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Highlights and outlook
Upstream

  • Continuing strong exploration track record: discovered 1.1 billion boe of additional resources at a cost of 0.6 $/boe. Additions to the Company’s resources backlog of 3.4 billion boe in the latest 3 years, at a cost of 1 $/boe. Promising new prospects to be drilled in future years
  • Divested a 40% interest in Zohr, proving the effectiveness of our dual exploration model
  • Organic reserves replacement ratio surged to 193%, the best ever performance in Eni’s history. The 2016 reserves replacement ratio remains very robust at 139%, also considering the 40% sale of Zohr on a pro forma basis
  • Kashagan and Goliat in production
  • 2016 hydrocarbon production: 1.76 million boe/d in the year, in line with 2015, despite the Val d’Agri shutdown; 1.86 million boe/d in the quarter (down by 1.5%)
  • Progressed construction activities at our development projects expected to come on stream in 2017(Jangkrik - Indonesia, OCTP oil - Ghana and Zohr - Egypt). In February, started-up the East Hub project in Angola, five months earlier than scheduled. These projects, together with the ramp-up of 2016 new production from Kashagan and Goliat, will strongly contribute to the cash generation in 2017 and following years
  • Opex efficiency above expectations at 6.2 $/boe compared to 7.2 $/boe in 2015

G&P

  • Confirmed the goal of structural breakeven from 2017 owing also to the already achieved gas contract renegotiations and reductions in logistic costs

R&M and Chemicals

  • Refinery breakeven margin reduced to 4.2 $/bl (compared with 5.2 $/bl in 2015)
  • Green refinery projects on schedule
  • The Chemical business Ebit1 of €300 million in 2016 reflects the success of the segment’s restructuring

 

Consolidated financial results 2

  • Strong cash generation in the fourth quarter of €3.2 billion
  • FY normalized cash flow from operations3 of €8.3 billion, covering 95% of capex4 in an unfavorable oil price environment (Brent at 44 $/bl)
  • Improved prospects of organic production growth over the next four years notwithstanding a 19% capex reduction y-o-y
  • All mid-downstream businesses cash positive this year
  • Fourth quarter consolidated adjusted operating profit at €1.29 billion, up by 103% from the fourth quarter of 2015
  • FY adjusted operating profit of €2.32 billion, down by €2.17 billion (or 48%), due to the unfavorable oil price environment (-€3.3 billion) and the Val d’Agri shutdown. Efficiency measures and lower costs help to offset the effect of the low oil price by €1.7 billion
  • Fourth quarter consolidated net adjusted profit of €0.46 billion founded on a robust upstream recovery. FY adjusted net result roughly at breakeven (-€0.34 billion)
  • Disposals closed/agreed this year of €2.6 billion, approximately 40% of the 2016-2019 four-year target of €7 billion, announced in March 2016
  • Net debt reduced to €14.8 billion, equating to a leverage ratio of 0.28. Pro-forma leverage ratio to include 40% Zohr disposal at 0.24

2016 dividend: €0.80 of which €0.40 already paid as interim dividend

 


Claudio Descalzi, Eni’s Chief Executive Officer, commented:

"The 2016 results mark the successful conclusion of a radical transformation process. Over the past three years, Eni has restructured to withstand one of the most complex environments in the history of the oil industry, while strengthening its growth prospects and preserving a robust balance sheet. Our future growth trajectory will leverage on the key achievements made in this period: a strong production in Q4 of 1.86 million boe/d, our record proved reserve replacement ratio, a well-stocked pipeline of new, high quality projects which will contribute to an expected production growth rate of 3% on average in the next four-year period, and the advanced restructuring of our middownstream businesses. The solidity of our balance sheet has been preserved by maintaining a sustainable level of gearing, while Eni has been the only Major to reduce its leverage during the 2014-2016 period. In light of these achievements, we intend to propose at the next Annual General Shareholders Meeting the distribution of a cash dividend of €0.8 per share in 2016. Looking to the future, we are able to reaffirm our progressive remuneration policy, in line with the expected improvement of commodity prices and our own financial performance."

