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ENI S.p.A. 20-F 2009 Documents found in this filing:UNITED
STATES
Commission file number:
1-14090
Securities registered or to be
registered pursuant to Section 12(g) of the Act: Indicate the number of outstanding shares of
each of the issuer’s classes of capital or common stock as
of the close of the period covered by the annual report. Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Note - Checking the box above will not relieve
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
If "Other" has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
TABLE OF CONTENTS
i Table of ContentsCertain disclosures contained herein including, without limitation, information appearing in "Item 4 – Information on the Company", and in particular "Item 4 – Exploration & Production", “Item 5 – Operating and Financial Review and Prospects” and "Item 11 – Qualitative and Quantitative Disclosures about Market Risk" contain forward-looking statements regarding future events and the future results of Eni that are based on current expectations, estimates, forecasts, and projections about the industries in which Eni operates and the beliefs and assumptions of the management of Eni. Eni may also make forward-looking statements in other written materials, including other documents filed with or furnished to the U.S. Securities and Exchange Commission (the "SEC"). In addition, Eni’s senior management may make forward-looking statements orally to analysts, investors, representatives of the media and others. In particular, among other statements, certain statements with regard to management objectives, trends in results of operations, margins, costs, return on capital, risk management and competition are forward looking in nature. Words such as ‘expects’, ‘anticipates’, ‘targets’, ‘goals’, ‘projects’, ‘intends’, ‘plans’, ‘believes’, ‘seeks’, ‘estimates’, variations of such words, and similar expressions are intended to identify such forward-looking statements. These forward-looking statements are only predictions and are subject to risks, uncertainties, and assumptions that are difficult to predict because they relate to events and depend on circumstances that will occur in the future. Therefore, Eni’s actual results may differ materially and adversely from those expressed or implied in any forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report on Form 20-F under the section entitled "Risk Factors" and elsewhere. Any forward-looking statements made by or on behalf of Eni speak only as of the date they are made. Eni does not undertake to update forward-looking statements to reflect any changes in Eni’s expectations with regard thereto or any changes in events, conditions or circumstances on which any such statement is based. The reader should, however, consult any further disclosures Eni may make in documents it files with the SEC.
CERTAIN DEFINED TERMS In this Form 20-F, the terms "Eni", the "Group", or the "Company" refer to the parent company Eni SpA and its consolidated subsidiaries and, unless the context otherwise requires, their respective predecessor companies. All references to "Italy" or the "State" are references to the Republic of Italy, all references to the "Government" are references to the government of the Republic of Italy. For definitions of certain oil and gas terms used herein and certain conversions, see "Glossary" and "Conversion Table".
PRESENTATION OF FINANCIAL AND OTHER INFORMATION The Consolidated Financial Statements of Eni, included in this annual report, have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB). Unless otherwise indicated, any reference herein to "Consolidated Financial Statements" is to the Consolidated Financial Statements of Eni (including the Notes thereto) included herein. Unless otherwise specified or the context otherwise requires, references herein to "dollars", "$", "U.S. dollars" and "U.S. $" are to the currency of the United States, and references to "euro" and "€" are to the currency of the European Monetary Union.
STATEMENTS REGARDING COMPETITIVE POSITION Statements made in "Item 4 – Information on the Company" referring to Eni’s competitive position are based on the Company’s belief, and in some cases rely on a range of sources, including investment analysts’ reports, independent market studies and Eni’s internal assessment of market share based on publicly available information about the financial results and performance of market participants. Market share estimates contained in this document are based on management estimates unless otherwise indicated.
ii Table of ContentsGLOSSARY A glossary of oil and gas terms is available on Eni’s web page at the address www.eni.it. Below is a selection of the most frequently used terms.
iii Table of Contents
iv Table of Contents
v Table of ContentsABBREVIATIONS
CONVERSION TABLE
vi Table of ContentsPART I Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS NOT APPLICABLE
Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE NOT APPLICABLE
Item 3. KEY INFORMATION Selected Financial Information The Consolidated Financial Statements of Eni have been prepared in accordance with IFRS issued by the International Accounting Standards Board (IASB). The tables below show Eni selected historical financial data prepared in accordance with IFRS as of and for the years ended December 31, 2004, 2005, 2006, 2007 and 2008. The selected historical financial data for the years ended December 31, 2004, 2005, 2006, 2007 and 2008 are derived from Eni’s Consolidated Financial Statements included in Item 18. All such data should be read in connection with the Consolidated Financial Statements and the related notes thereto included in Item 18.
1 Table of Contents
2 Table of ContentsSelected Operating Information The tables below set forth selected operating information with respect to Eni’s proved reserves, developed and undeveloped, of crude oil (including condensates and natural gas liquids) and natural gas, as well as other data as of and for the years ended December 31, 2004, 2005, 2006, 2007 and 2008. Data on production of oil and natural gas and hydrocarbon production sold includes Eni’s share of production of affiliates and joint ventures accounted for under the equity or cost method of accounting.
3 Table of ContentsSelected Operating Information continued
4 Table of ContentsExchange Rates The following tables set forth, for the periods indicated, certain information regarding the Noon Buying Rate in U.S. dollars per euro, rounded to the second decimal (Source: The Federal Reserve Board).
Fluctuations in the exchange rate between the euro and the dollar affect the dollar equivalent of the euro price of the Shares on the Telematico and the dollar price of the ADRs on the NYSE. Exchange rate fluctuations also affect the dollar amounts received by owners of ADRs upon conversion by the Depository of cash dividends paid in euro on the underlying Shares. The Noon Buying Rate on May 4, 2009 was $1.34 per euro 1.00.
Risk Factors
There is strong competition worldwide, both within the oil industry and with other industries, to supply energy to the industrial, commercial and residential energy markets. Eni encounters competition from other oil and natural gas companies in all areas of its operations.
5 Table of Contents
The Company’s failure or inability to respond effectively to competition could adversely impact the Company’s growth prospects, future results of operations and cash flows.
The exploration and production of oil and natural gas requires high levels of capital expenditures and entails particular economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil and natural gas fields. The production of oil and natural gas is highly regulated and is subject to conditions imposed by governments throughout the world in matters such as the award of exploration and production interests, the imposition of specific drilling and other work obligations, environmental protection measures, control over the development and abandonment of fields and installations, and restrictions on production. The oil and gas industry is subject to the payment of royalties and income taxes which tend to be higher than those payable in many other commercial activities.
Drilling for oil and gas involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be unsuccessful as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or fires, blow-outs and various forms of accidents, marine risks such as collisions and adverse weather conditions and shortages or delays in the delivery of equipment. Exploring or drilling in offshore areas, particularly in deep waters, is generally more complex and riskier than onshore areas; the same is true for exploratory activity in remote areas or in challenging environmental conditions such as those we are experiencing in the Caspian region or Alaska. Failure to discover commercial quantities of oil and natural gas could have an adverse impact on Eni’s future growth prospects, results of operations and liquidity. Because Eni plans to invest significant capital expenditures in executing high risk exploration projects, it is likely that Eni will incur significant exploration and dry hole expenses in future years. High risk exploration projects include projects executed in deep and ultra-deep offshore and in new areas where the Company lacks installed production facilities. In particular Eni plans to explore for oil and gas offshore, frequently in deep water or at deep drilling depths, where 6 Table of Contentsoperations are more difficult and costly than on land or at shallower depths and in shallower waters. Deep water operations generally require a significant amount of time between a discovery and the time that Eni can produce and market the oil or gas, increasing both the operational and financial risks associated with these activities. In the case of the Company, risky exploration projects are conducted in the deep offshore of the Gulf of Mexico, Australia, Brazil, the Barents Sea, India, and offshore Ireland. In 2009, management plans to spend significant amounts of exploration expenditures in these areas that may result in significant dry hole expenses. Furthermore, shortage of deep water rigs and failure to find additional commercial reserves could reduce future production of oil and natural gas which is highly dependent on the rate of success of exploratory activity.
Eni is involved in a number of development projects for the production of hydrocarbon reserves, principally offshore. Eni’s future results of operations rely upon its ability to develop and operate major projects as planned. Key factors that may affect the economics of these projects include:
Furthermore, deep waters and other hostile environments, where the majority of Eni’s planned and existing development projects are located, can exacerbate these problems. Delays and differences between scheduled and actual timing of critical events, as well as cost overruns may adversely affect completion, the total amount of expenditures to be incurred and start up of production from such projects and, consequently, actual returns. Finally, developing and marketing hydrocarbons reserves typically requires several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commercial potential, sanctioning a development project and building and commissioning related facilities. As a consequence, rates of return for such long-lead-time projects are exposed to the volatility of oil and gas prices which may be substantially lower with respect to prices assumed when the investment decision was actually made, leading to lower rates of return. For example, we have experienced increased budgeted expenditures and a substantial delay in the scheduling of production start up at the Kashagan field, where development is ongoing. Moreover, in July 2007 these matters triggered a dispute with the relevant Kazakh authorities. On October 31, 2008, all the international partners of the project and the Kazakh authorities agreed upon a new contractual and governance framework of the Kashagan project, settling the dispute. See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the agreement. In conjunction with the finalization of the agreements, parties also sanctioned the revised expenditure budget of phase-one, amounting to U.S. $32.2 billion (excluding general and administrative expenses) of which U.S. $25.4 billion related to the original scope of work of phase 1 (including tranches 1 and 2), with the remaining part planned to be spent to execute tranche 3 and build certain exporting facilities. First oil is expected late in 2012. Eni will fund those investments in proportion to its participating interest of 16.81%. The original development plan that was filed with Kazakh Authorities in 2004 forecast expenditures of U.S. $10.3 billion (Eni’s interest being at the time 18.52%) to execute tranches 1&2 (to be adjusted to take into account cost inflation up to 2007) and first oil in 2008. The change in production start-up and the relevant cost increase over the original budget were driven by: depreciation of the U.S. dollar versus the euro and other currencies; cost price escalation of goods and services required to execute the project; an original underestimation of the costs and complexity to operate in the North Caspian Sea due to lack of benchmarks; design changes to enhance the operability and safety standards of the offshore facilities. 7 Table of ContentsSee "Item 4 – Business Overview – Exploration & Production". If the Company is unable to develop and operate major projects as planned, it may have a material adverse effect on our results of operations and liquidity.
Eni’s results of operations and financial condition are substantially dependent on its ability to develop and sell oil and natural gas. Unless the Company is able to replace produced oil and natural gas, its reserves will decline. The Company’s reserve replacement is affected by the entitlement mechanism in its Production Sharing Agreements and similar contractual schemes. In accordance with such contracts, Eni is entitled to a portion of a field’s reserves, the sale of which should cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to determine year-end amounts of Eni’s proved reserves, the lower the number of barrels necessary to recover the same amount of expenditures. The Company’s reserve replacement was negatively affected by reduced entitlements in its PSAs in the years 2006 and 2007 when Eni’s reserve replacement ratio was 38% in both years, meaning that the Company replaced less reserves than those produced. Eni’s proved reserves of subsidiaries declined by 6.1% in 2007 and by 5.8% in 2006. See "Item 4 – Business Overview – Exploration & Production". Future oil and gas production is dependent on the Company’s ability to access new reserves through new discoveries, application of improved techniques, success in development activity, negotiation with countries and other owners of known reserves and acquisitions. An inability to replace reserves could adversely impact future production levels and growth prospects, thus negatively affecting Eni’s future results of operations and financial condition. We forecast a significant reduction in costs to develop and operate oil and gas fields. If we fail to benefit from this expected trend, our oil and gas margins will deteriorate due to falling hydrocarbons prices Due to the current oil downturn, we expect that prices for oilfield services and materials will trend lower in the future. We intend to benefit from this reduction by implementing the needed cost initiatives to preserve our profitability in an environment of low oil prices. Cost initiatives include rescheduling of certain field developments to obtain cost saving and renegotiating contracts for oilfield services with our supplies on more favorable terms. If we fail to achieve the targeted levels of cost reductions, our profits per BOE in the Exploration & Production segment will be adversely affected.
The exploration and production of oil and gas is a commodity business with a history of price volatility. The single largest variable that affects the Company’s results of operations and financial condition is crude oil prices. Eni generally does not hedge its exposure to variability in future cash flows due to crude oil price movements. As a consequence, Eni’s profitability depends heavily on crude oil and natural gas prices. Crude oil and natural gas prices are subject to international supply and demand and other factors that are beyond Eni’s control, including among other things:
All these factors can affect the global balance between demand and supply for oil and prices of oil. Such factors can also affect the prices of natural gas because natural gas prices for the major part of our supplies are typically indexed to the prices of crude oil and certain refined petroleum products. Lower crude oil prices have an adverse impact on Eni’s results of operations and cash flows from operations. Furthermore, lower oil and gas prices over prolonged periods may also adversely affect Eni’s results of operations and cash flows by: (i) reducing rates of return of development projects either planned or being implemented, leading the Company to reschedule, postpone or cancel development projects; (ii) reducing the Group’s liquidity, entailing lower resources to fund expansion projects, further dampening the Company’s ability to grow future production and revenues; and (iii) triggering a review of future recoverability of the Company’s carrying amounts of oil and gas properties, which could lead to the recognition of significant impairments charges. 8 Table of Contents
Numerous uncertainties are inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of proved reserve estimates depends on a number of factors, assumptions and variables, among which the most important are the following:
Many of these factors, assumptions and variables involved in estimating proved reserves are beyond Eni’s control and may change over time and impact the estimates of oil and natural gas reserves. Accordingly, the estimated reserves could be significantly different from the quantities of oil and natural gas that ultimately will be recovered. Additionally, any downward revision in Eni’s estimated quantities of proved reserves would indicate lower future production volumes, which could adversely impact Eni’s results of operations and financial condition.
In recent years, Eni has experienced adverse changes in tax regimes applicable to oil and gas operations in Italy and in a number of countries where the Company conducts its upstream operations. Management believes that adverse changes are always possible in the tax regimes of any country in which Eni conducts its oil and gas operations, regardless of the level of stability of the political and legislative framework in each country. In recent years, developments in the regulatory framework, mainly regarding tax issues, have been implemented or announced also in EU countries and in North America. In 2008, Italy enacted new tax rules that increased the statutory tax rate applicable to energy companies with annual turnover in excess of euro 25 million by 5.5 percentage points, thus reversing a reduction in the statutory tax rate of the same amount that was enacted the previous year. Early in 2009, the Italian Parliament enacted a supplemental tax rate of 4% that has to be applied to profit before income taxes reported by the parent company Eni SpA associated with the Treaty between Italy and Libya. This supplemental tax rate will entail increased tax payables amounting to approximately euro 300 million for the full year 2009. Adverse changes in the tax rate applicable to the Group profit before income taxes would translate into negative impacts on Eni’s future results of operations and cash flows. Furthermore, the marginal tax rate in the oil and gas industry tends to increase in correlation with higher oil prices which could make it difficult for Eni to translate higher oil prices into increased net profit. However, the Company does not expect that the marginal tax rate will trend lower in response to falling oil prices.
Substantial portions of Eni’s hydrocarbon reserves are located in countries outside the EU and North America, some of which may be politically or economically less stable than EU or North American countries. At December 31, 2008, approximately 80% of Eni’s proved hydrocarbon reserves were located in such countries. Similarly, a substantial portion of Eni’s natural gas supplies comes from countries outside the EU and North America. In 2007, approximately 70% of Eni’s supplies of natural gas came from such countries. See "Item 4 – Gas & Power – Natural Gas Supplies". Adverse political, social and economic developments in any of those countries may affect Eni’s ability to continue operating in an economic way, either temporarily or permanently, and Eni’s ability to access oil and gas reserves. Particularly Eni faces risks in connection with the following issues: (i) lack of well-established and reliable legal systems and uncertainties surrounding enforcement of contractual rights; (ii) unfavorable developments in laws, regulations and contractual arrangements leading for example to expropriations or forced divestitures of assets and unilateral cancellation or modification of contractual terms. For example, in conjunction with the rescheduling of the Kashagan project in 2007, the Kazakh authorities opened a dispute against the international partners of the consortium operating the Kashagan development claiming failure on part of the consortium to fulfill certain contractual obligations. Subsequently, the Kazakh authorities and the international partners of the consortium have agreed on a new contractual framework of the project. See "Item 4 – Exploration & Production – Caspian Sea" for a full description of the material terms of the agreement; (iii) restrictions on exploration, production, imports and exports; (iv) tax or royalty increases (including retroactive claims); and (v) civil and social unrest leading to sabotages, acts of violence and incidents. For example, we have been 9 Table of Contentsexperiencing continuing social unrest in Nigeria leading to a number of disruptions at certain Eni oil producing facilities in the country. As a consequence, our oil and gas production in the country has yet to return to normal production levels. In the first quarter of 2009, security problems have continued to impact our operations. In 2008 we incurred significant asset impairments in our Exploration & Production business amounting to euro 989 million mainly driven by changes in contractual arrangements and regulatory provisions and environmental obligations leading the Company to reassess the recoverable amounts of a number of its oil and gas properties. See "Item 4 – Exploration & Production – Oil and Natural Gas Reserves"; and "Item 5 – Recent Developments". While the occurrence of these events is unpredictable, it is likely that the occurrence of such events could cause Eni to incur material losses or facility disruptions, by this way adversely impacting Eni’s results of operations and cash flows.
Eni is currently conducting oil and gas operations in Iran. The legislation and other regulations of the United States of America impose sanctions on this country and may lead to the imposition of sanctions on any persons doing business in this country or with Iranian counterparties. Under the Iran Sanctions Act of 1996 (as amended, "ISA"), which implements sanctions against Iran with the objective of denying it the ability to support acts of international terrorism and fund the development or acquisition of weapons of mass destruction, upon receipt by the U.S. authorities of information indicating potential violation of this act, the President of the United States is authorized to start an investigation aiming at possibly imposing sanctions from a six-sanction menu against any person found in particular to have knowingly made investments of U.S. $20 million or more in any twelve-month period, contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources. Furthermore, the ISA envisages that the President of the United States is bound to impose sanctions against any persons that knowingly contribute to certain military programs of Iran, effective on June 6, 2006. Eni cannot predict interpretations of, or the implementation policy of the U.S. Government under ISA with respect to Eni’s current or future activities in Iran or other areas. Eni has incurred capital expenditures in excess of U.S. $20 million in Iran in each of the last 9 years. Management expects to continue investing in Iran yearly amounts in excess of that threshold in the foreseeable future. Eni’s current activities in Iran are primarily limited to carrying out residual development activities relating to certain buy-back contracts it entered into in 2000 and 2001 and no sanctions have ever been imposed on Eni’s activities in the country. Adding to Eni’s risks arising from this matter, a bill to amend and extend the extra-territorial reach of the economic sanctions imposed by the United States with respect to Iran has been passed by the U.S. House of Representatives and may lead to the passage of new laws in this area. Iran continues to be designated by the U.S. State Department as a State sponsoring terrorism. For a description of Eni’s operations in Iran see "Item 4 – Information on the Company – Exploration & Production – North Africa and Rest of World". It is possible that in future years Eni’s activities in Iran may be sanctioned under relevant U.S. legislation. We are aware of initiatives by certain U.S. states and U.S. institutional investors, such as pension funds, to adopt or consider adopting laws, regulations or policies requiring divestment from, or reporting of interests in, companies that do business with countries designated as states sponsoring terrorism. These policies could adversely impact investment by certain investors in our securities.
The petrochemical industry is subject to cyclical fluctuations in demand, with consequential effects on prices and profitability exacerbated by the highly competitive environment of this industry. Eni’s petrochemical operations have been in the past and may be adversely affected in the future by worldwide economic slowdowns and excess installed production capacity. Furthermore, Eni’s petrochemical operations face increasing competition from Asiatic companies and national oil companies’ petrochemical divisions which can leverage on certain long-term competitive advantages in terms of lower operating costs and feedstock purchase costs. In particular, Eni’s petrochemical operations are located mainly in Italy and Western Europe where regulatory framework and public environmental sensitivity are generally more stringent than in other countries, especially Far East countries, resulting in higher operating costs of our petrochemical operation compared to the Company’s Asiatic competitors due to the need to comply with applicable laws and regulations in environmental and other related matters. In 2008 our petrochemicals operations posted operating losses of euro 822 million due to sharply higher feed-stock costs in the first half of the year and lower product volumes and margins in the second half due to the current economic downturn and related asset impairments. Impairment losses were recorded amounting to euro 278 million as the recoverable amounts of certain petrochemicals plants were lower than their carrying amounts due to deteriorating profitability prospects on the back of lowered expectations for industry fundamentals and unfavorable trends in the trading environment. As 10 Table of Contentsthe downturn is expected to continue for the full year 2009, we do not project any significant improvement in our petrochemicals business profitability.
Legislative Decree No. 164/2000 opened up the Italian natural gas market to competition as from January 1, 2003. As a result, all customers in Italy are free to choose their supplier of natural gas. The decree, among other things, introduced rules which have a significant impact on Eni’s activity, as the Company is present in all the phases of the natural gas chain:
Furthermore, on June 30, 2008 provisions came into effect on the unbundling of regulated entities in the Italian gas sector on the basis of a Code that was adopted by the Authority for Electricity and Gas in 2007. According to unbundling rules, controlling entities as in the case of the parent company Eni SpA are forbidden from interfering in the decision-making process of its subsidiaries running gas transport, storage and distribution infrastructures. Eni expects that a combination of regulatory effects and increasing competition will limit growth prospects and profitability of our natural gas business in Italy as discussed below.
Since the inception of the liberalization process in the Italian natural gas market, Eni has been experiencing rising competition in its natural gas business leading to lower selling margins due to the entry of new competitors into the market. Certain competitors of Eni are supplied by the Company itself, generally on the basis of long-term contracts. In fact, in order to comply with the above mentioned regulatory thresholds relating to volumes supplied through the national transport network and sales volumes in Italy, Eni sold part of its gas availability under its take-or-pay supply contracts to third parties importing said volumes to Italy and marketing them to Italian customers. For more information on Eni’s take-or-pay contracts, see "Item 4 – Gas & Power – Natural gas purchases". Management expects Eni’s gas selling margins in Italy to remain under pressure in the foreseeable future considering deteriorating demand fundamentals in the current economic downturn, Eni’s gas availability under its take-or-pay supply contracts, build-up of Eni’s supplies to the above mentioned competitors and new competitors entering the Italian market also in light of ongoing or already implemented capital projects designed to expand the transport capacity of import pipelines to Italy and to build new import infrastructures, particularly LNG terminals. In fact, Eni is currently implementing its plans to upgrade its natural gas import pipelines mainly from Algeria and Russia to Italy to achieve an increase of 13 BCM/y in import capacity reaching full operation in 2010. Specifically, the upgrading of the TTPC pipeline from Algeria was completed in 2008 and is expected to be fully operational in 2009. The upgrade of the Russian pipeline is ongoing. Further 3 BCM/y of new import capacity will be added by upgrading the GreenStream gasline from Libya with expected start up in 2012. A large portion of the new capacity deriving from Eni’s upgrading projects has been or is planned to be sold to third parties. In addition, a third party project has been implemented to build a new LNG terminal with an 8 BCM/y capacity in the Adriatic Sea and is expected to commence operations by late 2009. These new or upgraded gas infrastructures will considerably increase supplies to the Italian natural gas market at a time when demand is falling due to the economic downturn.
11 Table of ContentsDespite the fact that an increasing portion of natural gas volumes purchased by Eni under its take-or-pay contracts is planned to be marketed outside Italy, management believes that unfavorable trends in the Italian demand and supply for natural gas on both the short and the longer-term, also due to the reaching of full operation at new supply infrastructures, and the evolution of Italian regulations of the natural gas sector, represent risk factors to the fulfillment of Eni’s obligations in connection with its take-or-pay supply contracts and may result in a downward pressure on the Company’s gas selling margins. Based on the foregoing, Eni’s future results of operations and cash flows might be adversely affected.
Over the medium-term, Eni plans to increase its natural gas sales in Europe leveraging on its natural gas availability under take-or-pay purchase contracts it has entered into with major natural gas producing countries (namely Russia, Algeria, Libya, Norway and the Netherlands) and synergies from the acquisition of the Belgian gas operator Distrigas that was completed in 2008. Should Eni fail to increase natural gas sales in Europe as planned due to poor strategy execution or competition, Eni’s future growth prospects, results of operations and cash flows might be adversely affected also taking account that Eni might be unable to fulfill its contractual obligations to purchase certain minimum amounts of natural gas based on its take-or-pay purchase contracts currently in force.
Over the medium-term, Eni has scheduled its import volumes of natural gas to Italy based on the assumption to use the purchase flexibility contractually provided by its take-or-pay purchase contracts during periods in which demand is expected to peak. These import programs are also based on the assumption that Eni will obtain the necessary transport capacity entitlements on the Italian transport network. However, Eni’s planning assumptions may be considered to be not fully in line with current rules regulating the access to the Italian transport infrastructures as provided for by the Network Code currently in force which has been drafted in accordance with Decision No. 137 of July 17, 2002 of the Authority for Electricity and Gas. Such rules establish certain priority criteria for transport capacity entitlements at points where the Italian transport infrastructure connects with international import pipelines (the so-called entry points to the Italian transport system). Specifically, Eni’s gas volumes purchased under take-or-pay contracts are entitled to a priority in the allocation of available transport capacity for amounts not exceeding average daily contractual volumes. Accordingly, Eni’s purchase volumes exceeding average daily contractual volumes are not entitled to any priority in gaining access to the Italian transport infrastructures. The contractual flexibility represented by Eni’s right to uplift daily volumes larger than average daily contractual volumes under its take-or-pay purchase contracts is used when demand peaks, usually during the wintertime. In the event congestion occurs at entry points to the Italian transport network, under current regulation available transport capacity would be entitled firstly to operators having a priority right, i.e. holders of take-or-pay contracts within the limits of average daily contractual volumes. Then any residual available transport capacity would be allocated in proportion to all pending capacity requests. Eni considers Decision No. 137/2002 to be inconsistent with the overall rationale of the European natural gas regulatory framework, especially with reference to Directive 98/30/CE (superseded and replaced by Directive 03/55/CE) and Legislative Decree No. 164/2000, and has opened an administrative procedure to repeal Decision No. 137/2002 before an administrative court. See "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power". Eni cannot rule out a negative outcome for this matter. However, management believes that Eni’s results of operations and cash flows could be adversely affected should market conditions in light of current regulatory constraints prevent Eni from selling its whole availability of natural gas purchased to fulfill its minimum take contract obligations (e.g. in case a congestion occurs at the entry points of the Italian transport infrastructure, Eni would be forced to uplift a smaller volume of gas than the minimum contractual take). See "Item 5 – Management Expectations of Operations".
