Reserves

Overview

The Company has adopted comprehensive classification criteria for the estimate of proved, proved developed and proved undeveloped oil and gas reserves in accordance with applicable US Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. Proved oil and gas reserves are those quantities of liquids (including condensates and natural gas liquids) and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, 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. Oil and natural gas prices used in the estimate of proved reserves are obtained from the official survey published by Platt’s Marketwire, except when their calculation derives from existing contractual conditions. Prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Prices include consideration of changes in existing prices provided only by contractual arrangements.

Engineering estimates of the Company’s oil and gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil and gas reserves can be designated as “proved”, the accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information.

Proved reserves to which Eni is entitled under concession contracts 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. 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 on the Profit Oil set contractually (Profit Oil). A similar scheme applies to buyback and service contracts.

Reserves Governance

Eni retains rigorous control over the process of booking proved reserves, through a centralized model of reserves governance. The Reserves Department of the Exploration & Production Division is entrusted with the task of: (i) ensuring the periodic certification process of proved reserves; (ii) continuously updating the Company’s guidelines on reserves evaluation and classification and the internal procedures; and (iii) providing training of staff involved in the process of reserves estimation. Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has stated that those guidelines comply with the SEC rules¹.

D&M has also stated that the Company guidelines provide reasonable interpretation of facts and circumstances in line with generally accepted practices in the industry whenever SEC rules may be less precise. When participating in exploration and production activities operated by other entities, Eni estimates its share of proved reserves on the basis of the above guidelines. The process for estimating reserves, as described in the internal procedure, involves the following roles and responsibilities: (i) the business unit managers (geographic units) and Local Reserves Evaluators (LRE) are in charge with estimating and classifying gross reserves including assessing production profiles, capital expenditure, operating expenses and costs related to asset retirement obligations; (ii) the petroleum engineering department at the head office verifies the production profiles of such properties where significant changes have occurred; (iii) geographic area managers verify the commercial conditions and the progress of the projects; (iv) the Planning and Control Department provides the economic evaluation of reserves; (v) the Reserves Department, through the Division Reserves Evaluators (DRE), provides independent reviews of fairness and correctness of classifications carried out by the above mentioned units and aggregates worldwide reserves data.

The head of the Reserves Department attended the “Politecnico di Torino” and received a Master of Science degree in Mining Engineering in 1985. She has more than 25 years of experience in the oil and gas industry and more than 15 years of experience in evaluating reserves.

Staff involved in the reserves evaluation process fulfils the professional qualifications requested and maintains the highest level of independence, objectivity and confidentiality in accordance with professional ethics. Reserves Evaluators qualifications comply with international standards defined by the Society of Petroleum Engineers.

Reserves independent evaluation

Since 1991, Eni has requested qualified independent oil engineering companies² to carry out an independent evaluation of part of its proved reserves on a rotational basis. The description of qualifications of the persons primarily responsible for the reserves audit is included in the third party audit report³. In the preparation of their reports, independent evaluators rely, without independent verification, upon information furnished by Eni with respect to property interests, production, current costs of operations 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, technical analysis relevant to field performance, development plans, future capital and operating costs.

In order to calculate the economic value of Eni’s equity reserves, actual prices applicable to hydrocarbon sales, price adjustments required by applicable contractual arrangements and other pertinent information are provided by Eni to third party evaluators.

In 2013 Ryder Scott Company and DeGolyer and MacNaughton³ provided an independent evaluation of approximately 30% of Eni’s total proved reserves at December 31, 2013⁴, confirming, as in previous years, the reasonableness of Eni internal evaluation.

In the 2011-2013 three year period, 92% of Eni total proved reserves were subject to an independent evaluation. As at December 31, 2013, the main Eni properties not subjected to independent evaluation in the last three years were M’Boundi (Congo) and Elgin Franklin (United Kingdom).

Movements in estimated net proved reserves

Eni’s estimated proved reserves were determined taking into account Eni’s share of proved reserves of equity-accounted entities. Movements in Eni’s 2013 estimated proved reserves were as follows:

Additions to proved reserves booked in 2013 were 621 mmboe and derived from: (i) revisions of previous estimates were up 508 mmboe mainly reported in Congo, Iraq, Australia and Nigeria; (ii) extensions, discoveries and other factors were 108 mmboe, with major increases booked in Angola, Indonesia and the United States; (iii) improved recovery were 5 mmboe reported particularly in Nigeria.

Price effects were negligible, leading to an upward revision of 14 mmboe, due to a lowered Brent price used in the reserve estimation process down to $108 per barrel in 2013 compared to $111 per barrel in 2012.

Sales of mineral-in-place related to the divestment of assets in Russia (652 mmboe) and the United Kingdom (13 mmboe).

Acquisitions referred to interests in assets located in Egypt (4 mmboe).

In 2013 Eni achieved an organic reserves replacement ratio⁵ of 105%. Reserves life index was 11.1 years (11.5 years in 2012).

Proved undeveloped reserves

Proved undeveloped reserves as of December 31, 2013 totalled 3,108 mmboe, of which 1,361 mmboe of liquids mainly concentrated in Africa and Kazakhstan and 9,592 bcf of natural gas mainly located in Africa and Venezuela. Proved undeveloped reserves of consolidated subsidiaries amounted to 1,248 mmbbl of liquids and 5,900 bcf of natural gas.

In 2013, total proved undeveloped reserves decreased by 542 mmboe due to disposal made in Russia as well as upwards and downwards revisions related to contractual and technical review.

During 2013, Eni converted 337 mmboe of proved undeveloped reserves to proved developed reserves due to development activities, production start-ups and revisions. The main reclassifications to proved developed reserves are related to the following fields/projects: Kashagan (Kazakhstan), CAFC-MLE and Block 208 (Algeria), Jasmine (United Kingdom) and Zubair (Iraq).

In 2013, capital expenditure amounted to approximately €2 billion and was made to progress the development of proved undeveloped reserves.

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 0.8 bboe of proved undeveloped reserves have remained undeveloped for five years or more with respect to the balance sheet date, mainly related to: (i) the Kashagan project in Kazhakstan (0.4 bboe) residual after the start-up of Phase 1 development (Experimental Program) following the completion of the facilities and the drilling campaign (for more details regarding this project please refer to "Main exploration and development projects"); (ii) some Libyan gas fields (0.3 bboe) where development completion and production start-up are planned according to the delivery obligations set forth in a long-term gas supply agreement currently in force. In order to secure fulfilment of the contractual delivery quantities, Eni will implement phased production start-up from the relevant fields, which are expected to be put in production over the next several years; and (iii) other minor projects where development activities are progressing.

Delivery commitments

Eni 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 348 mmboe from producing assets located mainly in Algeria, Australia, Egypt, Libya, Nigeria and Norway.

The sales contracts contain a mix of fixed and variable pricing formulas that are generally referenced 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 75% of delivery commitments.

Eni has met all contractual delivery commitments as of December 31, 2013.