 

SUMMARY GROUP RESULTS (A)Fourth Quarter Third Quarter Fourth Quarter % Ch.
IV Q. 16
vs. IV Q. 15
         Full year(€ million)20152016201620152016% Ch.6342581,286102.8Adjusted operating profit (loss) (b)4,4862,315(48.4)(301)(484)459..Adjusted net profit (loss) (b803(340)..3,9641,3253,248(18.1)Net cash provided by operating activities (b)12,1557,673(36.9)(8,454)(562)340104.0Net profit (loss) from continuing operations(7,952)(1,051)..(2.35)(0.16)0.09 - per share (€) (c)(2.21)(0.29) (5.15)(0.36)0.19 - per ADR ($) (c)(d)(4.91)(0.64) (8,723)(562)340103.9Group net profit (loss)(8,778)(1,464)..(2.42)(0.16)0.09 - per share (€) (c)(2.44)(0.41) (5.30)(0.36)0.19 - per ADR ($) (c)(d)(5.42)(0.91)  (a) Attributable to Eni's shareholders. 
(b) From continuing operations, The comparative reporting period are calculated on a standalone basis, They reinstate the elimination of gains and losses on intercompany transactions with the E&C sector classified as discontinued operations under the IFRS 5. until Eni lost control following the closing of the divestment transaction in January 2016. 
(c) Fully diluted, Dollar amounts are converted on the basis of the average EUR/USD exchange rate quoted by the ECB for the periods presented, 
(d) One ADR (American Depositary Receipt) is equal to two Eni ordinary shares.


Adjusted results

In the fourth quarter of 2016, Eni reported an adjusted operating profit of €1.29 billion, up by 103% or €0.65 billion quarter-on-quarter, reversing the negative trend of the previous quarters, thanks to doubling in the E&P operating performance to €1.4 billion (up by €0.8 billion). The E&P improvement was driven mainly by efficiency and optimization measures (up by €0.7 billion) and by a marginal recovery in the oil scenario (the Brent benchmark was up by 13.2%), which has yet to be fully reflected in gas prices which were down due to the time lags in oil-linked price formulas. These increases were partly offset by lower non-recurring gains in the G&P segment. 
On the minus side, the G&P segment reported an adjusted operating loss of €72 million, compared to a profit of €18 million in the fourth quarter of 2015, which was negatively affected by an unfavourable trading environment, particularly in the LNG business, as well as by lower non-recurring gains and higher operating charges. The Refining & Marketing and Chemical segment reported lower results (down by €59 million or 44%) due to competitive pressures, a less favourable refining and commodity environment y-o-y and the negative impact of the shutdown of the EST conversion plant following the accident occurred in December 2016. These negatives were partly counteracted by cost efficiencies and optimization gains. 
After five quarters affected by the downturn in oil prices, the fourth quarter of 2016 saw the Group revert to a net profit of €0.46 billion, compared to a net loss of €0.3 billion in the fourth quarter of 2015. This recovery reflected an improved operating performance and a material reduction in the adjusted tax rate to 58% from about 168% in the fourth quarter of 2015. 
For the FY2016, adjusted operating profit of €2.32 billion was down by €2.2 billion y-o-y, or 48%. 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. By contrast, efficiency gains and a reduced cost base, mainly in the E&P segment, improved the performance by €1.7 billion. 
Adjusted net loss for the FY2016 amounted to €0.34 billion, lower by €1.14 billion from the adjusted net profit of 2015 (€0.8 billion). This was due to a lowered operating performance, declining results from equity-accounted entities reflecting a weaker oil price scenario and a higher tax rate (up by 38 percentage points). The latter point reflected the recording of a tax rate as high as 100% in the first nine months of the year due to the oil downturn, which determined a larger relative weight of taxable profit earned under PSA schemes, which are characterized by higher-than-average rates of taxes. Furthermore, the Group tax rate was negatively affected by the classification as special items of the reversals of certain deferred tax assets, which were written down in the previous reporting period.

 