Italian institutional and political forces are urging a higher degree of competition in the Italian natural gas market and this may produce significant developments in this area. A brief description follows of certain recently enacted laws and certain proceedings before the Authority for Electricity and Gas and the Italian Antitrust Authority in order to allow investors to gain some insight into the complexity of this matter. For a full discussion of laws and procedures described herein see "Item 4 – Regulation of the Italian Hydrocarbons Industry – Gas & Power". In 2003, Law No. 290 was enacted which prohibits Eni from holding an interest higher than 20% in undertakings owning natural gas transport infrastructure in Italy (Eni currently holds a 50.04% interest in Snam Rete Gas, which owns and manages approximately 97% of the Italian natural gas transport infrastructure). A decree is expected to be enacted by the Italian Prime Minister to establish the relevant provisions to implement this mandatory disposal. The deadline for the disposal, which was initially scheduled for December 31, 2008, is to be re- 12 Table of Contentsscheduled in a 24-month term starting from the date in which this decree from the Italian Prime Minister becomes effective. Currently, Eni is unable to foresee a deadline for this disposal. On the basis of a joint inquiry conducted from 2003 through June 2004 on the Italian natural gas market, the Authority for Electricity and Gas and the Italian Antitrust Authority (the "Antitrust Authority") concluded that the overall level of competition of the Italian natural gas market is unsatisfactory due to the dominant position held by Eni in many phases of the natural gas chain. According to both the Authority for Electricity and Gas and the Antitrust Authority, the vertical integration of Eni in the supply, transport and storage of gas has restricted the development of competition in Italy notwithstanding the antitrust ceilings introduced by Legislative Decree No. 164/2000. It was further stated that the price of natural gas in Italy (in particular for the industrial sector) is higher than in other European countries. In order to implement a Law Decree defined by the Italian Government to face the economic downturn, in March 2009 the Authority for Electricity and Gas proposed certain rules on the Italian gas market designed to increase competition. These rules provide that Eni supplies to the market preset amounts of natural gas at fixed prices. Implementation of these rules could materially and adversely affect the Company’s results of operations and cash flow. In November 2006, the Authority for Electricity and Gas concluded an inquiry concerning the competitive behavior of operators selling natural gas to residential and commercial customers. This inquiry found that the retailing market for natural gas in Italy lacked a sufficient degree of competition due to current commercial practices and the existence of both entry and exit barriers. In November 2007, the Italian Authority for Electricity and Gas and the Italian Antitrust Authority opened an inquiry to gain insight into the functioning of the natural gas storage activity in Italy, particularly with regard to lack of investments by operators directed to expand capacity to store natural gas in Italy. Eni through its wholly-owned subsidiary Stogit Italia owns almost the entire storage capacity currently existing in Italy. Management believes the institutional debate on the degree of competition in the Italian natural gas market and the regulatory activity to be areas of attention and cannot exclude negative impacts deriving from developments on these matters on Eni’s future results of operations and cash flows.
On the basis of certain legislative provisions, the Authority for Electricity and Gas ("the Authority") holds a general monitoring power on pricing in the natural gas market in Italy and the power to establish selling tariffs for supplying natural gas to residential and commercial users consuming less than 200,000 CM/y (qualified as non eligible customers at December 31, 2002 as defined by Legislative Decree No. 164/2000) taking into account, among other things, the public interest of containing inflationary pressure due to rising energy costs. The decisions of the Authority on these matters may limit the ability of Eni to pass an increase in the purchase cost of natural gas on to the final consumers. Following a complex and lengthy administrative procedure started in 2004 and finalized in March 2007 with Resolution No. 79/2007, the Authority established a new indexation mechanism for updating the raw material cost component in supplies to residential and commercial users consuming less than 200,000 CM/y, establishing, among other things: (i) that an increase in the international price of Brent crude oil is only partially transferred to residential and commercial users of natural gas in case international prices of Brent crude oil exceed the 35 dollars per barrel threshold; and (ii) that Italian natural gas importers – including Eni – must renegotiate wholesale supply contracts in order to take account of this new indexation mechanism. Management cannot exclude the possibility that in the future the Authority could implement similar measures that may negatively affect Eni results of operations and liquidity. Certain provisions of law may also limit the Company’s ability to set commercial margins. Specifically, Law Decree No. 112 enacted in June 2008 forbids energy companies such as Eni to transfer on to customers, through higher prices, the higher income taxes incurred in connection with a supplemental tax rate of 5.5 percentage points introduced by the same decree on energy companies with a yearly turnover in excess of euro 25 million. The Authority for Electricity and Gas is in charge of monitoring compliance with the rule. The Authority has subsequently that energy companies have to adopt effective operational and monitoring systems in order to prevent the transfer to customers by means of unlawful variations of final prices of gas. For more information on these issues (particularly the Authority’s Decisions No. 248/2004, 134/2006 and 79/2007) see "Item 4 – Regulation – Gas & Power".
The Group’s activities are subject to antitrust and competition laws and regulations in many countries of operations, especially in Europe. In the years prior to 2008, Eni recorded significant loss provisions due to unfavorable developments in certain antitrust proceedings before the Italian Antitrust Authority, and the European 13 Table of ContentsCommission. It is possible that the Group may incur significant loss provisions in future years relative to ongoing antitrust proceedings or possible new proceedings. The Group is particularly exposed to this risk in its natural gas and refining and marketing activities due to its large presence in these markets in Italy and in Europe. See Note 29 to the Consolidated Financial Statements for a full description of Eni’s main pending antitrust proceedings. Particularly, as a result of an inquiry on the level of competition in the European natural gas market, on March 9, 2009 the European Commission sent Eni a Statement of Objections related to a proceeding under Article No. 82 of the EU Treaty and Article No. 54 of the SEE agreement with reference to an alleged unjustifiable refusal of access to the TAG and TENP/Transitgas gas pipelines, that are interconnected with the Italian gas transport system through actions intended to "capacity hoarding, capacity degradation and strategic limitation of investment" with the effect of "hindering the development of a real competition in the downstream market and […] harming the consumers". The European Commission envisages the possible imposition of a fine and of structural remedies. Based on available information and its knowledge of the proceeding, the Company is currently unable to determine the outcome of the matter. Furthermore, based on the findings of antitrust proceedings, plaintiffs could seek payment to compensate for any alleged damages as a result of antitrust business practices on part of Eni. Both these risks could adversely affect the Group’s future results of operations and cash flows.
Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil and gas operations, products and other activities. In particular, these laws and regulations require the acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, as well as refining, petrochemicals and other Group operations, limit or prohibit drilling activities in certain protected areas, provide for measures to be taken to protect the safety of the workplace and health of communities involved by the company’s activities, and impose criminal or civil liabilities for polluting the environment or harming employees or communities health and safety resulting from oil, natural gas, refining, petrochemical and other Group’s operations. 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 owned by Eni. In addition, Eni’s operations are subject to laws and regulations relating to the production, handling, transportation, storage, disposal and treatment of waste materials. Breach of environmental, health and safety laws exposes the Company’s employees to criminal and civil liability and the Company to the incurrence of liabilities associated with compensation for environment health or safety damage. Additionally, in the case of violation of certain rules regarding safety in the workplace, the Company can be liable as provided for by a general EU rule on businesses liability due to negligent or willful conduct on part of their employees as adopted in Italy with Law Decree No. 231/2001. Environmental, health and safety laws and regulations have a substantial impact on Eni’s operations. Management expects that the Group will continue to incur significant amounts of operating expenses and expenditures to comply with environmental, health and safety laws and regulations, also taking into account possible future developments in environmental regulations in Italy and in other countries where Eni operates, particularly the implementation of increasingly strict measures decided at both international and country level to reduce greenhouse gas emissions.
Risks of environmental, health and safety incidences and liabilities are inherent in many of Eni’s operations and products. Notwithstanding management believes that Eni adopts high operational standards to ensure safety of its operations and to protect the environment and health of people and employees, it is always possible that incidents like blow-outs, spillovers, contaminations and similar events could occur that would result in damage to the environment, employees and communities. In particular, Eni is performing a number of remedial actions to restore and clean-up certain industrial sites that were contaminated by the Group’s industrial activities in previous years, mainly in Italy. Management expects further remedial actions to be implemented in future years. The Group has accrued risk provisions to cope with all existing environmental liabilities whereby both a legal or constructive obligation to perform a clean-up or other remedial actions is in place and the associated costs can be reasonably estimated. The accrued amount represents the management’s best estimates of future environmental expenses to be incurred. Notwithstanding this, management believes that it is possible that in the future Eni may incur significant environmental expenses and liabilities in addition to the amounts already accrued due to: (i) the chance of as yet 14 Table of Contentsunknown contamination; (ii) the results of on-going surveys or surveys to be carried out on the environmental status of certain Eni’s industrial sites as required by the applicable regulations on contaminated site; (iii) unfavorable developments in ongoing litigation on the environmental status of certain Company’s site where a number of public administrations and the Italian Ministry for environment act as plaintiffs; (iv) the possibility that new litigation might arise; and (v) the probability that new and stricter environmental laws might be implemented.
Eni is party to a number of civil actions and administrative proceedings arising in the ordinary course of the business. In addition to existing provisions accrued as of the balance sheet date to account for ongoing proceedings, it is possible that in future years Eni may incur significant losses in addition to amounts already accrued in connection with pending legal proceedings due to: (i) uncertainty regarding the final outcome of each proceeding; (ii) the occurrence of new developments that management could not take into consideration when evaluating the likely outcome of each proceeding in order to accrue the risk provisions as of the date of the latest financial statements; (iii) the emergence of new evidence and information; and (iv) underestimation of probable future losses.
Operating results in Eni’s Exploration & Production, Refining & Marketing, and Petrochemical segments are affected by changes in the price of crude oil and by movements in crude oil prices on margins of refined and petrochemical products.
Overall, lower oil prices have a net adverse impact on Eni’s results of operations. The effect of lower oil prices on Eni’s average realizations for produced oil is generally immediate. Furthermore, Eni’s average realizations for produced oil differ from the price of Brent crude marker primarily due to the circumstance that Eni’s production slate, which also includes heavy crude qualities, has a lower API gravity compared with Brent crude (when processed the latter allows for higher yields of valuable products compared to heavy crude qualities, hence higher market price).
The impact of changes in crude oil prices on Eni’s downstream businesses, including the Gas & Power, the Refining & Marketing and the Petrochemical businesses, depends upon the speed at which the prices of gas and products adjust to reflect these changes. Wholesale margins in the Gas & Power business are substantially independent from fluctuations in crude oil prices as purchase and selling prices of natural gas are contractually indexed to prices of crude oil and certain refined products according to similar pricing schemes. However, quarterly performance and year-to-year comparability of results of Eni’s natural gas business may be somewhat affected by the indexation mechanism of the raw material component in gas supplies to residential customers and certain resellers to residentials in Italy in accordance with applicable regulations from the Italian Authority for Electricity and Gas as outlined above in the risk factor describing the "Liberalization of the Italian Natural Gas Market". Specifically, this indexation mechanism provides a certain time lag between movements in the price of crude oil and the related adjustment to the selling price of natural gas. For a detailed discussion of this indexation mechanism in Italy see "Item 4 – Regulation – Gas & Power – Natural gas prices". In the Refining & Marketing and Petrochemical businesses a time lag exists between movements in oil prices and in prices of finished products.
The results of operations of Eni’s Refining & Marketing segment are substantially affected by changes in European refining margins which reflect changes in relative prices of crude oil and refined products as outlined above. The prices of refined products in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather. Furthermore, Eni’s realized margins are also affected by relative price movements of heavy crude qualities vs. light crude qualities, taking into account the ability of Eni’s refineries to process complex crudes that represent a cost advantage when market prices of heavy crudes are relatively cheaper than the marker Brent price. In 2009, Eni expects that weak demand for products and narrowing price differentials between heavy and light crudes ones will negatively affect the performance of Eni’s refining operations. 15 Table of Contents
Eni’s margins on petrochemical products are affected by trends in demand for petrochemical products and changes in oil prices which influence changes in purchase costs of petroleum-based feedstock. Given the commoditized nature of Eni petrochemical products, it is difficult for the Company to transfer higher purchase costs for oil-based feedstock to selling prices to customers. In 2008, the profitability of Eni’s petrochemical segment was significantly affected by lower selling margins for commodity petrochemical products due to higher purchase costs for oil-based feedstock that were not fully transferred to selling prices of products in the first half of the year and, subsequently by weak demand for petrochemical products. These negative factors also triggered asset impairments. Management’s outlook for 2009 is also challenging, and management does not expect any significant improvement in the trading environment from 2008 and possibly a further contraction in margins on petrochemical products.
Eni constantly monitors the oil and gas market in search of opportunities to acquire individual assets or corporations in order to achieve its growth targets or complement its asset portfolio. Acquisitions entail an execution risk – the risk that the acquirer will not be able to effectively integrate the purchased assets so as to achieve expected synergies. In addition, acquisitions entail a financial risk – the risk of not being able to recover the purchase costs of acquired assets, in case a prolonged decline in the market prices of oil and natural gas occurs. We also incur unanticipated costs or assume unexpected liabilities and losses in connection with companies or assets we acquire. If the integration and financial risks connected to acquisitions materialize our financial performance may be adversely affected.
Credit risk is the potential exposure of the Group to losses in case counterparties fail to perform or pay amounts due. Credit risks arise from both commercial partners and financial ones. Although the Group has never experienced material non-performance from its counterparties, due to the severity of the current economic and financial crisis it is possible that we may experience a higher than normal level of counterparty failure. In our consolidated financial statements for the year 2008, we accrued an allowance against doubtful accounts amounting to euro 251 million more than doubling the allowance made a year earlier.
Movements in the exchange rate of the euro against the U.S. dollar can have a material impact on Eni’s results of operations. Prices of oil, natural gas and refined products generally are denominated in, or linked to, U.S. dollars, while a significant portion of Eni’s expenses are denominated in euros. Similarly, prices of Eni’s petrochemical products are generally denominated in, or linked to, the euro, whereas expenses in the Petrochemical segment are denominated both in euros and U.S. dollars. Accordingly, a depreciation of the U.S. dollar against the euro generally has an adverse impact on Eni results of operations and liquidity because it reduces booked revenues by an amount greater than the decrease in dollar-denominated expenses. The Exploration & Production segment is particularly affected by movements in the U.S. dollar vs. the euro exchange rates. In 2008, Eni’s operating profit in this business segment has been impacted by an estimated amount of euro 1.2 billion due to a 7.3% depreciation of the U.S. dollar versus the euro.
Significant changes in weather conditions in Italy and in the rest of Europe from year to year may affect demand for natural gas and some refined products; in colder years, demand is higher. Accordingly, the results of operations of the Gas & Power segment and, to a lesser extent, the Refining & Marketing segment, as well as the comparability of results over different periods may be affected by such changes in weather conditions. Furthermore, our operations, particularly offshore production of oil and natural gas, are exposed to extreme weather phenomena that can result in material disruption to our operations and consequent loss or damage of properties and facilities.
Interest on Eni’s finance debt is primarily indexed at a spread to benchmark rates such as the Europe Interbank Offered Rate, "Euribor", and the London Interbank Offered Rate, "Libor". As a consequence, movements in interest rates can have a material impact on Eni’s finance expense in respect to its finance debt. 16 Table of Contents
The preparation of financial statements requires management to make certain accounting estimates that are characterized by a high degree of uncertainty, complexity and judgment. These estimates affect the reported amount of the Company’s assets and liabilities, as well as the reported amount of the Company’s income and expenses for a given period. Although management believes these estimates to represent the best outcome of the estimation process, actual results could differ from such estimates, due to, among other things, the following factors: uncertainty, lack or limited availability of information; the availability of new informative elements, variations in economic conditions such as prices, significant factors (e.g. removal technologies and costs) and the final outcome of legal, environmental or regulatory proceedings. See "Item 5 – Critical Accounting Estimates".
Item 4. INFORMATION ON THE COMPANY History and Development of the Company Eni SpA with its consolidated subsidiaries is engaged in the oil and gas, electricity generation, petrochemicals, oilfield services and engineering industries. Eni has operations in about 70 countries and 78,880 employees as of December 31, 2008. Eni, the former Ente Nazionale Idrocarburi, a public law agency, established by Law No. 136 of February 10, 1953, was transformed into a joint stock company by Law Decree No. 333 published in the Official Gazette of the Republic of Italy No. 162 of July 11, 1992 (converted into law on August 8, 1992, by Law No. 359, published in the Official Gazette of the Republic of Italy No. 190 of August 13, 1992). The Shareholders’ Meeting of August 7, 1992 resolved that the company be called Eni SpA. Eni is registered at the Companies Register of Rome, register tax identification number 00484960588, R.E.A. Rome No. 756453. Eni is expected to remain in existence until December 31, 2100; its duration can however be extended by resolution of the shareholders. Eni’s registered head office is located at Piazzale Enrico Mattei 1, Rome, Italy (telephone number: +39-0659821). Eni branches are located in: • San Donato Milanese (Milan), Via Emilia, 1; and • San Donato Milanese (Milan), Piazza Ezio Vanoni, 1. Internet address: www.eni.it. The name of the agent of Eni in the United States is De Luca Vincenzo, 485 Madison Ave., New York, NY 10002. Eni’s principal segments of operations are described below. Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations in 39 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the U.S., Kazakhstan, Russia, Algeria, Pakistan and Australia. In 2008, Eni’s production of oil and natural gas amounted to 1,748 KBOE/d on an available-for-sale basis. As of December 31, 2008, Eni’s proved reserves of subsidiaries stood at 6,242 mmBOE; Eni’s share of reserves of equity-accounted entities amounted to 666 mmBOE. In 2008, Eni’s Exploration & Production segment reported net sales from operations (including inter-segment sales) of euro 33,318 million and operating profit of euro 16,415 million. Eni’s Gas & Power segment engages in supply, transport, distribution and marketing of natural gas, as well as of LNG. This segment also includes the activity of power generation that enables Eni to extract further value from gas, diversifying its commercial outlets. In 2008, Eni’s worldwide sales of natural gas amounted to 104.23 BCM, including 6.00 BCM of gas sales made directly by the Eni’s Exploration & Production segment in Europe and the U.S. Sales in Italy amounted to 52.87 BCM, while sales in European markets were 43.03 BCM that included 11.25 BCM of gas sold to certain importers to Italy. Sales to markets outside Europe amounted to 2.33 BCM. Through its 50.03 per cent-owned subsidiary Snam Rete Gas, Eni operates an Italian network of high and medium pressure pipelines for natural gas transport that is approximately 31,474-kilometer long, while outside Italy Eni holds capacity entitlements on a network of European pipelines extending for approximately 4,400 kilometers made up of high pressure pipelines to import gas from Russia, Algeria, Libya and North Europe production basins to European markets. Eni, through its 100 percent-owned subsidiary Italgas and other subsidiaries, is engaged in natural gas distribution activity in Italy serving 1,320 municipalities through a low pressure network consisting of approximately 49,400 kilometers of pipelines as of December 31, 2008. Eni produces electricity and steam at its operated sites of Livorno, Taranto, Mantova, Ravenna, Brindisi, Ferrera Erbognone and Ferrara with a total installed capacity of 4.9 GW as of December 31, 2008. In 2008, sales of electricity totaled 29.93 TWh. Eni operates a re-gasification terminal in Italy and holds indirect interest or capacity entitlements in a number of LNG facilities in 17 Table of ContentsEurope, Egypt and in certain projects under construction in the U.S. In 2008, Eni’s Gas & Power segment reported net sales from operations (including inter-segment sales) of euro 36,936 million and operating profit of euro 3,933 million. Eni’s Refining & Marketing segment engages in refining and marketing of petroleum products mainly in Italy and in the rest of Europe. In 2008, processed volumes of crude oil and other feedstock amounted to 35.84 mmtonnes and sales of refined products were 50.68 mmtonnes, of which 28.92 mmtonnes in Italy. Retail sales of refined product at operated service stations amounted to 12.67 mmtonnes including Italy and the rest of Europe. In 2008, Eni’s retail market share in Italy through its Agip-branded network of service stations was 30.6%. In 2008, Eni’s Refining & Marketing segment reported net sales from operations (including inter-segment sales) of euro 45,083 million and operating net loss of euro 1,023 million. Eni’s petrochemical activities include production of olefins and aromatics, basic intermediate products, polyethylene, polystyrenes, and elastomers. Eni’s petrochemical operations are concentrated in Italy and Western Europe. In 2008, Eni sold 4.7 mmtonnes of petrochemical products. In 2008, Eni’s Petrochemical segment reported net sales from operations (including inter-segment sales) of euro 6,303 million and an operating net loss of euro 822 million. Eni’s oilfield services, construction and engineering activities are conducted through its 42.91 per cent-owned subsidiary Saipem and Saipem’s controlled entities. Activities involve offshore construction, particularly fixed platform installation, sub-sea pipe laying and floating production systems and onshore construction. Offshore and onshore drilling services and engineering and project management services are also provided to the oil and gas, refining and petrochemical industries. In 2008, Eni’s Engineering & Construction segment reported net sales from operations (including intra-group sales) of euro 9,176 million and operating profit of euro 1,045 million. A list of subsidiaries of Eni is included as an exhibit to this Annual Report on Form 20-F.
Eni’s strategy is to grow the Company’s main businesses, over both the medium and the long-term, with improving profitability. This strategy has remained unchanged in spite of the current economic downturn and an uncertain outlook for the global energy demand. In executing this strategy, management intends to preserve a solid capital structure targeting an optimal mix between net borrowings and shareholders’ equity. By this means, management expects to maintain the Company’s current credit rating. Over the next four-years, Eni plans to execute a capital expenditure program amounting to euro 48.8 billion to support organic growth. Eni plans to fund this capital expenditure program mostly by means of cash flows provided by operating activities. Capital projects will be assessed and implemented in accordance with tight financial criteria. The Company intends to remunerate its shareholders through significant dividend distributions so as to ensure to its shareholders competitive dividend yields (measured as the ratio of dividend to the share price recorded on average in the month of December on the Italian stock exchange). Management intends to support the Company’s profitability by focusing on cost reduction initiatives, including a number of actions that will be implemented in order to benefit from the expected reduction in purchase costs for oilfield materials, equipment and services in the Exploration and Production segment. For a description of risks and uncertainties associated with the Company’s outlook and the capital expenditure program See "Item 5 – Management’s Expectations of Operations". Eni’s strategy in its Exploration & Production operations is to grow production leveraging on the development of the Company’s asset portfolio. Eni targets to achieve a production growth rate of 3.5% on average over the 2009-2012 period, assuming Eni’s Brent price scenario of 55 U.S. dollar per barrel in 2012. For a discussion of Eni’s production volume sensitivity to oil prices see "Item 5 – Management’s Expectations of Operations". Management will continue to assess opportunities to increase production through acquisitions. Eni intends to pay special attention to reserve replacement in order to secure the medium to long-term sustainability of its business. In its Gas & Power activities, Eni intends to grow natural gas sales in the international market, preserve the profitability of the Italian marketing business, effectively manage regulated businesses, and develop a global LNG business. Due to the current economic downturn, the Company has revised down its long-term growth expectations for the European gas demand from 3% to 2% per annum until 2020. For a description of trends in the natural gas markets see "Gas & Power" below. The impact of a worsening demand outlook and increasing competitive pressure on Eni’s results of operations on the domestic market is expected to be offset by the contribution of regulated businesses and continuing growth in European markets, mainly driven by the integration of the recently acquired Belgian company Distrigas. Eni targets worldwide gas sales of 124 BCM in 2012, including E&P sales in Europe and the U.S. In particular, Eni targets to achieve an annual average growth rate of 7% in international sales in the four-year period 2009 to 2012. The Company’s strategy contemplates a further strengthening of Eni’s presence in the European market, leveraging on the synergies expected from the acquisition of Distrigas (for further details see below – "Significant business and portfolio developments"). The integration with upstream activities will provide the Gas & Power business with opportunities to monetize the equity gas reserves and develop LNG sales. 18 Table of ContentsIn its Refining & Marketing activities, the Company’s strategy focuses on improving the business profitability and reducing the cash requirements of the business by means of strict capital discipline also in light of a weak outlook for refined products demand. The Company intends to selectively upgrade its refinery system and improve quality standards in marketing activities as well as increase operating efficiency. In refining Eni plans to increase the conversion index and flexibility of plants in order to achieve a higher yield of middle distillates and increase the ability of its refineries to process less valuable crudes. In marketing, Eni intends to strengthen its leadership position in the Italian retail market trough plant upgrading, loyalty programs and enhanced non-oil service formats. In Europe, Eni’s growth strategy will continue to be selective, focusing on those markets where it can leverage on scale, supply and logistic synergies and brand awareness. In its Engineering & Construction activities, Eni aims at developing and expanding its geographical reach and technical characteristics of its world class fleet in order to maintain its strong competitive position and reduce its exposure to the cyclicality of the oil industry. In technological research and innovation activities, Eni plans to implement significant capital expenditures amounting to euro 1.1 billion in the next four years to develop such technologies that management believes may ensure competitive advantages in the long-term. Eni plans to continue developing ongoing programs focused on reducing costs to find and recover hydrocarbons, developing clean fuels, upgrading heavy crude (in particular the EST project), monetizing natural gas through projects such as high pressure high distance gas transmission (TAP) and Gas to Liquids (GTL), and protecting the environment by investing in the fields of renewable sources of energy and reduction of GHG emissions.
The significant business and portfolio developments that occurred in 2008 and to date in 2009 were the following:
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In addition, in 2008 Eni completed the following transactions:
Recent developments are described below.
