | | | | | | | | | | Commonwealth Fusion Systems Llc(a) | | | Wilmington (USA) | | | USA | | | USD | | | | | 115,000,519 | | | | Eni Next Llc Third parties | | | | | | | | | | | Eq. | | | Form Energy Inc(b) | | | Sommerville (USA) | | | USA | | | USD | | | | | 50,889,548.24 | | | | Eni Next Llc Third parties | | | | | | | | | | | Eq. | | |
Other activities In Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Filatura Tessile Nazionale
Italiana - FILTENI SpA
(in liquidation)
| | | Ferrandina (MT) | | | Italy | | | EUR | | | | | 4,644,000 | | | | Syndial SpA
Third parties | | | 59.56(a)
40.44
| | | | | | | | Co. | | | Ottana Sviluppo ScpA (in liquidation)bankruptcy) | | | Nuoro | | | Italy | | | EUR | | | | | 516,000 | | | | SyndialEni Rewind SpA Third parties | | | 30.00
70.00 | | | | | | | | Eq. | | | | Progetto Nuraghe Scarl | | | Porto Torres (SS) | | | Italy | | | EUR | | | | | 10,000 | | | | Eni Rewind SpA Third parties | | | 48.55
51.45 | | | | | | | | Eq. | | | | Saipem SpA(#)(†) | | | San Donato Milanese (MI) | | | Italy | | | EUR | | | | | 2,191,384,693 | | | | Eni SpA Saipem SpA Third parties | | | 30.54(b)(c)
0.701.46
68.7668.00 | | | | | | | | Eq. | | | | Outside Italy | | | | | | | | | | | Ayla Energy Ltd(†) | | | London (United Kingdom) | | | United Kingdom | | | USD | | | | | 1,000 | | | | Eni En. Solutions BV Third parties | | | 50.00
50.00 | | | | | | | | Eq. | | | | Grid Edge (Private) Ltd(†) | | | Saddar Town - Karachi (Pakistan) | | | Pakistan | | | PKR | | | | | 1,200,000 | | | | Eni International BV Third parties | | | 40.00
60.00 | | | | | | | | Eq. | | | | Société Energies Renouvelables Eni-ETAP SA (†) | | | Tunisi (Tunisia) | | | Tunisia | | | TND | | | | | 1,000,000 | | | | Eni International BV Third parties | | | 50.00
50.00 | | | | | | | | Eq. | | | | Solenova Ltd (†) | | | London (United Kingdom) | | | United Kingdom | | | USD | | | | | 20,000 | | | | Eni En. Solutions BV Third parties | | | 50.00
50.00 | | | | | | | | Eq. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (#)
Company with shares quoted in the regulated market of Italy or of other EU countries (†)
Jointly controlled entity. (a)
The ownership cannot be determined. The capital subscribed by Eni Next Llc amounts to $50 million. (b)
The ownership cannot be determined. The capital subscribed by Eni Next Llc amounts to $15 million. | (a)
Controlling interest:
| | | Syndial SpA
Third parties | | | 48.00
52.00 | | | (b)(c)
Controlling interest: | | | Eni SpA Third parties | | | 30.7630.99
69.2469.01 | |
Other significant investments Exploration & Production In Italy Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity
ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Consorzio Universitario in Ingegneria per la Qualità e l’Innovazione | | | Pisa | | | Italy | | | EUR | | | | | 135,000 | | | | Eni SpA Third parties | | | 16.6720.00
83.3380.00 | | | | | | | | Co.F.V. | | |
Outside Italy Outside Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Administradora del Golfo de Paria Este SA | | | Caracas (Venezuela) | | | Venezuela | | | VEFVES | | | | | 1000.001 | | | | Eni Venezuela BV Third parties | | | 19.50 80.50 | | | | | | | | Co.F.V. | | | | Brass LNG Ltd | | | Lagos (Nigeria) | | | Nigeria | | | USD | | | | | 1,000,000 | | | | Eni Int. NA NV Sàrl Third parties | | | 20.48
79.52 | | | | | | | | Co.F.V. | | | | Darwin LNG Pty Ltd | | | West Perth (Australia) | | | Australia | | | AUD | | | | | 845,104,523.19367,278,503.01 | | | | Eni G&P LNG Aus. BV Third parties | | | 10.99
89.01 | | | | | | | | Co.F.V. | | | | New Liberty Residential Co Llc | | | West Trenton (USA) | | | USA | | | USD | | | | | 0(a) | | | | Eni Oil & Gas Inc Third parties | | | 17.50 82.50 | | | | | | | | Co.F.V. | | | | Nigeria LNG Ltd | | | Port Harcourt (Nigeria) | | | Nigeria | | | USD | | | | | 1,138,207,000 | | | | Eni Int. NA NV Sàrl Third parties | | | 10.40
89.60 | | | | | | | | Co.F.V. | | | Norsea Pipeline Ltd | | | Woking Surrey
(United
Kingdom) | | | United
Kingdom | | | GBP | | | | | 7,614,062 | | | | Eni SpA
Third parties | | | 10.32
89.68 | | | | | | | | Co. | | | North Caspian Operating Co NV | | | Amsterdam (Netherlands) | | | Kazakhstan | | | EUR | | | | | 128,520 | | | | Agip Caspian Sea BV Third parties | | | 16.81
83.19 | | | | | | | | Co.F.V. | | | | OPCO - Sociedade Operacional Angola LNG SA | | | Luanda (Angola) | | | Angola | | | AOA | | | | | 7,400,000 | | | | Eni Angola Prod.BV Third parties | | | 13.60
86.40 | | | | | | | | Co.F.V. | | | | Petrolera Güiria SA | | | Caracas (Venezuela) | | | Venezuela | | | VEFVES | | | | | 1,000,00010 | | | | Eni Venezuela BV Third parties | | | 19.50 80.50 | | | | | | | | Co.F.V. | | | Point Fortin LNG Exports Ltd | | | Port Of Spain
(Trinidad and
Tobago) | | | Trinidad and
Tobago | | | USD | | | | | 10,000 | | | | Eni T&T Ltd
Third parties | | | 17.31
82.69 | | | | | | | | Co. | | | SOMG - Sociedade de Operações e Manutenção de Gasodutos SA | | | Luanda (Angola) | | | Angola | | | AOA | | | | | 7,400,000 | | | | Eni Angola Prod.BV Third parties | | | 13.60
86.40 | | | | | | | | Co.F.V. | | | | Torsina Oil Co | | | Cairo (Egypt) | | | Egypt | | | EGP | | | | | 20,000 | | | | Ieoc Production BV Third parties | | | 12.50
87.50 | | | | | | | | Co.F.V. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (a)
Shares without nominal value.
Gas & Power Outside Italy Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity
ratio | | | Consolidation or valutation method(*) | | Outside Italy | | | | | | | | | | Angola LNG Supply Services
Llc | | | Wilmington
(USA) | | | USA | | | USD | | | | | 19,278,782 | | | | Eni USA Gas M. Llc
Third parties | | | 13.60
86.40 | | | | | | | | Co. | | | Norsea Gas GmbH | | | Emden (Germany) | | | Germany | | | EUR | | | | | 1,533,875.64 | | | | Eni International BV Third parties | | | 13.04 86.96 | | | | | | | | Co.F.V. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
Refining & Marketing and Chemical Refining & Marketing In Italy Company name | | | Registered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | % Equity
ratio | | | Consolidation or valutation method(*) | | In Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Consorzio Obbligatorio
degli Oli Usati | | | Rome | | | Italy | | | EUR | | | | | 36,149 | | | | Eni SpA
Third parties | | | 13.27
86.73 | | | | | | | | Co. | | | Società Italiana Oleodotti di Gaeta SpA(1)(a) | | | Rome | | | Italy | | | ITL | | | | | 360,000,000 | | | | Eni SpA Third parties | | | 72.48 27.52 | | | | | F.V. | | |
Outside Italy Company name | | | Co. | | | Outside ItalyRegistered office | | | Country of operation | | | Currency | | | Share Capital | | | Shareholders | | | % Ownership | | | | | | | | | | | | | | | Consolidation or valutation method(*) | | BFS Berlin Fuelling Services GbR | | | Hamburg (Germany) | | | Germany | | | EUR | | | | | 145,75889,199 | | | | Eni Deutsch.GmbH Third parties | | | 12.50 87.50 | | | | | | | | Co.F.V. | | | Compania de Economia Mixta ‘Austrogas’ | | | Cuenca (Ecuador) | | | Ecuador | | | USD | | | | | 3,028,7495,665,329 | | | | Eni Ecuador SA Third parties | | | 13.3113.38
86.6986.62 | | | | | | | | Co.F.V. | | | Dépotpôt Pétrolier de Fos SA | | | Fos-Sur-Mer (France) | | | France | | | EUR | | | | | 3,954,196.40 | | | | Eni France Sàrl Third parties | | | 16.81 83.19 | | | | | | | | Co.F.V. | | | Dépôt Pétrolier de la Côte
dAzur d’Azur SAS | | | Nanterre (France) | | | France | | | EUR | | | | | 207,500 | | | | Eni France Sàrl Third parties | | | 18.00 82.00 | | | | | | | | Co.F.V. | | | Joint Inspection Group Ltd | | | London
(United (United Kingdom) | | | United Kingdom | | | GBP | | | | | 0(ab) | | | | Eni SpA Third parties | | | 12.50 87.50 | | | | | | | | Co.F.V. | | | S.I.P.G. SocéSociété ImmobilierImmobilière Pétroliertrolière de Gestion Snc | | | Tremblay-En-
FranceTremblay-En-France (France) | | | France | | | EUR | | | | | 40,000 | | | | Eni France Sàrl Third parties | | | 12.50 87.50 | | | | | | | | Co.F.V. | | | Sistema Integrado de Gestion de Aceites Usados | | | Madrid (Spain) | | | Spain | | | EUR | | | | | 175,713 | | | | Eni Iberia SLU Third parties | | | 15.44 84.56 | | | | | | | | Co.F.V. | | | Tanklager - Gesellschaft Tegel (TGT) GbR | | | Hamburg (Germany) | | | Germany | | | EUR | | | | | 234,953 | | | | Eni Deutsch.GmbH Third parties | | | 12.50 87.50 | | | | | | | | Co.F.V. | | | TAR - Tankanlage Ruemlang AG | | | Ruemlang (Switzerland) | | | Switzerland | | | CHF | | | | | 3,259,500 | | | | Eni Suisse SA Third parties | | | 16.27 83.73 | | | | | | | | Co.F.V. | | | Tema Lube Oil Co Ltd | | | Accra (Ghana) | | | Ghana | | | GHS | | | | | 258,309 | | | | Eni International BV Third parties | | | 12.00 88.00 | | | | | | | | Co.F.V. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value (a)
Shares without nominal value.
(1)
Company under extraordinary administration procedure pursuant to Lawlaw no. 95 of Aprilapril 3, 1979. The liquidation was concluded on april 28, 2015. The cancellation has been filed and is pending the authorization by the Ministry of Economic Development. (b)
Shares without nominal value.
Corporate and other activities
Corporate and financial companies
Company name | | | Registered
office | | | Country of
operation | | | Currency | | | Share
Capital | | | Shareholders | | | %
Ownership | | | % Equity
ratio | | | Consolidation
or valutation
method(*)
| | In Italy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Emittenti Titoli SpA | | | Milan | | | Italy | | | EUR | | | | | 4,264,000 | | | | Eni SpA
Emittenti Titoli SpA
Third parties | | | 10.00 (a)
0.78
89.22
| | | | | | | | Co. | | | Mip Politecnico di Milano - Graduate School of Business ScpA | | | Milan | | | Italy | | | EUR | | | | | 150,000 | | | | Eni Corporate U.SpA
Third parties | | | 10.67
89.33 | | | | | | | | Co. | | |
(*)
F.C. = full consolidation, J.O. = joint operation, Eq. = equity-accounted, Co. = valued at cost, F.V. = valued at fair value
| (a)
Controlling interest:
| | | Eni SpA
Third parties | | | 10.08
89.92 | |
Information on Eni’s consolidated subsidiaries with significant non-controlling interest In 2016,2019 and 2018, Eni did not own any consolidated subsidiaries with a significant non-controlling interest. In 2015, Eni did not own any consolidated subsidiaries with significant non-controlling The total shareholders’ equity pertaining to minority interests as consequence of the classification of the Saipem Group as discontinued operations. Total shareholders’ equity attributable to non-controlling interestsDecember 31, 2019, amounted to €49€61 million (€1,91657 million at December 31, 2015, of which €1,872 million pertaining to the Saipem Group)2018).
Changes in the ownership interest without loss of control In 2015 and 2016,2019, Eni acquired a 10% stake of Windirect BV. In 2018, Eni did not report any changes in ownership interest without loss or acquisition of control. Principal joint ventures, joint operations and associates as of December 31, 20162019 Company name | | Registered office | | Operating office | | Business segment | | % ownership interest | | % voting rights | | | Registered office | | Country of operation | | Business segment | | % ownership interest | | Eni’s % of the investment | | Joint venture | | | | | | | | | | | | | | | | | CARDÓN IV SA | | Caracas (Venezuela) | | Venezuela | | Exploration & Production | | 50.00 | | 50.00 | | | Gas Distribution Company of Thessaloniki - Thessaly SA | | Ampelokipi- Menemeni (Greece) | | Greece | | Gas & Power | | 49.00 | | 49.00 | | | PetroJunín SA | | Caracas (Venezuela) | | Venezuela | | Exploration & Production | | 40.00 | | 40.00 | | | Vår Energi AS | | | Forus (Norway) | | Norway | | Exploration & Production | | | | 69.60 | | | 69.60 | | Saipem SpA | | San Donato Milanese (MI) (Italy) | | Italia | | Other Activities | | 30.54 | | 30.76 | | | San Donato Milanese (MI) (Italy) | | Italy | | Other Activities | | | | 30.54 | | | 30.99 | | Unión Fenosa Gas SA | | Madrid (Spain) | | Spain | | Gas & Power | | 50.00 | | 50.00 | | | Madrid (Spain) | | Spain | | Gas & Power | | | | 50.00 | | | 50.00 | | Cardón IV SA | | | Caracas (Venezuela) | | Venezuela | | Exploration & Production | | | | 50.00 | | | 50.00 | | Gas Distribution Company of Thessaloniki - Thessaly SA | | | Ampelokipi-Menemeni (Greece) | | Greece | | Gas & Power | | | | 49.00 | | | 49.00 | | Joint Operation | | | | | | | | | | | | | | | | | Mozambique Rovuma Venture SpA | | | San Donato Milanese (MI) (Italy) | | Mozambique | | Exploration & Production | | | | 35.71 | | | 35.71 | | Raffineria di Milazzo ScpA | | | Milazzo (ME) (Italy) | | Italy | | Refining & Marketing | | | | 50.00 | | | 50.00 | | GreenStream BV | | | Amsterdam (Netherlands) | | Libya | | Gas & Power | | | | 50.00 | | | 50.00 | | Blue Stream Pipeline Co BV | | Amsterdam (Netherlands) | | Russia | | Gas & Power | | 50.00 | | 50.00 | | | Amsterdam (Netherlands) | | Russia | | Gas & Power | | | | 74.62 | | | 74.62 | | Eni East Africa SpA | | San Donato Milanese (MI) (Italy) | | Mozambique | | Exploration & Production | | 71.43 | | 71.43 | | | Raffineria di Milazzo ScpA | | Milazzo (ME) (Italy) | | Italy | | Refining & Marketing | | 50.00 | | 50.00 | | | Associates | | | | | | | | | | | | | | | | | Abu Dhabi Oil Refining Co (Takreer) | | | Abu Dhabi (United Arab Emirates) | | United Arab Emirates | | Refining & Marketing | | | | 20.00 | | | 20.00 | | Angola LNG Ltd | | Hamilton (Bermuda) | | Angola | | Exploration & Production | | 13.60 | | 13.60 | | | Hamilton (Bermuda) | | Angola | | Exploration & Production | | | | 13.60 | | | 13.60 | | United Gas Derivatives Co | | Cairo (Egypt) | | Egypt | | Exploration & Production | | 33.33 | | 33.33 | | | Coral FLNG SA | | | Maputo (Mozambique) | | Mozambique | | Exploration & Production | | | | 25.00 | | | 25.00 | |
The mainMain line items of profit and loss and balance sheet related to the principal joint ventures, represented by the amounts included in the reports accounted under IFRS of each company, are provided in the table below:
| | | | | | | | 2015 | | | 2016 | | (€ million) | | | CARDÓN IV SA | | | Gas Distribution Company of Thessaloniki -Thessaly SA | | | Petro Junín SA | | | Unión Fenosa Gas SA | | | Other joint ventures | | | Saipem SpA | | | CARDÓN IV SA | | | Gas Distribution Company of Thessaloniki -Thessaly SA | | | Petro Junín SA | | | Unión Fenosa Gas SA | | | Other joint ventures | | Current assets | | | | | 1,125 | | | | | | 61 | | | | | | 197 | | | | | | 695 | | | | | | 326 | | | | | | 7,783 | | | | | | 451 | | | | | | 34 | | | | | | 336 | | | | | | 651 | | | | | | 209 | | | - of which cash and cash equivalent | | | | | 27 | | | | | | 34 | | | | | | 5 | | | | | | 55 | | | | | | 113 | | | | | | 1,892 | | | | | | 31 | | | | | | 8 | | | | | | 2 | | | | | | 25 | | | | | | 56 | | | Non-current assets | | | | | 2,951 | | | | | | 204 | | | | | | 623 | | | | | | 1,156 | | | | | | 1,086 | | | | | | 6,500 | | | | | | 3,628 | | | | | | 285 | | | | | | 703 | | | | | | 1,037 | | | | | | 886 | | | Total assets | | | | | 4,076 | | | | | | 265 | | | | | | 820 | | | | | | 1,851 | | | | | | 1,412 | | | | | | 14,283 | | | | | | 4,079 | | | | | | 319 | | | | | | 1,039 | | | | | | 1,688 | | | | | | 1,095 | | | Current liabilities | | | | | 3,356 | | | | | | 19 | | | | | | 361 | | | | | | 294 | | | | | | 705 | | | | | | 5,668 | | | | | | 455 | | | | | | 13 | | | | | | 480 | | | | | | 232 | | | | | | 469 | | | - current financial liabilities | | | | | 2,223 | | | | | | | | | | | | | | | | | | 55 | | | | | | 496 | | | | | | 206 | | | | | | | | | | | | | | | | | | | | | | | | 61 | | | | | | 299 | | | Non-current liabilities | | | | | 298 | | | | | | 23 | | | | | | 25 | | | | | | 697 | | | | | | 167 | | | | | | 3,730 | | | | | | 3,230 | | | | | | | | | | | | 32 | | | | | | 650 | | | | | | 339 | | | - non-current financial liabilities | | | | | | | | | | | | | | | | | | | | | | | 590 | | | | | | 76 | | | | | | 3,194 | | | | | | 2,108 | | | | | | | | | | | | | | | | | | 547 | | | | | | 281 | | | Total liabilities | | | | | 3,654 | | | | | | 42 | | | | | | 386 | | | | | | 991 | | | | | | 872 | | | | | | 9,398 | | | | | | 3,685 | | | | | | 13 | | | | | | 512 | | | | | | 882 | | | | | | 808 | | | Net equity | | | | | 422 | | | | | | 223 | | | | | | 434 | | | | | | 860 | | | | | | 540 | | | | | | 4,885 | | | | | | 394 | | | | | | 306 | | | | | | 527 | | | | | | 806 | | | | | | 287 | | | Eni’s ownership interest (%) | | | | | 50.00 | | | | | | 49.00 | | | | | | 40.00 | | | | | | 50.00 | | | | | | | | | | | | 30.76 | | | | | | 50.00 | | | | | | 49.00 | | | | | | 40.00 | | | | | | 50.00 | | | | Book value of the investment | | | | | 211 | | | | | | 109 | | | | | | 174 | | | | | | 503 | | | | | | 264 | | | | | | 1,497 | | | | | | 197 | | | | | | 150 | | | | | | 211 | | | | | | 434 | | | | | | 146 | | | Revenues and other operating income | | | | | 189 | | | | | | 137 | | | | | | 84 | | | | | | 1,770 | | | | | | 447 | | | | | | 10,009 | | | | | | 738 | | | | | | 152 | | | | | | 105 | | | | | | 905 | | | | | | 275 | | | Operating expense | | | | | (73) | | | | | | (92) | | | | | | (67) | | | | | | (1,739) | | | | | | (297) | | | | | | (9,100) | | | | | | (233) | | | | | | (98) | | | | | | (60) | | | | | | (921) | | | | | | (280) | | | Other operating profit (loss) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (5) | | | Depreciation, amortization and impairments | | | | | (29) | | | | | | (14) | | | | | | (33) | | | | | | (137) | | | | | | (178) | | | | | | (2,408) | | | | | | (87) | | | | | | (22) | | | | | | (40) | | | | | | (131) | | | | | | (169) | | | Operating profit | | | | | 87 | | | | | | 31 | | | | | | (16) | | | | | | (106) | | | | | | (28) | | | | | | (1,499) | | | | | | 418 | | | | | | 32 | | | | | | 5 | | | | | | (147) | | | | | | (179) | | | Finance (expense) income | | | | | (84) | | | | | | | | | | | | 107 | | | | | | (53) | | | | | | (5) | | | | | | (154) | | | | | | (206) | | | | | | | | | | | | 94 | | | | | | 31 | | | | | | (19) | | | Income (expense) from investments | | | | | | | | | | | | | | | | | | | | | | | 29 | | | | | | (7) | | | | | | 18 | | | | | | | | | | | | | | | | | | | | | | | | 13 | | | | Profit before income taxes | | | | | 3 | | | | | | 31 | | | | | | 91 | | | | | | (130) | | | | | | (40) | | | | | | (1,635) | | | | | | 212 | | | | | | 32 | | | | | | 99 | | | | | | (103) | | | | | | (198) | | | Income taxes | | | | | (11) | | | | | | (9) | | | | | | (18) | | | | | | 31 | | | | | | 1 | | | | | | (445) | | | | | | (252) | | | | | | (12) | | | | | | (24) | | | | | | 23 | | | | | | (20) | | | Net profit | | | | | (8) | | | | | | 22 | | | | | | 73 | | | | | | (99) | | | | | | (39) | | | | | | (2,080) | | | | | | (40) | | | | | | 20 | | | | | | 75 | | | | | | (80) | | | | | | (218) | | | Other comprehensive income | | | | | 44 | | | | | | | | | | | | 30 | | | | | | 25 | | | | | | 26 | | | | | | 48 | | | | | | 12 | | | | | | | | | | | | 18 | | | | | | 29 | | | | | | (2) | | | Total other comprehensive income | | | | | 36 | | | | | | 22 | | | | | | 103 | | | | | | (74) | | | | | | (13) | | | | | | (2,032) | | | | | | (28) | | | | | | 20 | | | | | | 93 | | | | | | (51) | | | | | | (220) | | | Net profit attributable to Eni | | | | | (4) | | | | | | 11 | | | | | | 29 | | | | | | (74) | | | | | | (14) | | | | | | (144) | | | | | | (20) | | | | | | 10 | | | | | | 30 | | | | | | (82) | | | | | | (125) | | | Dividends received by the joint venture | | | | | | | | | | | 8 | | | | | | | | | | | | 13 | | | | | | 8 | | | | | | | | | | | | | | | | | | 10 | | | | | | | | | | | | | | | | | | 35 | | | |
| | | | | | | | 2019 | | (€ million) | | | Vår Energi AS | | | Saipem SpA | | | Unión Fenosa Gas SA | | | Cardón IV SA | | | Gas Distribution Company of Thessaloniki -Thessaly SA | | | Other joint ventures | | Current assets | | | | | 1,385 | | | | | | 7,012 | | | | | | 585 | | | | | | 208 | | | | | | 31 | | | | | | 551 | | | - of which cash and cash equivalent | | | | | 182 | | | | | | 2,272 | | | | | | 41 | | | | | | 6 | | | | | | 12 | | | | | | 40 | | | Non-current assets | | | | | 18,427 | | | | | | 5,997 | | | | | | 827 | | | | | | 2,383 | | | | | | 322 | | | | | | 1,085 | | | Total assets | | | | | 19,812 | | | | | | 13,009 | | | | | | 1,412 | | | | | | 2,591 | | | | | | 353 | | | | | | 1,636 | | | Current liabilities | | | | | 2,374 | | | | | | 5,204 | | | | | | 225 | | | | | | 255 | | | | | | 24 | | | | | | 819 | | | - current financial liabilities | | | | | 33 | | | | | | 557 | | | | | | 49 | | | | | | | | | | | | 9 | | | | | | 165 | | | Non-current liabilities | | | | | 13,820 | | | | | | 3,680 | | | | | | 563 | | | | | | 2,040 | | | | | | 46 | | | | | | 354 | | | - non-current financial liabilities | | | | | 3,929 | | | | | | 3,147 | | | | | | 493 | | | | | | 1,140 | | | | | | 33 | | | | | | 274 | | | Total liabilities | | | | | 16,194 | | | | | | 8,884 | | | | | | 788 | | | | | | 2,295 | | | | | | 70 | | | | | | 1,173 | | | Net equity | | | | | 3,618 | | | | | | 4,125 | | | | | | 624 | | | | | | 296 | | | | | | 283 | | | | | | 463 | | | Eni’s % of the investment | | | | | 69.60 | | | | | | 30.99 | | | | | | 50.00 | | | | | | 50.00 | | | | | | 49.00 | | | | | | | | | Book value of the investment | | | | | 2,518 | | | | | | 1,250 | | | | | | 326 | | | | | | 148 | | | | | | 139 | | | | | | 199 | | | Revenues and other income | | | | | 2,552 | | | | | | 9,118 | | | | | | 1,255 | | | | | | 598 | | | | | | 58 | | | | | | 270 | | | Operating expense | | | | | (1,015) | | | | | | (7,972) | | | | | | (1,221) | | | | | | (456) | | | | | | (16) | | | | | | (277) | | | Depreciation, amortization and impairments | | | | | (1,208) | | | | | | (690) | | | | | | (53) | | | | | | (86) | | | | | | (14) | | | | | | (47) | | | Operating profit | | | | | 329 | | | | | | 456 | | | | | | (19) | | | | | | 56 | | | | | | 28 | | | | | | (54) | | | Finance income (expense) | | | | | (1) | | | | | | (210) | | | | | | (37) | | | | | | (133) | | | | | | (1) | | | | | | (14) | | | Income (expense) from investments | | | | | | | | | | | (18) | | | | | | 6 | | | | | | | | | | | | | | | | | | | | | Profit before income taxes | | | | | 328 | | | | | | 228 | | | | | | (50) | | | | | | (77) | | | | | | 27 | | | | | | (68) | | | Income taxes | | | | | (258) | | | | | | (130) | | | | | | 8 | | | | | | (103) | | | | | | (7) | | | | | | (12) | | | Net profit | | | | | 70 | | | | | | 98 | | | | | | (42) | | | | | | (180) | | | | | | 20 | | | | | | (80) | | | Other comprehensive income | | | | | 40 | | | | | | 66 | | | | | | 11 | | | | | | 5 | | | | | | | | | | | | | | | Total other comprehensive income | | | | | 110 | | | | | | 164 | | | | | | (31) | | | | | | (175) | | | | | | 20 | | | | | | (80) | | | Net profit attributable to Eni | | | | | 49 | | | | | | 4 | | | | | | (14) | | | | | | (90) | | | | | | 10 | | | | | | (40) | | | Dividends received from the joint venture | | | | | 1,057 | | | | | | | | | | | | | | | | | | | | | | | | 10 | | | | | | 6 | | | |
| | | | | | | | 2018 | | (€ million) | | | Vår Energi AS | | | Saipem SpA | | | Unión Fenosa Gas SA | | | Gas Distribution Company of Thessaloniki -Thessaly SA | | | Cardón IV SA | | | Lotte Versalis Elastomers Co Ltd | | | PetroJunín SA | | | Other joint ventures | | Current assets | | | | | 1,366 | | | | | | 6,211 | | | | | | 664 | | | | | | 32 | | | | | | 191 | | | | | | 56 | | | | | | 368 | | | | | | 130 | | | - of which cash and cash equivalent | | | | | 883 | | | | | | 1,674 | | | | | | 107 | | | | | | 13 | | | | | | 40 | | | | | | 8 | | | | | | | | | | | | 38 | | | Non-current assets | | | | | 11,407 | | | | | | 5,466 | | | | | | 832 | | | | | | 302 | | | | | | 2,433 | | | | | | 502 | | | | | | 253 | | | | | | 334 | | | Total assets | | | | | 12,773 | | | | | | 11,677 | | | | | | 1,496 | | | | | | 334 | | | | | | 2,624 | | | | | | 558 | | | | | | 621 | | | | | | 464 | | | Current liabilities | | | | | 608 | | | | | | 4,430 | | | | | | 260 | | | | | | 52 | | | | | | 232 | | | | | | 111 | | | | | | 470 | | | | | | 307 | | | - current financial liabilities | | | | | | | | | | | 305 | | | | | | 22 | | | | | | | | | | | | | | | | | | 78 | | | | | | | | | | | | 165 | | | Non-current liabilities | | | | | 7,139 | | | | | | 3,211 | | | | | | 581 | | | | | | 2 | | | | | | 2,196 | | | | | | 297 | | | | | | 34 | | | | | | 126 | | | - non-current financial liabilities | | | | | 366 | | | | | | 2,646 | | | | | | 510 | | | | | | | | | | | | 1,410 | | | | | | 289 | | | | | | | | | | | | 14 | | | Total liabilities | | | | | 7,747 | | | | | | 7,641 | | | | | | 841 | | | | | | 54 | | | | | | 2,428 | | | | | | 408 | | | | | | 504 | | | | | | 433 | | | Net equity | | | | | 5,026 | | | | | | 4,036 | | | | | | 655 | | | | | | 280 | | | | | | 196 | | | | | | 150 | | | | | | 117 | | | | | | 31 | | | Eni’s % of the investment | | | | | 69.60 | | | | | | 30.99 | | | | | | 50.00 | | | | | | 49.00 | | | | | | 50.00 | | | | | | 50.00 | | | | | | 40.00 | | | | | | | | | Book value of the investment | | | | | 3,498 | | | | | | 1,228 | | | | | | 335 | | | | | | 137 | | | | | | 98 | | | | | | 75 | | | | | | 47 | | | | | | (2) | | | Revenues and other income | | | | | | | | | | | 8,530 | | | | | | 1,521 | | | | | | 53 | | | | | | 610 | | | | | | 22 | | | | | | 112 | | | | | | 731 | | | Operating expense | | | | | | | | | | | (7,682) | | | | | | (1,461) | | | | | | (16) | | | | | | (372) | | | | | | (58) | | | | | | (100) | | | | | | (697) | | | Depreciation, amortization and impairments | | | | | | | | | | | (811) | | | | | | (70) | | | | | | (12) | | | | | | (137) | | | | | | (30) | | | | | | (394) | | | | | | (62) | | | Operating profit | | | | | | | | | | | 37 | | | | | | (10) | | | | | | 25 | | | | | | 101 | | | | | | (66) | | | | | | (382) | | | | | | (28) | | | Finance income (expense) | | | | | | | | | | | (165) | | | | | | (31) | | | | | | | | | | | | (208) | | | | | | (12) | | | | | | 31 | | | | | | (5) | | | Income (expense) from investments | | | | | | | | | | | (88) | | | | | | 9 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Profit before income taxes | | | | | | | | | | | (216) | | | | | | (32) | | | | | | 25 | | | | | | (107) | | | | | | (78) | | | | | | (351) | | | | | | (33) | | | Income taxes | | | | | | | | | | | (194) | | | | | | (1) | | | | | | (8) | | | | | | (35) | | | | | | | | | | | | (19) | | | | | | (10) | | | Net profit | | | | | | | | | | | (410) | | | | | | (33) | | | | | | 17 | | | | | | (142) | | | | | | (78) | | | | | | (370) | | | | | | (43) | | | Other comprehensive income | | | | | | | | | | | (46) | | | | | | 15 | | | | | | | | | | | | 6 | | | | | | | | | | | | 11 | | | | | | (4) | | | Total other comprehensive income | | | | | | | | | | | (456) | | | | | | (18) | | | | | | 17 | | | | | | (136) | | | | | | (78) | | | | | | (359) | | | | | | (47) | | | Net profit attributable to Eni | | | | | | | | | | | (146) | | | | | | (23) | | | | | | 8 | | | | | | (71) | | | | | | (39) | | | | | | (148) | | | | | | (21) | | | Dividends received from the joint venture | | | | | | | | | | | | | | | | | | | | | | | 8 | | | | | | | | | | | | | | | | | | | | | | | | 11 | | |
The mainMain line items of profit and loss and balance sheet related to the principal associates represented by the amounts included in the reports accounted under IFRS of each company are provided in the table below:
| | | 2015 | | 2016 | | | 2019 | | (€ million) | | Angola LNG Ltd | | PetroSucre SA | | United Gas Derivatives Co | | Other associates | | Angola LNG Ltd | | PetroSucre SA | | United Gas Derivatives Co | | Other associates | | | Abu Dhabi Oil Refining Co (TAKREER) | | Angola LNG Ltd | | Coral FLNG SA | | Other associates | | Current assets | | | | 111 | | | | | 950 | | | | | 329 | | | | | 215 | | | | | 507 | | | | | 1,119 | | | | | 253 | | | | | 219 | | | | | | 4,659 | | | | | 890 | | | | | 241 | | | | | 838 | | | - of which cash and cash equivalent | | | | 11 | | | | | 2 | | | | | 234 | | | | | 29 | | | | | 339 | | | | | 3 | | | | | 146 | | | | | 29 | | | | | | 42 | | | | | 653 | | | | | 240 | | | | | 91 | | | Non-current assets | | | | 8,092 | | | | | 618 | | | | | 126 | | | | | 417 | | | | | 8,376 | | | | | | | | | | 140 | | | | | 569 | | | | | | 18,868 | | | | | 9,952 | | | | | 4,119 | | | | | 3,259 | | | Total assets | | | | 8,203 | | | | | 1,568 | | | | | 455 | | | | | 632 | | | | | 8,883 | | | | | 1,119 | | | | | 393 | | | | | 788 | | | | | | 23,527 | | | | | 10,842 | | | | | 4,360 | | | | | 4,097 | | | Current liabilities | | | | 498 | | | | | 1,013 | | | | | 101 | | | | | 165 | | | | | 284 | | | | | 1,049 | | | | | 41 | | | | | 183 | | | | | | 8,470 | | | | | 185 | | | | | 230 | | | | | 585 | | | - current financial liabilities | | | | | | | | | | | | | | | | | | | 50 | | | | | | | | | | | | | | | | | | | | 25 | | | | | | 3,694 | | | | | | | | | | | | | | | 63 | | | Non-current liabilities | | | | 215 | | | | | 81 | | | | | 14 | | | | | 130 | | | | | 1,863 | | | | | 70 | | | | | 1 | | | | | 200 | | | | | | 912 | | | | | 2,135 | | | | | 3,722 | | | | | 2,677 | | | - non-current financial liabilities | | | | | | | | | | | | | | | | | | | 69 | | | | | 1,699 | | | | | | | | | | | | | | | 78 | | | | | | 479 | | | | | 1,943 | | | | | 3,722 | | | | | 2,515 | | | Total liabilities | | | | 713 | | | | | 1,094 | | | | | 115 | | | | | 295 | | | | | 2,147 | | | | | 1,119 | | | | | 42 | | | | | 383 | | | | | | 9,382 | | | | | 2,320 | | | | | 3,952 | | | | | 3,262 | | | Net equity | | | | 7,490 | | | | | 474 | | | | | 340 | | | | | 337 | | | | | 6,736 | | | | | | | | | | 351 | | | | | 405 | | | | | | 14,145 | | | | | 8,522 | | | | | 408 | | | | | 835 | | | Eni’s ownership interest (%) | | | | 13.60 | | | | | 26.00 | | | | | 33.33 | | | | | | | | | | 13.60 | | | | | 26.00 | | | | | 33.33 | | | | | Eni’s % of the investment | | | | | 20.00 | | | | | 13.60 | | | | | 25.00 | | | | | | | | Book value of the investment | | | | 1,019 | | | | | 123 | | | | | 113 | | | | | 150 | | | | | 916 | | | | | | | | | | 117 | | | | | 167 | | | | | | 2,829 | | | | | 1,159 | | | | | 102 | | | | | 264 | | | Revenues and other operating income | | | | | | | | | 466 | | | | | 142 | | | | | 487 | | | | | 84 | | | | | 315 | | | | | 102 | | | | | 924 | | | | Revenues and other income | | | | | 399 | | | | | 1,552 | | | | | | | | | | 818 | | | Operating expense | | | | (255) | | | | | (452) | | | | | (59) | | | | | (415) | | | | | (281) | | | | | (224) | | | | | (61) | | | | | (827) | | | | | | (357) | | | | | (549) | | | | | | | | | | (763) | | | Other operating profit (loss) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (2) | | | | Depreciation, depletion, amortization and impairments | | | | (3,180) | | | | | (197) | | | | | (28) | | | | | (36) | | | | | (188) | | | | | (568) | | | | | (13) | | | | | (57) | | | | Depreciation, amortization and impairments | | | | | (335) | | | | | (509) | | | | | | | | | | (28) | | | Operating profit | | | | (3,435) | | | | | (183) | | | | | 55 | | | | | 36 | | | | | (385) | | | | | (477) | | | | | 28 | | | | | 38 | | | | | | (293) | | | | | 494 | | | | | | | | | | 27 | | | Finance (expense) income | | | | (10) | | | | | (11) | | | | | 18 | | | | | (4) | | | | | (70) | | | | | 228 | | | | | 11 | | | | | (4) | | | | Finance income (expense) | | | | | (46) | | | | | (151) | | | | | (12) | | | | | (2) | | | Income (expense) from investments | | | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | 282 | | | | | | | | | | | | | | | 35 | | | Profit before income taxes | | | | (3,445) | | | | | (194) | | | | | 73 | | | | | 33 | | | | | (455) | | | | | (249) | | | | | 39 | | | | | 34 | | | | | | (57) | | | | | 343 | | | | | (12) | | | | | 60 | | | Income taxes | | | | | | | | | (60) | | | | | (12) | | | | | (7) | | | | | | | | | | (103) | | | | | 5 | | | | | (5) | | | | | | 11 | | | | | | | | | | 5 | | | | | (10) | | | Net profit | | | | (3,445) | | | | | (254) | | | | | 61 | | | | | 26 | | | | | (455) | | | | | (352) | | | | | 44 | | | | | 29 | | | | | | (46) | | | | | 343 | | | | | (7) | | | | | 50 | | | Other comprehensive income | | | | 992 | | | | | 71 | | | | | 35 | | | | | 9 | | | | | 200 | | | | | (8) | | | | | 11 | | | | | 1 | | | | | | (59) | | | | | 162 | | | | | 8 | | | | | 5 | | | Total other comprehensive income | | | | (2,453) | | | | | (183) | | | | | 96 | | | | | 35 | | | | | (255) | | | | | (360) | | | | | 55 | | | | | 30 | | | | | | (105) | | | | | 505 | | | | | 1 | | | | | 55 | | | Net profit attributable to Eni | | | | (469) | | | | | (66) | | | | | 20 | | | | | 3 | | | | | (62) | | | | | (92) | | | | | 14 | | | | | 4 | | | | | | (9) | | | | | 47 | | | | | (2) | | | | | 22 | | | Dividends received by the associate | | | | | | | | | | | | | | 21 | | | | | 1 | | | | | | | | | | 30 | | | | | 14 | | | | | 9 | | | | | | Dividends received from the associate | | | | | 46 | | | | | | | | | | | | | | | 15 | | |