Net borrowings and cash flow

As of December 31, 2016, net borrowings5 were €14.78 billion, €2.09 billion lower than December 31, 2015. The reduction reflected an increase in cash flow from operating activities (€7.67 billion), the closing of the Saipem transaction with net proceeds of €5.2 billion and other asset divestments for €0.6 billion, which comprised the available-for-sale shareholding in Snam due to the exercise of the conversion right from bondholders and marketing activities of fuels in Eastern Europe. These inflows funded capital expenditure of the year (€9.2 billion) and the payment of the final dividend 2015 and the 2016 interim dividend to Eni’s shareholders (for a total amount of €2.88 billion). The reduction in net borrowings was also due to other inflows relating to investing activities (€0.3 billion) and the fact that the financial assets (€0.57 billion) held by the Group insurance company are no longer committed to funding the loss provisions and therefore have been netted against finance debt in determining the Group’s net borrowings. These positives were offset by negative change in fair value of securities held for trading (down €0.3 billion) which are netted against net borrowings. A normalized measure of the cash flow from operating activities was €8.3 billion, calculated by excluding the negative effect of the Val d’Agri shutdown (€0.2 billion), a reclassification of certain receivables for investing activities to trading receivables (€0.3 billion), while including changes in working capital due to the sale of a 40% interest in Zohr (€0.1 billion). This normalized cash flow funded approximatly 95% of the capex of the year, which reduced from €9.2 billion to €8.7 billion when deducting the expected reimbursement of past capex related to the divestment of a 40% interest in the Zohr project (€0.5 billion).
Cash flow from operations was also influenced by a larger amount of receivables due beyond the end of the reporting period, being transferred to financing institutions compared to the amount sold at the end of the previous reporting period (approximately €1 billion).
Compared to September 30, 2016, net borrowings decreased by €1.23 billion due to the robust cash generation of the fourth quarter of €3.25 billion, which funded capital expenditure of the period (€2.25 billion) generating a surplus. A larger amount of receivables due beyond the end of the reporting period were sold to financing institutions compared to the amount sold at the end of the previous reporting period by approximately €700 million.

As of December 31, 2016, the ratio of net borrowings to shareholders’ equity including non-controlling interest – leverage6 – decreased to 0.28, compared to 0.29 as of December 31, 2015. This change was due to lower net borrowings which offset a €4 billion reduction in total equity, driven by the negative result of the period, the derecognition of the Saipem non-controlling interest and dividend distributions to Eni shareholders. 
It is worth mentioning the recovery in Group leverage to 0.28 from 0.32 on September 30, 2016, due to the robust cash generation of the fourth quarter 2016 and the increase in total equity driven by the positive result of the period and positive foreign currency translation differences (approximately €2.3 billion).

 

2016 Dividend distribution

The Board of Directors intends to submit a proposal for distributing a dividend of €0.80 per share7 (€0.80 in 2015) at the Annual Shareholders’ Meeting convened for April 13, 2017. Included in this annual payment is €0.40 per share paid as interim dividend in September 2016. The balance of €0.40 per share is payable to shareholders on April 26, 2017, the ex-dividend date being April 24, 2017.

 

Zohr operation

Eni signed two agreements with Bp and Rosneft for the disposal of a 40% interest in the giant discovery Zohr, located in the operated block of Shoruk (Eni 100%) off Egypt. These transactions confirm the effectiveness of Eni’s “dual exploration model”, which simultaneously targets the fast-track development of discovered resources, while reducing stakes retained in exploration leases in order to monetize in advance part of the discovered volumes and reduce expenditures in development process. 
These agreements have economic efficacy from January 1, 2016 and contemplate the reimbursement to Eni of capex incurred until the closing date. The new partners have the option to acquire a further 5% stake at the same terms defined in the agreements. 
The first transaction closed on February 2017 following approval by the Egyptian authorities; the second one is expected to close by the first half of 2017. The total consideration of the deal amounts to approximately €2 billion as of January 1, 2017, including the reimbursement of costs incurred by Eni in 2016.

 

Business developments:

2017

  • February 2017: started-up the Cabaça South East field of the East Hub Development Project, in Block 15/06 of the Angolan deep offshore, five months ahead of development plan estimates and with a time-to-market among the best in the sector. Block 15/06 will reach a peak of 150,000 barrels of oil per day this year.
  • January 2017: successfully drilled an appraisal well of the Merakes discovery under the Production Sharing Contract (PSC) in East Sepinggan. This discovery is located 35 kilometers from the Eni-operated Jangkrik field, close to starting operations, is estimated to have 2.0 Tcf of gas in place with additional potential still to be evaluated.         
  • January 2017: made a discovery in the PL128/128D licenses in the Norwegian Sea nearby the FPSO (Floating Production, Storage and Offloading) operating the Norne field. Volumes of oil in place are expected to range from 70 to 200 million barrels. This discovery is part of Eni’s near-field exploration strategy aimed at unlocking the presence of additional resources in proximity to existing infrastructures.
  • January 2017: awarded three new exploration licenses in Norway, as a part of the APA Round.
  • January 2017: signed a Memorandum of Understanding with the Nigerian Authorities for the development of the mineral potential of the Country. The agreement also comprises the upgrading of the Port Harcourt refinery and a capacity doubling of the power generation unit in Okpai IPP.