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In 2008 capital expenditures amounted to euro 14,562 million, of which 84% related to the Exploration & Production, Gas & Power and Refining & Marketing segments and mainly related to: (i) the development of oil and gas reserves (euro 6,429 million) deployed mainly in Kazakhstan, Egypt, Angola, Congo and Italy and exploration projects (euro 1,918 million), primarily in the United States, Egypt, Nigeria, Angola and Libya; (ii) the purchase of proved and unproved property for euro 836 million related mainly to the extension of mineral rights in Libya following an agreement signed in October 2007 with the state company NOC and the purchase of a 34.81% interest in the ABO project in Nigeria; (iii) the development and upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 1,130 million and euro 233 million, respectively) and upgrading of natural gas import pipelines to Italy (euro 233 million); (iv) the ongoing construction of combined cycle power plants (euro 107 million); (v) projects designed to upgrade the conversion capacity and flexibility of Eni’s refineries, including construction of a new hydrocracking unit at the Sannazzaro refinery, and to build of new service stations and upgrade of existing ones in Italy and outside Italy (totaling euro 965 million); and (vi) the upgrading of the fleet used in the Engineering & Construction division (euro 2,027 million). In 2008, Eni’s acquisitions amounted to euro 5.85 billion (euro 4.3 billion net of acquired cash of euro 1.54 billion) and mainly related to: (i) the acquisition of the 57.243% majority stake in Distrigas NV; (ii) the completion of the acquisition of Burren Energy Plc; (iii) the purchases of certain upstream properties and gas storage assets, related to the entire share capital of the Canadian company First Calgary operating in Algeria, a 52% stake in the Hewett Unit in the North Sea, a 20% stake in the Indian company Hindustan Oil Exploration Co; and (iv) other investments in non-consolidated entities mainly related to funding requirements for an LNG project in Angola. In 2007, capital expenditures amounted to euro 10,593 million, of which 84.7% related to the Exploration & Production, Gas & Power and Refining & Marketing businesses, and primarily related to: (i) the development of oil and gas reserves (euro 4,788 million) deployed predominantly in Kazakhstan, Egypt, Angola, Italy and Congo, and exploration projects (euro 1,659 million) particularly in the Gulf of Mexico, Egypt, Norway, Nigeria and Brazil; (ii) development and upgrading of Eni’s natural gas transport and distribution networks in Italy (euro 886 million) as well as upgrading of natural gas import pipelines to Italy (euro 253 million); (iii) the ongoing construction of combined cycle power plants (euro 175 million); (iv) projects designed to upgrade the conversion capacity and flexibility of Eni’s refineries, including construction of a new hydrocracking unit at the Sannazzaro refinery, and to build and upgrade service stations (totaling euro 979 million); and (v) the upgrading of the fleet used in the Engineering & Construction segment (euro 1,410 million). In 2007, Eni’s acquisitions amounted to euro 9.7 billion and mainly related to: (i) a 60% interest in three Russian gas companies as part of the liquidation procedure of bankrupt Russian company Yukos. Through the same transaction Eni also purchased a 20% stake in the oil and gas company OAO Gazprom Neft. Gazprom was granted a call option to purchase a 51% interest in those three gas companies and the 20% stake in OAO Gazprom Neft; (ii) the purchase of upstream assets in the Gulf of Mexico; (iii) the purchase of upstream assets onshore Congo; (iv) the purchase of a 24.9% interest in Burren Energy; (v) the acquisition of a further 16.11% stake in the Ceska Rafinerska in the Czech Republic increasing Eni’s ownership interest to 32.4%; (vi) the purchase of 102 retail fuel stations and related marketing assets located in the Czech Republic, Slovakia and Hungary; and (vii) the purchase of a 13.6% stake in the Angola LNG consortium.
BUSINESS OVERVIEW Exploration & Production Eni’s Exploration & Production segment engages in oil and natural gas exploration and field development and production, as well as LNG operations, in 39 countries, including Italy, Libya, Egypt, Norway, the UK, Angola, Congo, the U.S., Kazakhstan, Russia, Algeria, Pakistan and Australia. In 2008, Eni produced 1,748 KBOE/d on an available for-sale basis. As of December 31, 2008, Eni’s proved reserves of subsidiaries stood at 6,242 mmBOE; Eni’ share of reserves of equity-accounted entities amounted to 666 mmBOE. 21 Table of ContentsEni’s strategy in its Exploration & Production operations is to increase production leveraging on the development of its asset portfolio. Eni plans to achieve a production growth rate of 3.5% on average over the 2009-2012 period, under certain trading environment assumptions (See "Item 5 – Management’s Expectations of Operations"). A description of Eni’s production volume sensitivity to oil prices is disclosed under "Item 5 – Management’s Expectations of Operations". Future growth will be driven by the development of new projects located in a number of strategic oil and gas basins in the world, namely the Caspian Region, North and West Africa and the Gulf of Mexico. A high-quality portfolio geographically focused and resilient, with one of the lowest breakeven prices in the industry, high exposure to the most competitive giant projects and long-standing relationships with key host countries will enable any to deliver industry-leading growth even in current market conditions. Management will continue to evaluate opportunities to increase production through focused acquisitions. Eni intends to pay special attention to reserve replacement in order to guarantee the medium-to long-term sustainability of its business. Eni intends to optimize its portfolio of development properties by focusing on areas where its presence is established, seeking new opportunities and divesting marginal assets. Eni also intends to develop its LNG business in order to monetize its large base of gas reserves mainly in North and West Africa. In exploration activities, Eni intends to concentrate resources in well established areas of presence where availability of production facilities, existing competencies and long-term relationships with host countries will enable Eni to readily put in production discovered reserves, reducing the time-to-market and capturing synergies. Approximately 80% of planned capital expenditures will be directed to such core areas (located mainly in the United States, Egypt, Libya, Nigeria, Angola, Italy, Norway and Congo). Eni also plans to selectively pursue high risk/high reward opportunities arising from expansion in areas with high mineral potential. Eni expects to purchase new exploration permits and to divest or exit marginal or non strategic ones. In order to execute these strategies, Eni intends to invest approximately euro 32.6 billion on reserve development and field optimization as well as exploration projects over the next four-year period; euro 1.8 billion of which will be spent to build transportation infrastructures and execute LNG projects through equity-accounted entities. In 2009, oil and gas prices are expected to be significantly lower than 2008. In response Eni plans to improve profitability of its operations by implementing a number of initiatives designed to reduce costs to develop and operate oil and gas fields by leveraging on the expected reduction in purchase costs of oilfield services, materials and equipment due to the economic downturn. Management has yet to commit a large amount of future development expenditures and plans to be able to benefit from ongoing downward trends in rates of oilfield services and purchase costs of goods and equipment. Additional cost control measures will address ongoing operations. The amount of planned capital expenditures for the years 2009-2012 already factors in the benefits associated with cost control. See "Item 3 – Risk Factors".
Eni has always exercised rigorous control over the booking of proved reserves. The Reserve Department of the Exploration & Production segment is entrusted with the task of continuously updating the Company’s guidelines regarding reserves evaluation. The department monitors the periodic estimation process. Company guidelines follow Regulation S-X Rule 4-10 of the U.S. Securities and Exchange Commission (SEC) as well as on specific issues not regulated by the SEC rules, the established practice endorsed by qualified institutions on the marketplace. Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineering company, which has certified their compliance with applicable SEC rules. D&M has also stated that the Company guidelines regulate situations for which the SEC rules are less precise, providing a reasonable interpretation in line with the generally accepted practices in international markets. When participating in exploration and production activities operated by other entities, Eni also estimates its proved reserves on the basis of the above guidelines. The process for evaluating reserves involves: (i) business unit managers (geographic units) and Local Reserve Evaluators (LRE) who perform the evaluation and classification of reserves including estimates of production profiles, capital expenditures, operating costs and costs related to asset retirement obligations; (ii) geographic area managers at head offices checking evaluations carried out by business unit managers; and (iii) the Reserve Department, which provides independent reviews of the fairness and correctness of classifications carried out by business units, aggregates worldwide reserve data and performs an economic assessment of reserves to calculate equity volumes. Moreover, the Reserve Department has the responsibility to ensure the periodic certification process of reserves and to update continuously the Company guidelines on reserves evaluation and classification. Since 1991, Eni has requested qualified independent oil engineering companies to carry out an independent evaluation2 of its proved reserves on a rotational basis. Eni believes those independent evaluators to be experienced
22 Table of Contentsand qualified in the marketplace. In the preparation of their reports, those independent evaluators relied, without independent verification, upon information furnished by Eni with respect to property interest, production, current cost of operation and development, agreements relating to future operations and sale, prices and other factual information and data that were accepted as represented by the independent evaluators. This information was used by Eni in determining its proved reserves and included log, directional surveys, core and PVT (Pressure Volume Temperature) analysis, maps, oil/gas/water production/injection data of wells, reservoir, and field, 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 reserves net present value (NPV), actual prices received from hydrocarbon sales, instructions on future prices, and other pertinent information are provided. Accordingly, Eni believes that the work performed by the independent evaluators is to be considered an evaluation of Eni’s proved reserves carried out in parallel with the internal evaluation. The circumstance that the independent evaluations achieved the same results as those of the Company for the vast majority of fields support management’s confidence that the company’s booked reserves meet the regulatory definition of proved reserves which are reasonably certain to be produced in the future. When the assessment of independent engineers is lower than internal evaluations, Eni revises its estimates based on information provided by independent evaluators. In any case, those differences were not significant. In 2008, a total of 1.5 BBOE of proved reserves of subsidiaries have been evaluated, representing approximately 25% of Eni’s total proved reserves of subsidiaries at December 31, 2008. In the 2006-2008 three-year period, 76% of Eni’s total proved reserves of subsidiaries were subject to independent evaluations. As at December 31, 2008 the most important of Eni’s properties which were not subject to an independent evaluation were: Bouri and Bu Attifel (Libya), Barbara (Italy), M’Boundi (Congo) and Elgin-Franklin (United Kingdom). Eni’s proved reserves of subsidiaries at December 31, 2008 totaled 6,242 mmBOE (oil and condensates 3,243 mmBBL; natural gas 17,214 BCF) representing an increase of 232 mmBOE, or 3.9%, from December 31, 2007. Additions to proved reserves booked by Eni’s subsidiaries in 2008 were 850 mmBOE deriving from: (i) revisions of previous estimates of 746 mmBOE, partly related to higher entitlements reported in certain PSAs (up 340 mmBOE) resulting from lower year end oil prices from a year ago (Brent price was $36.55 per barrel at December 31, 2008 compared to $96.02 per barrel at December 31, 2007), net of downward revisions associated with marginal productions in certain mature fields such as Angola, Kazakhstan and Libya; (ii) extensions and discoveries (71 mmBOE) with major increases booked in Angola, Egypt, Nigeria, Norway and United States; and (iii) improved recovery (33 mmBOE) mainly reported in Algeria, Angola, Congo and Libya. Acquisitions amounted to 91 mmBOE reflecting the contribution of the acquired Burren assets in Congo, Turkmenistan and India. Sales of reserves (59 mmBOE) related to the divestment of a 1.71% stake in the Kashagan project following the finalization of the agreements implementing the new contractual and governance framework of the project effective January 1, 2008 (information on the Kashagan agreements is provided below under the section "Caspian Area" on page 39). Due to risks inherent in the exploration and production business, a degree of uncertainty still exists as to whether these additions will actually be produced. See "Item 3 – Risks associated with exploration and production of oil and natural gas" and – "Uncertainties in estimates of oil and natural gas reserves". As of December 31, 2008 Eni’s share of proved reserves of equity-accounted entities amounted to 666 mmBOE. The 2008 year end amounts comprise 60% of proved reserves of the three Russian gas companies purchased in 2007 as part of a bid procedure for assets of bankrupt Russian company Yukos. Terms of the call option granted to Gazprom to purchase a 51% interest in the share capital of OOO SeverEnergia (Eni’s interest being 60%), which owns 100% of these three Russian companies engaging in the development of gas reserves, are currently under review by Eni, Enel and Gazprom. The reserve replacement ratio for Eni’s subsidiaries was 136% in 2008 (38% in 2007 and 38% in 2006). The average reserve life index for Eni’s subsidiaries was 9.6 years at December 31, 2008. The reserve replacement ratio was calculated by dividing additions to proved reserves by total production, each as derived from the tables of changes in proved reserves prepared in accordance with SFAS No. 69 (see the supplemental oil and gas information in the Consolidated Financial Statements). The reserve replacement ratio is a measure used by management to assess the extent to which produced reserves in the year are replaced by reserve additions booked according with SEC criteria under Rule 4-10 of Regulation S-X. Management considers the reserve replacement ratio to be an important gauge of the ability of the Company to sustain its growth prospects. However, this ratio measures past performances and 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. Specifically, in recent years Eni’s replacement produced reserves has been affected by the impact of higher year-end oil prices on reserves entitlements in the Company’s Production Sharing Agreements (PSAs) and similar contractual schemes. In accordance with such contracts, Eni is entitled to a portion of field reserves, the sale of which should cover expenditures incurred by the Company to develop and operate the field. The higher the reference prices for Brent crude oil used to determine year-end amounts of Eni’s proved reserves, the lower the number of barrels necessary to cover the same amount of expenditures. In 2008 this negative trend reversed resulting in a higher amount of booked reserves associated with the Company’s PSAs as the oil price recorded at 2008 year-end was lower than the previous year. 23 Table of ContentsThe table below show Eni’s calculations of its reserve replacement ratios for the years ended December 31, 2006, 2007 and 2008.
Proved developed reserves of subsidiaries at December 31, 2008 amounted to 3,948 mmBOE (2,009 mmBBL of liquids and 11,138 BCF of natural gas) representing 63% of total estimated proved reserves (64% and 63% at December 31, 2007 and 2006, respectively). Volumes of oil and natural gas applicable to long-term supply agreements with foreign governments in mineral assets where Eni is operator totaled 679 mmBOE as of December 31, 2008 (676 and 583 mmBOE as of December 31, 2007 and 2006, respectively). Said volumes are not included in reserves volumes shown in the table herein. The tables below set forth a geographical breakdown of Eni’s proved reserves and proved developed reserves of hydrocarbons, on a barrel of oil equivalent basis, for the periods indicated. Proved reserves Eni’s proved reserves of hydrocarbons by geographic area
Eni’s proved reserves of liquids by geographic area
24 Table of ContentsEni’s proved reserves of natural gas by geographic area
Eni’s proved developed reserves of hydrocarbons by geographic area
Eni’s proved developed reserves of liquids by geographic area
Eni’s proved developed reserves of natural gas by geographic area
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As of December 31, 2008, Eni’s mineral right portfolio consisted of 1,244 exclusive or shared rights for exploration and development in 39 countries on five continents, for a total net acreage of 415,494 square kilometers (394,490 at December 31, 2007). Of these 39,244 square kilometers concerned production and development (37,642 at December 31, 2007). Outside Italy net acreage (395,085 square kilometers) increased by 21,258 square kilometers mainly due to the acquisition of Burren Energy Plc for a total net exploration and development acreage of 9,569 square kilometers (mainly in Turkmenistan, Yemen, Congo and Egypt) and an increase of net exploration acreage in Mali. These increases were partly offset by the contractual revision in Libya. In addition, new exploration leases were awarded in Angola, Algeria, Alaska, the Gulf of Mexico, Gabon, Indonesia, Norway and the United Kingdom for a total acreage of 57,361 square kilometers (net to Eni, 99% operated). In Italy, net acreage (20,409 square kilometers) declined by 255 square kilometers due to releases. A total of 111 new exploratory wells were drilled in 2008 (58.4 of which represented Eni’s share), as compared to 81 exploratory wells completed in 2007 (43.5 of which represented Eni’s share). In addition, 21 exploratory wells were in progress at year end. The overall commercial success rate was 36.5% (43.4% net to Eni) as compared to 40% (38% net to Eni) in 2007. In 2006, 68 exploratory wells were completed (35.9 of which represented Eni’s share), with an overall success rate of 43% (the success rate of Eni’s share of exploratory wells was 49%).
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 2008, oil and natural gas production available for sale averaged 1,748 KBOE/d (liquids 1,026 KBBL/d; natural gas 4,143 mmCF/d), an increase of 64 KBOE/d, or 3.8%, compared to 2007. This improvement mainly came from the assets acquired in the Gulf of Mexico, Congo and Turkmenistan (up 62 KBOE/d), as well as continuing production ramp-up in Angola, Congo, Egypt, Pakistan and Venezuela. This increase was partially offset by mature field declines as well as planned and unplanned facility downtime in the North Sea and hurricane-related impacts in the Gulf of Mexico (down 11 KBOE/d). Higher oil prices on a yearly average resulted in lower volume entitlements in Eni’s PSAs and similar contractual schemes, down approximately 37 KBOE/d. When excluding the impact of lower entitlements in PSAs, production was up 5.6%. The share of oil and natural gas produced outside Italy was 89% (88% in the full year 2007). Production of liquids amounted to 1,026 KBBL/d and was up 0.6% from a year ago. The most significant increases were registered in: (i) the Gulf of Mexico, Congo and Turkmenistan due to the contribution of acquired assets; (ii) Angola due to the start-up of the Mondo and Saxi/Batuque fields in the development area of former Block 15 (Eni’s interest 20%); and (iii) Venezuela due to the start-up of the Corocoro field (Eni’s interest 26%). Production decreases were reported in the North Sea and Italy due to planned and unplanned facility downtime and mature field declines. In addition, lower volume entitlements associated with higher average yearly oil prices were reported in the Company’s PSAs. Production of natural gas for the full year was 4,143 mmCF/d and increased by 324 mmCF/d, or 8.5%, from a year ago. The improvement was driven by growth in the Gulf of Mexico, due to the contribution of acquired assets, and Pakistan due to production ramp-up of the Zamzama field (Eni’s interest 17.25%) and start-up of the Badhra field (Eni operator with a 40% interest). Production decreased in Italy and the United Kingdom due to mature field declines. Oil and gas production sold in 2008 amounted to 632 mmBOE. Approximately 53% of liquids production sold (370.2 mmBBL) was destined to Eni’s Refining & Marketing division; about 32% of natural gas production sold (1,503 BCF) was destined to Eni’s Gas & Power division.
Table of ContentsThe tables below set forth Eni’s production of liquids and natural gas on an available-for-sale basis for the periods indicated.
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 93 KBOE/d, 75 KBOE/d and 57 KBOE/d in 2008, 2007 and 2006, respectively.
Table of ContentsThe table below sets forth certain information and operating data regarding Eni’s principal oil and natural gas interests as of December 31, 2008. Principal oil and natural gas interests at December 31, 2008
Eni’s principal regions of operations are described below. In the discussion that follows references to hydrocarbon production are to be intended to hydrocarbon production available for sale. 28 Table of Contents
29 Table of Contentssidetracking and infilling (Antares, Cervia, Emma, Fratello North, Giovanna, Hera-Lacinia, Gela, Luna and Fiumetto); (ii) continuation of drilling and upgrading of producing facilities in the Val d’Agri; and (iii) completion of development activities at Cascina Cardana field and phase 1 of the Val d’Agri project. Other development activities were the development of the Annamaria and the Guendalina gas fields in the Adriatic Sea. The Annamaria project provides for the installation of a production platform and the linkage by sealines to the Fano plant. Start-up is expected in 2009. Actions on Guendalina include the installation of a platform and the linkage by existing facilities to the Ravenna plant. Start-up is expected in 2010. In December 2008 Eni was awarded two onshore exploration blocks in Puglia region. Major discoveries were made in offshore Sicily with the operated gas discovery Cassiopea that has yielded excellent results in addition to the positive appraisal of the Argo gas field. Eni holds a 60% interest in the two discoveries. In particular for Cassiopea an accelerated development plan is foreseen in order to provide optimal synergies with the nearby Panda and Argo discoveries. The project provides for the drilling of undersea producing wells and the installation of a production platform linked to the existing onshore treatment facilities. Production start up is expected in 2011. In the medium-term, management expects production in Italy to remain stable at current level due to the production ramp-up of the Val d’Agri fields and ongoing new field project and continuing development activities designed to counteract mature field decline.
Eni’s operations in North Africa are conducted in Algeria, Egypt, Libya and Tunisia. In 2008, North Africa accounted for 36% of Eni’s total worldwide production of oil and natural gas. Algeria. Eni has been present in Algeria since 1981. In 2008, Eni’s oil and gas production averaged 80 KBOE/d. Operating activities are located in the Bir Rebaa area in the South-Eastern desert and include the following exploration and production blocks: (a) Blocks 403 a/d (Eni’s interest 100%); (b) Blocks 401a/402a (Eni’s interest 55%); (c) Blocks 403 (Eni’s interest 50%) and 404a (Eni’s interest 12.25%); and (d) under development Blocks 212 (Eni’s interest 22.38%) and 208 (Eni’s interest 12.25%).
30 Table of ContentsRhourde Messaoud and Zemlet Adreg development licenses for further 10 years and the Bir Rebaa North license for further 5 years. Production in Blocks 401a/402a is supplied mainly by the Rod and satellite fields and accounted for approximately 23% of Eni’s production in Algeria in 2008. Infilling activities are being performed in order to maintain the current production plateau. The main fields in Block 403 are BRN, BRW and BRSW and accounted for approximately 14% of Eni’s production in Algeria in 2008. Exploration activities for appraising the mineral potential of the area are planned. Block 208 is located south of Bir Rebaa. The El Merk Synergy, designed to jointly develop of this block and adjoining blocks operated by other companies, is the main project underway in Algeria. In 2008 following an international bid procedure, the seven EPC contracts of the project have been awarded. The project provides for the construction of a new treatment plant with a capacity of 11 KBOE/d net to Eni and production facilities in Block 404/208. Start-up is expected in the first quarter of 2012. Main discoveries for the year were achieved in: (a) the Block 401a/402a with the ROD-21 appraisal well that started production through existing facilities; (b) the Block 404a with the BKNE-24 and HBNSE-12 appraisal wells, with the latter starting production through existing facilities. The new Algerian hydrocarbon law No. 05 of 2007 introduced a higher tax burden for the national oil company Sonatrach that requested to renegotiate the economic terms of certain PSAs in order to restore the initial economic equilibrium. Eni signed an agreement for Block 403 while negotiations are ongoing for Block 401a/402a (Eni’s interest 55%) and Block 208 (Eni’s interest 12.25%). At present, management is not able to foresee the final outcome of such renegotiations. In the medium-term, management expects to increase Eni’s production in Algeria to approximately 110 KBOE/d, reflecting the development and integration of the First Calgary acquired assets. Egypt. Eni has been present in Egypt since 1954. In 2008, Eni’s share of production in this country amounting to 232 KBOE/d and accounted for 13% of Eni’s total annual hydrocarbon production. Eni’s main producing liquid fields are located in the Belayim concession (Eni’s interest 100%) and offshore the Gulf of Suez. Gas production mainly comes from the operated or participated concession of North Port Said (former Port Fouad, Eni’s interest 100%), Baltim (50% interest), Ras el Barr (50% interest, non-operated) and el Temsah (50% interest) offshore the Nile Delta. In 2008 production from these concessions also including a portion of liquids accounted for 90% of Eni’s production in Egypt.
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In the medium-term, management expects production in Egypt to be one of Eni’s largest oil and gas producing countries. Libya. Eni started operations in Libya in 1959. In 2008, Eni’s oil and gas production averaged 300 KBOE/d, the portion of liquids being 48%. Production activity is carried out in the Mediterranean offshore facing Tripoli and in the Libyan Desert area. In June 2008, Eni and the Libyan national oil company NOC finalized six Exploration and Production Sharing contracts (EPSA) converting the original agreements that regulated Eni’s exploration and development activities in the country. The terms of Eni’s assets in Libya have been extended till 2042 and 2047 for oil and gas properties respectively. The two partners have also agreed to develop a number of industrial initiatives designed to monetize the large reserve base, particularly through the implementation of important gas projects. The economic effects and Eni’s production entitlements based on the new contracts have been determined effective from January 1, 2008. Under above agreement the Eni’s assets have been grouped into six contract areas as follows: (i) area A including 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 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, Eni is operator of four onshore blocks in the Muzurk basin (161/1, 161/2&4, 176/3) and in the Kufra area (186/1, 2, 3 & 4). The tax burden on Eni’s taxable profit has been determined based on the renewed tax framework, enacted in 2007, applicable to foreign oil companies operating under PSA schemes. In line with past practice, NOC has retained the role of tax agent on behalf of foreign oil companies. This tax regime does not alter the agreed economic value of the EPSAs currently in place between Eni and NOC. Based on the arrangements agreed upon with NOC, the tax base of the Company’s Libyan oil properties has been reassessed resulting in the partial utilization of previously accrued deferred tax liabilities amounting to euro 173 million. 32 Table of Contents
Tunisia. Eni has been present in Tunisia since 1961. In 2008, Eni’s production amounted to 15 KBOE/d. Eni’s activities are located mainly in the Mediterranean offshore facing Hammamet and in the Southern desert areas. Exploration and production in this country are regulated by concessions. Production mainly comes from the Adam (Eni operator with a 25% interest), Oued Zar (Eni operator with a 50% interest), MLD (Eni’s interest 50%) and El Borma (Eni’s interest 50%) onshore blocks. The ongoing development activities mainly regarded the optimization of production at the Adam, Oued Zar, MLD and El Borma concessions. Development activities started also at the production platform of the Maamoura (Eni’s interest 49%) and Baraka (Eni’s interest 49%) fields. Production start-up is expected in 2009. Main discoveries for the year were achieved in the following permits: (a) Adam, where the Mejda-1 and El Azzel North-1 wells showed the presence of oil; (b) Bek (Eni operator with a 25% interest), where the Abir-1 well found oil and natural gas; (c) MLD, where the LASSE-1 well found oil and natural gas; and (d) El Borma, where the EB-406 exploratory well showed additional oil resources. In the medium-term, Eni expects production in Tunisia to increase due to the development of recent discoveries.