| | | | | | | | 2018 | | (€ million) | | | Angola LNG Ltd | | | Coral FLNG SA | | | Other associates | | Current assets | | | | | 1,027 | | | | | | 109 | | | | | | 926 | | | - of which cash and cash equivalent | | | | | 698 | | | | | | 109 | | | | | | 178 | | | Non-current assets | | | | | 9,079 | | | | | | 2,434 | | | | | | 2,296 | | | Total assets | | | | | 10,106 | | | | | | 2,543 | | | | | | 3,222 | | | Current liabilities | | | | | 472 | | | | | | 117 | | | | | | 785 | | | - current financial liabilities | | | | | | | | | | | | | | | | | 134 | | | Non-current liabilities | | | | | 1,500 | | | | | | 2,018 | | | | | | 1,755 | | | - non-current financial liabilities | | | | | 1,328 | | | | | | 2,016 | | | | | | 1,473 | | | Total liabilities | | | | | 1,972 | | | | | | 2,135 | | | | | | 2,540 | | | Net equity | | | | | 8,134 | | | | | | 408 | | | | | | 682 | | | Eni’s % of the investment | | | | | 13.60 | | | | | | 25.00 | | | | | | | | | Book value of the investment | | | | | 1,106 | | | | | | 102 | | | | | | 241 | | | Revenues and other income | | | | | 1,919 | | | | | | | | | | | | 1,053 | | | Operating expense | | | | | (872) | | | | | | (1) | | | | | | (887) | | | Depreciation, amortization and impairments | | | | | 1,647 | | | | | | | | | | | | (58) | | | Operating profit | | | | | 2,694 | | | | | | (1) | | | | | | 108 | | | Finance income (expense) | | | | | (97) | | | | | | (11) | | | | | | (1) | | | Income (expense) from investments | | | | | | | | | | | | | | | | | 16 | | | Profit before income taxes | | | | | 2,597 | | | | | | (12) | | | | | | 123 | | | Income taxes | | | | | | | | | | | | | | | | | (26) | | | Net profit | | | | | 2,597 | | | | | | (12) | | | | | | 97 | | | Other comprehensive income | | | | | 337 | | | | | | 16 | | | | | | 17 | | | Total other comprehensive income | | | | | 2,934 | | | | | | 4 | | | | | | 114 | | | Net profit attributable to Eni | | | | | 353 | | | | | | (3) | | | | | | 25 | | | Dividends received from the associate | | | | | | | | | | | | | | | | | 25 | | |
4938 Significant non-recurring events and operations
In 2014,2019, in 20152018 and 2016,2017, Eni did not report any non-recurring events and operations. 5039 Positions or transactions deriving from atypical and/or unusual operations
In 2014, 20152019, 2018 and 20162017 no transactions deriving from atypical and/or unusual operations were reported. 5140 Subsequent events
NoImpact of COVID-19 and current trends in the oil market
The outbreak of a contagious disease known as COVID-19 which has spread rapidly to many countries in the world at the beginning of 2020 and is currently ongoing has triggered a sharp sell-off in energy commodities markets due to a sudden drop in worldwide consumption of oil, gas and other energy products as a result of measures taken worldwide to contain the spread of the disease. In early March 2020, members of the OPEC+ failed to reach a new deal for additional oil production cuts desired by some participants to counteract the decrease in demand from COVID-19 effects. These developments triggered a collapse in crude oil prices. The price of the Brent crude benchmark has fallen by more than 50% from 65$/BBL early in January 2020 to current values; however the average Brent price for the first quarter 2020 of approximately 51$/BBL has fallen by a considerably lower amount over the corresponding period a year ago (down by approximately 20%). Also, the price of natural gas at the Italian spot market “PSV”, which is the main benchmark for sales volumes of equity gas production has fallen in this period, with the average price for the first quarter 2020 at approximately 3.7$/mmBTU, down by approximately 50% over the year-ago quarter. Future trends in crude oil and natural gas prices will greatly depend on how the current COVID-19 crisis unfolds and on how long it lasts. Under the worst of the assumptions, the spread of the disease could trigger a global recession which could materially hit demand for energy products and prices of energy commodities. This scenario could be further complicated in case the members of the OPEC+ continue to cease supporting crude oil prices. These trends could have a material and adverse effect on our results of operations, cash flow, liquidity and business prospects, including trends in Eni shares and shareholders’ returns. We retain some levers of financial flexibility in case of a significant events were reported aftercontraction in cash flow from operations. The Group has established a liquidity reserve consisting of very liquid sovereign bonds and corporate securities which amounted to €6.8 billion at the balance sheet date, which together with cash on hands of approximately €6 billion will cushion the impact of a decline in liquidity. Furthermore, we have as of December 31, 2016.2019, undrawn uncommitted borrowing facilities amounting to €13,299 million and undrawn long-term committed borrowing facilities of €4,667 million. Those facilities bore interest rates reflecting prevailing conditions on the marketplace. The main financial commitments of 2020 include long-term debt maturities of approximately €3.2 billion and short-term debt of €2.45 billion, while our take-or-pay obligations under long-term gas contracts and other similar obligations amount to an estimated €8 billion at our budget scenario. The effects of the recent trends in the oil market on the Group’s results of operations, liquidity and assets are currently under evaluation by management. This assessment implies the oil price scenario update and the management’s actions to counteract the changed environment, the effects of which, currently not yet determinable, will be accounted for in future reporting periods.
Supplemental oil and gas information (unaudited) The following information pursuant to “International Financial Reporting Standards” (IFRS) is presented in accordance with FASB Extractive Activities — Oil & Gas (Topic 932). Amounts related to minority interests are not significant. Capitalized costs Capitalized costs represent the total expenditures for proved and unproved mineral interests and related support equipment and facilities utilized in oil and gas exploration and production activities, together with related accumulated depreciation, depletion and amortization. Capitalized costs by geographical area consist of the following: (€ million) | | | | 2015 | | Italy | | Rest of Europe | | North Africa* | | *Egypt (of which) | | Sub - Saharan Africa | | Kazakhstan | | Rest of Asia | | America | | Australia and Oceania | | Total | | | (€ million) 2019 | | | Italy | | Rest of Europe | | North Africa | | Egypt | | Sub - Saharan Africa | | Kazakhstan | | Rest of Asia | | America | | Australia and Oceania | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved property | | | | 15,280 | | | | | 15,110 | | | | | 26,904 | | | | | | | | | | 35,241 | | | | | 3,364 | | | | | 10,424 | | | | | 16,156 | | | | | 2,037 | | | | | 124,516 | | | | | | 17,643 | | | | | 6,747 | | | | | 15,512 | | | | | 20,691 | | | | | 43,272 | | | | | 12,118 | | | | | 11,434 | | | | | 15,912 | | | | | 1,360 | | | | | 144,689 | | | Unproved property | | | | 18 | | | | | 297 | | | | | 444 | | | | | | | | | | 2,443 | | | | | 1 | | | | | 1,229 | | | | | 874 | | | | | 203 | | | | | 5,509 | | | | | | 18 | | | | | 323 | | | | | 502 | | | | | 34 | | | | | 2,361 | | | | | 11 | | | | | 1,592 | | | | | 979 | | | | | 194 | | | | | 6,014 | | | Support equipment and facilities | | | | 355 | | | | | 42 | | | | | 1,758 | | | | | | | | | | 1,318 | | | | | 112 | | | | | 34 | | | | | 74 | | | | | 15 | | | | | 3,708 | | | | | | 384 | | | | | 21 | | | | | 1,549 | | | | | 225 | | | | | 1,328 | | | | | 116 | | | | | 36 | | | | | 23 | | | | | 12 | | | | | 3,694 | | | Incomplete wells and other | | | | 1,114 | | | | | 3,501 | | | | | 2,280 | | | | | | | | | | 4,932 | | | | | 8,900 | | | | | 1,665 | | | | | 729 | | | | | 123 | | | | | 23,244 | | | | | | 635 | | | | | 103 | | | | | 1,362 | | | | | 359 | | | | | 2,541 | | | | | 1,165 | | | | | 1,006 | | | | | 457 | | | | | 43 | | | | | 7,671 | | | Gross Capitalized Costs | | | | 16,767 | | | | | 18,950 | | | | | 31,386 | | | | | | | | | | 43,934 | | | | | 12,377 | | | | | 13,352 | | | | | 17,833 | | | | | 2,378 | | | | | 156,977 | | | | | | 18,680 | | | | | 7,194 | | | | | 18,925 | | | | | 21,309 | | | | | 49,502 | | | | | 13,410 | | | | | 14,068 | | | | | 17,371 | | | | | 1,609 | | | | | 162,068 | | | Accumulated depreciation, depletion and amortization | | | | (12,184) | | | | | (11,431) | | | | | (20,268) | | | | | | | | | | (25,235) | | | | | (1,422) | | | | | (9,691) | | | | | (13,344) | | | | | (1,122) | | | | | (94,697) | | | | | | (14,604) | | | | | (5,778) | | | | | (12,802) | | | | | (12,879) | | | | | (33,237) | | | | | (2,652) | | | | | (9,100) | | | | | (13,465) | | | | | (754) | | | | | (105,271) | | | Net Capitalized Costs consolidated subsidiaries(a) | | | | 4,583 | | | | | 7,519 | | | | | 11,118 | | | | | | | | | | 18,699 | | | | | 10,955 | | | | | 3,661 | | | | | 4,489 | | | | | 1,256 | | | | | 62,280 | | | | | | 4,076 | | | | | 1,416 | | | | | 6,123 | | | | | 8,430 | | | | | 16,265 | | | | | 10,758 | | | | | 4,968 | | | | | 3,906 | | | | | 855 | | | | | 56,797 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved property | | | | | | | | | 3 | | | | | 89 | | | | | | | | | | 23 | | | | | | | | | | 624 | | | | | 2,010 | | | | | | | | | | 2,749 | | | | | | | | | | | 11,223 | | | | | 71 | | | | | | | | | | 1,511 | | | | | | | | | | 2 | | | | | 1,987 | | | | | | | | | | 14,794 | | | Unproved property | | | | | | | | | 17 | | | | | | | | | | | | | | | | | | | | | | | | | 93 | | | | | | | | | | | | | | | 110 | | | | | | | | | | | 2,260 | | | | | | | | | | | | | | | | | | | | | | | | | 11 | | | | | | | | | | | | | | | 2,271 | | | Support equipment and facilities | | | | | | | | | | | | | | 8 | | | | | | | | | | | | | | | | | | | | | | | | | 6 | | | | | | | | | | 14 | | | | | | | | | | | 19 | | | | | 8 | | | | | | | | | | | | | | | | | | | | | | | | | 7 | | | | | | | | | | 34 | | | Incomplete wells and other | | | | | | | | | 10 | | | | | 5 | | | | | | | | | | 1,508 | | | | | | | | | | 23 | | | | | 112 | | | | | | | | | | 1,658 | | | | | | | | | | | 945 | | | | | 7 | | | | | | | | | | 15 | | | | | | | | | | 19 | | | | | 229 | | | | | | | | | | 1,215 | | | Gross Capitalized Costs | | | | | | | | | 30 | | | | | 102 | | | | | | | | | | 1,531 | | | | | | | | | | 740 | | | | | 2,128 | | | | | | | | | | 4,531 | | | | | | | | | | | 14,447 | | | | | 86 | | | | | | | | | | 1,526 | | | | | | | | | | 32 | | | | | 2,223 | | | | | | | | | | 18,314 | | | Accumulated depreciation, depletion and amortization | | | | | | | | | (23) | | | | | (77) | | | | | | | | | | (441) | | | | | | | | | | (628) | | | | | (338) | | | | | | | | | | (1,507) | | | | | | | | | | | (5,287) | | | | | (61) | | | | | | | | | | (323) | | | | | | | | | | (20) | | | | | (1,124) | | | | | | | | | | (6,815) | | | Net Capitalized Costs equity-accounted entities(a) | | | | | | | | | 7 | | | | | 25 | | | | | | | | | | 1,090 | | | | | | | | | | 112 | | | | | 1,790 | | | | | | | | | | 3,024 | | | | 2016 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net Capitalized Costs equity-accounted entities (a)(c) | | | | | | | | | | 9,160 | | | | | 25 | | | | | | | | | | 1,203 | | | | | | | | | | 12 | | | | | 1,099 | | | | | | | | | | 11,499 | | | 2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved property | | | | 15,951 | | | | | 18,678 | | | | | 28,754 | | | | | 15,262 | | | | | 38,539 | | | | | 10,790 | | | | | 11,680 | | | | | 17,127 | | | | | 2,085 | | | | | 143,604 | | | | | | 16,569 | | | | | 6,236 | | | | | 14,140 | | | | | 17,474 | | | | | 40,607 | | | | | 11,240 | | | | | 12,711 | | | | | 15,347 | | | | | 1,967 | | | | | 136,291 | | | Unproved property | | | | 18 | | | | | 301 | | | | | 471 | | | | | 55 | | | | | 2,461 | | | | | 1 | | | | | 1,155 | | | | | 903 | | | | | 210 | | | | | 5,520 | | | | | | 18 | | | | | 332 | | | | | 456 | | | | | 56 | | | | | 2,311 | | | | | 3 | | | | | 1,530 | | | | | 861 | | | | | 193 | | | | | 5,760 | | | Support equipment and facilities | | | | 357 | | | | | 42 | | | | | 1,830 | | | | | 203 | | | | | 1,375 | | | | | 111 | | | | | 37 | | | | | 77 | | | | | 15 | | | | | 3,844 | | | | | | 369 | | | | | 21 | | | | | 1,516 | | | | | 208 | | | | | 1,281 | | | | | 108 | | | | | 38 | | | | | 52 | | | | | 12 | | | | | 3,605 | | | Incomplete wells and other | | | | 724 | | | | | 242 | | | | | 4,175 | | | | | 1,828 | | | | | 5,117 | | | | | 2,565 | | | | | 2,248 | | | | | 317 | | | | | 134 | | | | | 15,522 | | | | | | 653 | | | | | 103 | | | | | 1,554 | | | | | 1,504 | | | | | 2,307 | | | | | 1,382 | | | | | 562 | | | | | 595 | | | | | 127 | | | | | 8,787 | | | Gross Capitalized Costs | | | | 17,050 | | | | | 19,263 | | | | | 35,230 | | | | | 17,348 | | | | | 47,492 | | | | | 13,467 | | | | | 15,120 | | | | | 18,424 | | | | | 2,444 | | | | | 168,490 | | | | | | 17,609 | | | | | 6,692 | | | | | 17,666 | | | | | 19,242 | | | | | 46,506 | | | | | 12,733 | | | | | 14,841 | | | | | 16,855 | | | | | 2,299 | | | | | 154,443 | | | 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) | | | | | | (13,717) | | | | | (5,355) | | | | | (11,741) | | | | | (11,722) | | | | | (29,727) | | | | | (2,175) | | | | | (10,460) | | | | | (13,443) | | | | | (1,265) | | | | | (99,605) | | | 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 | | | | | | 3,892 | | | | | 1,337 | | | | | 5,925 | | | | | 7,520 | | | | | 16,779 | | | | | 10,558 | | | | | 4,381 | | | | | 3,412 | | | | | 1,034 | | | | | 54,838 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved property | | | | | | | | | 2 | | | | | 82 | | | | | | | | | | 14 | | | | | | | | | | 657 | | | | | 2,037 | | | | | | | | | | 2,792 | | | | | | | | | | | 9,102 | | | | | 58 | | | | | | | | | | 1,481 | | | | | | | | | | 2 | | | | | 1,912 | | | | | | | | | | 12,555 | | | Unproved property | | | | | | | | | 15 | | | | | | | | | | | | | | | | | | | | | | | | | 96 | | | | | | | | | | | | | | | 111 | | | | | | | | | | | 1,045 | | | | | | | | | | | | | | | | | | | | | | | | | 11 | | | | | | | | | | | | | | | 1,056 | | | Support equipment and facilities | | | | | | | | | | | | | | 8 | | | | | | | | | | | | | | | | | | | | | | | | | 7 | | | | | | | | | | 15 | | | | | | | | | | | 25 | | | | | 6 | | | | | | | | | | | | | | | | | | | | | | | | | 7 | | | | | | | | | | 38 | | | Incomplete wells and other | | | | | | | | | 9 | | | | | 5 | | | | | | | | | | 1,596 | | | | | | | | | | 24 | | | | | 253 | | | | | | | | | | 1,887 | | | | | | | | | | | 364 | | | | | 10 | | | | | | | | | | 10 | | | | | | | | | | 19 | | | | | 224 | | | | | | | | | | 627 | | | Gross Capitalized Costs | | | | | | | | | 26 | | | | | 95 | | | | | | | | | | 1,610 | | | | | | | | | | 777 | | | | | 2,297 | | | | | | | | | | 4,805 | | | | | | | | | | | 10,536 | | | | | 74 | | | | | | | | | | 1,491 | | | | | | | | | | 32 | | | | | 2,143 | | | | | | | | | | 14,276 | | | Accumulated depreciation, depletion and amortization | | | | | | | | | (20) | | | | | (72) | | | | | | | | | | (482) | | | | | | | | | | (682) | | | | | (602) | | | | | | | | | | (1,858) | | | | | | | | | | | (4,543) | | | | | (54) | | | | | | | | | | (266) | | | | | | | | | | (19) | | | | | (1,052) | | | | | | | | | | (5,934) | | | Net Capitalized Costs equity-accounted entities(a) | | | | | | | | | 6 | | | | | 23 | | | | | | | | | | 1,128 | | | | | | | | | | 95 | | | | | 1,695 | | | | | | | | | | 2,947 | | | | | | Net Capitalized Costs equity-accounted entities (a)(b) | | | | | | | | | | 5,993 | | | | | 20 | | | | | | | | | | 1,225 | | | | | | | | | | 13 | | | | | 1,091 | | | | | | | | | | 8,342 | | |
(a)
The amounts include net capitalized financial charges totalling €1.029€878 million in 20152019 and €1.090€831 million in 20162018 for the consolidates subsidiaries and €92€166 million in 20152019 and €95€180 million in 20162018 for equity-accounted entities. (b)
Includes Vår Energi AS asset fair value. (c)
F-143Includes allocation at fair value of the assets purchased by Vår Energi AS.