2016

  • November 2016: signed four agreements in Bahrein with the National Oil Companies for the evaluation of the mineral potential of certain exploration areas and for the study of the Awali fields.
  • October 2016: signed a binding agreement between the partners of the Area 4 in Mozambique (Eni East Africa, joint operation between Eni and CNPC, Galp, Kogas and ENH) and BP for the sale, over a 20-year period, of approximately 3.3 million tons of LNG per annum (corresponding to about 5 bcm), which will be produced at the Coral South Floating facility. The agreement, approved by the Government of Mozambique, is a fundamental step towards achieving the Final Investment Decision (FID) of the project. The achievement of the FID is prerequisite to the efficacy of the sale contract. Back in February 2016, the Mozambique authorities approved the first development phase of Coral, targeting production of 5 trillion cubic feet (TCF) of gas.
  • October 2016: restarted production at the Kashagan giant field following completion of the operations to replace certain auxiliary pipelines which were put out of order due to a gas leakage. The original damage, which occurred at the end of 2013, forced the Consortium to shut down the oilfield. The Consortium is targeting an initial plateau of 185 kbbl/d and from there to ramp up to 370 kbbl/d by the end of 2017.
  • September 2016: as part of Eni’s “near-field” exploration strategy, activities resumed onshore Tunisia with the Larich East discovery. The well yielded approximately 2 kbbl/d during test production and has been put into production by linking the discovery well to the MLD oil treatment center.
  • September 2016: reached a production plateau of 700 mmcf/d (corresponding to 128 kboe/d, 67 kboe/d net to Eni) from the Nooros field. This record-setting production level was reached in just 13 months after the discovery and ahead of schedule, thanks to the success of the latest exploration wells drilled in the ​​Nooros area and the drilling of new development wells. The production is currently flowing from 7 wells; furthermore, with the drilling of additional development wells, the field is expected to reach a maximum production capacity of about 160 kboe/d in 2017. In addition, thanks to the mature operating environment and the conventional nature of the project, production costs are among the lowest in Eni’s portfolio.
  • September 2016: the potential at the Baltim South West field discovery, in the conventional water of Egypt, was upped to 1 TCF of gas in place due to successful test of the first appraisal well. The discovery is located near the Nooros field and has increased the relevant gas potential of the so-called “Great Nooros Area” to 3 TCF of gas in place, of which about 2 TCF are in the Nooros field, while the remaining are in the new independent discovery of Baltim South West.
  • September 2016: successfully drilled the Zohr 5x appraisal well, located in 1,538 meters of water depth and 12 kilometers south west from the discovery well. The appraisal well confirmed the overall potential of the Zohr Field, estimated to retain 30 TCF of gas in place and produced more than 50 mmcf/d during a test, which was constrained by limits of the surface infrastructures. The Zohr development was sanctioned by Egyptian authorities in February 2016. Expected the drilling of a sixth well that will accelerate the production start-up within the end of 2017.
  • March 2016: production start-up at the Goliat oilfield, which is the first producing oilfield in the Barents Sea in the license PL229. Goliat is operated through the largest and most sophisticated floating cylindrical production and storage vessel (FPSO) in the world. Production has achieved the full-field plateau at 100 kbbl/d (65 kbbl/d net to Eni). The field is estimated to contain reserves amounting to about 180 million barrels of oil.
  • In 2016, Eni increased its exploration rights portfolio by about 10,500 square kilometers net, mainly in Egypt, Ghana, Morocco, Montenegro, Norway and the United Kingdom.

 

SUSTAINABILITY PERFORMANCES  Full year  20152016 % Ch.Total recordable injury rate (TRIR)(total recordable injury rate/worked hours) x 1,000,0000.450.35(20.8)Direct GHG emissions (mmtonnes CO2 eq,)41.640.1(3.5)- of which CO2 from combustion and process 31.530.6(2.8)- of which CO2 eq from methane 2.82.4(12.4)- of which CO2 eq from flaring   5.55.4(2.0)- of which CO2 eq from venting   1.81.7(7.2)Direct GHG emissions E&P/production(tonnes CO2 eq,/toe)0.180.17(8.7)Oil spills due to operations (>1 barrel)(barrels) 1,6341,159(29.1)Water reinjection(%)56583.9

 

Eni reported positive performances when comparing to the corresponding period of 2015:

  • GHG emissions recorded in 2016 declined by 3.5% compared to the 2015. Higher emissions recorded in the G&P segment, reflected higher power production and increasing gas volumes transported. Lower emissions from combustion and process were recorded (down 1.8 mmtonnes CO2eq) and reduced methane emissions (down 0.4 mmtonnes CO2eq) in the upstream segment. These were achieved leveraging on energy efficiency projects (gas consumption reduction and logistics optimization) and ongoing initiatives to contain fugitive emissions developed for the 2016 in Egypt, Kazakhstan, UK, Ecuador and USA. In March 2016, the Goliat platform started-up, through advanced technology solutions (power supply by undersea cables connected to the ground) thus contributing to the containment of emissions from combustion.
  • The trend of GHG emission index compared to operated gross hydrocarbon production of the upstream segment remain positive with a reduction of 8.7%. This performance is better than the guided 2016 full year target.
  • In 2016 the trend in safety improvement continued, reporting a lower total recordable injury rate (TRIR), down by 20.8% from the 2015. This result reflected a better performance for both employees and contractors (down by 10.8% and 25.2% respectively). This positive performance leveraged on inspections on sites, HSE audit processes on suppliers, employment in industrial sites of people trained at the Safety Competence Center in Gela as well as specific training projects and programs to raise awareness of HSEQ issues as “Eni in Safety” new phase finalized to spread over the company the near miss and incident lessons learnt.
  • Oil spills due to operations (88% related to E&P segment and 12% to R&M and Chemicals) declined by 29.1% from 2015; E&P recorded the best improvement in Nigeria due to the revamping of industrial installations; the Refining & Marketing and Chemicals segment reduced the overall volume spilled (down by 290 barrels compared to 2015).
  • Water reinjections reached the threshold of 58%, due to the contribution of Ecuador, Egypt and Congo (for the latter the best contribution came from Mboundi field and since July 2016 Loango field after the revamping activities).

Renewable energies and climate change

As part of its strategy designed to evolve the Company’s business model towards a low-carbon environment, Eni intends to develop renewable energy projects in its countries of operations. In 2016, Eni selected and launched a number of industrial initiatives on a large scale in Italy and abroad.
- The “Italy project” plans to build facilities, mainly in the solar photovoltaic business, in owned industrial areas, which are ready to use and currently lack any industrial value. Fifteen projects have been identified with an overall capacity of approximately 220 MW to be installed by 2022. The first phase of the project foresees the installation of five units: Assemini and Porto Torres in Sardinia (obtained the Final Investment Decision for both projects, while the approval is ongoing from the relevant authorities), Manfredonia in Puglia and Priolo in Sicily (FID obtained) and finally Augusta in Sicily. 
- Outside Italy the company has identified a number of projects to be deployed in countries of operations considered strategic for the Company (mainly Africa and Asia) to increase Eni’s energy efficiency, the sustainability of our consumptions, as well as to improve the access to energy of local communities through a more sustainable energy mix. In December 2016 Eni obtained the FID for a development project in the upstream field BRN in Algeria.
Futhermore, a number of agreements for collaboration have been settled with Ghana, Algeria and Tunisia, to strengthen Eni’s presence in these countries and to enlarge the scope of activities.

Finally, in 2016 Eni signed strategic framework agreements with:

  • General Electric (GE) for the development of innovative technologies on renewable energy projects (brownfield and greenfield) and hybrid renewable projects focused on energy efficiency. This agreement is intended to identify and develop jointly projects for power generation from renewable sources on large scale;
  • Terna for the evaluation of opportunities for the development of energy systems with a focus on sustainability and supporting production from renewables.

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

 

Outlook

The Group financial outlook, its business prospects and the key industrial and profitability targets in the short and medium term are disclosed in the press release “Eni’s strategic plan 2017-2020”, which will be issued later today, available on the Company’s website eni.com and publicly disseminated as required by applicable listing standards.