Eni’s operations in West Africa are conducted in Angola, Congo and Nigeria. In 2008, West Africa accounted for 19% of Eni’s total worldwide production of oil and natural gas. Angola. Eni has been present in Angola since 1980. In 2008, Eni’s production averaged 121 KBOE/d. Eni’s activities are concentrated in the conventional and deep offshore. 33 Table of Contents
Development at the Landana and Tombua oil fields in offshore Block 14 (Eni’s interest 20%) progressed. Early production is ongoing in the north area of Landana that was linked to the Benguela/Belize-Lobito/Tomboco facilities. Production is expected to peak at 100 KBBL/d in 2010 at the end of the drilling program. Activities at the Banzala oil field in Block 0 in Cabinda (Eni’s interest 9.8%) progressed as planned. The commissioning of a third production platform was achieved early 2008. Peak production at 27 KBBL/d (3 net to Eni) is expected in 2009. Mafumeira project in Block 0 also progressed according to schedule toward first production expected in 2009. With respect to the activities for gas flaring reduction, projects progressed at the Takula and Nemba fields in Block 0. The start-up of Takula project is expected in 2009. Gas currently flared will be re-injected in the field; condensates will be shipped via a new pipeline to the Malongo treatment plant to be converted into LPG. Development activities at the Nemba field are planned including the drilling of gas injection wells and the installation of a new production platform. Start-up is expected in 2011. The Mondo and Saxi/Batuque fields in Block 15 (Eni’s interest 20%) were started-up by means of a floating, production, storage and offloading (FPSO) vessel. Peak production at 100 KBBL/d (18 KBBL/d net to Eni) was achieved at both fields in 2008. The outlined projects and other ongoing development activities aim at maintaining current oil production plateau in the area. In 2008 the final investment decision was achieved regarding the development of the Kizomba Satellites project-phase 1. The project plans to produce reservoir of the Clochas and Mavacola oil discoveries. Start-up is expected in 2012. Eni holds a 13.6% interest in the Angola LNG Limited (A-LNG) consortium responsible for the construction of an LNG plant in Soyo, 300 kilometers north of Luanda. It will be designed with a processing capacity of 1 BCF/y of natural gas and produce 5.2 mmtonnes/y of LNG and related products. The project has been sanctioned by relevant Angolan authorities. It envisages the development of 10,594 BCF of associated gas reserves in 30 years. Gas volumes currently being produced from offshore production blocks are flared. In 2008 the final investment decision was reached to build a pipeline linking the fields located in Blocks 0 and 14 to LNG plant in order to monetize gas currently flared. Start-up is expected in 2012. 34 Table of ContentsMain oil discoveries for the year were made in: (a) Block 15/06, with the Ngoma-1 and Sangos-1 discoveries. Both discoveries were declared of commercial interest; (b) Block 0, with the Kambala appraisal well; (c) the development area of former Block 14, with the Lucapa-5 appraisal well; and (d) the development area of former Block 15 with the Mavacola-3 appraisal well. In the medium-term, management expects to increase Eni’s production to approximately 150 KBBL/d reflecting contributions from ongoing development projects, despite mature field declines.
Eni plans to monetize the heavy oil by applying its EST (Eni Slurry Technology) proprietary technology intended to fully convert the heavy oil into high quality light products. The project will also benefit from synergies resulting from the close proximity of the operated M’Boundi oilfield; (ii) collaboration in the use of vegetable oils, aimed at covering domestic demand for food uses and using excess amounts for the production of bio-diesel with Eni’s proprietary technology Ultra-Bio-Diesel; and (iii) construction of a 450 MW electricity generation plant near the Djeno oil terminal, with start-up expected in late 2009. The power station (Eni’s share 20%) will be fired with the associated natural gas from the M’Boundi field and offshore discoveries in permit Marine XII (Eni operator with a 90% interest) contributing to the reduction of gas flaring. The final investment decision was reached in 2008. This project aims at qualifying as Clean Development Mechanism in implementing the Kyoto protocol and as a contribution to the sustainable development of the Country. The Awa Paloukou (Eni’s interest 90%) and Ikalou-Ikalou Sud (Eni’s interest 100%) operated fields in the Marine X and Madingo permits were started up in 2008 with production peaking at 13 KBOE/d net to Eni in 2009. Development activities of the M’Boundi field moved forward with the revision of the production schemes and layout to plan application of advanced recovery techniques and a design to monetize associated gas. In the medium-term, management expects to increase Eni’s production in Congo due to the integration and development of recently acquired assets as well as projects underway, targeting a level in excess of 140 KBBL/d in 2012. Nigeria. Eni has been present in Nigeria since 1962. In 2008, Eni’s oil and gas production averaged 119 KBOE/d located mainly in the onshore and offshore of the Niger Delta. 35 Table of Contents
In the development/production phase Eni is operator of onshore Oil Mining Leases (OML) 60, 61, 62 and 63 (Eni’s interest 20%) and offshore OML 125 (Eni’s interest 85%), OMLs 120-121 (Eni’s interest 40%) and holds a 12.5% interest in OML 118 as well as in OML 119 and 116 service contracts. Through SPDC JV oil joint venture, Eni also holds a 5% interest in 31 onshore blocks and a 12.86% interest in 5 conventional offshore blocks. In the exploration phase Eni is operator of Oil prospecting Leases (OPL) 244 (Eni’s interest 60%), OML 134 (former OPL 211 - Eni’s interest 85%) 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 (former OPL 219). In December 2008 Eni exercised its pre-emption rights on the remaining 49.81% interest in Blocks OML 125 and 134. On the same occasion Eni transferred a 15% stake to the Nigerian company OANDO. This transaction has been approved by relevant authorities. Exploration and production activities in Nigeria are regulated mainly by Production Sharing Agreements and concession contracts as well as service contracts, where Eni acts as contractor for state owned companies. In Blocks OMLs 60, 61, 62 and 63 development activities of gas reserves are underway: (i) the basic engineering work for increasing capacity at the Obiafu/Obrikom plant was completed. The project also provides for the installation of a new treatment plant and transport facilities; and (ii) the development plan of the Tuomo gas field has been progressing. Production is expected to start by means of linkage to the Ogbainbiri treatment plant. These activities target to supply 311 mmCF/d of feed gas to the Bonny liquefaction plant (Eni’s interest 10.4%) for a period of 20 years. In the OML 118, Bonga field produced about 19 KBOE/d net to Eni via a FPSO unit with a 225 KBBL/d treatment capacity. The associated gas is gathered into a platform in EA field and then delivered to the Bonny liquefaction plant. In the OML 119, Okono/Okpoho production reached about 12 KBBL/d net to Eni via a FPSO unit with a 40 KBBL/d treatment capacity. In the OMLs 120/121 blocks (Eni operator with a 40% interest), the development plan of the Oyo oil discovery was approved. The project provides for the installation of an FPSO unit with treatment capacity of 40 kBBL/d and storage capacity of 1 mmBBL. Production start-up is expected in 2009. 36 Table of ContentsThrough the SPDC JV, the Forcados/Yokri oil and gas field is under development as part of the integrated associated gas gathering project aimed at supplying gas to the Bonny liquefaction plant. Offshore production facilities have been installed. Onshore activities regard the upgrading of the Yokri and North/South Bank flow stations and the construction of a gas compression plant with a 233 mmCF/d capacity. Completion is expected in 2009. In the OML 125, oil production deriving from Abo field. Ongoing development activities aim at reaching a peak production of 27 KBBL/d (18 KBBL/d net to Eni) in 2009. Production is supported by an FPSO unit with a 45 KBBL/d capacity and an 800 KBBL storage capacity. Eni holds a 10.4% interest in Nigeria LNG Ltd that manages the Bonny liquefaction plant located in the Eastern Niger Delta, with a treatment capacity of approximately 1,236 BCF/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on 6 trains. The seventh unit is being engineered with start-up expected in 2012. When fully operational, total capacity will amount to approximately 30 mmtonnes/y of LNG, corresponding to a feedstock of approximately 1,624 BCF/y. Natural gas supplies to the plant are provided under gas supply agreements with a 20-year term from the SPDC joint venture (Eni’s interest 5%) and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63. In 2008 total supplies were 3,461 mmCF/d (268 mmCF/d net to Eni, corresponding to 46 KBOE/d). LNG production is sold under long-term contracts and exported to European and American markets by the Bonny Gas Transport fleet, wholly-owned by Nigeria LNG Co. Eni is operator with a 17% interest of the Brass LNG Ltd Company for the construction of a natural gas liquefaction plant to be built near the existing Brass terminal. This plant is expected to start operating in 2014 with a production capacity of 10 mmtonnes/y of LNG corresponding to 618 BCF/y (approximately 64 net to Eni) of feed gas on 2 trains for twenty years. Supplies to this plant will derive from the collection of associated gas from nearby producing fields and from the development of gas reserves in the OMLs 60 and 61 onshore blocks. The venture signed preliminary long-term contracts to sell the whole LNG production capacity. Eni acquired 1.67 mmtonnes/y of LNG capacity. The front end engineering is underway and the final investment decision is expected in 2009. In the medium-term, management expects to increase Eni’s production in Nigeria to approximately 200 KBOE/d, reflecting in particular the development of gas reserves.
Eni’s operations in the North Sea area are conducted in Norway and United Kingdom. In 2008, the North Sea accounted for 13% of Eni’s total worldwide production of oil and natural gas.
37 Table of Contents
Currently Eni is only performing exploration activities in Barents Sea. Operations in this area are focused on the appraisal of the mineral potential of the large Goliath discovery made in 2000 at a water depth of 370 meters in PL 229 (Eni operator with a 65% interest) aimed at its commercial development. The project is progressing according to schedule. Commencement is expected in 2013 with a production plateau at 100 kBBL/d. In 2008 contracts were awarded for the study of two possible development plans by means of a cylindrical FPSO unit. The final investment decision is expected in 2009. Main discoveries for the year were achieved in the: (a) Prospecting License 312 (Eni’s interest 17%) with the Gamma gas discovery at a depth of about 2,500 meters. Production will be treated at the nearby Aasgaard facilities; (b) the Prospecting License 122 (Eni operator with a 20% interest), where appraisal activities confirmed the mineral potential of the Marulk discovery; (c) the Prospecting License 293 (Eni operator with a 45% interest), with the gas and condensate Aphrodite discovery. Ongoing pre-development activities aim to assessing the economic viability of the project; and (d) Prospecting License 128 (Eni’s interest 11.5%) with the Dompap gas discovery at a depth of about 2,750 meters. Appraisal activities are underway. United Kingdom. Eni has been present in the United Kingdom since 1964. Eni’s activities are carried out in the British section of the North Sea, in the Irish Sea and in some areas East and West of the Shetland Islands. In 2008 Eni’s net production of oil and gas averaged 104 KBOE/d. Exploration and production activities in the United Kingdom are regulated by concession contracts. In November 2008, Eni finalized an agreement with the British company Tullow Oil to purchase a 52% stake and the operatorship of fields in the Hewett Unit in the British section of the North Sea and relevant facilities including the associated Bacton terminal. Eni acquired operatorship of the assets with an 89% interest. Eni aims to upgrade certain depleted fields in the area so as to achieve a gas storage facility with a 177 BCF working gas capacity to support seasonal upswings in gas demand in the UK leveraging on the strategic purchased facilities. The Bacton terminal, in fact, is very close to the incoming point of the Interconnector pipeline connecting the United Kingdom with Europe. For this purpose, Eni intend to request a storage license. In December 2008 following an international bid procedure, Eni was awarded four exploration blocks with a 22% interest located in the Shetland Islands. One of the awarded blocks is located near the Tormore (Eni’s interest 20%) and Laggan (Eni’s interest 20%) recent gas discoveries in the North Sea. 38 Table of Contents
Eni holds interests in 12 production areas in the British section of the North Sea. The main fields are Elgin/Franklin (Eni’s interest 21.87%), the J-Block (Eni’s interest 33%), Andrew (Eni’s interest 16.21%), Farragon (Eni’s interest 30%), the Flotta Catchment Area (Eni’s interest 20%) and Mac-Culloch (Eni’s interest 40%) which in 2008 accounted for 63% of Eni’s production in the United Kingdom. Development activities progressed at the West Franklin field (Eni’s interest 21.87%) by completing a second development well planned. The production is supported by facilities of the nearby Elgin/Franklin field which peaked at 20 KBOE/d (4 net to Eni). Other activities related to: (i) optimization of production in the J-Block through the upgrading of existing facilities; and (ii) infilling actions at the Flotta Catchment Area and Mac-Culloch fields targeting to maintain production levels. Development activities started at the Burghely field (Eni’s interest 21.92%). Pre-development activity continued on the Suilven discovery (Eni’s interest 8.75%). Eni holds a 53.9% interest in 6 production fields in the Liverpool Bay area in the Eastern section of the Irish Sea. Main fields are Douglas, Hamilton and Lennox and their extension which in 2008 accounted for 24% of Eni’s production in UK. Facilities upgrading is underway. Eni holds interest in 6 production permits located East of the Shetland Islands. Main fields are Ninian (Eni’s interest 12.94%) and Magnus (Eni’s interest 5%) which in 2008 accounted for 4% of Eni’s production in the United Kingdom. In 2008 maintenance and optimization actions were performed with the drilling of infilling wells. Main discoveries for the year were achieved in the: (i) Block 16/23 (Eni’s interest 16.67%) with the Kinnoul oil and gas discovery which is planned to be developed in synergy with the production facilities of the Andrew field (Eni’s interest 16.21%); (ii) Block 30/6 (Eni’s interest 33%) where gas and condensates were found near the recent Jasmine discovery. Joint development of these two structures is being assessed in combination with existing facilities; and (iii) Block 22/25a (Eni’s interest 16.95%) with the gas and condensate Culzean discovery near the Elgin/Franklin producing field (Eni’s interest 21.87%). Study of development activities is underway.
In 2008, Eni’s operations in the Caspian Area accounted for 7% of its total worldwide production of oil and natural gas. Kazakhstan. Eni has been present in Kazakhstan since 1992. Eni is co-operator of the Karachaganak field and, up to January 2009, acted as the single operator of the North Caspian Sea Production Sharing Agreement (NCSPSA) activities. 39 Table of Contents
As outlined above, on October 31, 2008, all the international partners of the NCSPSA consortium and the Kazakh authorities signed the final agreement implementing the new contractual and governance framework of the Kashagan project, based on the Memorandum of Understanding signed on January 14, 2008. The material terms of the agreement are: (i) the proportional dilution of the participating interest of all the international members of the Kashagan consortium, following which the stake held by the national Kazakh Company KazMunayGas and the stake held by the other four major stakeholders are each equal to 16.81%, effective from January 1, 2008. The Kazakh partner will pay the other co-ventures an aggregate amount of $1.78 billion; (ii) a value transfer package to be implemented through changes to the terms of the NCSPA, the amount of which will vary in proportion to future levels of oil prices. Eni is expected to contribute to the value transfer package in proportion to its new participating interest in the project (16.81%); and (iii) a new operating model which entails an increased role of the Kazakh partner and defines the international parties’ responsibilities in the execution of the subsequent development phases of the project. The new North Caspian Operating Company (NCOC) BV has been established and capitalized by the seven partners of the consortium. In January 2009 the new entity has taken over the operatorship of the project. Subsequently development, drilling and production activities have been delegated by NCOC BV to the main partners of the Consortium. Eni is confirmed to be the operator of phase-one of the project (the so-called "Experimental Program") and in addition will retain operatorship of the onshore operations of phase 2 of the development plan. In conjunction with the signing of the final agreements, the partners also reached a final approval of the revised expenditure budget of phase-one of the development plan, amounting to $32.2 billion (excluding general and administrative expenses) of which $25.4 billion related to the original scope of work of phase 1 (including tranches 1 and 2), with the remaining part planned to be spent to execute tranche 3 and build certain exporting facilities. Eni will fund those expenditures in proportion to its participating interest of 16.81%. Management expects to achieve first oil late in 2012 on the basis of progress to completion (55% of phase 1 of the project) and accumulated expertise and project know-how. In the following 12-15 months treatment facilities and compression units for gas re-injection will be entirely commissioned enabling the Consortium to deploy an installed production capacity of 370 KBBL/d in 2014. Subsequently, production capacity of phase-one (Experimental Program) is expected to step-up to 450 KBBL/d, leveraging on additional compression capacity for gas re-injection associated with the start-up of phase-two offshore facilities. In addition, within phase-one a rail terminal with carrying capacity at 300 KBBL/d of oil and 4,500 tonnes/d of sulphur will be built. 40 Table of ContentsThe development plan of the Kashagan field was originally sanctioned by the Kazakh authorities in February 2004, contemplating a three-phase development scheme including partial gas re-injection in the reservoir to enhance the recovery factor of the crude oil. The sanctioned plan budgeted expenditures amounting to U.S. $10.3 billion (in 2007 real terms) to develop phase-one, with a target production level of 300 KBBL/d. First oil was originally scheduled to be produced by the end of 2008. Eni was expected to fund these expenditures according to its participating interest in this project. On June 29, 2007, Eni, as operator, filed with the relevant Kazakh authorities amendments to the sanctioned development plan. These amendments rescheduled the production start-up to 2010 and estimated development expenditures for phase-one at U.S. $19 billion. As outlined above the amended development plan that was sanctioned in October 2008 forecast production start-up late in 2012 and an expenditure budget for phase one amounting to $25.4 billion. The production delay and cost overruns were driven by a number of factors: depreciation of the U.S. dollar versus the euro and other currencies; cost price escalation of goods and services required to execute the project; an original underestimation of the costs and complexity to operate in the North Caspian Sea due to lack of benchmarks; design changes to enhance the operability and safety standards of the offshore facilities. The magnitude of the reserves base, the results of the well tests conducted and the findings of subsurface studies completed so far support expectations for a full field production plateau of 1.5 mmBBL/d, which represents a 25% increase above the original plateau as presented in the 2004 development plan. An independent reserve evaluation performed by a petroleum engineer (Ryder Scott Petroleum Consultants) fully supports the target production plateau. The achievement of the full field production plateau will require a material amount of expenditures in addition to the development expenditures needed to complete the execution of phase-one. However, taking into account that future development expenditures will be incurred over a long time horizon, 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, for which various options are currently under review by the consortium. These include: (i) the use of existing infrastructure, such as the Caspian Pipeline Consortium pipeline (Eni’s interest 2%) and the Atyrau-Samara pipeline, both of which are expected to undergo a capacity expansion; (ii) the construction of a new transportation system. In this respect, it is worth mentioning the project aimed at building a line connecting the onshore Bolashak production centre with the Baku-Tbilisi-Cehyan pipeline (where Eni holds an interest of 5% corresponding to the right to transport 50 KBBL/d) through the KCTS pipeline to Kuryk and a further shipping across the Caspian Sea to Baku; and (iii) the construction of a new transport system linking Samsum on the Turkish coast of the Black Sea to Cehyan on the Mediterranean coast in order to bypass the Turkish Straits of Bosporus and Dardanelles. As of December 31, 2008, Eni’s proved reserves booked for the Kashagan field amounted to 594 mmBOE determined according to Eni’s participating interest of 16.81%, recording an increase of 74 mmBOE with respect to 2007 despite the divestment of a 1.71% stake in the Kashagan project following the finalization of the agreements implementing the new contractual and governance framework of the project. The amount booked for the year reflected higher volume entitlements resulting from lower year end oil prices from a year ago and upward revisions of previous estimates which were supported by an independent evaluation of the field made by an oil engineering company (Ryder Scott Petroleum Consultants). As of December 31, 2007, Eni’s proved reserves booked for the Kashagan field amounted to 520 mmBOE, recording a decrease of 76 mmBOE with respect to 2006 mainly due to the impact of increased year-end oil prices on reserve entitlements in accordance with the PSA scheme. Proved reserves for the field as of December 31, 2007 were determined according to Eni’s then current participating interest of 18.52%. As of December 31, 2006, Eni’s proved reserves booked for the Kashagan field amounted to 596 mmBOE, recording an increase of 107 mmBOE with respect to 2005 due to an extension of the proved area and project cost revision, offset in part by the impact of price revisions. As of December 31, 2008, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $3.3 billion (euro 2.4 billion at the EUR/USD exchange rate of December 31, 2008) net of the divestment of a 1.71% stake in the Kashagan project following the finalization of the agreements implementing the new contractual and governance framework of the project ($0.4 billion). This capitalized amount included: (i) $2.3 billion relating to expenditures incurred by Eni for the development of the oilfield; and (ii) $1 billion relating primarily to accrued finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre-emption rights in previous years. As of December 31, 2007, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $2.6 billion. This capitalized amount included: (i) $1.8 billion relating to expenditures incurred by Eni for the development of the oilfield; and (ii) $0.8 billion relating primarily to accrued finance charges and expenditures for the acquisition of interests in the North Caspian Sea PSA consortium from exiting partners upon exercise of pre emption rights in previous years. The $2.6 billion amount was equivalent to euro 1.8 billion based on the 2007 year-end euro /U.S. dollar exchange rate. 41 Table of ContentsAs of December 31, 2006 the aggregate costs incurred by Eni for the Kashagan project that were capitalized by Eni in its financial statements amounted to $1.9 billion, corresponding to euro 1.5 billion based on 2006 year-end exchange rates. Costs borne by Eni to explore and develop this field are recovered in accordance with the mechanisms typically contemplated by a PSA scheme, which is widely used in the industry. In this type of contract the national oil company or State-owned entity assigns to the international oil company (the contractor) the task of performing exploration and production with the contractor’s equipment and financial resources. Exploration risks are borne by the contractor and production is generally 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. Accordingly, recoverability of the expenditures is subject to approval from the relevant State-owned or controlled entity who is party to the agreement. Similarly, cost overruns are recovered to the extent they are sanctioned by the State-owned or controlled entity who is party to the agreement. Karachaganak. Located in West onshore Kazakhstan, Karachaganak is a liquid and gas field. Operations are conducted by the Karachaganak Petroleum Operating consortium (KPO) and are regulated by a Production Sharing Agreement lasting 40 years, until 2037. Eni and British Gas are co-operators of the venture both with a 32.5% interest. In 2008 production from this field averaged 234 KBBL/d of liquids (69 KBBL/d net to Eni) and 774 mmCF/d of natural gas (227 mmCF/d net to Eni). This field is developed by producing liquids from the deeper layers of the reservoir and re-injecting the associated gas in the higher layers. Approximately two thirds of liquid production are stabilized at the Karachaganak Processing Complex (KPC) with a capacity in excess of 150 KBBL/d and exported to Western markets through the Caspian Pipeline Consortium (Eni’s interest 2%) and the Atyrau-Samara pipeline. The remaining third of non-stabilized liquid production and volumes of associated gas not re-injected in the reservoir are marketed at the Russian terminal in Orenburg. The execution of fourth oil treatment unit has been progressed to completion and will enable to increase the exported oil volumes to Western markets. The Phase 3 project engineering activities have identified a staged approach to best develop the Karachaganak field. The first stage envisages the development of approximately 55 mmtonnes of liquids the doubling of the existing gas injection capacity (from 233 to 466 BCF/y) and the maintenance of a production plateau at 12 mmtonnes/y of stabilized liquids (until 2018) and 318 BCF/y of acid gas at Orenburg. An alternative option is under review which entails marketing of a portion of the additional gas re-injected. Start-up is expected late in 2013 subject to approval by the relevant authorities. The construction of the Uralsk Gas Pipeline is ongoing. This new infrastructure, with a length of 150 kilometers, will link the Karachaganak field to the Kazakhstan gas network. Start-up is expected in 2009. In April 2008, the Kazakh authorities approved a tax decree enacting an Export Duty on crude oil; such tax was applied on Karachaganak from July 2008 up to January 2009 when it was "zero rated". In the same month the authorities enacted a new tax code that does not affect the profitability of this project taking into account that certain clauses in the PSA regulating the activities at the field provide the stability of the tax burden for the ventures. As of December 31, 2008, Eni’s proved reserves booked for the Karachaganak field amounted to 740 mmBOE, recording an increase of 200 mmBOE with respect to 2007 and derived from upward revisions of previous estimates mainly related to higher entitlements reported in PSA resulting from lower year end oil prices from a year ago. As of December 31, 2007, Eni’s proved reserves booked for the Karachaganak field amount to 541 mmBOE, recording a decrease of 82 mmBOE with respect to 2006 as a result of downward and upward revisions of previous estimates. Downward revisions mainly related to an adverse price impact in determining volume entitlements in accordance with the PSA scheme. These negative revisions were partly offset by upward revisions mainly related to the finalization of the gas sale contract as outlined above. 42 Table of Contents
In 2008, Eni’s operations in the rest of world accounted for 14% of its total worldwide production of oil and natural gas. Australia. Eni has been present in Australia since 2000. In 2008 Eni’s production of oil and natural gas averaged 16 KBOE/d. Activities are focused on conventional and deep offshore fields. The main production blocks in which Eni holds interests are WA-25-L (Eni operator with a 65% interest) and JPDA 03-13 (Eni’s interest 10.99%). In the exploration phase Eni holds interests in 13 licenses (in 7 as operator and in 5 of which with a 100% interest), of particular interest are the blocks WA-33-L and WA-313-P, where the Blacktip and Penguin discoveries are located. Exploration and production activities in Australia are regulated by concessions, while in the cooperation zone between East Timor and Australia (Joint Petroleum Development Area - JPDA) they are regulated by PSAs. The main producing fields are Woollybutt and Bayu Undan in WA-25-L and JPDA03-13, respectively. In 2008 development activities have been completed in the southern area of the Woollybutt oil field with a new horizontal production well that was linked to an FPSO unit with relevant production ramp-up in July 2008. Development activities are underway at the Blacktip gas field (Eni operator with a 100% interest). The development strategy envisages installation of an unmanned platform that will be linked to an onshore treatment plant. Start-up is expected in 2009, peaking at 26 BCF/y in 2010. Natural gas production is destined to supply a power plant. In 2008, an important discovery was made in the Block JPDA 06-105 (Eni operator with a 40% interest), located in the international offshore cooperation zone between East Timor and Australia, where the Kitan discovery showed the presence of oil at a depth of 3,658 meters and yielded 6.1 KBBL/d in test production. In June 2008, the oilfield development area was approved by the Timor Sea Designated Authority pursuant to the declaration of commercial discovery that was made by Eni. Activities are ongoing for the preparation of a development plan to be filed with relevant authorities. The final investment decision is expected in 2009. In the medium-term, management expects to increase Eni’s production in Australia through ongoing development activities. Brazil. Eni has been present in Brazil since 1999 and is performing exploration activities in: (i) operated blocks BM-S-4 and BM-S-857, subjected official awarding, (both with a 100% interest) located in the deep offshore in the Santos basin; (ii) block BM-CAL-14 (Eni operator with a 100% interest) in the deep offshore in the Camamu-Almada basin. The current exploration program aims at appraising the Belmonte gas discovery in block BM-S-4. 43 Table of Contents
Ongoing development activities are mainly focused on the HZ25-4 and the HZ25-3/1 fields, on the latter the construction of a production platform is ongoing and start-up is expected in 2009. The development plan of the HZ25-4 field, on stream since 2007, provides for the drilling of addition producing wells as planned. Colombia. In 2008 Eni signed a Memorandum of Understanding with the national oil company Ecopetrol aimed at identifying joint opportunities for exploration and production in Colombia and in other Southern American countries.