Costs incurred Costs incurred represent amounts both capitalized and expensed in connection with oil and gas producing activities. Costs incurred by geographical area consist of the following: (€ million) | | | | | | | | | | | | 2014 | | | Italy | | | Rest of Europe | | | North Africa* | | | *Egypt (of which) | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | 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 | | | |
(€ million) 2019 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved property acquisitions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 144 | | | | | | | | | | | | 144 | | | Unproved property acquisitions | | | | | | | | | | | | | | | | | 135 | | | | | | 1 | | | | | | | | | | | | | | | | | | 23 | | | | | | 97 | | | | | | | | | | | | 256 | | | Exploration | | | | | 20 | | | | | | 62 | | | | | | 101 | | | | | | 94 | | | | | | 206 | | | | | | 15 | | | | | | 232 | | | | | | 106 | | | | | | 39 | | | | | | 875 | | | Development(a) | | | | | 1,098 | | | | | | 230 | | | | | | 749 | | | | | | 1,589 | | | | | | 1,959 | | | | | | 481 | | | | | | 1,199 | | | | | | 879 | | | | | | 43 | | | | | | 8,227 | | | Total costs incurred consolidated subsidiaries | | | | | 1,118 | | | | | | 292 | | | | | | 985 | | | | | | 1,684 | | | | | | 2,165 | | | | | | 496 | | | | | | 1,454 | | | | | | 1,226 | | | | | | 82 | | | | | | 9,502 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved property acquisitions | | | | | | | | | | | 1,054 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,054 | | | Unproved property acquisitions | | | | | | | | | | | 1,178 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,178 | | | Exploration | | | | | | | | | | | 125 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | 124 | | | Development(b) | | | | | | | | | | | 1,574 | | | | | | 4 | | | | | | | | | | | | 5 | | | | | | | | | | | | | | | | | | 37 | | | | | | | | | | | | 1,620 | | | Total costs incurred equity-accounted entities(c) | | | | | | | | | | | 3,931 | | | | | | 4 | | | | | | | | | | | | 5 | | | | | | | | | | | | (1) | | | | | | 37 | | | | | | | | | | | | 3,976 | | |
2018 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved property acquisitions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 382 | | | | | | | | | | | | | | | | | | 382 | | | Unproved property acquisitions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 487 | | | | | | | | | | | | | | | | | | 487 | | | Exploration | | | | | 26 | | | | | | 106 | | | | | | 43 | | | | | | 102 | | | | | | 66 | | | | | | 3 | | | | | | 182 | | | | | | 215 | | | | | | 7 | | | �� | | | 750 | | | Development(a) | | | | | 382 | | | | | | 557 | | | | | | 445 | | | | | | 2,216 | | | | | | 1,379 | | | | | | 92 | | | | | | 589 | | | | | | 340 | | | | | | 36 | | | | | | 6,036 | | | Total costs incurred consolidated subsidiaries | | | | | 408 | | | | | | 663 | | | | | | 488 | | | | | | 2,318 | | | | | | 1,445 | | | | | | 95 | | | | | | 1,640 | | | | | | 555 | | | | | | 43 | | | | | | 7,655 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved property acquisitions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unproved property acquisitions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exploration | | | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | 103 | | | | | | | | | | | | | | | | | | 105 | | | Development(b) | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (16) | | | | | | | | | | | | (13) | | | Total costs incurred equity-accounted entities | | | | | | | | | | | | | | | | | 5 | | | | | | | | | | | | | | | | | | | | | | | | 103 | | | | | | (16) | | | | | | | | | | | | 92 | | |
2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved property acquisitions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 5 | | | Unproved property acquisitions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exploration | | | | | 31 | | | | | | 242 | | | | | | 77 | | | | | | 110 | | | | | | 65 | | | | | | 3 | | | | | | 76 | | | | | | 106 | | | | | | 5 | | | | | | 715 | | | Development(a) | | | | | 251 | | | | | | 364 | | | | | | 785 | | | | | | 3,041 | | | | | | 1,939 | | | | | | 246 | | | | | | 714 | | | | | | 292 | | | | | | 14 | | | | | | 7,646 | | | Total costs incurred consolidated subsidiaries | | | | | 282 | | | | | | 606 | | | | | | 862 | | | | | | 3,151 | | | | | | 2,009 | | | | | | 249 | | | | | | 790 | | | | | | 398 | | | | | | 19 | | | | | | 8,366 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Proved property acquisitions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unproved property acquisitions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Exploration | | | | | | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 90 | | | | | | | | | | | | | | | | | | 91 | | | Development(b) | | | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | 9 | | | | | | | | | ��� | | | 4 | | | | | | 48 | | | | | | | | | | | | 63 | | | Total costs incurred equity-accounted entities | | | | | | | | | | | 1 | | | | | | 2 | | | | | | | | | | | | 9 | | | | | | | | | | | | 94 | | | | | | 48 | | | | | | | | | | | | 154 | | |
(a)
Includes the abandonment costs of the assets for €2,062€2,069 million in 2014,2019, negative for €817€517 million in 2015 and negative2018, asset for €665€355 million in 2016.2017. (b)
Includes the abandonment costs of the assets for €838 million in 2019, negative €22 million in 2018, negative for €47€23 million in 2014, costs for €54 million in 2015 and negative for €15 million in 2016.2017. (c)
Includes allocation at fair value of the assets purchased by Vår Energi AS.
Results of operations from oil and gas producing activities Results of operations from oil and gas producing activities represent only those revenues and expenses directly associated with such activities, including operating overheads. These amounts do not include any allocation of interest expenses or general corporate overheads and, therefore, are not necessarily indicative of the contributions to consolidated net earnings of Eni. Related income taxes are calculated by applying the local income tax rates to the pre-tax income from production activities. Eni is party to certain Production Sharing Agreements (PSAs), whereby a portion of Eni’s share of oil and gas production is withheld and sold by its joint venture partners which are state owned entities, with proceeds being remitted to the state to meet Eni’s PSA related tax liabilities. Revenue and income taxes include such taxes owed by Eni but paid by state-owned entities out of Eni’s share of oil and gas production.
Results of operations from oil and gas producing activities by geographical area consist of the following: 2014 (€ million) | | | Italy | | | Rest of Europe | | | North Africa | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | 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) | | | D.D. & 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) | | | D.D. & 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
2015 (€ million) | | | Italy | | | Rest of Europe | | | North Africa | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | 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) | | | D.D. & 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) | | | D.D. & 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
2016 (€ million) | | Italy | | Rest of Europe | | North Africa* | | *Egypt (of which) | | Sub - Saharan Africa | | Kazakhstan | | Rest of Asia | | America | | Australia and Oceania | | Total | | | (€ million) 2019 | | | Italy | | Rest of Europe | | North Africa | | Egypt | | Sub - Saharan Africa | | Kazakhstan | | Rest of Asia | | America | | Australia and Oceania | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - sales to consolidated entities | | | | 1,217 | | | | | 1,673 | | | | | 941 | | | | | 9 | | | | | 3,178 | | | | | 252 | | | | | 1,027 | | | | | 833 | | | | | 4 | | | | | 9,125 | | | | | | 1,493 | | | | | 618 | | | | | 1,081 | | | | | | | | | | 4,576 | | | | | 1,195 | | | | | 2,367 | | | | | 825 | | | | | 5 | | | | | 12,160 | | | - sales to third parties | | | | | | | | | 432 | | | | | 4,312 | | | | | 1,471 | | | | | 485 | | | | | 606 | | | | | 114 | | | | | 102 | | | | | 165 | | | | | 6,216 | | | | | | | | | | | 30 | | | | | 4,084 | | | | | 3,715 | | | | | 944 | | | | | 766 | | | | | 149 | | | | | 180 | | | | | 227 | | | | | 10,095 | | | Total revenues | | | | 1,217 | | | | | 2,105 | | | | | 5,253 | | | | | 1,480 | | | | | 3,663 | | | | | 858 | | | | | 1,141 | | | | | 935 | | | | | 169 | | | | | 15,341 | | | | | | 1,493 | | | | | 648 | | | | | 5,165 | | | | | 3,715 | | | | | 5,520 | | | | | 1,961 | | | | | 2,516 | | | | | 1,005 | | | | | 232 | | | | | 22,255 | | | Operations costs | | | | (311) | | | | | (599) | | | | | (807) | | | | | (356) | | | | | (968) | | | | | (269) | | | | | (215) | | | | | (325) | | | | | (49) | | | | | (3,543) | | | | Production costs | | | | | (391) | | | | | (181) | | | | | (520) | | | | | (330) | | | | | (847) | | | | | (255) | | | | | (256) | | | | | (273) | | | | | (43) | | | | | (3,096) | | | Transportation costs | | | | | (5) | | | | | (31) | | | | | (60) | | | | | (10) | | | | | (39) | | | | | (158) | | | | | (4) | | | | | (15) | | | | | | | | | | (322) | | | Production taxes | | | | (96) | | | | | | | | | | (176) | | | | | | | | | | (282) | | | | | | | | | | (17) | | | | | | | | | | (5) | | | | | (576) | | | | | | (183) | | | | | | | | | | (263) | | | | | | | | | | (483) | | | | | | | | | | (252) | | | | | (7) | | | | | (6) | | | | | (1,194) | | | Exploration expenses | | | | (35) | | | | | (40) | | | | | (87) | | | | | (42) | | | | | (142) | | | | | | | | | | (39) | | | | | (28) | | | | | (3) | | | | | (374) | | | | | | (25) | | | | | (51) | | | | | (30) | | | | | (10) | | | | | (90) | | | | | (39) | | | | | (170) | | | | | (31) | | | | | (43) | | | | | (489) | | | D.D. & A. and Provision for abandonment(a) | | | | (923) | | | | | (943) | | | | | (1,366) | | | | | (691) | | | | | (1,093) | | | | | (129) | | | | | (952) | | | | | (480) | | | | | (67) | | | | | (5,953) | | | | | | (944) | | | | | (201) | | | | | (839) | | | | | (978) | | | | | (3,060) | | | | | (444) | | | | | (820) | | | | | (607) | | | | | (97) | | | | | (7,990) | | | Other income (expenses) | | | | (342) | | | | | (232) | | | | | (466) | | | | | (265) | | | | | (917) | | | | | (57) | | | | | (130) | | | | | (120) | | | | | (8) | | | | | (2,272) | | | | | | (337) | | | | | (16) | | | | | (452) | | | | | (433) | | | | | (502) | | | | | (71) | | | | | (76) | | | | | (86) | | | | | (1) | | | | | (1,974) | | | Pretax income from producing activities | | | | (490) | | | | | 291 | | | | | 2,351 | | | | | 126 | | | | | 261 | | | | | 403 | | | | | (212) | | | | | (18) | | | | | 37 | | | | | 2,623 | | | | | | (392) | | | | | 168 | | | | | 3,001 | | | | | 1,954 | | | | | 499 | | | | | 994 | | | | | 938 | | | | | (14) | | | | | 42 | | | | | 7,190 | | | Income taxes | | | | 159 | | | | | (1) | | | | | (1,707) | | | | | (89) | | | | | 97 | | | | | (139) | | | | | 32 | | | | | (9) | | | | | (9) | | | | | (1,577) | | | | | | 148 | | | | | (11) | | | | | (2,561) | | | | | (839) | | | | | (268) | | | | | (326) | | | | | (719) | | | | | (5) | | | | | (31) | | | | | (4,612) | | | Results of operations from E&P activities of consolidated subsidiaries | | | | (331) | | | | | 290 | | | | | 644 | | | | | 37 | | | | | 358 | | | | | 264 | | | | | (180) | | | | | (27) | | | | | 28 | | | | | 1,046 | | | | Results of operations from E&P activities of consolidated subsidiaries (b) | | | | | (244) | | | | | 157 | | | | | 440 | | | | | 1,115 | | | | | 231 | | | | | 668 | | | | | 219 | | | | | (19) | | | | | 11 | | | | | 2,578 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - sales to consolidated entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,080 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1,080 | | | - sales to third parties | | | | | | | | | | | | | | 15 | | | | | | | | | | | | | | | | | | | | 36 | | | | | 493 | | | | | | | | | | 544 | | | | | | | | | | | 677 | | | | | 15 | | | | | | | | | | 207 | | | | | | | | | | | | | | | 315 | | | | | | | | | | 1,214 | | | Total revenues | | | | | | | | | | | | | | 15 | | | | | | | | | | | | | | | | | | | | 36 | | | | | 493 | | | | | | | | | | 544 | | | | | | | | | | | 1,757 | | | | | 15 | | | | | | | | | | 207 | | | | | | | | | | | | | | | 315 | | | | | | | | | | 2,294 | | | Operations costs | | | | | | | | | | | | | | (9) | | | | | | | | | | | | | | | | | | | | (10) | | | | | (54) | | | | | | | | | | (73) | | | | Production costs | | | | | | | | | | (336) | | | | | (8) | | | | | | | | | | (24) | | | | | | | | | | | | | | | (25) | | | | | | | | | | (393) | | | Transportation costs | | | | | | | | | | (84) | | | | | (1) | | | | | | | | | | (11) | | | | | | | | | | | | | | | | | | | | | | | | | (96) | | | Production taxes | | | | | | | | | | | | | | (3) | | | | | | | | | | | | | | | | | | | | | | | | | (121) | | | | | | | | | | (124) | | | | | | | | | | | | | | | | (2) | | | | | | | | | | (7) | | | | | | | | | | | | | | | (81) | | | | | | | | | | (90) | | | Exploration expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (13) | | | | | | | | | | | | | | | (13) | | | | | | | | | | | (47) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (47) | | | D.D. & A. and Provision for abandonment | | | | | | | | | | | | | | (1) | | | | | | | | | | (26) | | | | | | | | | | (32) | | | | | (240) | | | | | | | | | | (299) | | | | | | | | | | | (722) | | | | | (1) | | | | | | | | | | (70) | | | | | | | | | | | | | | | (51) | | | | | | | | | | (844) | | | Other income (expenses) | | | | | | (3) | | | | | (1) | | | | | | | (26) | | | | | | | (16) | | | | | (25) | | | | | | | (71) | | | | | | | | | | | (237) | | | | | (1) | | | | | | | | | | (28) | | | | | | | | | | (3) | | | | | (133) | | | | | | | | | | (402) | | | Pretax income from producing activities | | | | | | | | | (3) | | | | | 1 | | | | | | | | | | (52) | | | | | | | | | | (35) | | | | | 53 | | | | | | | | | | (36) | | | | | | | | | | | 331 | | | | | 2 | | | | | | | | | | 67 | | �� | | | | | | | | | (3) | | | | | 25 | | | | | | | | | | 422 | | | Income taxes | | | | | | | | | | | | | | (2) | | | | | | | | | | | | | | | | | | | | (6) | | | | | (162) | | | | | | | | | | (170) | | | | | | | | | | | (179) | | | | | (2) | | | | | | | | | | | | | | | | | | | | | | | | | (54) | | | | | | | | | | (235) | | | Results of operations from E&P activities of equity-accounted entities | | | | | | | | | (3) | | | | | (1) | | | | | | | | | | (52) | | | | | | | | | | (41) | | | | | (109) | | | | | | | | | | (206) | | | | | | | | | | | 152 | | | | | | | | | | | | | | | 67 | | | | | | | | | | (3) | | | | | (29) | | | | | | | | | | 187 | | | | |
(a)
Includes asset net (reversal)impairment amounting to €700€1,217 million (b)
Results of operations exclude revenues, DD&A and income taxes associated with 3,8 million boe as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause. The price collected by the buyer has been recognized as revenues in the segment information of the E&P sector prepared in accordance with IFRS and DD&A and income taxes have been accrued accordingly, because the Group performance obligation under the contract has been fulfilled and it is very likely that the buyer will not redeem its contractual right to lift within the contractual terms.