This press release on the results of the full year and the fourth quarter 2016 has been prepared on a voluntary basis according to article 82-ter, Regulations on issuers (Consob Regulation No. 11971 of May 14, 1999 and subsequent amendments and inclusions). The disclosure of results and business trends on a quarterly basis is consistent with Eni’s policy to provide the market and investors with regular information about the Company’s financial and industrial performances and business prospects considering the reporting policy followed by oil&gas peers who are communicating results each quarter. Instead, the discussion about the full year results and performance of the Group complies with the listing standards set by the Italian Exchange (“Borsa Italiana”) with regard to the minimum set of disclosures of press release about the approval of statutory financial statements by listed companies’ boards.
Results and cash flow are presented for the fourth and the third quarter of 2016 and the full year of 2016, for the fourth quarter and the full year of 2015. Information on the Company’s financial position relates to end of the periods as of December 31, 2016, September 30, 2016 and December 31, 2015. Accounts set forth herein have been prepared in accordance with the evaluation and recognition criteria set by the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board (IASB) and adopted by the European Commission according to the procedure set forth in Article 6 of the European Regulation (CE) No. 1606/2002 of the European Parliament and European Council of July 19, 2002. These criteria are unchanged from the Interim Consolidated Financial Report as of June 30, 2016, which investors are urged to read.

 

Continuing and discontinued operations in Eni’s financial statements 2016
Effective January 1, 2016, Eni Group is no more engaged in the Engineering & Construction segment (“E&C”), following the closing of the sale of a 12.503% stake in Saipem SpA to CDP Equity SpA on January 22, 2016. Concurrently, a shareholder agreement between Eni and CDP Equity SpA 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. The retained interest of 30.55% in the former subsidiary has been recognized as an investment in an equity-accounted joint venture with an initial carrying amount aligned to the share price at the closing date of the transaction (€4.2 per share, equal to €564 million) recognizing a loss through profit of €441 million. Considering the pro-quota share capital increase of Saipem subscribed by Eni, the initial carrying amount of the investment amounted to €1,614 million. At the end of February 2016, Saipem reimbursed intercompany loans owed to Eni (€5,818 million as of December 31, 2015) by using the proceeds from the share capital increase and new credit facilities from third-party financing institutions.

Eni’s Chemical business, managed by the wholly-owned subsidiary Versalis, has been reclassified as continuing operations, with retroactive effects as of December 31, 2015. In accordance with IFRS 5, Versalis has ceased to be classified as discontinued operations due to termination of the negotiations with US-based SK hedge fund, who had shown an interest in acquiring a majority stake in Versalis. Eni’s Annual Report 2015 was prepared accounting this business as discontinued operations. Consequently, Eni’s management reinstated 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. Conversely, under IFRS 5 Versalis was measured at the lower of its carrying amount and fair value less cost to sell. This amendment in Versalis evaluation marginally affected the opening balance of Eni’s consolidated net assets (an increase of €294 million) and was neutral on the Group’s net financial position. For more information about the criteria of the continuing use to evaluate Versalis in Eni consolidated accounts 2016, see Eni Interim Consolidated Report as of June 30, 2016 (the section Basis of preparation in Notes to the Consolidated Interim Financial Statements). The results of Versalis have been aggregated with those of R&M, in the reportable segment “R&M and Chemicals” because the two segments exhibit similar economic characteristics.

 

Successful effort method (SEM) 
Effective January 1, 2016, management modified on voluntary basis, the criterion to recognize exploration expenses adopting the accounting of the successful-effort-method (SEM). The successful-effort method is largely adopted by oil&gas companies, to which Eni is increasingly comparable given the recent re-focalization of the Group activities on its core upstream business. 
Under the SEM, geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are initially capitalized as an unproved tangible asset until the drilling of the well is complete and 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 SEM application is a voluntary change in accounting policy explained by the alignment with an accounting standard largely adopted by oil&gas companies and as such it has been applied retrospectively.
The retrospective application of the SEM has required adjustment of the opening balance of the retained earnings and other comparative amounts as of January 1, 2014. Specifically, the opening balance of the carrying amount of property, plant and equipment was increased by €3,524 million, intangible assets by €860 million and the retained earnings by €3,001 million. Other adjustments related to deferred tax liabilities and other minor line items. More details are available on the “Basis of presentation” in the “Notes to the Consolidated Financial Statements” of Eni’s Interim Consolidated Report as of June 30, 2016.

The table below sets forth the amounts of the comparative periods 2015 which have been restated following the adoption of the SEM and the accounting of Versalis as part of the continuing operations.