East Timor. Eni entered East Timor in 2006 and is operator with an 80% interest of 5 offshore blocks. The first exploration phase of the exploration plan with a three-year term provides for the acquisition seismic data which was completed during the year, and the drilling of 2 wells. Ecuador. Eni has been present in Ecuador since 1988. In 2008 Eni’s production averaged 16 KBBL/d. Since 2000, Eni became operator of Block 10 (Eni’s interest 100%) located in the Amazon forest and on which Villano field has been discovered. Exploration and production activities in Ecuador are regulated by a service contract. 44 Table of ContentsProduction derives from the Villano field, started-up in 1999. Production is carried out by means of a Central Production Facility linked by pipeline to the storage facility. During the year work-over and infilling activities were aimed to contrast the natural depletion. India. Eni has been present in India since 2005. In August 2008, Eni acquired control of the Indian Company Hindustan Oil Exploration Ltd (HOEC) following execution of a mandatory tender offer on a 20% stake of the HOEC share capital. The mandatory offer was associated with Eni’s acquisition of a 27.18% of HOEC as part of the Burren Energy deal. Assets acquired, located onshore in the Cambay Basin and offshore Chennai, include: (i) development and producing assets which are expected to reach a production plateau of 10 KBOE/d in 2010; and (ii) fields where exploration and appraisal activities are underway. Main development activities are focused on the PY1 gas field. Start-up is expected in 2009. Other activities are related to exploration of the onshore Block RJ-ONN-2003/1 (Eni operator with a 34% interest) and offshore Blocks AN-DWN-2003/2 (Eni operator with a 40% interest) and MN-DWN-2002/1 (Eni’s interest 34%). The exploration program for Block RJ-ONN-2003/1 located in the desert of Rajasthan provides for the drilling of 4 wells in the first four years of the license. Any hydrocarbons discovered will be sold locally. The exploration program for Block AN-DWN-2003/2 near the Andaman Islands provides for the drilling of 3 wells in the first four years of the license and expected start-up in 2010. The exploration program for Block AN-DWN-2002/1 located in the deep offshore of the eastern coast provides for the drilling of 3 wells in the first year of the license. Indonesia. Eni has been present in Indonesia since 2000. Eni’s production amounted to 16 KBOE/d, mainly gas, in 2008. Activities are concentrated in the eastern offshore and onshore of Borneo and the offshore Sumatra, where Eni holds interest in 11 blocks. In May 2008, following an international bid procedure, Eni was awarded the operatorship of the West Timor exploration block extending over an offshore and onshore area of about 4,000 square kilometers. Exploration and production activities in Indonesia are regulated by PSAs. Production consists mainly of gas and derives from the Sanga Sanga permit (Eni’s interest 37.81%) with seven production fields. This gas is treated at the Bontang liquefaction plant, one of the largest in the world, and is exported to the Japanese, South Korean and Taiwanese markets. Eni as operator is evaluating major development opportunities in the Bukat permit (Eni’s interest 66.25%) where oil and gas discoveries were recently made. Eni, as partner, is also involved in the ongoing joint development of the five discoveries in the Kutei Deep Water Basin area (Eni’s interest 20%), gas production of which will be sent to the Bontang LNG plant. During 2008, the exploration activity was focused: (i) in the Krueng Mane permit (Eni operator with a 85% interest), with the start-up of the drilling activities; and (ii) in the Bukat permit, with the finalization of a seismic data acquisition campaign. Iran. Eni has been present in Iran since 1957. In 2008 Eni’s production averaged 28 KBBL/d. Activities are concentrated in the offshore and onshore facing of the Persian Gulf. Exploration and production activities in Iran are regulated by buy-back contracts. The main producing fields are South Pars phases 4&5 in the offshore of the Persian Gulf and Darquain field located onshore which accounted for 91% of Eni’s production in Iran in 2008. Eni also holds interests in the Dorood field (Eni’s interest 45%). The main project regards the Darquain field operated by Eni with a 60% interest. Upgrading activities are underway by means of drilling additional wells, increasing capacity of the existing treatment plant and gas injection. These actions aim at increasing production from the present 100 KBBL/d to over 160 KBBL/d (14 net to Eni) by 2009. The legislation and other regulations of the United States of America impose sanctions on this country and may lead to the imposition of sanctions on any persons doing business in this country or with Iranian counterparties. Particularly, under the Iran Sanctions Act of 1996 (as amended, "ISA"), which implements sanctions against Iran with the objective of denying it the ability to support acts of international terrorism and fund the development or acquisition 45 Table of Contentsof weapons of mass destruction, upon receipt by the U.S. authorities of information indicating potential violation of this act, the President of the United States is authorized to start an investigation aiming at possibly imposing sanctions from a six-sanction menu against any person found in particular to have knowingly made investments of U.S. $20 million or more in any twelve-month period, contributing directly and significantly to the enhancement of Iran’s ability to develop its hydrocarbons resources. Furthermore, the ISA envisages that the President of the United States is bound to impose sanctions against any persons that knowingly contribute to certain military programs of Iran, effective on June 6, 2006. Eni cannot predict interpretations of, or the implementation policy of the U.S. Government under, ISA with respect to Eni’s current or future activities in Iran or other areas. Eni has incurred capital expenditures in excess of U.S. $20 million in Iran in each of the last 9 years. Management expects to continue investing in Iran yearly amounts in excess of that threshold in the foreseeable future. Eni’s current activities in Iran are primarily limited to carrying out residual development activities relating to certain buyback contracts it entered into in 2000 and 2001 and no sanctions have ever been imposed on Eni’s activities in the country. It is possible that in future years Eni’s activities in Iran may be sanctioned under relevant U.S. legislation. Pakistan. Eni has been present in Pakistan since 2000. In 2008 Eni’s production averaged 54 KBOE/d, mainly gas. Exploration and production activities in Pakistan are regulated by concessions (onshore) and PSAs (offshore). In March, 2009 Eni signed a Protocol for Cooperation with the government of Pakistan to develop a number of important upstream, midstream and downstream projects in the Country. This deal follows Eni’s growth strategy through the discovery of new reserves. Eni will provide its expertise as well as new technologies developed in the oil and gas sector, mainly in the exploration and production of hydrocarbon fields. Eni’s main permits are Bhit (Eni operator with a 40% interest), Sawan (Eni’s interest 23.68%) and Zamzama (Eni’s interest 17.25%), which in 2008 accounted for 90% of Eni’s production in Pakistan. As part of the reserve development of the Bhit permit the operations of a third treatment unit started increasing the plant capacity by 46 mmCF/d and allowing the start-up of the satellite Badhra field. Other activities were targeted at optimizing production from the Kadanwari, Miano, Sawan and Zamzama fields by means of the drilling additional wells and upgrading the existing facilities. Main discoveries for the year were made in: (a) the Mubarak Block (Eni’s interest 38%) with the Saquib gas discovery which was tested at a production rate of 2,472 KCF/d; and (b) the Latif exploration license, where the Latif-2 appraisal well has confirmed the hydrocarbon potential of the area. Papua New Guinea. In 2008 Eni signed a Partnership Agreement with Papua New Guinea for the start of an exploration program aimed at identifying development opportunities and oil and gas projects. The agreement provides also for projects in electrical power generation and unconventional and renewable energy sources, which will foster sustainable development in this country. Qatar. In 2008 Eni signed a Memorandum of Understanding with the state-owned company Qatar Petroleum International to target joint investment opportunities in the exploration and production of oil and gas. The agreement also envisages the development of joint projects in the petrochemical industry and power generation.
46 Table of ContentsSambugorskoye currently under development and Urengoiskoye. The final investment decision for both fields is expected in 2009 with production start-up in 2010; (ii) ZAO Urengoil Inc owns exploration and development licenses for the Yaro-Yakhinskoye gas and condensates field. Ongoing are representend by workovers of some existing wells and by new seismic acquisition; and (iii) OAO Neftegaztechnologia owns the exploration and development license of the Severo-Chasselskoye field where an acquisition of seismographic data is underway. Other activities concern exploration in the Karalatskiy block (Eni’s interest 54%) in the Astrakhan region. This exploration license is part of the assets acquired from Burren Energy Plc. Saudi Arabia. Eni entered Saudi Arabia in 2004 and is performing exploration activities in the so called C Area in order to discover and develop gas reserves. This license is located in the Rub Al Khali basin at the border with Qatar and the United Arab Emirates. The exploration plan provides for the drilling of 4 wells in five years. In case of a commercial discovery, the contract will last 25 years with a possible extension to a maximum of 40 years. Any gas discovered will be sold locally for power generation and as feedstock for petrochemical plants. Condensates will be sold on international markets. Trinidad and Tobago. Eni has been present in Trinidad & Tobago since 1970. In 2008 Eni’s production averaged 55 mmCF/d. Activity is concentrated offshore north of Trinidad. Exploration and production activities in Trinidad & Tobago are regulated by PSAs. Production is provided by the Chaconia, Ixora and Hibiscus gas fields in the North Coast Marine Area 1 Block (Eni’s interest 17.4%). Production is supported by fixed platforms linked to the Hibiscus treatment facility. Natural gas is used to feed trains 2, 3 and 4 of the Atlantic LNG liquefaction plant under long-term contracts. LNG production is sold in the United States, Spain and the Dominican Republic. The main development project concerns the Poinsettia, Bougainvillea and Heliconia fields. The project provides for the installation of a production platform on Poinsettia and linked to the Hibiscus treatment facility, due to be upgraded. During the year drilling activity was started. Production start-up is expected in 2009. United States. Eni has been present in the United States since 1966. Activities are performed in the conventional and deep offshore in the Gulf of Mexico and more recently onshore and offshore Alaska. In 2008 Eni’s oil and gas production deriving mainly from the Gulf of Mexico averaged 86 KBOE/d.
47 Table of ContentsExploration and production activities in the United States are regulated by concessions. Eni holds interests in 412 exploration and production blocks in the Gulf of Mexico, 60% operated. The main fields operated by Eni with a 100% interest are Allegheny, East Breaks and Morphet as well as Devils Towers, Triton and Goldfinger (Eni operator with a 75% interest). Eni also holds interests in the Medusa (Eni’s interest 25%), Europa (Eni’s interest 32%), and King Kong (Eni operator with a 56% interest) fields. In March 2008, following an international bid procedure Eni was awarded 32 exploration blocks. The subsequent development phase will leverage synergies relating to the proximity of acquired acreage to existing operated facilities. In August 2008, Eni was awarded 5 exploration licenses in the Keathley Canyon area, one of the main exploration areas in the Gulf of Mexico. The blocks will be 100% operated by Eni. The transaction is subject to authorization from relevant authorities. In November 2008 Eni signed a cooperation agreement with the Colombian state company Ecopetrol for exploration assets in the Gulf of Mexico. Under the terms of this agreement, Ecopetrol will invest approximately $220 million to acquire a 20-25% interest in five exploration wells due to be drilled before 2012. The development program of the Longhorn discovery (Eni’s interest 75%) was sanctioned. The project provides for the installation of a fixed platform linked to three underwater wells. Start-up is expected in 2009 with peak production at 29 KBOE/d (about 20 net to Eni).
In June 2008, production started at the Oooguruk oil field (Eni’s interest 30%), in the Beaufort Sea, by linking to onshore facilities located on an artificial island. Peak production at 17 KBOE/d is expected in 2011. In the medium-term, management expects to increase Eni’s production due to the development and integration of assets acquired and the start-up of fields in Alaska, targeting at approximately 110 KBOE/d in 2012. Venezuela. Eni has been present in Venezuela since 1998. In 2008 Eni’s production averaged 5 KBBL/d. Activity is concentrated in the Gulf of Venezuela and in the Gulfo de Paira. 48 Table of ContentsExploration and production 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 Venezuela State oil company PDVSA, preferably Corporación Venezuelana de Petróleo (CVP). In February 2008, Eni and the Venezuelan Authorities reached a final settlement over the dispute regarding the expropriation of the Dación field which took place on April 1, 2006. Under the terms of the settlement, Eni will receive cash compensation in line with the carrying amount of the expropriated asset. Part of this cash compensation has been collected in the period. Eni believes this settlement represents an important step towards improving and strengthening cooperation with the PDVSA. As part of improving cooperation with PDVSA, the two partners signed two agreements in September 2008: (i) a joint study agreement for the development of the Junin Block 5 located in the Orinoco oil belt, covering a gross acreage of 670 square kilometers. Once relevant studies have been performed and a development plan defined, a joint venture between PDVSA and Eni will be established to execute the project. Eni intends to contribute its experience and leading technology to the project in order to maximize the value of the heavy oil; and (ii) an agreement for the exploration of two offshore areas, Blanquilla and Tortuga in the Caribbean Sea, both with a 20% interest over an area of 5,000 square kilometers. The prospective development of these areas will take place through an integrated LNG project. In 2008, production started at the Corocoro field (Eni’s interest 26%) in the Gulfo de Paira West Block. A second development phase is expected to be designed based on the results achieved in the first one regarding well production rate and field performance under water and gas injection. A production peak of 66 KBBL/d (17 net to Eni) is expected in 2012. Eni holds an interest of 50% in the Cardon IV offshore exploration block, covering an area of 938 square kilometers. Eni is participating with 19.5% interest in the Gulfo de Paira Centrale offshore exploration block, covering an area of 259 square kilometers, where the Punta Sur oil discovery is located.
Capital Expenditures See "Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment".
Natural gas storage activities are performed by Stoccaggi Gas Italia SpA (Stogit) to which such activity was conferred on October 31, 2001 by Eni SpA and Snam SpA, in compliance with Article 21 of Legislative Decree No. 164 of May 23, 2000, which provides for the separation of storage from other activities in the field of natural gas. Storage services are provided by Stogit through eight storage fields located in Italy, based on ten storage concessions3 vested by the Ministry of Productive Activities. In 2008, the share of storage capacity used by third parties was 61%. From the beginning of its operations, Stogit markedly increased the number of customers served and the share of revenues from third parties; the latter, from a non-significant value, passed to 50%.
Until 2008, results of the storage activities in Italy have been reported within the Exploration & Production segment. Following the 100% divestment of Stogit to Snam Rete Gas that was approved by Eni’s Board of Directors and is expected to close by mid 2009 (for details on this deal see "Significant Business and Portfolio Developments" above), from 2009 the results of the storage business conducted in Italy will be reported within the Gas & Power segment, under the "Regulated Business". In 2008 operating profit reported by the natural gas storage business was euro 183 million down euro 83 million or 31.2% from 2007.
49 Table of ContentsGas & Power Eni’s Gas & Power segment engages in supply, transport, distribution, storage and marketing of natural gas, as well as of LNG. This segment also includes the activity of power generation that enables Eni to extract further value from gas, diversifying its commercial outlets. Eni’s strategy in its Gas & Power segment is to grow international sales also leveraging on the Distrigas acquisition, preserve the profitability of Italian gas marketing operations, increase operational efficiency and effectiveness mainly in regulated businesses (i.e., Italian transport and distribution activities), and develop a global LNG business. Eni has revised down its long-term expectations for gas demand growth due to the current economic downturn that is reducing gas consumption in all industrial segments and in power generation. In Europe, Eni expects gas demand to remain substantially stable during 2009 and to resume growing at an average annual rate of 2% in the following years till 2020, reaching an amount of 722 BCM. The main long-term driver of growth in European demand will be the wider use of gas in power generation. A growing portion of European gas requirements is expected to be satisfied by imports via pipeline. According to Eni’s estimates, European gas imports will cover at least 80% of consumption from the current level of 60%, due to domestic production decrease, stressing European dependence on producing countries. The most important pipeline supply sources will remain Russia and Algeria and, to a lesser degree, Norway and Libya. Eni expects that LNG supplies will contribute to diversify sources of supply. In 2008, natural gas demand in Italy amounted to 84.88 BCM representing a small decline from 2007 due to the economic slowdown; approximately 90% of gas requirements were met through imports and 10% was covered by domestic production. The outlook for the Italian demand is more challenging as demand is expected to shrink in 2009 and to post a moderate recovery in subsequent years. Over the long-term, the Company expects Italian gas demand to increase at an average growth rate of approximately 2% through 2020, reaching an amount of 106.7 BCM in 2020 (gas volumes are projected at 94.2 BCM in 2012), driven by rising consumption in the power generation sector. Growing gas needs will be met by a projected increase in import capacity, which will be supported by significant capital expenditure projects designed to upgrade existing infrastructures and to build new ones, including new LNG terminals. The Company expects additional import capacity to supply up to 10 BCM in 2009 as Eni’s upgrades of its main TTPC and TAG pipelines from Algeria and Russia respectively reach full operations. In addition, Eni is completing another leg of expansion at the TAG pipeline and is planning to upgrade its pipeline from Libya. A competitor has commenced commissioning operations at a new LNG terminal in the Adriatic Sea. Overall the Company expects that import capacity will increase by 25 BCM by 2012 of which 90% available by 2010. Against this backdrop, management plans to increase international natural gas sales leveraging on the integration of and expected synergies from the Distrigas acquisition as well as Eni’s competitive advantages ensured by gas availability under long-term supply contracts and equity gas, access to infrastructures, long-term relationships with key producing countries (mainly Russia, Algeria and Libya), market knowledge and a wide portfolio of clients. Eni intends to strengthen its positioning in European markets where its presence is already established – such as the Iberian Peninsula, Germany, France, the United Kingdom, Benelux and Turkey – and to develop its marketing activities internationally, particularly in the U.S. leveraging on the planned expansion of the Company’s LNG business. In Italy, in an increasingly competitive market, Eni sales volumes are projected to decline from the 53 BCM level achieved in 2008 to approximately 50 BCM in 2012. The Company intends to preserve the profitability of its marketing operations by leveraging on cost controls and a number of marketing initiatives designed: (i) to focus the most profitable customer segments; (ii) to upgrade the commercial offer by tailoring pricing and services to customers’ specific needs; and (iii) to develop the combined offer of gas and power ("dual offer"). A strong focus will be devoted to reducing general and selling expenses. In the medium-term, Eni plans to increase worldwide gas sales targeting a volume of 124 BCM by 2012, leveraging on expected growth in international sales that are projected to achieve an average annual rate of increase of 7% and upon synergies deriving from the Distrigas acquisition. The matters regarding future natural gas demand and sales target discussed in this section and elsewhere here in 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 natural gas demand include changes in underlying economic factors, changes in regulation, population growth or shrinkage, changes in the relative mix of demand for natural gas and its principal competing fuels, and unexpected developments in the markets for natural gas and its principal competing fuels. 50 Table of Contents
In 2008 Eni’s consolidated subsidiaries, including Distrigas’ share amounting to 5.15 BCM, supplied 89.65 BCM of natural gas with a 5.85 BCM increase from 2007, up 7%. Excluding the contribution of Distrigas, gas volumes supplied outside Italy (76.50 BCM from consolidated companies), imported in Italy or sold outside Italy, represented 91% of total supplies with an increase of 1.35 BCM from 2007, or 1.8%, mainly due to the growth registered on European markets in particular in the first months of the year, with higher volumes purchased: (i) from Algeria via pipeline (up 1.07 BCM); (ii) from Libya (up 0.63 BCM) in line with the growth of gas equity production; and (iii) from the Netherlands (up 0.36 BCM); (iv) from Russia to Turkey (up 0.31 BCM) in line with the increased gas demand on the Turkish market. Supplies in Italy (8 BCM) declined by 0.65 BCM from 2007, or 7.5%, due to lower domestic production. Supplies of Russian gas for the Italian market declined by 0.97 BCM mainly due to the implementation of agreements with Gazprom providing for Gazprom’s entrance in the market of supplies to Italian importers and the corresponding reduction in Eni offtakes. In 2008, main gas volumes from equity production derived from: (i) Italian gas fields (7.5 BCM); (ii) the Wafa and Bahr Essalam fields in Libya linked to Italy through the GreenStream pipeline. In 2008 these two fields supplied 3.2 BCM net to Eni; (iii) certain Eni’s fields located in the British and Norwegian sections of the North Sea (2.3 BCM); and (iv) other European areas (in particular Croatia with 0.6 BCM). Considering also the direct sales of the Exploration & Production division in Europe and in the Gulf of Mexico and LNG supplied from the Bonny liquefaction plant in Nigeria, supplied gas volumes from equity production were approximately 21 BCM representing 21% of total volumes available for sale. In 2008, net input of natural gas volumes to storage deposits owned by Eni’s subsidiary Stoccaggi Gas were 0.08 BCM compared to volumes uplifted from storage of 1.49 BCM in 2007. The table below sets forth Eni’s purchases of natural gas by source for the periods indicated.
In order to meet the medium and long-term demand for natural gas, in particular in the Italian market, Eni entered into long-term purchase contracts with producing countries. The residual average life of the Company’s supply portfolio currently amounts to approximately 21 years. Such contracts, which generally contain take-or-pay clauses, will ensure a total of approximately 62.4 BCM/y of natural gas by 2010. The finalization of the purchase of the Belgian company Distrigas (for details on this deal see "Significant Business and Portfolio Developments" above) has entailed significant expansion of Eni’s supply portfolio with an addition of long-term supplies of approximately 14.7 BCM (Norway, the Netherlands and Qatar) having a residual average life of about 14 years. Eni’s supply portfolio will be more diversified and less risky, as Eni will depend from one single supplier for about 20-22% of total projected supplies in 2012. Despite the fact that an increasing portion of natural gas volumes is planned to be sold outside Italy, management believes that in the long-term unfavorable trends in the Italian natural gas demand and supply, also due to the increase in import capacity (pipeline upgrading and new LNG plants) that took place in 2008 and the 51 Table of Contentsfinalization of projects in progress or publicly announced by Eni and third parties, as well as the evolution of Italian regulations in the natural gas sector, represent risk factors to the fulfillment of Eni’s obligations in connection with its take-or-pay supply contracts. See "Item 3 – Risk Factors" and "Item 5 – Contractual Obligations". In 2008, Eni purchases under its take-or-pay contracts were higher than its minimum uplift obligation. This amount relates mainly to a contractual year, rather than a calendar year (from October to end of September for a sizeable part of Eni Gas & Power long-term supply contracts).
In 2008, worldwide natural gas sales of 104.23 BCM, including own consumption, sales by affiliates and E&P sales in Europe and in the Gulf of Mexico, increased by 5.3% from 2007 mainly due to the organic growth recorded in the European markets (up 9%) and the contribution of the acquisition of Distrigas as well as higher seasonal sales recorded in the first quarter. These positives were partly offset by the lower performance of the Italian market (down 5.8%). Natural gas sales in Italy were 52.87 BCM (including own consumption) and declined by 3.26 BCM from 2007, or 5.8%. The Italian market includes large businesses, power generation users, wholesalers, middle-sized enterprises and service and residential customers; they are further grouped as follows: (i) large industrial clients and power generation utilities directly linked to the national and the regional natural gas transport networks; (ii) wholesalers, mainly local selling companies which resell natural gas to residential customers through low pressure distribution networks and distributors of natural gas for automotive use; and (iii) residential customers include households (also referred to as the retail market), the tertiary sector (mainly commercial outlets, hospitals, schools and local administrations) and middle-sized enterprises (also referred to as the middle market) located in large metropolitan areas and urban centers. As of December 31, 2008, Eni clients amounted to 6.63 million units. In 2008, the decline in sales on the Italian gas market was primarily due to wholesalers (down 2.49 BCM) and industrial customers (down 2.13 BCM) mainly reflecting the impact of lower gas demand and competitive pressures. The decrease was partly offset by higher supplies to the power generation sector (up 0.48 BCM) and higher seasonal sales to residential customers (up 0.43 BCM) due to colder weather in the first quarter. The decline in sales to wholesalers and industrial customers also reflects the increase in sales under the gas release programs (3.28 BCM, up 0.91 BCM from 2007). These sales related to certain proceedings settled between Eni and the Italian Antitrust Authority. In June 2004, Eni agreed with the Antitrust Authority to sell a total volume of 9.2 BCM of natural gas (2.3 BCM/y) in the four thermal years from October 1, 2004 to September 30, 2008 at the Tarvisio entry point into the Italian network. In March 2007 a new gas release program was signed for volumes amounting to 4 BCM of natural gas to sell in the two thermal years from October 1, 2007 to September 30, 2009 at a virtual exchange point in the Italian market. Sales to importers in Italy (11.25 BCM) increased by 0.58 BCM, up 5.4%, as a larger portion of these sales in 2007 was replaced with direct sales in Italy. Gas sales in European markets (31.78 BCM including affiliates and the contribution of Distrigas acquisition) increased by 7.43 BCM, or 30.5%, also reflecting market share gains. Excluding the impact of Distrigas, sales of natural gas on European markets amounted to 26.55 BCM, increasing by 2.20 BCM, or 9%, mainly due to the growth registered in: (i) France (up 0.64 BCM) due to marketing initiatives targeting wholesalers and industrial customers; (ii) the Iberian Peninsula (up 0.53 BCM) due to higher supplies to wholesalers and the power generation segment; (iii) Turkey (up 0.31 BCM), due to the progressive reaching of full operations of the Blue Stream pipeline; and (iv) Germany-Austria (up 0.20 BCM) due to higher sales to wholesalers. Sales to markets outside Europe (2.33 BCM) are substantially in line with 2007. E&P sales in Europe and in the United States increased by 0.61 BCM, up 11.3%, as a result in particular of the production ramp-up in the Gulf of Mexico. 52 Table of ContentsThe tables below set forth Eni’s sales of natural gas by principal market for the periods indicated.