(€ million) 2018 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - sales to consolidated entities | | | | | 2,120 | | | | | | 2,740 | | | | | | 1,277 | | | | | | | | | | | | 4,701 | | | | | | 1,140 | | | | | | 1,902 | | | | | | 934 | | | | | | 4 | | | | | | 14,818 | | | - sales to third parties | | | | | | | | | | | 494 | | | | | | 3,741 | | | | | | 3,207 | | | | | | 830 | | | | | | 769 | | | | | | 493 | | | | | | 50 | | | | | | 190 | | | | | | 9,774 | | | Total revenues | | | | | 2,120 | | | | | | 3,234 | | | | | | 5,018 | | | | | | 3,207 | | | | | | 5,531 | | | | | | 1,909 | | | | | | 2,395 | | | | | | 984 | | | | | | 194 | | | | | | 24,592 | | | Production costs | | | | | (402) | | | | | | (488) | | | | | | (363) | | | | | | (343) | | | | | | (974) | | | | | | (269) | | | | | | (220) | | | | | | (234) | | | | | | (48) | | | | | | (3,341) | | | Transportation costs | | | | | (8) | | | | | | (142) | | | | | | (50) | | | | | | (11) | | | | | | (42) | | | | | | (136) | | | | | | (7) | | | | | | (16) | | | | | | | | | | | | (412) | | | Production taxes | | | | | (171) | | | | | | | | | | | | (243) | | | | | | | | | | | | (435) | | | | | | | | | | | | (191) | | | | | | | | | | | | (6) | | | | | | (1,046) | | | Exploration expenses | | | | | (25) | | | | | | (85) | | | | | | (48) | | | | | | (22) | | | | | | (44) | | | | | | (3) | | | | | | (79) | | | | | | (69) | | | | | | (5) | | | | | | (380) | | | D.D. & A. and Provision for abandonment(a) | | | | | (281) | | | | | | (664) | | | | | | (582) | | | | | | (795) | | | | | | (2,490) | | | | | | (387) | | | | | | (941) | | | | | | (594) | | | | | | (67) | | | | | | (6,801) | | | Other income (expenses) | | | | | (442) | | | | | | (193) | | | | | | (101) | | | | | | (239) | | | | | | (1,126) | | | | | | (67) | | | | | | (135) | | | | | | (54) | | | | | | | | | | | | (2,357) | | | Pretax income from producing activities | | | | | 791 | | | | | | 1,662 | | | | | | 3,631 | | | | | | 1,797 | | | | | | 420 | | | | | | 1,047 | | | | | | 822 | | | | | | 17 | | | | | | 68 | | | | | | 10,255 | | | Income taxes | | | | | (170) | | | | | | (1,070) | | | | | | (2,494) | | | | | | (542) | | | | | | (264) | | | | | | (308) | | | | | | (678) | | | | | | 7 | | | | | | (26) | | | | | | (5,545) | | | Results of operations from E&P activities of consolidated subsidiaries | | | | | 621 | | | | | | 592 | | | | | | 1,137 | | | | | | 1,255 | | | | | | 156 | | | | | | 739 | | | | | | 144 | | | | | | 24 | | | | | | 42 | | | | | | 4,710 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - sales to consolidated entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - sales to third parties | | | | | | | | | | | | | | | | | 15 | | | | | | | | | | | | 257 | | | | | | | | | | | | 6 | | | | | | 420 | | | | | | | | | | | | 698 | | | Total revenues | | | | | | | | | | | | | | | | | 15 | | | | | | | | | | | | 257 | | | | | | | | | | | | 6 | | | | | | 420 | | | | | | | | | | | | 698 | | | Production costs | | | | | | | | | | | | | | | | | (7) | | | | | | | | | | | | (34) | | | | | | | | | | | | (2) | | | | | | (36) | | | | | | | | | | | | (79) | | | Transportation costs | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | (28) | | | | | | | | | | | | | | | | | | (2) | | | | | | | | | | | | (31) | | | Production taxes | | | | | | | | | | | | | | | | | (3) | | | | | | | | | | | | (26) | | | | | | | | | | | | | | | | | | (114) | | | | | | | | | | | | (143) | | | Exploration expenses | | | | | | | | | | | (6) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (235) | | | | | | | | | | | | | | | | | | (241) | | | D.D. & A. and Provision for abandonment | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | 224 | | | | | | | | | | | | (3) | | | | | | (222) | | | | | | | | | | | | (2) | | | Other income (expenses) | | | | | | | | | | | (1) | | | | | | 2 | | | | | | | | | | | | (27) | | | | | | | | | | | | (25) | | | | | | (122) | | | | | | | | | | | | (173) | | | Pretax income from producing activities | | | | | | | | | | | (7) | | | | | | 5 | | | | | | | | | | | | 366 | | | | | | | | | | | | (259) | | | | | | (76) | | | | | | | | | | | | 29 | | | Income taxes | | | | | | | | | | | | | | | | | (3) | | | | | | | | | | | | | | | | | | | | | | | | (2) | | | | | | (35) | | | | | | | | | | | | (40) | | | Results of operations from E&P activities of equity-accounted entities | | | | | | | | | | | (7) | | | | | | 2 | | | | | | | | | | | | 366 | | | | | | | | | | | | (261) | | | | | | (111) | | | | | | | | | | | | (11) | | |
(a)
Includes asset net impairment amounting to €726 million
(€ million) 2017 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - sales to consolidated entities | | | | | 1,619 | | | | | | 1,897 | | | | | | 1,056 | | | | | | | | | | | | 3,888 | | | | | | 681 | | | | | | 911 | | | | | | 932 | | | | | | 3 | | | | | | 10,987 | | | - sales to third parties | | | | | | | | | | | 481 | | | | | | 3,184 | | | | | | 2,128 | | | | | | 547 | | | | | | 713 | | | | | | 291 | | | | | | 96 | | | | | | 168 | | | | | | 7,608 | | | Total revenues | | | | | 1,619 | | | | | | 2,378 | | | | | | 4,240 | | | | | | 2,128 | | | | | | 4,435 | | | | | | 1,394 | | | | | | 1,202 | | | | | | 1,028 | | | | | | 171 | | | | | | 18,595 | | | Production costs | | | | | (332) | | | | | | (523) | | | | | | (455) | | | | | | (303) | | | | | | (952) | | | | | | (271) | | | | | | (202) | | | | | | (258) | | | | | | (48) | | | | | | (3,344) | | | Transportation costs | | | | | (5) | | | | | | (164) | | | | | | (49) | | | | | | (11) | | | | | | (34) | | | | | | (125) | | | | | | (4) | | | | | | (54) | | | | | | | | | | | | (446) | | | Production taxes | | | | | (130) | | | | | | | | | | | | (200) | | | | | | | | | | | | (331) | | | | | | | | | | | | (11) | | | | | | | | | | | | (5) | | | | | | (677) | | | Exploration expenses | | | | | (26) | | | | | | (122) | | | | | | (22) | | | | | | (191) | | | | | | (60) | | | | | | | | | | | | (61) | | | | | | (39) | | | | | | (4) | | | | | | (525) | | | D.D. & A. and Provision for abandonment(a) | | | | | (465) | | | | | | (838) | | | | | | (679) | | | | | | (767) | | | | | | (2,063) | | | | | | (289) | | | | | | (765) | | | | | | (577) | | | | | | (59) | | | | | | (6,502) | | | Other income (expenses) | | | | | 1,563 | | | | | | (141) | | | | | | (162) | | | | | | 690 | | | | | | (716) | | | | | | (221) | | | | | | (84) | | | | | | (342) | | | | | | 2 | | | | | | 589 | | | Pretax income from producing activities | | | | | 2,224 | | | | | | 590 | | | | | | 2,673 | | | | | | 1,546 | | | | | | 279 | | | | | | 488 | | | | | | 75 | | | | | | (242) | | | | | | 57 | | | | | | 7,690 | | | Income taxes | | | | | (299) | | | | | | (216) | | | | | | (1,978) | | | | | | (214) | | | | | | (38) | | | | | | (223) | | | | | | (67) | | | | | | (38) | | | | | | (23) | | | | | | (3,096) | | | Results of operations from E&P activities of consolidated subsidiaries | | | | | 1,925 | | | | | | 374 | | | | | | 695 | | | | | | 1,332 | | | | | | 241 | | | | | | 265 | | | | | | 8 | | | | | | (280) | | | | | | 34 | | | | | | 4,594 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - sales to consolidated entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - sales to third parties | | | | | | | | | | | | | | | | | 14 | | | | | | | | | | | | 129 | | | | | | | | | | | | 22 | | | | | | 517 | | | | | | | | | | | | 682 | | | Total revenues | | | | | | | | | | | | | | | | | 14 | | | | | | | | | | | | 129 | | | | | | | | | | | | 22 | | | | | | 517 | | | | | | | | | | | | 682 | | | Production costs | | | | | | | | | | | | | | | | | (6) | | | | | | | | | | | | (19) | | | | | | | | | | | | (9) | | | | | | (39) | | | | | | | | | | | | (73) | | | Transportation costs | | | | | | | | | | | | | | | | | (2) | | | | | | | | | | | | (18) | | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | (21) | | | Production taxes | | | | | | | | | | | | | | | | | (2) | | | | | | | | | | | | (8) | | | | | | | | | | | | | | | | | | (146) | | | | | | | | | | | | (156) | | | Exploration expenses | | | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (13) | | | | | | | | | | | | | | | | | | (14) | | | D.D. & A. and Provision for abandonment | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | (54) | | | | | | | | | | | | (13) | | | | | | (271) | | | | | | | | | | | | (339) | | | Other income (expenses) | | | | | | | | | | | (2) | | | | | | (2) | | | | | | | | | | | | 26 | | | | | | | | | | | | 3 | | | ��� | | | (199) | | | | | | | | | | | | (174) | | | Pretax income from producing activities | | | | | | | | | | | (3) | | | | | | 1 | | | | | | | | | | | | 56 | | | | | | | | | | | | (10) | | | | | | (139) | | | | | | | | | | | | (95) | | | Income taxes | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | | | | | | | (4) | | | | | | (20) | | | | | | | | | | | | (25) | | | Results of operations from E&P activities of equity-accounted entities | | | | | | | | | | | (3) | | | | | | | | | | | | | | | | | | 56 | | | | | | | | | | | | (14) | | | | | | (159) | | | | | | | | | | | | (120) | | |
(a)
Includes asset net reversal amounting to €158 million
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-scientificgeoscience 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 unweightedun-weighted 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 2016,2019, the average price for the marker Brent crude oil was $42.8$63 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 qualifiedits proved reserves audited on a rotational basis by independent oil engineering companies to carry out an independent evaluation2039 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 report2140.
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 2016,2019, Ryder Scott Company, and DeGolyer and MacNaughton and Gaffney, Cline & Associates21 provided an independent evaluation of about 41%31% of Eni’s total proved reserves as of December 31, 201620192241, confirming, as in previous years, the reasonableness of Eni’s internal evaluations. In the three-year period from 20142017 to 2016, 94%2019, 86% of Eni’s total proved reserves were subject to independent evaluation. As of December 31, 2016,2019, the principal propertiesproperty not subjected to independent evaluation in the last three years are Zubair (Iraq), Bu Attifel (Libya), and Cafc-Mle (Algeria).was Zohr. 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%57%, 52%61% and 59%60% of total proved reserves as of December 31, 2014, 20152019, 2018 and 2016,2017, 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%3% and 5%4% of total proved reserves on an oil-equivalent basis as of December 31, 2014, 20152019, 2018 and 2016,2017, respectively. 39
From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott. In 2018 and independent evaluation was provided also by Societé Generale de Surveillance (SGS). 40
See “Item 19 – Exhibits”. 41
Including reserves of equity-accounted investments.
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%4%, 0,6%4% and 1,8%1.6% of total proved reserves as of December 31, 2014, 20152019, 2018 and 2016,2017, 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. 20
From 1991 to 2002 DeGolyer and McNaughton, from 2003 also Ryder Scott, from 2015 also Gaffney, Cline & Associates.
21
The reports of independent engineers are available on Eni website eni.com, section Publications/Annual Report 2016.
22
Including reserves of equity-accounted entities.