 

THE TABLE BELOW SETS FORTH THE AMOUNTS OF THE COMPARATIVE PERIODS 2015 REPORTED RESTATED(€ million)IV quarter 2015Full year 2015IV quarter 2015Full year 2015Operating profit (loss) - continuing operations(5,008)(2,781)(6,699)(3,076)Operating profit (loss) E&P(3,614)(144)(4,696)(959)Adjusted operating profit (loss) - continuing operations on a standalone basis8584,1046344,486Adjusted operating profit (loss) - E&P8634,1085984,182Net profit (loss) attributable to Eni's shareholders - continuing operations(6,778)(7,680)(8,454)(7,952)Adjusted net profit (loss) attributable to Eni's shareholders - continuing operations on a standalone basis(202)334(301)803Total assets 134,792 139,001Eni's shareholders equity 51,753 55,493Cash flow from operations from continuing operations on a standalone basis4,01211,1814,44412,875Net cash flow (232)(1,414)(223)(1,405)

 

Non-GAAP financial measures and other alternative performance indicators disclosed throughout this press release are accompanied by explanatory notes and tables in line with guidance provided by ESMA guidelines on alternative performance measures (ESMA/2015/1415), published on October 5, 2015. For further information see the section “Alternative performance measures (Non-GAAP measures)” of this press release.

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

 

1 Adjusted Earnings before interest and taxes. 
2 In this press release, adjusted results from continuing operations of the comparative periods 2015 are reported on a standalone basis, thus excluding the results of Saipem. An equivalent performance measure has been provided for net cash provided by operating activities. Adjusted results and standalone results are Non-GAAP measures; for further information see page 25. 
3 Net cash provided by operating activities. For an explanation of the items of the cash flow normalization see page 15 in the section “Summarized Group Cash Flow Statement”. 
4 Net of the Zohr reimbursement; see page 15.
5 Details on net borrowings are furnished on page 33. 
6 Non-GAAP financial measures and other alternative performance indicators disclosed throughout this press release are accompanied by explanatory notes and tables in line with guidance provided by ESMA guidelines on alternative performance measures (ESMA/2015/1415), published on October 5, 2015. For further information see the section “Non-GAAP measures” of this press release. See pages 25 and subsequent. 
7 Dividends are not entitled to tax credit and, depending on the receiver, are subject to a withholding tax on distribution or are partially cumulated to the receiver’s taxable income.

 

* * *

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

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

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In 2018, the United States consumed more energy than ever before

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Primary energy consumption in the United States reached a record high of 101.3 quadrillion British thermal units (Btu) in 2018, up 4% from 2017 and 0.3% above the previous record set in 2007. The increase in 2018 was the largest increase in energy consumption, in both absolute and percentage terms, since 2010.

Consumption of fossil fuels—petroleum, natural gas, and coal—grew by 4% in 2018 and accounted for 80% of U.S. total energy consumption. Natural gas consumption reached a record high, rising by 10% from 2017. This increase in natural gas, along with relatively smaller increases in the consumption of petroleum fuels, renewable energy, and nuclear electric power, more than offset a 4% decline in coal consumption.

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Petroleum consumption in the United States increased to 20.5 million barrels per day (b/d), or 37 quadrillion Btu in 2018, up nearly 500,000 b/d from 2017 and the highest level since 2007. Growth was driven primarily by increased use in the industrial sector, which grew by about 200,000 b/d in 2018. The transportation sector grew by about 140,000 b/d in 2018 as a result of increased demand for fuels such as petroleum diesel and jet fuel.

Natural gas consumption in the United States reached a record high 83.1 billion cubic feet/day (Bcf/d), the equivalent of 31 quadrillion Btu, in 2018. Natural gas use rose across all sectors in 2018, primarily driven by weather-related factors that increased demand for space heating during the winter and for air conditioning during the summer. As more natural gas-fired power plants came online and existing natural gas-fired power plants were used more often, natural gas consumption in the electric power sector increased 15% from 2017 levels to 29.1 Bcf/d. Natural gas consumption also grew in the residential, commercial, and industrial sectors in 2018, increasing 13%, 10%, and 4% compared with 2017 levels, respectively.

Coal consumption in the United States fell to 688 million short tons (13 quadrillion Btu) in 2018, the fifth consecutive year of decline. Almost all of the reduction came from the electric power sector, which fell 4% from 2017 levels. Coal-fired power plants continued to be displaced by newer, more efficient natural gas and renewable power generation sources. In 2018, 12.9 gigawatts (GW) of coal-fired capacity were retired, while 14.6 GW of net natural gas-fired capacity were added.