In the medium-term, Eni plans to increase its sales volumes of natural gas in international markets, mainly in Europe and the U.S., in order to compensate for lower growth opportunities on its domestic market due to sector-specific regulation imposing limits to the size of Italian gas operators. In order to achieve its growth targets, Eni will leverage on its strengths represented by gas availability both as equity gas and under long-term purchase contracts, operational flexibility ensured by access to a large transport network, regasification terminals and logistic assets, a large portfolio of clients and market knowledge. Eni expects to increase international sales also leveraging on synergies deriving from the Distrigas acquisition that will help drive sales growth and markets share gains in Eni’s target markets in spite of an unfavorable short-term outlook for European gas demand. 53 Table of Contents
In the medium-term, the Italian gas market will be characterized by greater competition related to the short-term decline in demand resulting from the economic slowdown and the entry on the market of new supplies related to the upgrade of import infrastructure. In particular import capacity is expected to increase by approximately 25 BCM in the next four years. About 90% of new capacity is expected to come on stream in 2010. This capacity derives in particular from the upgrades achieved by Eni on pipelines from Russia (TAG), Algeria (TTPC) and Libya (GreenStream) and the full operation of the re-gasification plant of Rovigo owned by third parties. In order to support sales and profitability of its marketing operations in Italy, Eni intends to implement an effective marketing policy, intended to deliver value to customers leveraging on the quality of the service and the offer of customized price formulas. Eni’s marketing initiatives will focus on all segments in particular the middle and retail markets, also leveraging on the expected development of the combined offer of gas and power to residential customers ("dual offer"). Large industrial clients will be retained based on selective marketing policies targeting the most valuable and profitable. Volumes to thermoelectric utilities will be supported in order to maintain current levels. At the same time, Eni expects to preserve its selling margins by means of reducing the cost to serve leveraging on technological innovation, streamlining front-end and back-end processes and achieving economies of scale and synergies, particularly those driving from the dual offer in terms of process integration for acquiring, retaining and managing customers. As part of its marketing activities in Italy, Eni engages in the marketing of power. Particularly, the Company offers to its retail clients a commercial offer that provides the combined supply of gas and power ("the dual offer"). Eni plans to achieve by 2012 a penetration rate of over 20% of Eni’s retail customer base. In 2008, sales of power amounted to 29.93 TWh and decreased by 3.26 TWh from 2007, down 9.8%, reflecting lower traded volumes as the economic activity declined in the last part of the year. The decrease mainly regarded sales to the power exchange. Sales on the free market to wholesalers increased due to higher spot sales, and so did sales to industrial users due to new customers acquired. Sales of power amounting to 29.93 TWh were directed to the free market (76%), the power exchange (13%), industrial sites (9%) and Electricity Service Operator (2%). In 2008, the program for expanding the combined integrated offer of gas and power (dual offer) progressed in accordance with the Company’s expansion plans.
Power availability to Eni is ensured by internal production (see the generation business below) and purchases on the free market. In 2008, production availability covered 78% of sales volumes.
In the future, Eni intends to strengthen its leadership in the European gas markets, targeting to increase both volumes and market shares. A review of Eni’s presence in key European markets and volume targets for 2012 is presented below. Benelux. The acquisition of Distrigas finalized in October 2008 granted Eni a solid base from which to develop its presence in Benelux countries (Belgium, the Netherlands and Luxembourg). Distrigas is a key operator in Benelux, in particular in Belgium, the strategic hub of the continental European gas market thanks to its central position and high level of interconnectivity with the transit gas networks of central and northern Europe. The company sells natural gas mainly to industries, wholesalers and power generation. Distrigas also has diversified sources of supply, both in geographical terms with its long-term supply contracts portfolio in the Netherlands, Norway and Qatar, and technically as it purchases natural gas, transports it via pipeline and as LNG. It also owns an 54 Table of Contents11% interest in Interconnector UK Ltd, the company that owns the interconnection of the transit gas networks between Belgium and the UK and the Methania gas tanker ship. Its transport assets connect natural gas sources with European markets and the Zeebrugge hub on the Belgian coast. In 2008 Distrigas natural gas sales in Benelux amounted to approximately 13.5 BCM and by 2012 Eni targets sales of 14.8 BCM, an annual average growth rate of 2% and a 22% market share. France. Eni sells natural gas to industrial clients and resellers and to the segments of small businesses and retail though its partnership with Altergaz in which it holds a 38.91% stake. Altergaz supplies approximately 23,000 clients (of these 17,000 are residential customers), with revenues of approximately euro 260 million. Eni will support Altergaz’s development in the target segments through a 10-year supply contract of 1.3 BCM/y and will pursue synergies with its own commercial structure. On September 23, 2008, Eni and Altergaz acquired a 17% stake each in the share capital of Gaz de Bordeaux SAS, a gas distributor in the municipality of Bordeaux and defined the terms of a long-term supply contract for 250 mmCM/y to Gaz de Bordeaux. In addition, the recent acquisition of Distrigas provides Eni with a customer base and sound commercial structures. The retail segment in France presents attractive development opportunities with its 10.8 million of sites and delivery points and consumption equaling 27% of total national consumption. Eni expects to ramp sales on the French market to achieve 6.8 BCM of sales by 2012. This target represents an annual average growth rate of 14%. Eni’s market share is expected to reach 13%. Germany/Austria. Eni is present on the German natural gas market through its affiliate GVS (Gasversorgung Süddeutschland GmbH - Eni 50%) which sold approximately 4.22 BCM in 2008 (2.11 BCM being Eni’s share) and through a direct marketing structure (Eni G&P GmbH). In the medium-term, Eni, supported by the synergies achieved with GVS, plans to significantly increase its sales to the local distribution companies and industrial segment, leveraging on the pursuit of opportunities arising from the ongoing liberalization process. The objective is to sell 7.6 BCM in 2012, equal to a 7% market share with an annual growth rate of 9%. Iberian Peninsula Spain. Eni operates in the Spanish gas market through a direct marketing structure that markets in particular LNG from Nigeria and through Unión Fenosa Gas (UFG) (Eni’s interest 50%) which supplies natural gas mainly to final customers and power generation utilities. In 2008 gas sales of UFG in Europe amounted to 4.32 BCM (2.16 BCM Eni’s share). UFG holds an 80% interest in the Damietta liquefaction plant, on the Egyptian coast (see below), and a 7.36% interest in a liquefaction plant in Oman. In addition, it holds interests in the Sagunto (Valencia) and El Ferrol (Galicia) regasification plants, with a 42.5% and 18.9% interest, respectively. Eni targets to increase its sales in the Iberian Peninsula from the current 7.44 BCM level to approximately 8.6 BCM by 2012, with an annual average growth rate of 4%, in line with the growth of the Spanish market. UK/Northern Europe. Eni through its subsidiary North Sea Gas & Power (Eni UK Ltd) markets equity gas produced at Eni’s fields in the North Sea and operates in the main continental natural gas hubs (NBP, Zeebrugge, TTF). Eni plans to grow volumes sold on the markets of the UK/ Northern Europe from the current 3.2 BCM level to approximately 6.8 BCM by 2012, with a 21% average annual growth rate. Turkey. Eni sells gas supplied from Russia and transported via the Blue Stream pipeline. In 2008 sales amounted to 4.93 BCM. Leveraging on the expected demand growth, Eni plans to increase sales up to 6.4 BCM by 2012, equal to a 7% growth rate.
Eni’s plans to expand its natural gas sales in the U.S. are described under the "LNG business" below.
Eni is present in the all phases of LNG: liquefaction, shipping, regasification and sale, and intends to speed up the development of its LNG business on a global scale, aiming at building or acquiring assets in the LNG value chain in order to seize the opportunities arising from the increasing role of LNG in satisfying energy requirements. 55 Table of ContentsExpansion of LNG business in particular on extra European markets, mainly in the USA, will enable Eni to fully monetize its large equity reserves. Eni’s main assets in the LNG business are described below. Italy. Eni, through Snam Rete Gas, operates the only regasification terminal operating in Italy at Panigaglia (Liguria). At full capacity, this terminal can regasify 17,500 CM of LNG per day and input 3.5 BCM/y into the Italian transport network. Eni plans to increase the capacity of the Panigaglia plant from the current 3.5 BCM to 8 BCM. From 2014 the upgrade of this structure will allow to increase imports to Italy by 4.5 BCM/y. In accordance with Management’s revised plans, works are expected to commence by 2011, if all authorizations are granted. Qatar. The closing of the acquisition of Distrigas allowed Eni to increase its development opportunities in the LNG business with the access to new supply sources mainly from Qatar, under a 20-year long agreement with RasGas (owned by Qatar Petroleum with a 70% interest and ExxonMobil with a 30% interest) and to the Zeebrugge LNG terminal on the Western coast of Belgium. In 2008 the terminal was authorized to load gas carriers, allowing Distrigas to start its LNG export activity to very profitable markets. Egypt. Eni, through its interest in Unión Fenosa Gas, owns a 40% interest in the Damietta liquefaction plant producing approximately 5 mmtonnes/y of LNG equal to a feedstock of 7 BCM/y of natural gas. In 2008, the Gas & Power segment withdrew 0.7 mmtonnes of LNG (approximately 1 BCM of natural gas) to be marketed in Europe. Spain. Eni through Unión Fenosa Gas holds a 21.25% interest in the Sagunto regasification plant, near Valencia, with a capacity of 6.7 BCM/y. At present, Eni’s capacity entitlement amounts to 1.6 BCM/y of gas. A capacity upgrading plan has been sanctioned targeting a 0.8 BCM/y capacity increase by 2009. Eni through Unión Fenosa Gas also holds a 9.5% interest in the El Ferrol regasification plant, located in Galicia, which started operations in November 2007, with a treatment capacity of approximately 3.6 BCM/y, 0.4 BCM/y being Eni’s capacity entitlements. USA Pascagoula. Within the upstream project related to the construction of an LNG plant in Angola designed to produce 5.2 mmtonnes/y of LNG (approximately 7.3 BCM/y) for the North American market, Eni has an option to purchase a capacity entitlement amounting to 5.8 BCM/y for 20 years at the regasification plant that will be built near Pascagoula in Mississippi, with start up expected by end of 2011. With the contribution of the Distrigas acquisition and of sales of the E&P segment, by 2012 Eni targets sales of LNG of about 17 BCM (12 BCM in 2008).
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Eni conducts its power generation activities at its sites of Ferrera Erbognone, Ravenna, Livorno, Taranto, Mantova, Brindisi and Ferrara. In 2008 production of power amounted to 23.33 TWh, down 2.16 TWh from 2007, or 8.5% due mainly to a decline in sales volumes. Total installed capacity was 4.9 GW at December 31, 2008. Sales of steam (10,584 ktonnes) in 2008 decreased by 265 ktonnes from 2007, down 2.4% and were directed to end customers. In the medium-term Eni intends to complete its plan for expanding power generation capacity, targeting an installed capacity of 5.5 GW. At full capacity in 2012, production is expected to amount to approximately 29 TWh, corresponding to approximately 8% of power expected to be generated in Italy at that date. This expansion will allow Eni to consolidate its market share and its position as third power producer in Italy. Supplies of natural gas are expected to amount to approximately 5.6 BCM/y from Eni’s diversified supply portfolio. Residual expected capital expenditure amount to euro 0.7 billion in addition to the euro 2.4 billion already invested until 2008. The development plan is underway at Ferrara (Eni’s interest 51%), where in partnership with EGL Holding Luxembourg (a company belonging to Swiss group EGL) construction of two new 390 MW combined cycle units is currently undergoing testing and the relevant authorizations are pending with start up expected in early 2009. New installed generation capacity uses the combined cycle gas fired technology (CCGT), ensuring a high level of efficiency and low environmental impact. In particular, management estimates that for a given amount of energy (electricity and heat) produced, the use of the CCGT technology on a production of 26.5 TWh reduces emissions of carbon dioxide by approximately 5 mmtonnes, as compared to emissions using conventional power generation technology. The CCGT technology has been acknowledged by the Authority for Electricity and Gas as a production technology that entails priority on the national dispatching network and the exemption from the purchase of "green certificates". Article 11 of Legislative Decree No. 79/1999 concerning the opening up of the Italian electricity market obliges importers and producers of power from non renewable sources to input into the national power system a share of power produced from renewable sources set at 2% of power imported or produced from non renewable sources exceeding 100 GW. Calculations are made on total amounts net of co-generation and own consumption. This obligation can be met also by purchasing volumes or rights from other producers employing renewable sources (the so-called green certificates) to cover all or part of such 2% share. Legislative Decree No. 387/2003 established that from 2004 to 2006 the minimum amount of power from renewable sources to be input in the grid in the following year be increased by 0.35% per year. The Minister of Productive Activities, with decrees issued in consent with the Minister of the Environment, will define further increases for the 2007-2009 and 2010-2012 periods. Eni’s operated power plants are described below. Ferrera Erbognone. This power plant has an installed capacity of approximately 1,030 MW divided on three combined cycle units, two of them with an approximately 390 MW capacity are fired with natural gas, the third one with approximately 250 MW capacity is fired whit a mixed fuel, natural gas and refinery gas obtained from the gasification of a heavy residue form crude processing at the nearby Eni-operated Sannazzaro refinery. Ravenna. Two new combined cycle 390 MW units started operations in 2004. Added to the existing capacity, the power plant’s installed capacity has reached approximately 1,100 MW. Brindisi. This power plant has been upgraded by installing three new combined cycle units, each with capacity of 390 MW, increasing overall capacity at approximately 1,500 MW. Mantova. This power plant has been upgraded by installing two new combined cycle units, each with capacity of 390 MW, increasing overall capacity at approximately 900 MW. This power plant also provides steam for heating purposes delivered to the Mantova’s urban network through a heat exchanger. Livorno. This power plant has an installed capacity of approximately 200 MW, divided on gas and steam turbines with steam generators. Taranto. The existing power units have a capacity of approximately 75 MW, divided on gas and steam turbines with steam generators. Ferrara. Two new combined cycle 390 MW units started operations in 2008. Added to already existing gas and steam turbines, the power plant’s installed capacity has reached approximately 840 MW. 57 Table of Contents
Eni operates a large European network of integrated infrastructure for transporting natural gas, which links key consumption basins with the main producing areas (North Africa, Russia and the North Sea). In Italy Eni operates almost all the national transport network and can count on an extended system of local distribution networks serving retail markets. The availability of regasification capacity in Italy and the Iberian Peninsula coupled with a significant storage capacity ensures a high level of operating flexibility. These assets represent a significant competitive advantage. Eni is implementing plans for upgrading its import pipelines from Russia, Algeria and Libya and its storage capacity, and for expanding and modernizing its national transport and distribution networks. The Company plans to invest approximately euro 7 billion in the next four years in these businesses to cope with long-term growth expected in the European gas demand.
In order to import natural gas to Italy, Eni owns capacity entitlements in a network of international high pressure pipelines extending for a total of over 4,400 kilometers enabling the Company to import natural gas produced in Russia, Algeria, the North Sea and Libya to Italy. A description of the main pipelines is provided below.
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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.
Eni and Gazprom are assessing a project to build a new route for importing gas from Russia to Europe through the Black Sea. The South Stream pipeline is expected to be composed by two sections: (i) an offshore 900-kilometer long section crossing the Black Sea from the Russian coast at Beregovaya (the same starting point of the Blue Stream pipeline) to the Bulgarian coast at Varna. It will be laid reaching water depths of more than 2,000 meters; and (ii) an onshore section for which two options are currently being evaluated: one envisages crossing Serbia and Hungary to connect to existing trunklines from Russia; another section pointing South West crossing Greece and Albania then linking to the Italian network. Eni and Gazprom will carry out the project using the most advanced technologies in full respect of the strictest environmental criteria.
Eni, through Snam Rete Gas, a company listed on the Italian Stock Exchange, in which Eni holds a 50.03% interest, operates most of the Italian natural gas transport network as well as the only regasification terminal currently operating in Italy. Under Legislative Decree No. 164/2000 concerning the opening up of the natural gas market in Italy, transport and regasification activities are regulated by the Authority for Electricity and Gas which determines the methods for calculating tariffs and fixing the return on capital employed. This makes transport a low risk business capable of delivering stable returns. Eni’s network extends for 31,474 kilometers and comprises: (i) a national transport network extending over 8,779 kilometers, made up of high pressure trunk-lines mainly with a large diameter, which carry natural gas from the entry points to the system – import lines, storage sites and main Italian natural gas fields – to the linking points with regional transport networks. The national network includes also some interregional lines reaching important markets; and (ii) a regional transport network extending over 22,695 kilometers, made up of smaller lines and allowing the transport of natural gas to large industrial complexes, power stations and local distribution companies in the various local areas served. The major pipelines interconnected with import trunk-lines that are part of Eni’s national network are:
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In 2008, Eni’s national transport network increased by 393 kilometers due to certain upgrades to both national trunklines (231 kilometers) and the regional network (162 kilometers). Eni’s system is completed by: (i) 11 compressor stations with a total power of 830 MW used to increase gas pressure in pipelines to the level required for its flow; and (ii) 5 marine terminals linking underwater pipelines with the on-land network at Mazara del Vallo, Messina and Gela in Sicily and Favazzina and Palmi in Calabria. The interconnections managed by Snam Rete Gas in the Italian transport network are guaranteed by 23 linkage and dispatching nodes and by 569 plant units including pressure reduction and regulation plants. These plants allow to regulate the flow of natural gas in the network and guarantee the connection of pipes working at different pressures. Snam Rete Gas is currently assessing a project to build the Italian section of the new Galsi pipeline connecting Algeria to Italy through Sardinia with an 8 BCM/y capacity. The Italian section of this new infrastructure will be consist of an onshore section crossing Sardinia and an offshore section reaching Tuscany where it will link with the national network for a total length of 600 kilometers. Galsi will be responsible for project engineering and obtaining needed licenses and authorizations, while Snam Rete Gas will build the pipeline and manage it when operational. For the next four years Snam Rete Gas approved a capital expenditure plan of approximately euro 4.3 billion aimed mainly at increasing transport capacity by 25% and upgrading the network in view of increasing import flows. In 2008, volumes of natural gas input in the national grid (85.64 BCM) increased by 2.36 BCM from 2007, up 2.8%, mainly due to higher volumes of natural gas input to storage for the rebuilding of stocks in summer months as a result of higher offtakes related to higher seasonal sales registered in the first months of the year. Eni transported 33.84 BCM of natural gas on behalf of third parties, up 2.95 BCM from 2007, or 9.6%.
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In 2008, the LNG terminal in Panigaglia (La Spezia) regasified 1.52 BCM of natural gas (2.38 BCM in 2007).
Distribution involves the delivery of natural gas to residential and commercial customers in urban centers through low pressure networks. Eni, through its 100% subsidiary Italgas and other subsidiaries, operates in the distribution activity in Italy serving 1,320 municipalities through a low pressure network consisting of approximately 49,400 kilometers of pipelines supplying 5.6 million customers and distributing 7.3 BCM in 2008. Under Legislative Decree No. 164/2000 on the opening up of the natural gas market in Italy, distribution activities are considered a public service and therefore are regulated by the Authority for Electricity and Gas which determines the methods for calculating tariffs and fixing the return on capital employed. This business, therefore, presents a low risk and a steady cash generation profile. Distribution activities are conducted under concession agreements whereby local public administrations award the service of gas distribution to companies. According to Legislative Decree No. 164/2000, the award of the service has to take place by competitive bid from the end of a transition period no later than December 31, 2012. Future concessions will last no more than twelve years. Eni intends to develop its market and improve efficiency and quality of services rendered.
For the next four years Eni defined a capital expenditures plan of approximately euro 1 billion for the development/upgrade of its distribution networks and their technological upgrade.
Following the 100% divestment of Stogit to Snam Rete Gas that was approved by Eni’s Board of Directors and is expected to close by mid 2009 (for details on this deal see "Significant Business and Portfolio Developments" above), from 2009 the results of the storage business conducted in Italy described in the Exploration & Production section will be reported within the Gas & Power segment, under the "Regulated Business". The storage gas business in Italy is a fully-regulated activity which returns are preset by the Italian Authority for Electricity and Gas. Italian regulated storage services are provided through eight storage fields, with a modulation capacity of 8.6 BCM. In addition to storage activities conducted in Italy, Eni, through its Gas & Power segment, engages in certain gas storage activities in Europe. Particularly, the Company is developing a storage facility in the UK section of the North Sea following the acquisition of the Hewett Unit where certain depleted fields will be converted to gas storage deposits (for further detailed information see "Item 4 – Exploration & Production" above). The expected capital expenditure program for this project amounts to euro 0.7 billion with expected start-up in 2011. The storage capacity 61 Table of Contentswill be located to complement Eni’s production, sales and trading activities in Europe and will further enhance the flexibility of Eni’s portfolio in serving the main markets. Eni considers the development of gas storage facilities as a core element of the gas business. Gas storage capacity provides flexibility to match gas demand in peak periods, thereby contributing to the optimization of the gas supply portfolio. The activity of gas storage in the UK is de-regulated and results from this project will be reported within the "Marketing business".
See "Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment".
Eni’s Refining & Marketing segment engages in refining of crude oil and marketing of refined products in Italy and in a number of European markets. Based on public data, Eni is the main operator in the markets for refining and marketing of refined products in Italy. Eni’s refining and marketing operations are efficiently integrated and supported by a full set of logistic assets. Refining know-how, strong market acceptance of the brand, the ability to develop innovative fuels, and the integration with upstream operations represent Eni’s principal competitive advantages. Eni’s key medium-term target is to enhance the profitability of its downstream oil business and to reduce the cash requirements of the business by applying tight financial discipline on capital expenditures. The strategic guidelines to attain this target are:
In the next four years the implementation of these strategies will be supported by a capital expenditure program of approximately euro 2.8 billion that will be directed to upgrade Eni’s most efficient and profitable refineries and improve the quality standards of Eni’s retail operations, in particular in Italy, expanding activities for the supply of non oil products and developing the market share in selected European markets. Efficiency improvement actions will be directed to all activities targeting control of operating costs and improvement of energy efficiency. The matters regarding future plans discussed in this section 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 include difficulties in obtaining approvals from relevant Antitrust Authorities and developments in the relevant market.
In 2008, a total of 57.91 mmtonnes of crude were purchased by the Company’s Refining & Marketing segment (59.56 mmtonnes in 2007), of which 29.71 mmtonnes from Eni’s Exploration & Production segment. Volumes amounting to 16.11 mmtonnes were purchased under long-term supply contracts with producing countries, while 12.09 mmtonnes were purchased on the spot market. Approximately 29% of crude purchased in 2008 came from West Africa, 19% from European and Asian Russia, 29% from North Africa, 14% from the Middle East, 14% from the North Sea and 6% from Italy. Approximately 26 mmtonnes of crude purchased in 2008 were resold, up 0.7% from 2007. In addition, 3.39 mmtonnes of intermediate products were purchased (3.59 mmtonnes in 2007) to be used as feedstock in conversion plants and 17.42 mmtonnes of refined products (16.14 mmtonnes in 2007) were purchased to complement production availability.
Eni’s refining system has total refinery capacity (balanced with conversion capacity) of approximately 36.8 mmtonnes (equal to 737 KBBL/d) and a conversion index of 57.6%. The conversion index is a measure of a refinery complexity. The higher the index, the wider is the spectrum of crude qualities and feedstock that a refinery is able to process thus enabling it to benefit from the cost economies associated with the fact that certain qualities of crude (particularly the heavy ones) trade at discount with reference to the light crude benchmark Brent. Eni’s five 100-percent owned refineries have balanced capacity of 27.2 mmtonnes (equal to 544 KBBL/d), with a 60.3% conversion rate. In 2008, refinery throughputs in Italy and outside Italy were 35.84 mmtonnes. 62 Table of ContentsIn the next four years, Eni plans to selectively upgrade its refining system by increasing complexity and flexibility of plants, using Eni’s proprietary EST technology and achieving a conversion index of 65% in Europe (71% in Italy). The completion of construction of three new hydrocrackers at Sannazzaro, Taranto and Bayernoil is scheduled in 2009. Middle distillate yields are expected to come in at 45% from 40% in 2008 (more than double of gasoline yields) and equity crude volumes processed to increase from 19.0% to 19.6%. Improvement in operations as result of investment upgrading and efficiency actions targeting operating costs are expected to enable refining operations to lower the break-even level with respect to 2008. This means that in the medium-term our refineries will achieve positive results in a lower refining margin scenario compared to 2008. Management’s projections about the break-even level also take into account the operating expenses required to comply with environmental rules on the emissions of carbon dioxide (CO2) which amounted to approximately euro 17 million in 2008 as the business emissions are higher than the entitled allowance based on the criteria of Law Decree No. 216/2006 which implemented in Italy the EU Directive on Emission Trading (see below under the section Environmental Regulation). Management expects that the Refining & Marketing business will incur a level of operating expenses similar to 2008 in the next four-years to comply with the outlined environmental regulation. In the next four-years period, Eni’s investment plans are designed to take advantage of certain expected market trends in the refining industry:
Eni’s refinery capital projects will be designed to: (i) increase plant conversion capacity in view of boosting middle distillate yields and extracting value from equity crude; (ii) improve refinery flexibility in order to optimize processed feedstock and capture market opportunities arising from an expected increased availability of heavy/sour crudes that are typically discounted in the marketplace; (iii) produce fuels in line with product specifications provided for increasingly tight European environmental standards; and (iv) enhance operational efficiency of refineries, including energy efficiency gains. The table below sets forth certain statistics regarding Eni’s refineries at December 31, 2008. Refining system in 2008
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Eni’s refining system in Italy is composed of five 100-percent owned refineries and a 50% interest in the Milazzo refinery in Sicily. Each of Eni’s refineries in Italy has operating and strategic features that aim at maximizing the value associated to the asset structure, the geographic positioning with respect to end markets and the integration with Eni’s other activities. The Sannazzaro refinery has balanced refining capacity of 170 KBBL/d and a conversion index of 50.9%. It is one of the most efficient refineries in Europe. Located in the Po Valley, it supplies mainly markets in North-Western Italy and Switzerland. The high degree of flexibility of this refinery allows it to process a wide range of feedstock. From a logistical standpoint this refinery is located along the route of the Central Europe Pipeline, which links the Genova terminal with French speaking Switzerland. This refinery contains two primary distillation plants and relevant facilities, including three desulphurization units. Conversion is obtained through a fluid catalytic cracker (FCC), a mild hydrocracker (HdCK) middle distillate conversion unit and a visbreaking thermal conversion unit with a gasification facility using the heavy residue from visbreaking (tar) to produce syngas to feed the nearby EniPower power plant at Ferrera Erbognone. A significant conversion capacity and flexibility upgrading program is ongoing in order to transform it in a world class plant. In particular, a new hydrocracking unit with a processing capacity of 28 KBBL/d is under construction with expected start-up in 2009. In addition Eni plans to develop a conversion plant employing the Eni Slurry Technology with a 23 KBBL/d capacity for the processing of extra heavy crude with high sulphur content producing high quality middle distillates, in particular gasoil, and reducing the yield of fuel oil to zero. Start-up of this facility is scheduled in 2012. The Taranto refinery has balanced refining capacity of 110 KBBL/d and a conversion index of 64.6%. This refinery can process a wide range of crude and other feedstock. It mainly produces fuels for automotive use and residential heating purposes for the Southern Italian markets. Besides its primary distillation plants and relevant facilities, including two units for the desulphurization of middle distillates, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) and an RHU conversion plant for the conversion of high sulphur content residues into valuable products and catalytic cracking feedstocks. It processes most of the oil produced in Eni’s Val d’Agri fields carried to Taranto through the Monte Alpi pipeline (in 2008 a total of 2.3 mmtonnes of this oil were processed). A new hydrocracking unit with a capacity of 17 KBBL/d is expected to start production in 2009. Eni’s plan to upgrade the conversion capacity of this refinery will enable to extract value from fuel oil and other semifinished products currently exported. Gela, with a balanced refining capacity of 100 KBBL/d and a conversion index of 144.8%, this refinery located on the Southern coast of Sicily is highly integrated with upstream operations as it processes heavy crude produced from nearby Eni fields offshore and onshore Sicily. In addition, it is integrated downstream as it supplies large volumes of petrochemical feedstock to Eni’s in site petrochemical plants. The refinery also manufactures fuels for automotive use and petrochemical feedstock. Its high conversion level is ensured by an FCC unit with go-finer for the upgrading of feedstocks and two coking plants for the vacuum conversion of heavy residues. The power plant of this refinery also contains modern residue and exhaust fume treatment plants which allow full compliance with the tightest environmental standards. An upgrade of the Gela refinery is underway by means of an upgrade of its power plant, through the revamping of its boilers, aimed at increasing profitability by exploiting the synergies deriving from the integration of refining and power generation. Livorno, with a balanced refining capacity of 84 KBBL/d and a conversion index of 11.4%, manufactures mainly gasoline, fuel oil for bunkering and lubricant bases. Besides its primary distillation plants, this refinery contains two lubricant manufacturing lines. Its pipeline links with the local harbor and with the Florence storage sites by means of two pipelines optimizes intake, handling and distribution of products. Porto Marghera, with a balanced refining capacity of 80 KBBL/d and a conversion index of 20.2%, this refinery supplies mainly markets in North-Eastern Italy and Austria. Besides its primary distillation plants, this refinery contains a two-stage thermal conversion plant (visbreaking/thermal cracking) designed to increase yields of valuable products.