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, 20152019, 2018 and 2016.2017. CrudeCRUDE OIL (INCLUDING CONDENSATE AND NATURAL GAS LIQUIDS)
(million barrels) | | | | | | | | | | | | 2019 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2018 | | | | | 208 | | | | | | 48 | | | | | | 493 | | | | | | 279 | | | | | | 718 | | | | | | 704 | | | | | | 476 | | | | | | 252 | | | | | | 5 | | | | | | 3,183 | | | of which: developed | | | | | 156 | | | | | | 44 | | | | | | 317 | | | | | | 153 | | | | | | 551 | | | | | | 587 | | | | | | 252 | | | | | | 143 | | | | | | 5 | | | | | | 2,208 | | | undeveloped | | | | | 52 | | | | | | 4 | | | | | | 176 | | | | | | 126 | | | | | | 167 | | | | | | 117 | | | | | | 224 | | | | | | 109 | | | | | | | | | | | | 975 | | | Purchase of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 29 | | | | | | | | | | | | 29 | | | Revisions of Previous Estimates | | | | | 5 | | | | | | 1 | | | | | | 37 | | | | | | 10 | | | | | | 46 | | | | | | 79 | | | | | | 45 | | | | | | (16) | | | | | | (4) | | | | | | 203 | | | Improved Recovery | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Extensions and Discoveries | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | | | 21 | | | | | | | | | | | | 2 | | | | | | 9 | | | | | | | | | | | | 34 | | | Production | | | | | (19) | | | | | | (8) | | | | | | (62) | | | | | | (27) | | | | | | (90) | | | | | | (37) | | | | | | (32) | | | | | | (20) | | | | | | | | | | | | (295) | | | Sales of Minerals in Place(a) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | (29) | | | | | | | | | | | | (30) | | | Reserves at December 31, 2019 | | | | | 194 | | | | | | 41 | | | | | | 468 | | | | | | 264 | | | | | | 694 | | | | | | 746 | | | | | | 491 | | | | | | 225 | | | | | | 1 | | | | | | 3,124 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2018 | | | | | | | | | | | 297 | | | | | | 11 | | | | | | | | | | | | 12 | | | | | | | | | | | | | | | | | | 37 | | | | | | | | | | | | 357 | | | of which: developed | | | | | | | | | | | 154 | | | | | | 11 | | | | | | | | | | | | 8 | | | | | | | | | | | | | | | | | | 32 | | | | | | | | | | | | 205 | | | undeveloped | | | | | | | | | | | 143 | | | | | | | | | | | | | | | | | | 4 | | | | | | | | | | | | | | | | | | 5 | | | | | | | | | | | | 152 | | | Purchase of Minerals in Place | | | | | | | | | | | 109 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 109 | | | Revisions of Previous Estimates | | | | | | | | | | | 45 | | | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (5) | | | | | | | | | | | | 42 | | | Improved Recovery | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Extensions and Discoveries | | | | | | | | | | | 6 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6 | | | Production | | | | | | | | | | | (27) | | | | | | (1) | | | | | | | | | | | | (2) | | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | (31) | | | Sales of Minerals in Place | | | | | | | | | | | (6) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (6) | | | Reserves at December 31, 2019 | | | | | | | | | | | 424 | | | | | | 12 | | | | | | | | | | | | 10 | | | | | | | | | | | | | | | | | | 31 | | | | | | | | | | | | 477 | | | Reserves at December 31, 2019 | | | | | 194 | | | | | | 465 | | | | | | 480 | | | | | | 264 | | | | | | 704 | | | | | | 746 | | | | | | 491 | | | | | | 256 | | | | | | 1 | | | | | | 3,601 | | | Developed | | | | | 137 | | | | | | 256 | | | | | | 313 | | | | | | 149 | | | | | | 526 | | | | | | 682 | | | | | | 245 | | | | | | 179 | | | | | | 1 | | | | | | 2,488 | | | consolidated subsidiaries | | | | | 137 | | | | | | 37 | | | | | | 301 | | | | | | 149 | | | | | | 519 | | | | | | 682 | | | | | | 245 | | | | | | 148 | | | | | | 1 | | | | | | 2,219 | | | equity-accounted entities | | | | | | | | | | | 219 | | | | | | 12 | | | | | | | | | | | | 7 | | | | | | | | | | | | | | | | | | 31 | | | | | | | | | | | | 269 | | | Undeveloped | | | | | 57 | | | | | | 209 | | | | | | 167 | | | | | | 115 | | | | | | 178 | | | | | | 64 | | | | | | 246 | | | | | | 77 | | | | | | | | | | | | 1,113 | | | consolidated subsidiaries | | | | | 57 | | | | | | 4 | | | | | | 167 | | | | | | 115 | | | | | | 175 | | | | | | 64 | | | | | | 246 | | | | | | 77 | | | | | | | | | | | | 905 | | | equity-accounted entities | | | | | | | | | | | 205 | | | | | | | | | | | | | | | | | | 3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 208 | | |
(a)
Includes 0.6 Mboe as part of a long-term supply agreement to a state-owned national oil (Including Condensate and Natural Gas Liquids)company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid. (million barrels) | | | | | | | | | | | 2014 | | | Italy | | | Rest of Europe | | | North Africa | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | 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 | | | |
2015 | | | Italy | | | Rest of Europe | | | North Africa | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | 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 | | | |
2018 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2017 | | | | | 215 | | | | | | 360 | | | | | | 476 | | | | | | 280 | | | | | | 764 | | | | | | 766 | | | | | | 232 | | | | | | 162 | | | | | | 7 | | | | | | 3,262 | | | of which: developed | | | | | 169 | | | | | | 219 | | | | | | 306 | | | | | | 203 | | | | | | 546 | | | | | | 547 | | | | | | 81 | | | | | | 144 | | | | | | 5 | | | | | | 2,220 | | | undeveloped | | | | | 46 | | | | | | 141 | | | | | | 170 | | | | | | 77 | | | | | | 218 | | | | | | 219 | | | | | | 151 | | | | | | 18 | | | | | | 2 | | | | | | 1,042 | | | Purchase of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 319 | | | | | | | | | | | | | | | | | | 319 | | | Revisions of Previous Estimates | | | | | 15 | | | | | | 6 | | | | | | 73 | | | | | | 21 | | | | | | 30 | | | | | | (27) | | | | | | (54) | | | | | | 23 | | | | | | (1) | | | | | | 86 | | | Improved Recovery | | | | | | | | | | | | | | | | | | | | | | | 7 | | | | | | | | | | | | | | | | | | 6 | | | | | | | | | | | | | | | | | | 13 | | | Extensions and Discoveries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 13 | | | | | | | | | | | | 1 | | | | | | 86 | | | | | | | | | | | | 100 | | | Production | | | | | (22) | | | | | | (40) | | | | | | (56) | | | | | | (28) | | | | | | (89) | | | | | | (35) | | | | | | (28) | | | | | | (19) | | | | | | (1) | | | | | | (318) | | | Sales of Minerals in Place | | | | | | | | | | | (278) | | | | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (279) | | | Reserves at December 31, 2018 | | | | | 208 | | | | | | 48 | | | | | | 493 | | | | | | 279 | | | | | | 718 | | | | | | 704 | | | | | | 476 | | | | | | 252 | | | | | | 5 | | | | | | 3,183 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2017 | | | | | | | | | | | | | | | | | 12 | | | | | | | | | | | | 12 | | | | | | | | | | | | | | | | | | 136 | | | | | | | | | | | | 160 | | | of which: developed | | | | | | | | | | | | | | | | | 12 | | | | | | | | | | | | 6 | | | | | | | | | | | | | | | | | | 25 | | | | | | | | | | | | 43 | | | undeveloped | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6 | | | | | | | | | | | | | | | | | | 111 | | | | | | | | | | | | 117 | | | Purchase of Minerals in Place | | | | | | | | | | | 297 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 297 | | | Revisions of Previous Estimates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | | | | | | | (96) | | | | | | | | | | | | (95) | | | Improved Recovery | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Extensions and Discoveries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Production | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | (3) | | | | | | | | | | | | (5) | | | Sales of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2018 | | | | | | | | | | | 297 | | | | | | 11 | | | | | | | | | | | | 12 | | | | | | | | | | | | | | | | | | 37 | | | | | | | | | | | | 357 | | | Reserves at December 31, 2018 | | | | | 208 | | | | | | 345 | | | | | | 504 | | | | | | 279 | | | | | | 730 | | | | | | 704 | | | | | | 476 | | | | | | 289 | | | | | | 5 | | | | | | 3,540 | | | Developed | | | | | 156 | | | | | | 198 | | | | | | 328 | | | | | | 153 | | | | | | 559 | | | | | | 587 | | | | | | 252 | | | | | | 175 | | | | | | 5 | | | | | | 2,413 | | | consolidated subsidiaries | | | | | 156 | | | | | | 44 | | | | | | 317 | | | | | | 153 | | | | | | 551 | | | | | | 587 | | | | | | 252 | | | | | | 143 | | | | | | 5 | | | | | | 2,208 | | | equity-accounted entities | | | | | | | | | | | 154 | | | | | | 11 | | | | | | | | | | | | 8 | | | | | | | | | | | | | | | | | | 32 | | | | | | | | | | | | 205 | | | Undeveloped | | | | | 52 | | | | | | 147 | | | | | | 176 | | | | | | 126 | | | | | | 171 | | | | | | 117 | | | | | | 224 | | | | | | 114 | | | | | | | | | | | | 1,127 | | | consolidated subsidiaries | | | | | 52 | | | | | | 4 | | | | | | 176 | | | | | | 126 | | | | | | 167 | | | | | | 117 | | | | | | 224 | | | | | | 109 | | | | | | | | | | | | 975 | | | equity-accounted entities | | | | | | | | | | | 143 | | | | | | | | | | | | | | | | | | 4 | | | | | | | | | | | | | | | | | | 5 | | | | | | | | | | | | 152 | | | |
2017 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2016 | | | | | 176 | | | | | | 264 | | | | | | 454 | | | | | | 281 | | | | | | 809 | | | | | | 767 | | | | | | 307 | | | | | | 163 | | | | | | 9 | | | | | | 3,230 | | | of which: developed | | | | | 132 | | | | | | 228 | | | | | | 287 | | | | | | 205 | | | | | | 507 | | | | | | 556 | | | | | | 124 | | | | | | 143 | | | | | | 8 | | | | | | 2,190 | | | undeveloped | | | | | 44 | | | | | | 36 | | | | | | 167 | | | | | | 76 | | | | | | 302 | | | | | | 211 | | | | | | 183 | | | | | | 20 | | | | | | 1 | | | | | | 1,040 | | | Purchase of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2 | | | Revisions of Previous Estimates | | | | | 59 | | | | | | 29 | | | | | | 73 | | | | | | 21 | | | | | | 31 | | | | | | 29 | | | | | | (69) | | | | | | 19 | | | | | | (1) | | | | | | 191 | | | Improved Recovery | | | | | | | | | | | 1 | | | | | | 6 | | | | | | 7 | | | | | | | | | | | | | | | | | | 9 | | | | | | | | | | | | | | | | | | 23 | | | Extensions and Discoveries | | | | | | | | | | | 103 | | | | | | 1 | | | | | | | | | | | | 18 | | | | | | | | | | | | 4 | | | | | | 3 | | | | | | | | | | | | 129 | | | Production | | | | | (20) | | | | | | (37) | | | | | | (58) | | | | | | (26) | | | | | | (90) | | | | | | (30) | | | | | | (19) | | | | | | (23) | | | | | | (1) | | | | | | (304) | | | Sales of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | (3) | | | | | | (6) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (9) | | | Reserves at December 31, 2017 | | | | | 215 | | | | | | 360 | | | | | | 476 | | | | | | 280 | | | | | | 764 | | | | | | 766 | | | | | | 232 | | | | | | 162 | | | | | | 7 | | | | | | 3,262 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2016 | | | | | | | | | | | | | | | | | 13 | | | | | | | | | | | | 15 | | | | | | | | | | | | | | | | | | 140 | | | | | | | | | | | | 168 | | | of which: developed | | | | | | | | | | | | | | | | | 13 | | | | | | | | | | | | 8 | | | | | | | | | | | | | | | | | | 22 | | | | | | | | | | | | 43 | | | undeveloped | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 7 | | | | | | | | | | | | | | | | | | 118 | | | | | | | | | | | | 125 | | | Purchase of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revisions of Previous Estimates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (2) | | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | (1) | | | Improved Recovery | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Extensions and Discoveries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Production | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | (5) | | | | | | | | | | | | (7) | | | Sales of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2017 | | | | | | | | | | | | | | | | | 12 | | | | | | | | | | | | 12 | | | | | | | | | | | | | | | | | | 136 | | | | | | | | | | | | 160 | | | Reserves at December 31, 2017 | | | | | 215 | | | | | | 360 | | | | | | 488 | | | | | | 280 | | | | | | 776 | | | | | | 766 | | | | | | 232 | | | | | | 298 | | | | | | 7 | | | | | | 3,422 | | | Developed | | | | | 169 | | | | | | 219 | | | | | | 318 | | | | | | 203 | | | | | | 552 | | | | | | 547 | | | | | | 81 | | | | | | 169 | | | | | | 5 | | | | | | 2,263 | | | consolidated subsidiaries | | | | | 169 | | | | | | 219 | | | | | | 306 | | | | | | 203 | | | | | | 546 | | | | | | 547 | | | | | | 81 | | | | | | 144 | | | | | | 5 | | | | | | 2,220 | | | equity-accounted entities | | | | | | | | | | | | | | | | | 12 | | | | | | | | | | | | 6 | | | | | | | | | | | | | | | | | | 25 | | | | | | | | | | | | 43 | | | Undeveloped | | | | | 46 | | | | | | 141 | | | | | | 170 | | | | | | 77 | | | | | | 224 | | | | | | 219 | | | | | | 151 | | | | | | 129 | | | | | | 2 | | | | | | 1,159 | | | consolidated subsidiaries | | | | | 46 | | | | | | 141 | | | | | | 170 | | | | | | 77 | | | | | | 218 | | | | | | 219 | | | | | | 151 | | | | | | 18 | | | | | | 2 | | | | | | 1,042 | | | equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 6 | | | | | | | | | | | | | | | | | | 111 | | | | | | | | | | | | 117 | | | |
(billion cubic feet) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2019 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2018 | | | | | 1,199 | | | | | | 320 | | | | | | 2,890 | | | | | | 5,275 | | | | | | 3,506 | | | | | | 1,989 | | | | | | 1,217 | | | | | | 277 | | | | | | 651 | | | | | | 17,324 | | | of which: developed | | | | | 980 | | | | | | 300 | | | | | | 1,447 | | | | | | 3,331 | | | | | | 1,871 | | | | | | 1,846 | | | | | | 822 | | | | | | 154 | | | | | | 452 | | | | | | 11,203 | | | undeveloped | | | | | 219 | | | | | | 20 | | | | | | 1,443 | | | | | | 1,944 | | | | | | 1,635 | | | | | | 143 | | | | | | 395 | | | | | | 123 | | | | | | 199 | | | | | | 6,121 | | | Purchase of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 7 | | | | | | | | | | | | 7 | | | Revisions of Previous Estimates | | | | | (310) | | | | | | 4 | | | | | | 267 | | | | | | 467 | | | | | | 747 | | | | | | 79 | | | | | | 104 | | | | | | (23) | | | | | | (108) | | | | | | 1,227 | | | Improved Recovery | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Extensions and Discoveries | | | | | | | | | | | 2 | | | | | | | | | | | | | | | | | | 78 | | | | | | | | | | | | 274 | | | | | | 4 | | | | | | | | | | | | 358 | | | Production | | | | | (137) | | | | | | (64) | | | | | | (419) | | | | | | (551) | | | | | | (210) | | | | | | (99) | | | | | | (198) | | | | | | (24) | | | | | | (36) | | | | | | (1,738) | | | Sales of Minerals in Place(a) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (18) | | | | | | | | | | | | (48) | | | | | | (1) | | | | | | | | | | | | (67) | | | Reserves at December 31, 2019 | | | | | 752 | | | | | | 262 | | | | | | 2,738 | | | | | | 5,191 | | | | | | 4,103 | | | | | | 1,969 | | | | | | 1,349 | | | | | | 240 | | | | | | 507 | | | | | | 17,111 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2018 | | | | | | | | | | | 360 | | | | | | 14 | | | | | | | | | | | | 310 | | | | | | | | | | | | | | | | | | 1,716 | | | | | | | | | | | | 2,400 | | | of which: developed | | | | | | | | | | | 276 | | | | | | 14 | | | | | | | | | | | | 57 | | | | | | | | | | | | | | | | | | 1,716 | | | | | | | | | | | | 2,063 | | | undeveloped | | | | | | | | | | | 84 | | | | | | | | | | | | | | | | | | 253 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 337 | | | Purchase of Minerals in Place | | | | | | | | | | | 405 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 405 | | | Revisions of Previous Estimates | | | | | | | | | | | 76 | | | | | | 1 | | | | | | | | | | | | 13 | | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | 91 | | | Improved Recovery | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Extensions and Discoveries | | | | | | | | | | | (2) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (2) | | | Production | | | | | | | | | | | (67) | | | | | | (1) | | | | | | | | | | | | (36) | | | | | | | | | | | | | | | | | | (69) | | | | | | | | | | | | (173) | | | Sales of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2019 | | | | | | | | | | | 772 | | | | | | 14 | | | | | | | | | | | | 287 | | | | | | | | | | | | | | | | | | 1,648 | | | | | | | | | | | | 2,721 | | | Reserves at December 31, 2019 | | | | | 752 | | | | | | 1,034 | | | | | | 2,752 | | | | | | 5,191 | | | | | | 4,390 | | | | | | 1,969 | | | | | | 1,349 | | | | | | 1,888 | | | | | | 507 | | | | | | 19,832 | | | Developed | | | | | 657 | | | | | | 839 | | | | | | 1,388 | | | | | | 4,777 | | | | | | 1,946 | | | | | | 1,969 | | | | | | 685 | | | | | | 1,834 | | | | | | 322 | | | | | | 14,417 | | | consolidated subsidiaries | | | | | 657 | | | | | | 242 | | | | | | 1,374 | | | | | | 4,777 | | | | | | 1,858 | | | | | | 1,969 | | | | | | 685 | | | | | | 186 | | | | | | 322 | | | | | | 12,070 | | | equity-accounted entities | | | | | | | | | | | 597 | | | | | | 14 | | | | | | | | | | | | 88 | | | | | | | | | | | | | | | | | | 1,648 | | | | | | | | | | | | 2,347 | | | Undeveloped | | | | | 95 | | | | | | 195 | | | | | | 1,364 | | | | | | 414 | | | | | | 2,444 | | | | | | | | | | | | 664 | | | | | | 54 | | | | | | 185 | | | | | | 5,415 | | | consolidated subsidiaries | | | | | 95 | | | | | | 20 | | | | | | 1,364 | | | | | | 414 | | | | | | 2,245 | | | | | | | | | | | | 664 | | | | | | 54 | | | | | | 185 | | | | | | 5,041 | | | equity-accounted entities | | | | | | | | | | | 175 | | | | | | | | | | | | | | | | | | 199 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 374 | | |
(a)
Includes 17.6 BCF as part of a long-term supply agreement to a state-owned national oil (Including Condensate and Natural Gas Liquids) continuedcompany, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid. (million barrels) | | | | | | | | | | | | 2016 | | | Italy | | | Rest of Europe | | | North Africa* | | | *Egypt (of which) | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | 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 | | | |
Natural Gas(a)
(billion cubic feet) | | | | 2014 | | Italy | | Rest of Europe | | North Africa | | Sub - Saharan Africa | | Kazakhstan | | Rest of Asia | | America | | Australia and Oceania | | Total | | | 2018 | | | Italy | | Rest of Europe | | North Africa | | Egypt | | Sub - Saharan Africa | | Kazakhstan | | Rest of Asia | | America | | Australia and Oceania | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2013 | | | | 1,532 | | | | | 1,247 | | | | | 5,231 | | | | | 2,374 | | | | | 1,957 | | | | | 744 | | | | | 509 | | | | | 848 | | | | | 14,442 | | | | Reserves at December 31, 2017 | | | | | 1,131 | | | | | 896 | | | | | 3,145 | | | | | 4,351 | | | | | 3,660 | | | | | 2,108 | | | | | 1,065 | | | | | 225 | | | | | 709 | | | | | 17,290 | | | of which: developed | | | | 1,266 | | | | | 904 | | | | | 2,432 | | | | | 1,295 | | | | | 1,488 | | | | | 286 | | | | | 310 | | | | | 561 | | | | | 8,542 | | | | | | 987 | | | | | 771 | | | | | 1,233 | | | | | 1,421 | | | | | 1,693 | | | | | 1,878 | | | | | 862 | | | | | 171 | | | | | 519 | | | | | 9,535 | | | undeveloped | | | | 266 | | | | | 343 | | | | | 2,799 | | | | | 1,079 | | | | | 469 | | | | | 458 | | | | | 199 | | | | | 287 | | | | | 5,900 | | | | | | 144 | | | | | 125 | | | | | 1,912 | | | | | 2,930 | | | | | 1,967 | | | | | 230 | | | | | 203 | | | | | 54 | | | | | 190 | | | | | 7,755 | | | Purchase of Minerals in Place | | | | | | | | | 21 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 21 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 69 | | | | | | | | | | | | | | | 69 | | | Revisions of Previous Estimates | | | | 113 | | | | | 99 | | | | | 668 | | | | | 214 | | | | | 165 | | | | | 156 | | | | | 23 | | | | | (1) | | | | | 1,437 | | | | | | 138 | | | | | 50 | | | | | 219 | | | | | 2,238 | | | | | 23 | | | | | (22) | | | | | 81 | | | | | 45 | | | | | (16) | | | | | 2,756 | | | Improved Recovery | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Extensions and Discoveries | | | | | | | | | | | | | | 19 | | | | | 341 | | | | | | | | | | 59 | | | | | 16 | | | | | | | | | | 435 | | | | | | 86 | | | | | | | | | | | | | | | | | | | | 7 | | | | | | | | | | 205 | | | | | 76 | | | | | | | | | | 374 | | | Production | | | | (213) | | | | | (195) | | | | | (627) | | | | | (185) | | | | | (73) | | | | | (113) | | | | | (80) | | | | | (40) | | | | | (1,526) | | | | | | (156) | | | | | (162) | | | | | (474) | | | | | (445) | | | | | (184) | | | | | (97) | | | | | (201) | | | | | (43) | | | | | (42) | | | | | (1,804) | | | Sales of Minerals in Place | | | | | | | | | (1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | (464) | | | | | | | | | | (869) | | | | | | | | | | | | | | | (2) | | | | | (26) | | | | | | | | | | (1,361) | | | Reserves at December 31, 2014 | | | | 1,432 | | | | | 1,171 | | | | | 5,291 | | | | | 2,744 | | | | | 2,049 | | | | | 846 | | | | | 468 | | | | | 807 | | | | | 14,808 | | | | Reserves at December 31, 2018 | | | | | 1,199 | | | | | 320 | | | | | 2,890 | | | | | 5,275 | | | | | 3,506 | | | | | 1,989 | | | | | 1,217 | | | | | 277 | | | | | 651 | | | | | 17,324 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2013 | | | | | | | | | | | | | | 15 | | | | | 330 | | | | | | | | | | 28 | | | | | 3,353 | | | | | | | | | | 3,726 | | | | Reserves at December 31, 2017 | | | | | | | | | | | | | | | 14 | | | | | | | | | | 349 | | | | | | | | | | | | | | | 1,819 | | | | | | | | | | 2,182 | | | of which: developed | | | | | | | | | | | | | | 15 | | | | | | | | | | | | | | | 14 | | | | | 5 | | | | | | | | | | 34 | | | | | | | | | | | | | | | | 14 | | | | | | | | | | 83 | | | | | | | | | | | | | | | 1,819 | | | | | | | | | | 1,916 | | | undeveloped | | | | | | | | | | | | | | | | | | | 330 | | | | | | | | | | 14 | | | | | 3,348 | | | | | | | | | | 3,692 | | | | | | | | | | | | | | | | | | | | | | | | | | 266 | | | | | | | | | | | | | | | | | | | | | | | | | 266 | | | Purchase of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 360 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 360 | | | Revisions of Previous Estimates | | | | | | | | | | | | | | 2 | | | | | 25 | | | | | | | | | | (2) | | | | | | | | | | | | | | | 25 | | | | | | | | | | | | | | | | 2 | | | | | | | | | | (6) | | | | | | | | | | | | | | | (22) | | | | | | | | | | (26) | | | Improved Recovery | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Extensions and Discoveries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Production | | | | | | | | | | | | | | (2) | | | | | (4) | | | | | | | | | | (8) | | | | | | | | | | | | | | | (14) | | | | | | | | | | | | | | | | (2) | | | | | | | | | | (33) | | | | | | | | | | | | | | | (81) | | | | | | | | | | (116) | | | 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 | | | | Reserves at December 31, 2018 | | | | | | | | | | 360 | | | | | 14 | | | | | | | | | | 310 | | | | | | | | | | | | | | | 1,716 | | | | | | | | | | 2,400 | | | Reserves at December 31, 2018 | | | | | 1,199 | | | | | 680 | | | | | 2,904 | | | | | 5,275 | | | | | 3,816 | | | | | 1,989 | | | | | 1,217 | | | | | 1,993 | | | | | 651 | | | | | 19,724 | | | Developed | | | | 1,192 | | | | | 887 | | | | | 2,125 | | | | | 1,360 | | | | | 1,553 | | | | | 271 | | | | | 399 | | | | | 675 | | | | | 8,462 | | | | | | 980 | | | | | 576 | | | | | 1,461 | | | | | 3,331 | | | | | 1,928 | | | | | 1,846 | | | | | 822 | | | | | 1,870 | | | | | 452 | | | | | 13,266 | | | consolidated subsidiaries | | | | 1,192 | | | | | 887 | | | | | 2,110 | | | | | 1,271 | | | | | 1,553 | | | | | 261 | | | | | 393 | | | | | 675 | | | | | 8,342 | | | | | | 980 | | | | | 300 | | | | | 1,447 | | | | | 3,331 | | | | | 1,871 | | | | | 1,846 | | | | | 822 | | | | | 154 | | | | | 452 | | | | | 11,203 | | | equity-accounted entities | | | | | | | | | | | | | | 15 | | | | | 89 | | | | | | | | | | 10 | | | | | 6 | | | | | | | | | | 120 | | | | | | | | | | | 276 | | | | | 14 | | | | | | | | | | 57 | | | | | | | | | | | | | | | 1,716 | | | | | | | | | | 2,063 | | | Undeveloped | | | | 240 | | | | | 284 | | | | | 3,181 | | | | | 1,735 | | | | | 496 | | | | | 593 | | | | | 3,422 | | | | | 132 | | | | | 10,083 | | | | | | 219 | | | | | 104 | | | | | 1,443 | | | | | 1,944 | | | | | 1,888 | | | | | 143 | | | | | 395 | | | | | 123 | | | | | 199 | | | | | 6,458 | | | consolidated subsidiaries | | | | 240 | | | | | 284 | | | | | 3,181 | | | | | 1,473 | | | | | 496 | | | | | 585 | | | | | 75 | | | | | 132 | | | | | 6,466 | | | | | | 219 | | | | | 20 | | | | | 1,443 | | | | | 1,944 | | | | | 1,635 | | | | | 143 | | | | | 395 | | | | | 123 | | | | | 199 | | | | | 6,121 | | | equity-accounted entities | | | | | | | | | | | | | | | | | | | 262 | | | | | | | | | | 8 | | | | | 3,347 | | | | | | | | | | 3,617 | | | | | | | | | | | 84 | | | | | | | | | | | | | | | 253 | | | | | | | | | | | | | | | | | | | | | | | | | 337 | | | |
Natural Gas(a) continued
(billion cubic feet) | | | | | | | | | | | 2015 | | | Italy | | | Rest of Europe | | | North Africa | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | 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 | | | |
| | | | | | | | | | | | 2016 | | | Italy | | | Rest of Europe | | | North Africa* | | | *Egypt (of which) | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | 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.
