Profit and loss account

Summarized Group Balance Sheet

Summarized Group Cash Flow Statement

Changes in net borrowings

Net sales from operations

Net sales to customers

Net sales by geographic area of destination

Purchases, services and other

Principal accountant fees and services

Payroll and related costs

Depreciation, depletion, amortization and impairments

Operating profit by Division

Non-GAAP measures
Reconciliation of reported operating profit and reported net profit to results on an adjusted basis

Management evaluates Group and business performance on the basis of adjusted operating profit and adjusted net profit, which are arrived at by excluding inventory holding gains or losses and special items. Furthermore, finance charges on finance debt, interest income, gains or losses deriving from the evaluation of certain derivative financial instruments at fair value through profit or loss (as they do not meet the formal criteria to be assessed as hedges under IFRS, excluding commodity derivatives), and exchange rate differences are all excluded when determining adjusted net profit of each business segment. The taxation effect of the items excluded from adjusted operating or net profit is determined based on the specific rate of taxes applicable to each of them. The Italian statutory tax rate is applied to finance charges and income (34% is applied to charges recorded by companies in the energy sector, whilst a tax rate of 27.5% is applied to all other companies). Adjusted operating profit and adjusted net profit are non-GAAP financial measures under either IFRS, or US GAAP. Management includes them in order to facilitate a comparison of base business performance across periods and allow financial analysts to evaluate Eni’s trading performance on the basis of their forecasting models. In addition, management uses segmental adjusted net profit when calculating return on average capital employed (ROACE) by each business segment.

The following is a description of items that are excluded from the calculation of adjusted results.
Inventory holding gain or loss is the difference between the cost of sales of the volumes sold in the period based on the cost of supplies of the same period and the cost of sales of the volumes sold calculated using the weighted average cost method of inventory accounting.

Special items include certain significant income or charges pertaining to either: (i) infrequent or unusual events and transactions, being identified as non-recurring items under such circumstances; or (ii) certain events or transactions which are not considered to be representative of the ordinary course of business, as in the case of environmental provisions, restructuring charges, asset impairments or write ups and gains or losses on divestments even though they occurred in past periods or are likely to occur in future ones. As provided for in Decision no. 15519 of July 27, 2006, of the Italian market regulator (CONSOB), non recurring material income or charges are to be clearly reported in the management’s discussion and include gains and losses on re-measurement at fair value of certain commodity derivatives, which do not meet formal criteria to the classified as hedges under IFRS, including the ineffective portion of cash flow hedges.

Finance charges or income related to net borrowings excluded from the adjusted net profit of business segments are comprised of interest charges on finance debt and interest income earned on cash and cash equivalents not related to operations. In addition gains or losses on the fair value evaluation of the aforementioned derivative financial instruments, excluding commodity derivatives, and exchange rate differences are excluded from the adjusted net profit of business segments. Therefore, the adjusted net profit of business segments includes finance charges or income deriving from certain segment-operated assets, i.e., interest income on certain receivable financing and securities related to operations and finance charge pertaining to the accretion of certain provisions recorded on a discounted basis (as in the case of the asset retirement obligations in the Exploration & Production Division).
Finance charges or interest income and related taxation effects excluded from the adjusted net profit of the business segments are allocated on the aggregate Corporate and financial companies.

For a reconciliation of adjusted operating profit and adjusted net profit to reported operating profit and reported net profit see tables below.

2006

2007

2008

2009

2010

Breakdown of special items

Adjusted operating profit by Division

Adjusted net profit by Division

Finance income (expense)

Income (expense on) from investments

Property, plant and equipment by Division (at year end)

Capital expenditures by Division

Capital expenditures by geographic area of origin

Net borrowings

Employees

Employees at year end

Supplemental oil and gas information

Oil and natural gas reserves
Eni’s criteria concerning evaluation and classification of proved developed and undeveloped reserves follow Regulation S-X 4-10 of the US 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 geoscience 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 1 shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Net proved reserves exclude interests and royalties owned by others.
Proved reserves are classified as either developed or undeveloped.
Developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation 2 of part of its proved reserves on a rotational basis. The description of qualifications of the person primarily responsible of the reserve audit is included in the third party audit report 3.
In the preparation of their reports, independent evaluators rely, without independent verification, upon information furnished by Eni with respect to property interest, production, current cost 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, technical analysis relevant to field performance, reservoir 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 2010, Ryder Scott Company and DeGolyer and MacNaughton 3 provided an independent evaluation of almost 28% of Eni’s total proved reserves as of December 31, 2010 4, confirming, as in previous years, the reasonableness of Eni’s internal evaluations.
In the three year period from 2008 to 2010, 78% of Eni’s total proved reserves were subject to independent evaluation.
As of December 31, 2010, the principal properties not subjected to independent evaluation in the last three years are Karachaganak (Kazakhstan), Samburgskoye and Yaro-Yakhinskoye (Russia).
Eni operates under Production Sharing Agreements, PSAs, 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 stateowned 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 54%, 57% and 55% of total proved reserves as of December 31, 2008, 2009 and 2010, respectively, on an oil-equivalent basis.
Similar effects as PSAs apply to service and “buy-back” contracts; proved reserves associated with such contracts represented 2%, 2% and 3% of total proved reserves on an oil-equivalent basis as of December 31, 2008, 2009 and 2010, respectively.
Oil and gas reserve 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.
Reserve volumes associated with oil and gas deriving from such obligation represent 0.1%, 0.3% and 0,6% of total proved reserves as of December 31, 2008, 2009 and 2010, respectively, on an oil-equivalent basis; (ii) volumes of natural gas used for own consumption; (iii) the quantities of natural gas produced to feed the Angola LNG plant; and (iv) volumes of natural gas held in certain Eni storage fields in Italy. Proved reserves attributable to these fields include: (a) the residual natural gas volumes of the reservoirs; and (b) natural gas volumes from other Eni fields input into these reservoirs in subsequent periods. Proved reserves do not include volumes owned by or acquired from third parties. Gas withdrawn from storage is produced and thereby removed from proved reserves when sold.

Numerous uncertainties are inherent in estimating quantities of proved reserves, in projecting future productions and development expenditures.
The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and evaluation. The results of drilling, testing and production after the date of the estimate may require substantial upward or downward revisions. In addition, changes in oil and natural gas prices have an effect on the quantities of Eni’s proved reserves since estimates of reserves are based on prices and costs relevant to the date when such estimates are made. Consequently, the evaluation of reserves could also significantly differ from actual oil and natural gas volumes that will be produced.
The following table presents yearly changes in estimated proved reserves, developed and undeveloped, of hydrocarbons, liquids and natural gas as of December 31, 2008, 2009 and 2010.

Movements in net proved hydrocarbons reserves

Movements in net proved liquids reserves

Movements in net proved natural gas reserves

Results of operations from oil & gas producing activities

Capitalized costs

Costs incurred

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 year-end prices of oil and gas for the year ended December 31, 2008, and the average prices during the years ended December 31, 2009 and 2010, to estimated future production of proved reserves. 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.

Standardized measure of discounted future net cash flows

Changes in standardized measure of discounted future net cash flows

Quarterly information

Main financial data

Key market indicators

Main operating data

Tables and data