In Germany Eni holds an 8.3% interest in the Schwedt refinery and a 20% interest in Bayernoil, an integrated pole that included the Ingolstadt, Vohburg and Neustadt refineries. Eni’s refining capacity in Germany amounts to approximately 70 KBBL/d mainly used to supply Eni’s distribution network in Bavaria and Eastern Germany. In 2008 the restructuring of the whole complex was completed with the closing down and divestment of the Ingolstadt site, the construction of a new hydrocracker with a capacity of approximately 2 mmtonnes/y (40 KBBL/d), the revamping other assets (in particular a reformer and a hydrofiner) and the shutting-down of a topping unit in Neustadt. The project completed in 2008 with start-up in the second half of December and production expected in 2009, aimed at increasing middle distillate yields and reducing the production of gasoline. 64 Table of ContentsEni holds a 32.4% stake in Ceska Rafinerska, which includes two refineries, Kralupy and Litvinov, in the Czech Republic. Eni’s share of refining capacity amounts to about 53 KBBL/d. In addition, with its 33.34% interest in Galp, with the Portuguese group Amorim Eni jointly controls two refineries in Portugal: a small one in Porto specialized in the manufacture of lubricant bases and a larger and more complex one in Sines integrated with petrochemicals. The table below sets forth Eni’s petroleum products availability figures for the periods indicated.
In 2008, refining throughputs on own account in Italy and outside Italy were 35.84 mmtonnes, down 1.31 mmtonnes from 2007, or 3.5%. Volumes processed in Italy decreased by 2.06 mmtonnes, or 6.3%, due to planned and unplanned refinery downtime at the Taranto, Porto Marghera and Gela plants, as well as lower volumes at the Livorno refinery due to a challenging refining environment in the first half of the year. The increase recorded outside Italy (up 750 ktonnes) was mainly due to higher capacity entitlements at Ceska Rafinerska following the purchase of an additional ownership interest made in 2007, partly offset by the lower volumes in Germany. Total throughputs in wholly-owned refineries (25.59 mmtonnes) decreased 2.20 mmtonnes, down 7.9%, from 2007. Approximately 21.5% of volumes processed crude was supplied by Eni’s Exploration & Production segment (30.2% in 2007) representing a 8.7% decrease from 2007, equivalent to a lower volume of 2.3 mmtonnes due to lower equity crude availability from Russia, Libya and Italy.
Eni is a primary operator in storage and transport of petroleum products in Italy with its logistical integrated infrastructure consisting of 21 directly managed storage sites and a network of petroleum product pipelines for the sale and storage of refined products, LPG and crude. Eni holds interests in five joint entities established by partnering the major Italian operators. These are located in Vado Ligure-Genova (Petrolig), Arquata Scrivia (Sigemi), Venice (Petroven), Ravenna (Petra) and Trieste (DCT) and aim at reducing logistic costs, and increasing efficiency. Eni operates in the transport of oil and refined products: (i) on land through a pipeline network of leased and owned pipelines extending over 3,019 kilometers (1,447 kilometers are owned by Eni); and (ii) by sea through spot and long-term lease contracts of tanker ships. Secondary distribution to retail and wholesale markets is effected through third parties who also own their means of transportation, in some instances with minority participation of Eni. 65 Table of ContentsIn 2008 Eni implemented a new hub model made up of five main areas in Italy and including all Eni logistic assets among which refining ones. This new model aims to enhance the efficiency of logistic operations by: (i) centralizing the handling of products flows on a single platform enabling real time monitoring; and (ii) introducing more efficient operating modes in the collection and delivery of orders with the aim of reducing unit delivery costs.
Eni markets a wide range of refined petroleum products, primarily in Italy, through an extensive 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.
In 2008, sales volumes of refined products (50.68 mmtonnes) were up 0.53 mmtonnes from 2007, or 1.1%, mainly due to larger volumes sold on retail and wholesale markets in Italy and wholesale market in the rest of Europe.
Eni markets refined products in Italy trough its Agip-branded network of operated service stations. In 2008, volumes of refined products marketed on the Italian network (8.81 mmtonnes) were up 190 ktonnes from 2007, or 2.2%, despite a decrease recorded in domestic consumption, mainly due to marketing activities ("Iperself" promotional campaign – see below – and fidelity programs) that sustained market share growth from 29.2% to 30.6%; market share is computed as ratio of Eni’s sales volumes to national consumption as published in national statistics. Higher sales mainly related to gasoil sales while gasoline sales registered a decrease. The average throughput per service station measured on gasoline and gasoil sales was 2,470 kliters, an increase of 26 kliters from 2007, or up 1.1%. At December 31, 2008, Eni’s retail network in Italy consisted of 4,409 service stations, 19 more than at December 31, 2007, resulting from the positive balance of acquisitions/releases of lease concessions (32 units), the opening of new service stations (7 units), partly offset by the closing of service stations with low throughput (19 units) and the release of one service station under highway concession. In 2008, fuel sales of the Blu line – high performance and low environmental impact fuel – declined due to sensitivity of demand to prices of these products in an environment of economic downturn and high fuel prices on average. Sales of BluDiesel and its reformulated version BluDieselTech amounted to 583 ktonnes (677 mmliters), declining by 152 ktonnes from 2007 and represented 10.6% of gasoil sales on Eni’s retail network. At year end, service stations marketing BluDiesel totaled 4,095 units (4,065 in 2007) covering to approximately 93% of Eni’s network. Retail sales of BluSuper amounted to 78 ktonnes (91 mmliters) and decreased by 20 ktonnes from 2007 and covered 2.5% of gasoline sales on Eni’s retail network. At year end, service stations marketing BluSuper totaled 2,631 units (2,565 at December 31, 2007), covering approximately 60% of Eni’s network. 66 Table of ContentsIn 2007, Eni launched its "You&Agip" promotional campaign, lasting 3 years, designed to boost customer loyalty to the Agip brand. This three-year long initiative offers prizes to customers in proportion to purchases of fuels and convenience items at Agip’s stores as well as at the ones of certain partners to the program. At every purchase of fuels or convenience items, clients are granted a proportional amount of points that are credited to a fidelity card. Clients are able to decide how to accumulate points and when to spend them. At December 31, 2008, the number of customers that actively used the card in the period amounted to over about 4 million. The average number of cards active each month was over 3 million. Volumes of fuel marketed under this initiative represented 46% of total volumes marketed on Eni’s service stations joining the program, and 44% of overall volumes marketed on Eni’s network. In 2008, Eni revamped its "Iperself" promotional campaign, which provides a euro 0.06 discount per liter to customers purchasing fuel in self service stations during closing hours. Supported by other marketing activities this initiative allowed to achieve higher sales and a higher market share in retail marketing even in an environment characterized by a steep decline in domestic demand. Eni plans to strengthen its competitive positioning in Italy by upgrading its outlets. Management targets to expand its share in the domestic retail market for fuels by 2012 from the 2008 level of 30.6%. Planned actions are designed to attain European standards of quality and services, leveraging on innovative marketing initiatives aimed at strengthening clients loyalty, develop the offer of premium products and develop innovative non oil formats. A strong focus will be devoted to pursue high levels of operating efficiency. In the next four years, Eni plans capital expenditures for the construction, upgrading and restructuring of its plants, increasing the number of "Iperself" and fully automated service stations as well as complying with applicable environmental standards and regulations. By 2012, Eni expects to achieve volumes of approximately 11.4 billion liters sold (approximately 11 billion liters in 2008) with a retail network composed of 4,451 service stations, of which 75% owned.
In recent years, Eni’s strategy focused on selectively growing its market share, particularly by means of acquiring valuable assets in European areas with interesting profitability perspectives. In implementing its growth strategy, Eni has been able to leverage on synergies ensured by the proximity of these markets to Eni’s production and logistic facilities, brand awareness and economies of scale. Growth outside Italy will continue to be selective and aimed at strengthening Eni’s competitive position in key markets. In 2008 retail sales of refined products marketed in the rest of Europe (3.86 mmtonnes) was down 170 ktonnes from 2007, or 4.2%, mainly in the Iberian Peninsula, due to the disposal of downstream activities to Galp, and in Germany. These decreases were partly offset by higher sales in the Czech Republic, Hungary and Slovakia due to the purchase of assets made in the fourth quarter of 2007. At December 31, 2008, Eni’s retail network in the rest of Europe consisted of 1,547 units, a decrease of 503 units from December 31, 2007 (2,050 service stations). The network evolution was as follows: (i) divestment of 371 service stations in the Iberian Peninsula to Galp; (ii) a negative balance of acquisition/releases of leased service station was recorded (down 135 units), with positive changes in Hungary and Switzerland and negative ones in Germany; (iii) 17 low throughput service stations were closed; (iv) purchased 15 service stations; and (v) opened 5 new outlets. Average throughput (2,577 kliters) was substantially in line with 2007. The key markets of Eni’s presence are: Austria with a 7% market share, Hungary with 11.6%, Czech Republic with 11.4%, Slovakia with 10.2%, Switzerland with 6.4% and Germany with a 3.8% on national base. These market shares were calculated by Eni based on public data on national consumption and Eni’s sales volumes. In 2008, management divested its retail and wholesale marketing activities in the Iberian Peninsula following the exercise of a call option on part of Eni’s partner Galp Energia (Eni’s share being 33.34%), in accordance with the agreement signed in December 2005 by the majority shareholders of Galp Energia (in addition to Eni, Amorim Energia and Caixa Geral de Depósitos). The transaction includes 371 Agip-branded service stations. Growth outside Italy will continue to be selective and aimed at strengthening Eni’s competitive position in key markets, based on the competitive advantage provided by synergies in supply, logistics and brand awareness. Eni intends to focus on the German, Swiss and Austrian markets where it targets to increase its market share. Non oil activities in the rest of Europe are carried out under the CiaoAgip brand name in 1,032 service stations, of these 325 are in Germany and 168 in France with a 67% coverage of the network and a virtually complete coverage of owned stations. 67 Table of Contents
Eni markets gasoline and other fuels on the wholesale market in Italy, including diesel fuel for automotive use and for heating purposes, for agricultural vehicles and for vessels and 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. Along with traditional products provided with the high quality Eni standard, there is also an innovative low environmental impact line, which includes AdvanceDiesel especially targeted for heavy duty public and private transports. Customer care and product distribution is supported by a widespread commercial and logistical organization presence all over Italy and articulated in local marketing offices and a network of agents and concessionaires. In 2008 volumes marketed on the wholesale market in Italy, were approximately 11.15 mmtonnes up 0.06 mmtonnes from 2007, or 0.5%, mainly reflecting an increase in market bunker consumption on the and fuel oil sales. Sales volumes on wholesale markets outside Italy were 4.82 mmtonnes, up approximately 430 ktonnes from 2007, or 9.8%, mainly due to the growth in the Czech and Swiss markets, offset by declines in Spain, Austria, France and Germany. Eni also markets jet fuel directly at 46 airports, of which 27 in Italy. In 2008, these sales amounted to 2.4 mmtonnes (of which 1.9 mmtonnes in Italy). Eni is active also in the international market of bunkering, marketing marine fuel mainly in 40 ports, of which 23 are in Italy. In 2008 marine fuel sales were 2.4 mmtonnes (2.3 mmtonnes in Italy). Other sales were 21.36 mmtonnes of which 19.66 mmtonnes referred to sales to oil companies and traders, and 1.70 mmtonnes, supplies to the petrochemical sector.
In Italy Eni is leader in LPG production, marketing and sale with 566 ktonnes sold for heating and automotive use (under the Agip brand and wholesale) equal to a 17.8% market share. Additional 234 ktonnes of LPG were marketed through other channels mainly to oil companies and traders. LPG activities in Italy are supported by direct production, availability from 5 bottling plants and 4 owned storage sites, in addition to products imported at coastal storage sites located in Livorno, Naples and Ravenna.
Eni operates 7 (owned and co-owned) blending plants, in Italy, Europe, North and South America and 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, industrial machinery and metal processing). In Italy Eni is leader in the manufacture and sale of lubricant bases. Base oils are manufactured primarily at Eni refinery in Livorno. Eni also owns one facility for the production of additives and solvents in Robassomero. In 2008, retail and wholesale sales in Italy amounted to 125 ktonnes with a 24.8% market share. Eni also sold approximately 5 ktonnes of special products (white oils, transformer oil and anti-freeze fluids). Outside Italy sales amounted to approximately 111 ktonnes, of these about 50% were registered in Europe (mainly Spain, Germany, and France).
Eni, through its subsidiary Ecofuel (Eni’s interest 100%), sells approximately 2 mmtonnes/y of oxygenates mainly ethers (approximately 10% of world demand) and methanol (approximately 1.5% of world demand). About 72% of products are manufactured in Italy in Eni’s plants in Ravenna, in Venezuela (in joint venture with Pequiven) and Saudi Arabia (in joint venture with Sabic), the remaining 28% is bought and resold. In 2008 Eni started distributing bio-ETBE on the Italian market in compliance with the new legislation indicating the minimum content of bio-fuels. Bio-ETBE is a kind of MTBE that gained a relevant position in the formulation of gasoline in the European Union, due to the fact that it is produced from ethanol from agricultural crops and qualified as bio-component in the European directive on bio-fuels. World market for ETBE is currently limited to the European Union and Japan and in 2008 was estimated to amount to 2.2 mmtonnes. 68 Table of Contents
See "Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment".
Engineering & Construction Eni operates in engineering, construction and drilling both offshore and onshore for the oil & gas industry through Saipem, a subsidiary listed on the Italian Stock Exchange (Eni’s interest is 43%). Saipem boasts a strong position in the relevant market leveraging on technological and operational skills mainly in frontier areas, harsh environments and complex projects, as well as on engineering and project management capabilities and ownership or availability of necessary technologies and also on its integration with Snamprogetti. In spite of a weaker scenario in the oil industry worldwide and the uncertainty of the changed economic context, Saipem plans to continue consolidating its position in onshore and offshore markets, completing the expansion of its construction and drilling fleet. Saipem plans to achieve these objectives implementing the following strategic guidelines: (i) to maximize the efficiency in all business areas with the aim in particular to maintain top execution and security standards, optimize the utilization rate of the fleet, preserve competitive supply costs and increase structure flexibility in order to mitigate the effects of negative business cycles; (ii) to consolidate the Company’s competitive position in large offshore and onshore projects for the development of hydrocarbon fields strengthening at the same time its market share in the strategic segments of deepwater, FPSO, heavy crude upgrading and gas monetization; (iii) to promote local content in terms of employment of local contractors and assets in strategic countries where large projects are carried out supporting the development of delocalized logistic hubs and construction yards when requested by clients in order to achieve a long-term consolidation of its market position in those countries; (iv) to leverage on the capacity to execute internally more phases of large projects on an EPC and EPIC basis, pursuing better control of costs and terms of execution adapting with flexibility to clients’ needs, thus expanding the Company’s value proposition; and (v) to complete the expansion and revamping program of its construction and drilling fleet in order to confirm the Company’s leading position in the segment of complex projects with high profitability. Saipem expects to invest approximately euro 3.9 billion over the next four years to further expand the geographical reach and operational features of its fleet as well as to support the activities related to the execution of projects in portfolio and the acquisition of new orders. Orders acquired in 2008 amounted to euro 13,860 million, of these projects to be carried out outside Italy represented 94%, while orders from Eni companies amounted to 4% of the total. Order backlog was euro 19,105 million at December 31, 2008 (euro 15,390 million at December 31, 2007). Projects to be carried out outside Italy represented 98% of the total order backlog, while orders from Eni companies amounted to 13% of the total.
Saipem is well positioned in the market of large, complex projects for the development of offshore hydrocarbon fields leveraging on its technical and operational skills, supported by a technologically-advanced fleet, the ability to operate in complex environments, and engineering and project management capabilities acquired on the marketplace over recent years. Saipem intends to consolidate its market share strengthening its EPIC oriented 69 Table of Contentsbusiness model and leveraging on its satisfactory long-term relationships with the major oil companies and National Oil Companies ("NOCs"). Higher levels of efficiency and flexibility are expected to be achieved by outsourcing the management of EPC projects and non core engineering activities in cost efficient areas reaching economies of scale in its engineering hubs and employing local resources in contexts where this represents a competitive advantage, directly managing offshore construction processes through the creation of a large construction yard and revamping/upgrading its construction fleet. Over the next years, Saipem will invest in the upgrading of its fleet, by building a pipelayer, a field development ship for deepwater and other supporting assets for offshore activity. Saipem’s offshore construction fleet is made up of 28 vessels and 45 robotized vehicles able to perform advanced sub-sea operations. Its major vessels are: (i) the Saipem 7000 semi-submersible dynamic positioned vessel, with 14 ktonnes of lift capacity, capable to lay pipelines using the J-lay technique to the maximum depth of 3,000 meters; (ii) the Saibos FDS for the development of underwater fields in dynamic positioning, provided with cranes lifting up to 600 tonnes and a system for J-lay pipe laying to a depth of 2,000 meters; (iii) the Castoro 6 semi-submersible vessel, capable of laying pipes in waters up to 1,000 meters deep; (iv) the Saipem 3000 multifunction vessel for the development of hydrocarbon fields, able to lay rigid and flexible pipes and provided with cranes capable of lifting over 2 ktonnes; and (v) the Semac semi-submersible vessel used for large diameter underwater pipe laying. The fleet also includes remotely operated vehicles (ROV), highly sophisticated and advanced underwater robots capable of performing complex interventions in deep waters. The most significant orders awarded in 2008 in Offshore construction were: (i) a contract on behalf of Nord Stream AG for laying the Nord Stream gas pipeline constituted by a twin natural gas pipeline that will link Russia and Germany across the Baltic Sea. Overall capacity of about 55 BCM/y will be reached when both lines are operational; (ii) an EPIC contract on behalf of Elf Petroleum Nigeria Ltd (Total) for the construction and installation of underwater pipelines and related facilities connecting the Usain offshore oil field to an FPSO unit (Floating Production Storage Offloading); and (iii) a contract on behalf of OLT Offshore LNG Toscana for the FSRU (Floating, Storage and Regasification Unit) of the LNG terminal of Livorno through the conversion of a gas carrier ship moored offshore Tuscany into a floating, storage and regasification unit. The FSRU will have a storage capacity of 137 KCM of LNG and a production capacity of 3.75 BCM/y of natural gas.
Saipem operates in the construction of plants for hydrocarbon production (extraction, separation, stabilization, collection of hydrocarbons, water injection) and treatment (removal and recovery of sulphur dioxide and carbon dioxide, fractioning of gaseous liquids, recovery of condensates) and in the installation of large onshore transport systems (pipelines, compression stations, terminals). Saipem intends to capture opportunities arising from the market, both in the plants and pipeline segment, by leveraging on its solid competitive position in the strategic areas of Middle East/Caspian Area, North and West Africa and Russia. In 2008, leveraging on its distinctive know-how in the gas monetization segment, Saipem has been awarded for the first time the role of main contractor for the construction of a large gas liquefaction plant in Algeria, asserting its reputation as an integrated player, capable of managing large and complex turnkey projects in the high tech market of LNG. The most significant orders awarded in 2008 in Onshore construction were: (i) an EPC contract on behalf of Sonatrach for the construction of a single-train gas liquefaction plant, with a capacity of 4.7 mmtonnes/y of LNG near the Algerian city of Arzew; (ii) an EPC contract on behalf of Saudi Aramco for the construction of three gas/oil separation trains (GOSP, Gas Oil Separation Process) as part of the Manifa Field Development Program to increase the production capacity of Saudi Arabia by 900 BBL/d; (iii) an EPC contract on behalf of Sonatrach for the construction of three LPG production trains with a total capacity of 8 mmCM/d as part of the development of the Hassi Messaoud field in Algeria; and (iv) an EPC contract on behalf of Total Exploration and Production Nigeria Ltd for the upgrade of OML 58 Block through the revamping of the existing Flow Station and the construction of a new gas treatment train in order to increase gas production to 17.5 mmCM/d.
Saipem is the only engineering and construction contractor that provides also offshore and onshore drilling services to oil companies. In the offshore drilling segment Saipem mainly operates in West Africa, North Sea, Mediterranean Sea and Middle East and boasts significant market positions in the most complex segments of deep and ultra-deep offshore, leveraging on the outstanding technical features of its drilling platforms and vessels, capable of drilling exploration and development wells at a maximum depth of 9,200 meters. In order to better meet industry demands, Saipem is finalizing an upgrading program of its drilling fleet providing it with state-of-art rigs to enhance its role as high quality player capable of operating also in complex and harsh environments. In particular, over the next four years Saipem intends to build: (i) the Scarabeo 8 and 9, new generation semi-submersible platforms, to be employed in drilling operations in the deep-water of the Barents Sea and in the Gulf of Mexico, respectively, initially on behalf of Eni’s upstream activity; (ii) the Perro Negro 6 jack-up to conduct operations in shallow waters; and (iii) the new S12000 drilling ship to perform operations in West Africa on behalf of Total. In parallel, significant investments are planned to keep up the production capacity of other fleet equipment (upgrade equipment to the characteristics of projects or to clients needs and purchase of support equipment). 70 Table of ContentsSaipem’s offshore drilling fleet consists of 11 vessels fully equipped for its primary operations and some drilling plants installed on board of fixed offshore platforms. One of its most important offshore drilling vessels is the Saipem 10000, designed to explore and develop hydrocarbon reservoirs operating in excess of 3,000 meters water depth in full dynamic positioning. The ship has a storage capacity of 140,000 BBL and is able to maintain a steady operating position without anchor moorings by means of 6 computerized azimuth thrusters, which offset and correct the effect of wind, waves and current in real time. The vessel is operating in ultra deep waters (over 1,000 meters) in West Africa. Other relevant vessels are Scarabeo 5 and 7, third and fourth generation semi-submersible rigs able to operate at depths of 1,900 and 1,200 meters of water, respectively. Average utilization of drilling vessels in 2008 stood at 84.7% (94.7% in 2007). The most significant contracts awarded in Offshore drilling in 2008 included: (i) a 5-year extension of the contract for the use of the Scarabeo 7 semi-submersible platform in West Africa on behalf of Eni; (ii) a 2-year extension of the contract for the use of semi-submersible platform Scarabeo 3 in Nigeria on behalf of Addax Petroleum; and (iii) a 12-month contract extension for the use of the Scarabeo 6 semi-submersible platform in Egypt on behalf of Burullus Gas Co.
Saipem operates in this area as main contractor for the major international oil companies and NOCs executing its activity mainly in South America, Saudi Arabia, North Africa and, at a lower extent, in Europe. In this areas Saipem can leverage on its knowledge of the market, long-term relations with customers and synergies and integration with other business areas. Saipem boasts a solid track record in remote areas (in particular in the Caspian Sea), leveraging on its own operational skills and its ability to operate in complex environments. Average utilization of rigs in 2008 stood at 99% (99.6% in 2007). The 73 rigs owned by Saipem at year end were located as follows: 30 in Venezuela, 16 in Peru, 9 in Saudi Arabia, 7 in Algeria, 3 in Kazakhstan, 3 in Brazil, 2 in Italy, 1 in Ecuador, 1 in Colombia and 1 in Egypt. The most significant orders awarded in 2008 in Onshore drilling were: (i) contracts on behalf of various oil companies for the lease of 17 rigs with an average contract duration of five years; and (ii) contracts on behalf of various oil companies for the lease of 32 rigs, of which 13 new ones, in South America (mainly in Venezuela and Peru) and Ukraine. The average contract duration was one year for the existent rigs and five years for the new ones.
See "Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment".