TABLE OF CONTENTS2017 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2016 | | | | | 977 | | | | | | 878 | | | | | | 3,738 | | | | | | 5,520 | | | | | | 2,767 | | | | | | 2,485 | | | | | | 1,003 | | | | | | 353 | | | | | | 741 | | | | | | 18,462 | | | of which: developed | | | | | 845 | | | | | | 801 | | | | | | 1,732 | | | | | | 799 | | | | | | 1,651 | | | | | | 2,239 | | | | | | 280 | | | | | | 338 | | | | | | 559 | | | | | | 9,244 | | | undeveloped | | | | | 132 | | | | | | 77 | | | | | | 2,006 | | | | | | 4,721 | | | | | | 1,116 | | | | | | 246 | | | | | | 723 | | | | | | 15 | | | | | | 182 | | | | | | 9,218 | | | Purchase of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1 | | | Revisions of Previous Estimates | | | | | 315 | | | | | | 163 | | | | | | 66 | | | | | | 969 | | | | | | 134 | | | | | | (281) | | | | | | 188 | | | | | | (61) | | | | | | 6 | | | | | | 1,499 | | | Improved Recovery | | | | | | | | | | | | | | | | | (19) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (19) | | | Extensions and Discoveries | | | | | | | | | | | 29 | | | | | | | | | | | | 64 | | | | | | 1,839 | | | | | | | | | | | | | | | | | | 4 | | | | | | | | | | | | 1,936 | | | Production | | | | | (161) | | | | | | (174) | | | | | | (640) | | | | | | (315) | | | | | | (162) | | | | | | (96) | | | | | | (126) | | | | | | (71) | | | | | | (38) | | | | | | (1,783) | | | Sales of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | (1,887) | | | | | | (919) | | | �� | | | | | | | | | | | | | | | | | | | | | | | | | | | (2,806) | | | Reserves at December 31, 2017 | | | | | 1,131 | | | | | | 896 | | | | | | 3,145 | | | | | | 4,351 | | | | | | 3,660 | | | | | | 2,108 | | | | | | 1,065 | | | | | | 225 | | | | | | 709 | | | | | | 17,290 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2016 | | | | | | | | | | | | | | | | | 15 | | | | | | | | | | | | 368 | | | | | | | | | | | | 4 | | | | | | 3,484 | | | | | | | | | | | | 3,871 | | | of which: developed | | | | | | | | | | | | | | | | | 15 | | | | | | | | | | | | 104 | | | | | | | | | | | | 4 | | | | | | 1,782 | | | | | | | | | | | | 1,905 | | | undeveloped | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 264 | | | | | | | | | | | | | | | | | | 1,702 | | | | | | | | | | | | 1,966 | | | Purchase of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revisions of Previous Estimates | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 13 | | | | | | | | | | | | | | | | | | (1,565) | | | | | | | | | | | | (1,552) | | | Improved Recovery | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Extensions and Discoveries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Production | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | (32) | | | | | | | | | | | | (4) | | | | | | (100) | | | | | | | | | | | | (137) | | | Sales of Minerals in Place | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Reserves at December 31, 2017 | | | | | | | | | | | | | | | | | 14 | | | | | | | | | | | | 349 | | | | | | | | | | | | | | | | | | 1,819 | | | | | | | | | | | | 2,182 | | | Reserves at December 31, 2017 | | | | | 1,131 | | | | | | 896 | | | | | | 3,159 | | | | | | 4,351 | | | | | | 4,009 | | | | | | 2,108 | | | | | | 1,065 | | | | | | 2,044 | | | | | | 709 | | | | | | 19,472 | | | Developed | | | | | 987 | | | | | | 771 | | | | | | 1,247 | | | | | | 1,421 | | | | | | 1,776 | | | | | | 1,878 | | | | | | 862 | | | | | | 1,990 | | | | | | 519 | | | | | | 11,451 | | | consolidated subsidiaries | | | | | 987 | | | | | | 771 | | | | | | 1,233 | | | | | | 1,421 | | | | | | 1,693 | | | | | | 1,878 | | | | | | 862 | | | | | | 171 | | | | | | 519 | | | | | | 9,535 | | | equity-accounted entities | | | | | | | | | | | | | | | | | 14 | | | | | | | | | | | | 83 | | | | | | | | | | | | | | | | | | 1,819 | | | | | | | | | | | | 1,916 | | | Undeveloped | | | | | 144 | | | | | | 125 | | | | | | 1,912 | | | | | | 2,930 | | | | | | 2,233 | | | | | | 230 | | | | | | 203 | | | | | | 54 | | | | | | 190 | | | | | | 8,021 | | | consolidated subsidiaries | | | | | 144 | | | | | | 125 | | | | | | 1,912 | | | | | | 2,930 | | | | | | 1,967 | | | | | | 230 | | | | | | 203 | | | | | | 54 | | | | | | 190 | | | | | | 7,755 | | | equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 266 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 266 | | | |
Standardized measure of discounted future net cash flows 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.
The standardized measure of discounted future net cash flows by geographical area consists of the following: (€ million) | | | | | | | | | | | | | | | Italy | | | Rest of Europe | | | North Africa* | | | *Egypt (of which) | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | 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 | | | | | (6,374) | | | | | | (6,856) | | | | | | (19,906) | | | | | | | | | | | | (18,236) | | | | | | (9,878) | | | | | | (4,158) | | | | | | (2,680) | | | | | | (1,092) | | | | | | (69,180) | | | Future development 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 consolidated subsidiaries and equity-accounted entities | | | | | 6,232 | | | | | | 4,933 | | | | | | 17,525 | | | | | | | | | | | | 11,997 | | | | | | 11,187 | | | | | | 1,604 | | | | | | 4,809 | | | | | | 1,306 | | | | | | 59,593 | | | December 31, 2015 | | | | | | | | | | | | Consolidated subsidiaries | | | | | | | | | | | | Future cash inflows | | | | | 16,760 | | | | | | 18,692 | | | | | | 58,390 | | | | | | | | | | | | 44,114 | | | | | | 34,589 | | | | | | 13,027 | | | | | | 8,101 | | | | | | 3,519 | | | | | | 197,192 | | | Future production costs | | | | | (4,995) | | | | | | (5,554) | | | | | | (13,481) | | | | | | | | | | | | (14,645) | | | | | | (8,846) | | | | | | (4,585) | | | | | | (3,091) | | | | | | (804) | | | | | | (56,001) | | | Future development and abandonment costs | | | | | (4,299) | | | | | | (4,379) | | | | | | (9,457) | | | | | | | | | | | | (9,359) | | | | | | (4,108) | | | | | | (4,964) | | | | | | (1,644) | | | | | | (218) | | | | | | (38,428) | | | Future net inflow before income tax | | | | | 7,466 | | | | | | 8,759 | | | | | | 35,452 | | | | | | | | | | | | 20,110 | | | | | | 21,635 | | | | | | 3,478 | | | | | | 3,366 | | | | | | 2,497 | | | | | | 102,763 | | | Future income tax | | | | | (1,657) | | | | | | (4,349) | | | | | | (17,195) | | | | | | | | | | | | (8,222) | | | | | | (4,682) | | | | | | (1,230) | | | | | | (933) | | | | | | (604) | | | | | | (38,872) | | | Future net cash flows | | | | | 5,809 | | | | | | 4,410 | | | | | | 18,257 | | | | | | | | | | | | 11,888 | | | | | | 16,953 | | | | | | 2,248 | | | | | | 2,433 | | | | | | 1,893 | | | | | | 63,891 | | | 10% discount factor | | | | | (2,077) | | | | | | (817) | | | | | | (7,844) | | | | | | | | | | | | (4,976) | | | | | | (10,561) | | | | | | (1,276) | | | | | | (970) | | | | | | (901) | | | | | | (29,422) | | | Standardized measure of discounted future net cash flows | | | | | 3,732 | | | | | | 3,593 | | | | | | 10,413 | | | | | | | | | | | | 6,912 | | | | | | 6,392 | | | | | | 972 | | | | | | 1,463 | | | | | | 992 | | | | | | 34,469 | | | Equity-accounted entities | | | | | | | | | | | | Future cash inflows | | | | | | | | | | | | | | | | | 313 | | | | | | | | | | | | 3,047 | | | | | | | | | | | | 85 | | | | | | 18,519 | | | | | | | | | | | | 21,964 | | | Future production costs | | | | | | | | | | | | | | | | | (177) | | | | | | | | | | | | (1,021) | | | | | | | | | | | | (32) | | | | | | (5,370) | | | | | | | | | | | | (6,600) | | | Future development and abandonment costs | | | | | | | | | | | | | | | | | (5) | | | | | | | | | | | | (95) | | | | | | | | | | | | (22) | | | | | | (2,118) | | | | | | | | | | | | (2,240) | | | Future net inflow before income tax | | | | | | | | | | | | | | | | | 131 | | | | | | | | | | | | 1,931 | | | | | | | | | | | | 31 | | | | | | 11,031 | | | | | | | | | | | | 13,124 | | | Future income tax | | | | | | | | | | | | | | | | | (8) | | | | | | | | | | | | (251) | | | | | | | | | | | | (10) | | | | | | (4,088) | | | | | | | | | | | | (4,357) | | | Future net cash flows | | | | | | | | | | | | | | | | | 123 | | | | | | | | | | | | 1,680 | | | | | | | | | | | | 21 | | | | | | 6,943 | | | | | | | | | | | | 8,767 | | | 10% discount factor | | | | | | | | | | | | | | | | | (70) | | | | | | | | | | | | (1,016) | | | | | | | | | | | | (2) | | | | | | (4,358) | | | | | | | | | | | | (5,446) | | | Standardized measure of discounted future net cash flows | | | | | | | | | | | | | | | | | 53 | | | | | | | | | | | | 664 | | | | | | | | | | | | 19 | | | | | | 2,585 | | | | | | | | | | | | 3,321 | | | Total consolidated subsidiaries and equity-accounted entities | | | | | 3,732 | | | | | | 3,593 | | | | | | 10,466 | | | | | | | | | | | | 7,576 | | | | | | 6,392 | | | | | | 991 | | | | | | 4,048 | | | | | | 992 | | | | | | 37,790 | | | 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 consolidated subsidiaries and equity-accounted entities | | | | | 1,372 | | | | | | 2,410 | | | | | | 8,817 | | | | | | 4,620 | | | | | | 6,389 | | | | | | 5,256 | | | | | | 1,508 | | | | | | 3,264 | | | | | | 822 | | | | | | 29,838 | | | |
(€ million) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2019 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Future cash inflows | | | | | 12,363 | | | | | | 3,268 | | | | | | 38,083 | | | | | | 37,020 | | | | | | 48,778 | | | | | | 36,435 | | | | | | 31,220 | | | | | | 11,378 | | | | | | 1,686 | | | | | | 220,231 | | | Future production costs | | | | | (5,078) | | | | | | (1,175) | | | | | | (6,944) | | | | | | (10,934) | | | | | | (15,534) | | | | | | (8,239) | | | | | | (8,888) | | | | | | (5,060) | | | | | | (293) | | | | | | (62,145) | | | Future development and abandonment costs | | | | | (3,551) | | | | | | (1,338) | | | | | | (4,985) | | | | | | (1,591) | | | | | | (6,265) | | | | | | (2,362) | | | | | | (6,047) | | | | | | (2,629) | | | | | | (225) | | | | | | (28,993) | | | Future net inflow before income tax | | | | | 3,734 | | | | | | 755 | | | | | | 26,154 | | | | | | 24,495 | | | | | | 26,979 | | | | | | 25,834 | | | | | | 16,285 | | | | | | 3,689 | | | | | | 1,168 | | | | | | 129,093 | | | Future income tax | | | | | (796) | | | | | | (249) | | | | | | (13,632) | | | | | | (7,829) | | | | | | (9,926) | | | | | | (5,485) | | | | | | (11,379) | | | | | | (1,034) | | | | | | (143) | | | | | | (50,473) | | | Future net cash flows | | | | | 2,938 | | | | | | 506 | | | | | | 12,522 | | | | | | 16,666 | | | | | | 17,053 | | | | | | 20,349 | | | | | | 4,906 | | | | | | 2,655 | | | | | | 1,025 | | | | | | 78,620 | | | 10 % discount factor | | | | | (466) | | | | | | 63 | | | | | | (5,852) | | | | | | (5,822) | | | | | | (6,604) | | | | | | (10,832) | | | | | | (1,990) | | | | | | (1,187) | | | | | | (443) | | | | | | (33,133) | | | Standardized measure of discounted future net cash flows | | | | | 2,472 | | | | | | 569 | | | | | | 6,670 | | | | | | 10,844 | | | | | | 10,449 | | | | | | 9,517 | | | | | | 2,916 | | | | | | 1,468 | | | | | | 582 | | | | | | 45,487 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Future cash inflows | | | | | | | | | | | 25,094 | | | | | | 380 | | | | | | | | | | | | 1,787 | | | | | | | | | | | | | | | | | | 7,730 | | | | | | | | | | | | 34,991 | | | Future production costs | | | | | | | | | | | (6,953) | | | | | | (113) | | | | | | | | | | | | (863) | | | | | | | | | | | | | | | | | | (2,038) | | | | | | | | | | | | (9,967) | | | Future development and abandonment costs | | | | | | | | | | | (6,519) | | | | | | (23) | | | | | | | | | | | | (59) | | | | | | | | | | | | | | | | | | (145) | | | | | | | | | | | | (6,746) | | | Future net inflow before income tax | | | | | | | | | | | 11,622 | | | | | | 244 | | | | | | | | | | | | 865 | | | | | | | | | | | | | | | | | | 5,547 | | | | | | | | | | | | 18,278 | | | Future income tax | | | | | | | | | | | (7,020) | | | | | | (77) | | | | | | | | | | | | (225) | | | | | | | | | | | | | | | | | | (1,783) | | | | | | | | | | | | (9,105) | | | Future net cash flows | | | | | | | | | | | 4,602 | | | | | | 167 | | | | | | | | | | | | 640 | | | | | | | | | | | | | | | | | | 3,764 | | | | | | | | | | | | 9,173 | | | 10 % discount factor | | | | | | | | | | | (1,544) | | | | | | (88) | | | | | | | | | | | | (322) | | | | | | | | | | | | | | | | | | (1,809) | | | | | | | | | | | | (3,763) | | | Standardized measure of discounted future net cash flows | | | | | | | | | | | 3,058 | | | | | | 79 | | | | | | | | | | | | 318 | | | | | | | | | | | | | | | | | | 1,955 | | | | | | | | | | | | 5,410 | | | Total consolidated subsidiaries and equity-accounted entities | | | | | 2,472 | | | | | | 3,627 | | | | | | 6,749 | | | | | | 10,844 | | | | | | 10,767 | | | | | | 9,517 | | | | | | 2,916 | | | | | | 3,423 | | | | | | 582 | | | | | | 50,897 | | | |