U.S. fossil fuel energy consumption by sector

Source: U.S. Energy Information Administration, Monthly Energy Review

Renewable energy consumption in the United States reached a record high 11.5 quadrillion Btu in 2018, rising 3% from 2017, largely driven by the addition of new wind and solar power plants. Wind electricity consumption increased by 8% while solar consumption rose 22%. Biomass consumption, primarily in the form of transportation fuels such as fuel ethanol and biodiesel, accounted for 45% of all renewable consumption in 2018, up 1% from 2017 levels. Increases in wind, solar, and biomass consumption were partially offset by a 3% decrease in hydroelectricity consumption.

U.S. energy consumption of selected fuels

Source: U.S. Energy Information Administration, Monthly Energy Review

Nuclear consumption in the United States increased less than 1% compared with 2017 levels but still set a record for electricity generation in 2018. The number of total operable nuclear generating units decreased to 98 in September 2018 when the Oyster Creek Nuclear Generating Station in New Jersey was retired. Annual average nuclear capacity factors, which reflect the use of power plants, were slightly higher at 92.6% in 2018 compared with 92.2% in 2017.

More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

April, 17 2019
Casing design course
Candidates :Drilling engineers/ drilling supervisors- Venue: Istanbul/Turkey- Duration: 5 days- For more information contact me at: Tel: +905364320900- [email protected] [email protected]
April, 17 2019
A New Frontier for LNG Pricing and Contracts

How’s this for a first? As the world’s demand for LNG continues to grow, the world’s largest LNG supplier (Shell) has inked an innovative new deal with one of the world’s largest LNG buyers (Tokyo Gas), including a coal pricing formula link for the first time in a large-scale LNG contract. It’s a notable change in an industry that has long depended on pricing gas off crude, but could this be a sign of new things to come?

Both parties have named the deal an ‘innovative solution’, with Tokyo Gas hailing it as a ‘further diversification of price indexation’ and Shell calling it a ‘tailored solutions including flexible contract terms under a variety of pricing indices.’ Beneath the rhetoric, the actual nuts and bolts is slightly more mundane. The pricing formula link to coal indexation will only be used for part of the supply, with the remainder priced off the conventional oil & gas-linked indexation ie. Brent and Henry Hub pricing. This makes sense, since Tokyo Gas will be sourcing LNG from Shell’s global portfolio – which includes upcoming projects in Canada and the US Gulf Coast. Neither party provided the split of volumes under each pricing method, meaning that the coal-linked portion could be small, acting as a hedge.

However, it is likely that the push for this came from Tokyo Gas. As one of the world’s largest LNG buyers, Tokyo Gas has been at the forefront of redefining the strict traditions of LNG contracts. Reading between the lines, this deal most likely does not include any destination restriction clauses, a change that Tokyo Gas has been particularly pushing for. With the trajectory for Brent crude prices uncertain – owing to a difficult-to-predict balance between OPEC+ and US shale – creating a third link in the pricing formula might be a good move. Particularly since in Japan, LNG faces off directly with coal in power generation. With the general retreat from nuclear power in the country, the coal-LNG battle will intensify.

What does this mean for the rest of the industry? Could coal-linked contracts become the norm? The industry has been discussing new innovations in LNG contracts at the recent LNG2019 conference in Shanghai, while the influx of new American LNG players hungry to seal deals has unleashed a new sense of flexibility. But will there be takers?

I am not a pricing expert but the answer is maybe. While Tokyo Gas predominantly uses natural gas as its power generation fuel (hence the name), it is competing with other players using cheaper coal-based generation. So in Japan, LNG and coal are direct competitors. This is also true in South Korea and much of Southeast Asia. In the two rising Asian LNG powerhouses, however, the situation is different. In China – on track to become the world’s largest LNG buyer in the next two decades – LNG is rarely used in power generation, consumed instead by residential heating. In India – where LNG imports are also rising sharply – LNG is primarily aimed at petrochemicals and fertiliser. LNG based power generation in China and India could see a surge, of course, but that will take plenty of infrastructure, and time, to build. It is far more likely that their contracts will be based off existing LNG or natural gas benchmarks, several of which are being developed in Asia alone.

If it takes off  the coal-link LNG formula is likely to remain a Asian-based development. But with the huge volumes demanded by countries in this region, that’s still a very big niche. Enough perhaps for the innovation to slowly gain traction elsewhere, next stop -  Europe?

The Shell-Tokyo Gas Deal:

Contract – April 2020-March 2030 (10 Years)

Volume – 500,000 metric tons per year

Source – Shell global portfolio

Pricing – Formula based on coal and oil & gas-linked indexes

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April, 15 2019