Eni’s proved and undeveloped reserves
In detail:
  • Proved undeveloped reserves
  • Delivery commitments

Proved undeveloped reserves as of December 31, 2017 totalled 2,629 mmboe, of which 1,159 mmbbl of liquids mainly concentrated in Africa and Asia and 8,021 bcf of natural gas mainly located in Africa. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,042 mmbbl of liquids and 7,755 bcf of natural gas. Movements in Eni's 2017 proved undeveloped reserves were as follows:

Proved undeveloped reserves as of December 31, 2016 3,215
Reclassification to proved developed reserves (489)
Reclassification of the Perla Phase 2 project reserves (315)
Extensions and discoveries 483
Revisions of previous estimates 240
Improved recovery 18
Sales of minerals in place (523)
Proved undeveloped reserves as of December 31, 2017 2,629

(5) The reports of independent engineers are available on Eni website eni.com section Publications/Integrated Annual Report 2017.
(6) Includes Eni's share of proved reserves of equity accounted entities.
(7) Organic ratio of changes in proved reserves for the year resulting from revisions of previously reported reserves, improved recovery, extensions and discoveries, to production for the year. All sources ratio includes sales or purchases of minerals in place. A ratio higher than 100% indicates that more proved reserves were added than produced in a year. The Reserves 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 environmental risks.

In 2017, total proved undeveloped reserves decreased by 586 mmboe mainly due to: (i) progress in maturing PUD to proved developed (down by 489 mmboe); (ii) extensions and discoveries (up by 483 mmboe) due to the FID made for the Coral project offshore Mozambique and the Johan Castberg project offshore Norway; (iii) reclassification of 315 million boe of proved undeveloped reserves at the Perla gas project in Venezuela to the unproved category in accordance with the applicable US SEC regulation; (iv) revisions of previous estimates (up by 240 mmboe) mainly reported in Egypt due to the development activity of the Zohr project; (v) improved recovery (up 18 mmboe) in particular Iraq and Egypt; and (vi) divestments (down by 523 mmboe) related to Mozambique and Egypt disposals, as mentioned above.

During 2017, Eni converted 489 mmboe of proved undeveloped reserves to proved developed reserves due to the progress of the development activities, production start-ups and project revisions. The main reclassifications to proved developed reserves are related to the following fields/projects: Zohr (Egypt), Jangkrik (Indonesia); Cabaca South East (Angola), Sankofa (Ghana) and Nené (Congo). In 2017, capital expenditure amounted to approximately €7.1 billion. Most proved undeveloped reserves are converted to proved developed reserves within five years. Reserves that remain proved undeveloped for five or more years are a result of several physical factors that affect the timing of the projects development and execution, such as the complex nature of the development project in adverse and remote locations, physical limitations of infrastructures or plant capacity and contractual limitations that establish production levels. The Company estimates that approximately 1 bboe of proved undeveloped reserves have remained undeveloped for five years or more at the balance sheet date, mainly related to: (i) the Kashagan project in Kazakhstan (0.2 bboe), related to forthcoming development phases (for further information see Main exploration and development projects - Kashagan); (ii) the Zubair field in Iraq (0.2 bboe).

Zubair is an infrastructure-driven large scale project, where the development of PUDs has been conditioned by the completion of such infrastructures. The large part of the planned expenditures for such project have already been made by Eni and the installation of the production facilities required to achieve and maintain the full field production plateau of 700 kbbl/d is almost complete. Eni's planned conversion activities contemplate the drilling of additional production and injection wells to be linked to the facilities currently in place; (iii) the Junin 5 field in Venezuela (0.1 bboe) where the development activities concerned several optimization activities which are not expected to involve high technical complexities; and (iv) certain Libyan gas fields (0.5 bboe) where development completion and production start-ups are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force.


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 534 mmboe from producing assets located mainly in Algeria, Australia, Egypt, Indonesia, Libya, Nigeria, Norway and Venezuela. The sales contracts contain a mix of fixed and variable pricing formulas that are generally indexed to the market price for crude oil, natural gas or other petroleum products. Management believes it can satisfy these contracts from quantities available from production of the Company's proved developed reserves and supplies from third parties based on existing contracts. Production will account for approximately 88% of delivery commitments. Eni has met all contractual delivery commitments as of December 31, 2017.

Back to top