December 31, 2018 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Future cash inflows | | | | | 18,372 | | | | | | 4,895 | | | | | | 43,578 | | | | | | 39,193 | | | | | | 53,534 | | | | | | 40,698 | | | | | | 33,384 | | | | | | 14,192 | | | | | | 2,319 | | | | | | 250,165 | | | Future production costs | | | | | (5,659) | | | | | | (1,438) | | | | | | (6,653) | | | | | | (12,193) | | | | | | (16,417) | | | | | | (8,276) | | | | | | (9,492) | | | | | | (6,038) | | | | | | (511) | | | | | | (66,677) | | | Future development and abandonment costs | | | | | (4,670) | | | | | | (1,350) | | | | | | (4,700) | | | | | | (2,769) | | | | | | (6,778) | | | | | | (2,640) | | | | | | (5,755) | | | | | | (2,467) | | | | | | (291) | | | | | | (31,420) | | | Future net inflow before income tax | | | | | 8,043 | | | | | | 2,107 | | | | | | 32,225 | | | | | | 24,231 | | | | | | 30,339 | | | | | | 29,782 | | | | | | 18,137 | | | | | | 5,687 | | | | | | 1,517 | | | | | | 152,068 | | | Future income tax | | | | | (1,671) | | | | | | (798) | | | | | | (17,514) | | | | | | (7,829) | | | | | | (11,566) | | | | | | (6,524) | | | | | | (11,980) | | | | | | (1,791) | | | | | | (289) | | | | | | (59,962) | | | Future net cash flows | | | | | 6,372 | | | | | | 1,309 | | | | | | 14,711 | | | | | | 16,402 | | | | | | 18,773 | | | | | | 23,258 | | | | | | 6,157 | | | | | | 3,896 | | | | | | 1,228 | | | | | | 92,106 | | | 10 % discount factor | | | | | (2,045) | | | | | | (124) | | | | | | (6,727) | | | | | | (6,564) | | | | | | (7,501) | | | | | | (12,477) | | | | | | (2,258) | | | | | | (1,508) | | | | | | (491) | | | | | | (39,695) | | | Standardized measure of discounted future net cash flows | | | | | 4,327 | | | | | | 1,185 | | | | | | 7,984 | | | | | | 9,838 | | | | | | 11,272 | | | | | | 10,781 | | | | | | 3,899 | | | | | | 2,388 | | | | | | 737 | | | | | | 52,411 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Future cash inflows | | | | | | | | | | | 18,608 | | | | | | 347 | | | | | | | | | | | | 2,675 | | | | | | | | | | | | | | | | | | 8,292 | | | | | | | | | | | | 29,922 | | | Future production costs | | | | | | | | | | | (4,686) | | | | | | (138) | | | | | | | | | | | | (873) | | | | | | | | | | | | | | | | | | (2,192) | | | | | | | | | | | | (7,889) | | | Future development and abandonment costs | | | | | | | | | | | (3,633) | | | | | | (3) | | | | | | | | | | | | (75) | | | | | | | | | | | | | | | | | | (191) | | | | | | | | | | | | (3,902) | | | Future net inflow before income tax | | | | | | | | | | | 10,289 | | | | | | 206 | | | | | | | | | | | | 1,727 | | | | | | | | | | | | | | | | | | 5,909 | | | | | | | | | | | | 18,131 | | | Future income tax | | | | | | | | | | | (6,822) | | | | | | (43) | | | | | | | | | | | | (204) | | | | | | | | | | | | | | | | | | (1,839) | | | | | | | | | | | | (8,908) | | | Future net cash flows | | | | | | | | | | | 3,467 | | | | | | 163 | | | | | | | | | | | | 1,523 | | | | | | | | | | | | | | | | | | 4,070 | | | | | | | | | | | | 9,223 | | | 10 % discount factor | | | | | | | | | | | (1,104) | | | | | | (76) | | | | | | | | | | | | (793) | | | | | | | | | | | | | | | | | | (2,009) | | | | | | | | | | | | (3,982) | | | Standardized measure of discounted future net cash flows | | | | | | | | | | | 2,363 | | | | | | 87 | | | | | | | | | | | | 730 | | | | | | | | | | | | | | | | | | 2,061 | | | | | | | | | | | | 5,241 | | | Total consolidated subsidiaries and equity-accounted entities | | | | | 4,327 | | | | | | 3,548 | | | | | | 8,071 | | | | | | 9,838 | | | | | | 12,002 | | | | | | 10,781 | | | | | | 3,899 | | | | | | 4,449 | | | | | | 737 | | | | | | 57,652 | | | |
December 31, 2017 | | | Italy | | | Rest of Europe | | | North Africa | | | Egypt | | | Sub - Saharan Africa | | | Kazakhstan | | | Rest of Asia | | | America | | | Australia and Oceania | | | Total | | Consolidated subsidiaries | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Future cash inflows | | | | | 14,339 | | | | | | 19,507 | | | | | | 31,793 | | | | | | 29,156 | | | | | | 41,136 | | | | | | 30,263 | | | | | | 11,826 | | | | | | 6,205 | | | | | | 2,593 | | | | | | 186,818 | | | Future production costs | | | | | (5,091) | | | | | | (5,711) | | | | | | (6,677) | | | | | | (6,153) | | | | | | (14,790) | | | | | | (6,992) | | | | | | (3,653) | | | | | | (2,351) | | | | | | (590) | | | | | | (52,008) | | | Future development and abandonment costs | | | | | (3,943) | | | | | | (5,483) | | | | | | (4,350) | | | | | | (4,496) | | | | | | (6,522) | | | | | | (2,787) | | | | | | (3,694) | | | | | | (1,011) | | | | | | (318) | | | | | | (32,604) | | | Future net inflow before income tax | | | | | 5,305 | | | | | | 8,313 | | | | | | 20,766 | | | | | | 18,507 | | | | | | 19,824 | | | | | | 20,484 | | | | | | 4,479 | | | | | | 2,843 | | | | | | 1,685 | | | | | | 102,206 | | | Future income tax | | | | | (859) | | | | | | (4,490) | | | | | | (10,836) | | | | | | (5,709) | | | | | | (6,418) | | | | | | (3,970) | | | | | | (757) | | | | | | (699) | | | | | | (303) | | | | | | (34,041) | | | Future net cash flows | | | | | 4,446 | | | | | | 3,823 | | | | | | 9,930 | | | | | | 12,798 | | | | | | 13,406 | | | | | | 16,514 | | | | | | 3,722 | | | | | | 2,144 | | | | | | 1,382 | | | | | | 68,165 | | | 10 % discount factor | | | | | (1,633) | | | | | | (1,050) | | | | | | (4,566) | | | | | | (6,698) | | | | | | (5,430) | | | | | | (9,172) | | | | | | (1,239) | | | | | | (777) | | | | | | (607) | | | | | | (31,172) | | | Standardized measure of discounted future net cash flows | | | | | 2,813 | | | | | | 2,773 | | | | | | 5,364 | | | | | | 6,100 | | | | | | 7,976 | | | | | | 7,342 | | | | | | 2,483 | | | | | | 1,367 | | | | | | 775 | | | | | | 36,993 | | | Equity-accounted entities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Future cash inflows | | | | | | | | | | | | | | | | | 245 | | | | | | | | | | | | 2,062 | | | | | | | | | | | | 11 | | | | | | 10,797 | | | | | | | | | | | | 13,115 | | | Future production costs | | | | | | | | | | | | | | | | | (119) | | | | | | | | | | | | (930) | | | | | | | | | | | | (6) | | | | | | (3,291) | | | | | | | | | | | | (4,346) | | | Future development and abandonment costs | | | | | | | | | | | | | | | | | (1) | | | | | | | | | | | | (66) | | | | | | | | | | | | | | | | | | (535) | | | | | | | | | | | | (602) | | | Future net inflow before income tax | | | | | | | | | | | | | | | | | 125 | | | | | | | | | | | | 1,066 | | | | | | | | | | | | 5 | | | | | | 6,971 | | | | | | | | | | | | 8,167 | | | Future income tax | | | | | | | | | | | | | | | | | (21) | | | | | | | | | | | | (57) | | | | | | | | | | | | (1) | | | | | | (2,459) | | | | | | | | | | | | (2,538) | | | Future net cash flows | | | | | | | | | | | | | | | | | 104 | | | | | | | | | | | | 1,009 | | | | | | | | | | | | 4 | | | | | | 4,512 | | | | | | | | | | | | 5,629 | | | 10 % discount factor | | | | | | | | | | | | | | | | | (50) | | | | | | | | | | | | (471) | | | | | | | | | | | | | | | | | | (2,475) | | | | | | | | | | | | (2,996) | | | Standardized measure of discounted future net cash flows | | | | | | | | | | | | | | | | | 54 | | | | | | | | | | | | 538 | | | | | | | | | | | | 4 | | | | | | 2,037 | | | | | | | | | | | | 2,633 | | | Total consolidated subsidiaries and equity-accounted entities | | | | | 2,813 | | | | | | 2,773 | | | | | | 5,418 | | | | | | 6,100 | | | | | | 8,514 | | | | | | 7,342 | | | | | | 2,487 | | | | | | 3,404 | | | | | | 775 | | | | | | 39,626 | | | |
Changes in standardized measure of discounted future net cash flows Changes in standardized measure of discounted future net cash flows for the years ended December 31, 2014, 20152019, 2018 and 2016,2017, are as follows: (€ million) | | | | | | | | | | | | | | | | | | | | | Consolidated subsidiaries | | Equity- accounted entities | | Total | | | Standardized measure of discounted future net cash flows at December 31, 2013 | | | | 56,177 | | | | | 2,327 | | | | | 58,504 | | | | 2019 | | | Consolidated subsidiaries | | Equity- accounted entities | | Total | | Standardized measure of discounted future net cash flows at December 31, 2018 | | | | | 52,411 | | | | | 5,241 | | | | | 57,652 | | | Increase (Decrease): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | - sales, net of production costs | | | | (21,795) | | | | | (192) | | | | | (21,987) | | | | | | (18,236) | | | | | (1,675) | | | | | (19,911) | | | - net changes in sales and transfer prices, net of production costs | | | | (12,053) | | | | | (500) | | | | | (12,553) | | | | | | (14,972) | | | | | (2,247) | | | | | (17,219) | | | - extensions, discoveries and improved recovery, net of future production and development costs | | | | 1,667 | | | | | | | | | | 1,667 | | | | | | 1,240 | | | | | 86 | | | | | 1,326 | | | - changes in estimated future development and abandonment costs | | | | (6,047) | | | | | 223 | | | | | (5,824) | | | | | | (1,157) | | | | | (916) | | | | | (2,073) | | | - development costs incurred during the period that reduced future development costs | | | | 8,745 | | | | | 451 | | | | | 9,196 | | | | | | 5,128 | | | | | 687 | | | | | 5,815 | | | - revisions of quantity estimates | | | | 8,085 | | | | | (325) | | | | | 7,760 | | | | | | 5,573 | | | | | 1,377 | | | | | 6,950 | | | - accretion of discount | | | | 11,064 | | | | | 512 | | | | | 11,576 | | | | | | 8,666 | | | | | 1,050 | | | | | 9,716 | | | - net change in income taxes | | | | 7,049 | | | | | 704 | | | | | 7,753 | | | | | | 6,013 | | | | | (761) | | | | | 5,252 | | | - purchase of reserves in-place | | | | 67 | | | | | | | | | | 67 | | | | | | 260 | | | | | 2,579 | | | | | 2,839 | | | - sale of reserves in-place | | | | (271) | | | | | | | | | | (271) | | | | - sale of reserves in-place(a) | | | | | (429) | | | | | (88) | | | | | (517) | | | - changes in production rates (timing) and other | | | | 3,347 | | | | | 358 | | | | | 3,705 | | | | | | 990 | | | | | 77 | | | | | 1,067 | | | Net increase (decrease) | | | | (142) | | | | | 1,231 | | | | | 1,089 | | | | | | (6,924) | | | | | 169 | | | ��� | | | (6,755) | | | 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 | | | | | | Standardized measure of discounted future net cash flows at December 31, 2019 | | | | | 45,487 | | | | | 5,410 | | | | | 50,897 | | |
(a)
Includes volume as part of a long-term supply agreement to a state-owned national oil company, whereby the buyer has paid the price without lifting the underlying volume in exercise of the take-or-pay clause because it is very likely that the buyer will not redeem its contractual right to lift (make up) the volume paid.
2018 | | | Consolidated subsidiaries | | | Equity- accounted entities | | | Total | | Standardized measure of discounted future net cash flows at December 31, 2017 | | | | | 36,993 | | | | | | 2,633 | | | | | | 39,626 | | | Increase (Decrease): | | | | | | | | | | | | | | | | | | | | - sales, net of production costs | | | | | (19,793) | | | | | | (445) | | | | | | (20,238) | | | - net changes in sales and transfer prices, net of production costs | | | | | 27,970 | | | | | | 671 | | | | | | 28,641 | | | - extensions, discoveries and improved recovery, net of future production and development costs | | | | | 1,649 | | | | | | | | | | | | 1,649 | | | - changes in estimated future development and abandonment costs | | | | | (2,525) | | | | | | 216 | | | | | | (2,309) | | | - development costs incurred during the period that reduced future development costs | | | | | 6,468 | | | | | | 14 | | | | | | 6,482 | | | - revisions of quantity estimates | | | | | 10,487 | | | | | | (803) | | | | | | 9,684 | | | - accretion of discount | | | | | 5,670 | | | | | | 384 | | | | | | 6,054 | | | - net change in income taxes | | | | | (16,566) | | | | | | 193 | | | | | | (16,373) | | | - purchase of reserves in-place | | | | | 5,369 | | | | | | 6,700 | | | | | | 12,069 | | | - sale of reserves in-place | | | | | (8,363) | | | | | | | | | | | | (8,363) | | | - changes in production rates (timing) and other | | | | | 5,052 | | | | | | (4,322) | | | | | | 730 | | | Net increase (decrease) | | | | | 15,418 | | | | | | 2,608 | | | | | | 18,026 | | | Standardized measure of discounted future net cash flows at December 31, 2018 | | | | | 52,411 | | | | | | 5,241 | | | | | | 57,652 | | | |
2017 | | | Consolidated subsidiaries | | | Equity- accounted entities | | | Total | | Standardized measure of discounted future net cash flows at December 31, 2016 | | | | | 26,717 | | | | | | 3,121 | | | | | | 29,838 | | | Increase (Decrease): | | | | | | | | | | | | | | | | | | | | - sales, net of production costs | | | | | (14,125) | | | | | | (432) | | | | | | (14,557) | | | - net changes in sales and transfer prices, net of production costs | | | | | 23,940 | | | | | | 1,482 | | | | | | 25,422 | | | - extensions, discoveries and improved recovery, net of future production and development costs | | | | | 1,697 | | | | | | | | | | | | 1,697 | | | - changes in estimated future development and abandonment costs | | | | | (2,817) | | | | | | 495 | | | | | | (2,322) | | | - development costs incurred during the period that reduced future development costs | | | | | 7,203 | | | | | | 45 | | | | | | 7,248 | | | - revisions of quantity estimates | | | | | 5,269 | | | | | | (2,285) | | | | | | 2,984 | | | - accretion of discount | | | | | 3,864 | | | | | | 438 | | | | | | 4,302 | | | - net change in income taxes | | | | | (6,498) | | | | | | 238 | | | | | | (6,260) | | | - purchase of reserves in-place | | | | | 10 | | | | | | | | | | | | 10 | | | - sale of reserves in-place | | | | | (2,995) | | | | | | | | | | | | (2,995) | | | - changes in production rates (timing) and other | | | | | (5,272) | | | | | | (469) | | | | | | (5,741) | | | Net increase (decrease) | | | | | 10,276 | | | | | | (488) | | | | | | 9,788 | | | Standardized measure of discounted future net cash flows at December 31, 2017 | | | | | 36,993 | | | | | | 2,633 | | | | | | 39,626 | | |
SIGNATURES The registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized. Date: March 22, 2017 | Eni SpA | | | /s/ Andrea Simoni | | | | | | Andrea Simoni | | | Title: Executive Vice President Accounting and Financial Statements Department | | April 2, 2020Eni SpA F-155/s/ MASSIMO MONDAZZI
Massimo Mondazzi Title: Chief Financial Officer
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