Petrochemicals Eni operates in the businesses of olefins and aromatics, basic and intermediate products, polystyrene, elastomers and polyethylene. Its major production sites are located in Italy and Western Europe. Eni’s strategy in its petrochemical business is to effectively and efficiently manage operations in order to lower the break-even considering the volatility of costs of oil-based feedstock and the commoditized feature of Eni’s main products. In fact, 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, also considering the cyclical nature of demand. See "Item 3 – Risk factors". The Company does not expect to incur significant amount of expenditures to develop this business. In future years, management forecast a yearly level of expenditures in line with 2008 mainly targeted to upgrade plant efficiency, execute de-bottlenecking interventions and to comply with all applicable regulations on environment, health and safety issues. In 2008 sales of petrochemical products (4,684 ktonnes) decreased by 829 ktonnes from 2007, down 15%, in all business areas as a result of lower petrochemical demand for petrochemical products, due to a negative market scenario. Petrochemical production (7,372 ktonnes) decreased by 1,423 ktonnes from 2007, or 16.2%. In a context of economic downturn, the steep decline in unit margins and sales determined unexpected outages of some plants, in particular in the last part of the year. Nominal production capacity decreased by approximately 2 percentage points from 2007, due to the shutdown of the Gela cracker. The average plant utilization rate calculated on nominal capacity decreased by 12 percentage 71 Table of Contentspoints from 80.6% to 68.6%, due to the current economic downturn that entailed reductions in production in all main plants. Approximately 49.5% of total production was directed to Eni’s own productions cycle (48.9% in 2007). Oil based feedstock supplied by Eni’s Refining & Marketing segment covered 24% of requirements (21% in 2007). Prices of Eni’s main petrochemical products increased on average by 7%, increasing in the business of: (i) olefins (up 13%) with increases in all products; (ii) elastomers (up 10%), in particular polybutadienic and nytrilic rubbers; and (iii) polyethylene (up 5%), in particular EVA. However, these prices increases did not made for higher purchase costs of oil-based feedstock (virgin naphtha was up 17.3% in dollar terms, 9.3% in euro), particularly until September, and as a result product margins significantly decreased from a year ago. The table below sets forth Eni’s main petrochemical products availability for the periods indicated.
The table below sets forth Eni’s sales of main petrochemical products by volume for the periods indicated.
Olefins sales (1,423 ktonnes) decreased by 374 ktonnes from 2007 (down 20.8%), penalized by a poorer market scenario that negatively affected product demand and lower product availability. Main reductions were registered in sales of ethylene (down 30%), butadiene (down 30.3%) and propylene (down 15%). Olefins production (2,819 ktonnes) declined by 671 ktonnes from 2007, or 19.2%, due to the maintenance shutdown of the Priolo cracker, technical problems at the Brindisi and Dunkerque plants, steep demand reduction and the shutdown of the Gela cracker.
Aromatics sales (420 ktonnes) decreased by 94 ktonnes from 2007 (down 18.3%) due to lower demand for isomers (down 33%), mainly in the second part of the year. Intermediates sales (576 ktonnes) decreased by 136 ktonnes from 2007 (down 19.1%) mainly due to temporary shutdown of the Porto Torres cracker as a result of the poorer market scenario that negatively affected demand. Main decreases were registered in phenol (down 30.6%) and cyclohexanone (down 6.4%). 72 Table of ContentsAromatics production (767 ktonnes) decreased by 171 ktonnes from 2007 (down 18.2%) mainly due to the maintenance shutdown of the Priolo cracker and the temporary shutdown of the Porto Torres plant. Intermediates production (977 ktonnes) decreased by 283 ktonnes from 2007 (down 22.5%) mainly due to the shutdown of Porto Torres plant.
Styrene sales (543 ktonnes) declined by 51 ktonnes from 2007 (down 8.6%). Sales reductions affected essentially compact polystyrene (down 13%) and ABS/SAN (down 13.2%) due to lower demand. Increases in styrene (up 9.8%) and expanded polystyrene (up 5.6%) were due to higher product availability. Elastomers sales (433 ktonnes) decreased by 14 ktonnes, or 3.1%, due to a steep decline in demand in the last part of the year, mainly in the automotive sector. Sales decreases were registered mainly in lattices (down 11%), NBR (down 9.5%) and polybutadienic rubbers (down 4%). Increases recorded in thermoplastic rubbers (up 6.3%) and SBR (up 3.4%) were due to higher product availability. Styrene production (1,018 ktonnes) decreased by 99 ktonnes, or 8.9%. Elastomer production (494 ktonnes) decreased by 21 ktonnes (down 4.1%) due to maintenance shutdown of the Ravenna plant and unexpected outages of the Porto Torres and Ferrara plants.
Polyethylene sales (1,289 ktonnes) were down 160 ktonnes or 11%, from 2007, reflecting mainly negative market conditions for LPDE (down 19.4%) and HDPE (down 11.4%). Production (1,297 ktonnes) decreased by 178 ktonnes, or 12.1%, due to the maintenance shutdown of the Gela, Ragusa and Priolo plants and the temporary shutdown of Porto Torres and Dunkerque plants reflecting lower demand. EVA production increased by 8% due to the fact that 2007 was impacted by the outage of Oberhausen plant.
See "Item 5 – Liquidity and Capital Resources – Capital Expenditures by Segment".
Corporate and Other activities These activities include the following businesses:
Management does not consider Eni’s activities in these areas to be material to its overall operations.
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-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 that are characterized by lower temperatures than historical 73 Table of Contentsaverage temperatures, demand for gas and products is typically higher than normal consumption patterns, and vice versa.
Research and Development Technological research and innovation represent key factors in implementing Eni’s business strategies. Eni’s efforts in technological innovation are primarily intended to develop such technologies so as to meet the environmental issues and climate change, to overcome limits in accessing to hydrocarbon resources, to strengthen partnerships with producing countries and to develop renewable sources of energy. Eni is committed to developing advanced upstream technologies in frontiers areas with environmental and geological complex features, reducing the costs of finding and recovering hydrocarbons, upgrading heavy oils, monetizing stranded gas and protecting the environment. Over the next four years, Eni plans to invest euro 1.1 billion to fund ongoing projects in Eni’s businesses as well as research in the field of renewable energy which could result in potential break-through technologies. Particularly in the next four years Eni plans to fund euro 102 million to "Along with Petroleum" program aimed at identifying and developing research projects on the most advanced aspects of large scale use of renewable energy sources and energy efficiency. In 2008, Eni’s expenditures on R&D amounted to euro 217 million which were almost entirely expensed as incurred (euro 208 million and euro 220 million in 2007 and 2006). At December 31, 2008, a total of 1,098 people were employed in research and development activities. In 2008, a total of 96 applications for patents were filed.
Insurance Eni constantly assesses its exposure for the Italian and foreign activities that are mainly covered through the Oil Insurance Ltd ("OIL"), a mutual insurance and reinsurance company that provides its members a broad coverage tailored to the specific requirements of oil and energy companies. Eni makes use of a captive insurance company that covers the risks and implements Eni’s Worldwide Insurance Program re-insured with high quality securities in order to integrate the terms and conditions of the OIL coverage. An insurance risk manager works in close contact with managers directly involved in core business activities in order to evaluate potential risks and their financial impact on the Group. This process allows Eni to define a constant level of risk retention and, conversely, the amount of risk to be transferred to the market. The level of insurance maintained by Eni is generally appropriate for the risks of its businesses.
Environmental Matters
Eni is subject to numerous EU, international, national, regional and local environmental, health and safety laws and regulations concerning its oil and gas operations, products and other activities, including legislation that implements international conventions or protocols. In particular, these laws and regulations require the acquisition of a permit before drilling for hydrocarbons may commence, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with exploration, drilling and production activities, limit or prohibit drilling activities on certain protected areas, provide for measures to be taken to protect the safety of the workplace and health of communities affected by the company’s activities, and impose criminal or civil liabilities for pollution resulting from oil, natural gas, refining and petrochemical operations. 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. A brief description of major environmental laws impacting Eni’s activities located in Italy and Europe is outlined below. 74 Table of Contents
On April 29, 2006, Legislative Decree No. 152/2006 "Environment Regulation" came into force. This was designed to rationalize and coordinate the whole regulation of environmental matters by setting:
The most important changes introduced by the Decree regarded reclamation and remediation activities as this Decree provided a site-specific risk-based approach to determine objectives of reclamation and remediation projects, cost-effective analysis required to evaluate remediation solutions, criteria for waste classification. The Decree 152/2006 was amended by two subsequent decrees: Legislative Decrees 284/2006 and 4/2008; the latter introduced important changes regarding SEA and EIA procedures, landfill, waste and remediation. A principle of waste hierarchy was introduced along with definition of by-product and secondary raw materials. The most important aspects of these regulations to Eni are those regulating permits for industrial activities, waste management, remediation of polluted sites, water protection and environmental liability. On April 9, 2008, Legislative Decree No. 81/2008 "Implementation of Article 1 of Law 123/2007, in matter of protection of the health and the security on the working places" came into force. This was designed to rationalize and coordinate working environments, the equipments and the Individual Protection Devices, the physical agents (noise, mechanical vibrations, electromagnetic fields, optical radiations, etc.), the dangerous substance (chemical agents, carcinogenic substances, etc.), the biological agents and explosive atmosphere, the system of signs, the video terminals. In 2008 Eni worked on the implementation of the general framework regulations on health and safety contained in this Legislative Decree No. 81/2008, developing all laws and regulations concerning prevention and protection of workers at national and European level to be applied for all kinds of workers and employees. At European level Eni continued its work for applying the REACH Regulation (Registration, Evaluation, Authorization and Restriction of Chemicals, EC Regulation No. 197/2006). The complexity and range of situations where Eni is operating imposed the definition and application of principles for consolidating its performance in health and prevention. To this end Eni upholds:
On January 23, 2008 the European Commission put forward a far-reaching package of proposals that will deliver on the European Union’s ambitious commitments to fight climate change, promote renewable energy and increase energy security (new Energy Policy for Europe - EPE, so called "20-20 by 2020"). In December 2008 the European Parliament and Council reached an agreement on the package. The EU is committed to reducing its overall emissions to at least 20% below 1990 levels by 2020, and is ready to scale up this reduction to as much as 30% under a new global climate change agreement when other developed countries make comparable efforts. It has also set itself the target of increasing the share of renewables in energy use to 20% by 2020. Central to the strategy is a strengthening and expansion of the Emissions Trading System (EU ETS), the EU’s key tool for cutting emissions cost-effectively. Emissions from the sectors covered by the system (energy and manufacturing industries) will be cut by 21% by 2020 compared with levels in 2005. A single EU-wide cap on ETS emissions will be set, and free allocation of emission allowances will be progressively replaced by auctioning of allowances by 2020. 75 Table of ContentsEmissions from sectors not included in the EU ETS – such as transport, housing, agriculture and waste – will be cut by 10% from 2005 levels by 2020. Each Member State will contribute to this effort according to its relative wealth, with national emission targets ranging from -20% for richer Member States to +20% for poorer ones. The Directive sets legally binding targets for each Member State, in order to reach the EU target of a 20% share of renewable energy in 2020. It creates cooperation mechanisms so that the EU can achieve the targets in a cost effective way. It also includes a flat 10% target for renewables in transport (biofuels, "green" electricity, etc.); this legislation also sets out sustainability criteria that biofuels will have to meet to ensure they deliver real environmental benefits. The package also seeks to promote the development and safe use of Carbon Capture & Storage (CCS), a suite of technologies that allows the carbon dioxide emitted by industrial processes to be captured and stored underground where it cannot contribute to global warming. The reinforced carbon market will provide a long-term incentive for investment, while up to 300 million allowances in the new entrants reserve under the EU ETS will be made available to stimulate the construction and operation of up to 12 commercial demonstration CCS projects, and for innovative renewable energy demonstration technologies in the EU. The fuel quality Directive will place an obligation on suppliers to reduce greenhouse gases from the entire life cycle of the fuel 6% by 2020, mostly by an increased use of biofuels. A review in 2012 will consider increasing the target to 10%, through the inclusion of international projects, carbon capture and storage as well as electricity for cars. Also a new regulation was approved to set emissions standards for new passenger cars, which is an important tool to assist Member States in meeting their emissions targets in the non-ETS sectors. It will set binding emissions targets to ensure that emissions from the new car fleet will be reduced to an average of 120g CO2/km by 2015, including the effect of the Fuel Quality Directive, then decreasing to a stringent long-term target of 95g CO2/km by 2020. On January 29, 2008, the new IPPC (Integrated Pollution Prevention and Control) Directive 2008/1/EC was published in the Official Journal of the European Union No. 24. Therefore, from February 18, 2008, the new IPPC directive repeals the Directive 96/61/EC with its successive amendments. This directive rationalizes all existing regulations on this issue, confirming the achievement of high levels of environmental protection to be of primary importance to member states. According to the IPPC Directive, the Member States of the EU have to communicate their national values of emissions into the atmosphere, wastes produced and managed and discharges of compounds into waste. The European Commission published in Official Journal of European Union, May 16, 2007 (2007/C 110/01) the definitive replacement of the European Pollutant Emission Register (EPER) by the European Pollutant Release and Transfer Register (E-PRTR), published in 2006 (Regulation No. 166/2006). In 2008 Italian legislation already required from the IPPC site owners to account and report environmental data related to 2007 according to PRTR Register as requested by the Regulation. Eni is implementing an Integrated Environmental Information System, able to gather, manage and report the data on all the pollutants released and off-site transferred as requested by PRTR Regulations. On December 21, 2007, the European Commission published its proposal of directive on Industrial Emissions. In view of the general call for "better regulation", the draft incorporates the reviews of six sector-specific directives (IPPC, Large Combustion Plants, VOC - Volatile Organic Compounds - emissions, incineration of waste and titanium industry). The proposed directive intends to enforce BAT definition, together with a tightening of current minimum emission values in some sectors. The directive extends the scope of the IPPC directive to cover certain activities (e.g. combustion plants between 20 and 50 MW). The new proposal introduces also more robust monitoring and inspections on installations, the review of permit conditions and the reporting of compliance. On November 22, 2008, the new Directive on waste (Directive 2008/98/EC) was published in the Official Journal of the European Union. The new Directive simplifies the existing legislative framework by clarifying definitions, streamlining provisions and integrating the directives on hazardous waste (91/689/EEC) and on waste oils (75/439/EEC). The Directive introduces a life-cycle approach, focuses on waste policy by improving the way of resources consumption. The scope is to improve the recycling market by setting environmental standards, specifying under which conditions certain recycled waste are no longer considered such. The Directive requires that Member States take appropriate measures to encourage the prevention or reduction of waste production and its harmfulness. This can be done by a combination of several strategies. Especially mentioned are the development of clean technologies, the technical development and marketing of products designed so to contribute as little as possible to increasing the amount of waste. The Directive also sets new recycling targets. Core of the Directive is the introduction of a waste management hierarchy. This hierarchy is as follows: 1. Waste prevention, 2. Re-use, 3. Recycling, 4. Recovery (including energy recovery), 5. Disposal. 76 Table of ContentsMoreover the Directive bolsters the importance of the extended producer responsibility in the future waste management measures. The Member States will have to transpose this Directive into national legislation until December 12, 2010.
Eni is committed to continuously improve its model for managing health, safety and environment across all its own operational activities in order to minimize risks associated with its industrial activities, ensure reliability of its industrial operations and comply with all applicable regulations. In 2008, Eni’s business units continued to obtain certifications of their management systems, industrial installations and operating units according to the most stringent international standards. In 2008, the total number of certifications obtained was 329 (248 in 2007), of which 123 certifications according to the ISO 14001 standard, 11 certifications according to the EMAS regulation (EMAS is the Environmental Management and Audit Scheme recognized by the European Union) and 51 according to the OHSAS 18001 standard (Occupational Health and Safety management Systems - requirements). Environment. In 2008, Eni incurred total expenditures amounting to euro 1,081 million for the protection of environment, up 1.7% from 2007. Current environmental expenses decreased by approximately 9% from 2007, and mainly related to costs incurred with respect to remediation and reclamation activities, carried out mainly in Italy. Capitalized environmental expenditure increased by 22% and mainly related to soil and subsoil protection, water management and air emissions. Safety. The safety of Eni’s employees, of its contractors and the one of the people living in the area where its activities and assets are located, is of fundamental importance to the Company. As to safety regulations, in 2008 the Legislative Degree No. 81/2008 on health and safety in workplaces came into force. This decree meaningfully increases the responsibility of companies for violating applicable laws regulating safety at work, then requiring more severe controls by supervisors and managers. Eni’s safety strategy is based on:
In 2008, the injury frequency rate was 1.45 and the injury severity rate was 0.05. Cost incurred in 2008 to support the safety levels of operations and to comply with applicable rules and regulations were euro 441 million, down 5.8% from 2007. Health. Eni’s activities for protecting health aim at the continuous improvement of work conditions. Results have been achieved through:
To protect the health and safety of its employees, Eni relies on a network of 332 health care centers located in is main operating areas. A set of international agreements with the best local and international health centers ensures efficient services and timely responses to emergencies. In 2008 Eni incurred a total expense of euro 68.6 million, up 27.5% from 2007 to protect the health of its employees. 77 Table of Contents
On February 16, 2005, the Kyoto Protocol entered into force and, with it, the commitments of the Annex I Parties which have ratified the Protocol, including the EU and Italy. According to Law No. 120/2002, Italy committed itself to reduce greenhouse gas (GHG) emissions by 6.5% in the period 2008-2012, as compared to GHG levels emitted in 1990. Reductions can be achieved through both internal measures and complementary initiatives. The latter include the so-called flexible mechanisms, which enables a Party to carry out projects in developing countries (CDM - Clean Development Mechanism) and in industrial countries with transition economies (JI - Joint Implementation) in order to obtain emission credits to fulfill the Kyoto compliance. Italy, as an EU Member State, is part of the EU Emission Trading Scheme ("ETS") that was established by Directive 2003/87/EC. Effective from January 1, 2005, ETS is the largest virtual market in the world for exchanging emission allowances targeting industrial installations with high carbon dioxide emissions. As foreseen by the Directive, Italy has issued two National Allocation Plans (NAP) covering the periods 2005-2007 and 2008-2012 which set out the allowances awarded to each sector and installation. Eni is part to the ETS. Moreover, Eni is active in the utilization of the Kyoto Flexible Mechanisms. In fact, due to its presence in about 70 countries, Eni is an elective partner for carrying out CDM and JI projects thus contributing to the Italian program of greenhouse gas emissions reduction. In December 2003 during the Conference of Parties to the Kyoto Protocol – COP9 – Eni and the Ministry of the Environment signed a Voluntary Agreement for using flexible mechanisms, promoting CDM and JI and contributing to the sustainable development of host countries. The ETS EU directive provides that each Member State shall ensure that any operator who produces GHG emissions in excess of the amounts awarded based on national allocation plan, will provide allowances to cover excess emissions a year later in addition to pay a penalty. The excess emissions penalty shall be euro 100 (euro 40 for the first period 2005-2007) for each tonne of carbon dioxide equivalent emitted. All companies are expected to identify and carry out projects for emission reductions. Eni participates in the ETS scheme with 56 plants in Italy and 4 outside Italy, which collectively represent about a third of all greenhouse gas emissions generated by Eni’s plants worldwide. In the whole period (2005-2007) Eni was entitled to allowances equal to 77.2 mmtonnes of carbon dioxide for existing and new installations (of which 25.7 mmtonnes of carbon dioxide for 2007). Based on the implementation of projects designed to reduce emissions, particularly the start-up of high efficiency combined cycles for the cogeneration of electricity and steam, the amount of carbon dioxide emitted by Eni’s plants complied with mandatory limits in the whole period. Management believes that a significant emission reduction can be achieved in connection with oil and gas production activities outside Italy, that in a number of cases, given lack of local market outlets, require the flaring of natural gas associated to oil production. The elimination of flaring and the use of associated gas for the development of local economies allow sustainable development while reducing greenhouse gas emissions. The validation of such projects as CDM and JI will provide emission credits and facilitate the achievement of the Italian reduction target, as set by the Kyoto Protocol. Eni already carried out Zero Gas Flaring projects in Nigeria and Congo while others are underway. In November 2006 the Nigerian Kwale-Okpai project has been registered as a CDM project. It regarded the construction of a combined cycle power station, which utilizes the associated gas to oil production formerly flared. More projects are being assessed or implemented in Congo, Nigeria and Angola. Moreover, Eni endorsed the Global Gas Flaring Reduction Initiative of the World Bank, in order to fight for the elimination of obstacles to the completion of gas flaring reduction projects. The best solutions for compliance with the Kyoto Protocol are the use of low emission energy sources and the adoption of highly efficient technologies. To address the greenhouse gas challenge, Eni performed a detailed analysis for defining its strategy to respond to climate change and to participate in the European emissions trading system, identifying a number of projects for energy saving and emission reductions from its plants. To ensure comprehensive, transparent and accurate accounting for GHG emissions, which is consistent over time, Eni introduced in 2005 its own Protocol for the accounting and reporting of greenhouse gas emissions (GHG Accounting and Reporting Protocol), which is an essential requirement for emission certification. Indeed, accurate reporting will support the strategic management of risks and opportunities related to greenhouse gases, the definition of objectives and the evaluation of progress. For safer and more accurate management of GHG emissions and with a view to supporting accounting, Eni provided all its divisions and 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. 78 Table of ContentsAs a support to its general strategy for a sustainable management of greenhouse gases, Eni continued its programs for the development of natural gas in Italy and outside Italy, by means of technologically advanced projects such as the Blue Stream gas pipeline from Russia to Turkey and the GreenStream pipeline from Libya to Sicily. Increased gas availability in Italy will lead to a further expansion of the gas-power integration, through high efficiency combined cycles with much lower carbon dioxide emissions than coal and liquid fuels. In the medium-term, work is underway on the separation of carbon dioxide and its permanent storage in geologic reservoirs, a part of the CO2 Capture Project, an international R&D program carried out in conjunction with other oil companies. In the long-term, Eni is actively engaged in the political process regarding future emission reduction regulations. In particular Eni is involved in bioenergy and biofuels.
Regulation of Eni’s Businesses
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.
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 and 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. 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 Product Sharing Agreement (PSAs), entitlements to production volumes are defined on the basis of contractual agreements drawn up with state oil companies which hold the concessions. Such contractual agreements regulate the recover of costs incurred for the exploration, development and operating activities (cost oil) and give entitlement to a portion of the production volumes exceeding volumes destined to cover costs incurred (profit oil). A similar scheme to PSAs 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 production sharing agreement). The taxes imposed upon oil and gas production profits and activities may be substantially higher than those imposed on other businesses.
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. 79 Table of Contents
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 a production concession, in each case granted by the Ministry of Productive Activities through competitive auctions. 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. The initial duration of a production concession is 20 years, with the possibility of obtaining a ten-year extension and an additional five-year extension until the field depletes. Royalties. The Hydrocarbons Laws require the payment of royalties for hydrocarbon production. Royalties are equal to 7% and 4%, respectively, for onshore and offshore production of oil and 7% for both onshore and offshore production of natural gas. A bill of law is currently under review by the Italian Parliament which provides for an increase of royalties on hydrocarbon production from the current rate of 7 to 10%. For the year 2009 management expects that this provision would translate into higher royalties amounting to approximately euro 20 million.
Storage activities in Italy are regulated by Legislative Decree No. 164/2000 ("Decree No. 164"), which enacted the European Directive on Natural Gas 98/30/CE into Italian legislation. The most important aspects of Decree No. 164 concerning storage activities are the following: (i) in vertically integrated enterprises, storage is to be carried out by a separate company not operating in other gas activities (such as Eni’s subsidiary Stoccaggi Gas Italia SpA) or by companies engaged only in transport and dispatching activities, provided the accounts of these two activities are clearly separated from the accounts of storage; (ii) storage activity is exercised pursuant to concessions granted by the Ministry of Productive Activities. The duration of a concession is 20 years, with the possibility of obtaining at most two ten-year extensions if operators complied with the storage programs and other obligations deriving from applicable laws. Existing storage concessions are subject to the Decree. Their original term was confirmed and includes relevant production concessions; (iii) the need for strategic storage in Italy is defined explicitly; the burden of strategic storage is imposed upon companies importing from non-EU countries, which have to provide a strategic storage capacity in Italy corresponding to 10% of the amount of natural gas imported each year; (iv) holders of storage concessions are required to provide storage capacity for domestic production, for strategic use and for modulation to eligible users without discriminations, where technically and economically viable; (v) modulation storage costs are charged to shippers which have to provide modulation services adequate to the requirements of their final customers; (vi) storage tariffs criteria are determined by the Authority for Electricity and Gas in order to ensure a preset return on capital employed, taking into account the typical risk inherent in this activity, as well as volumes stored for ensuring peak supplies and the need to incentive capital expenditure for upgrading the storage system; and (vii) the Authority for Electricity and Gas establishes the criteria and priority of access storage operators have to include in their own storage codes. In compliance with the provisions of Article 21 of Decree No. 164/2000, on October 21, 2001 all storage activities carried out within the Eni Group were conferred to Stoccaggi Gas Italia SpA ("Stogit"), which holds ten storage concessions. On March 3, 2006, the Authority for Electricity and Gas with Resolution No. 50/2006 published the criteria for determining storage tariffs for a regulated period starting from April 1, 2006 and ending on March 31, 2010. According to this Resolution, the storage company calculates revenues for the determination of unit tariffs for storage services by adding the following cost elements:
In the years following the first year of the newly regulated period, reference revenues are updated to take account of variations of capital employed and the impact of the indexation of depreciation charges and operating costs to consumer price inflation lowered by a preset rate of productivity recovery. Applicable regulation provides for incentives to capital expenditures intended to develop and upgrade storage capacity by recognizing an additional rate of return of 4% on the basic rate to capital expenditure projects aiming at 80 Table of Contentsdeveloping new storage deposits and increasing existing capacity. Such incentives are applicable for a sixteen-year period and an eight-year period, respectively. In November 2007, the Italian Authority for Electricity and Gas and the Italian Antitrust Authority opened an inquiry to gain insight into the functioning of the natural gas storage activity in Italy, particularly with regards to the lack of investments by operators aimed at expanding natural gas storage capacity to store natural gas in Italy. Eni, through its wholly-owned subsidiary Stogit Italia, owns nearly the entire storage capacity currently existing in Italy. With Resolution No. 220/2006, the Italian Authority for Electricity and Gas approved the storage code proposed by Stoccaggi Gas Italia on the basis of the framework and criteria established by Resolution No. 119/2005 ("Adoption of guarantees for free access to natural gas storage services, duties of subjects operating storage activities and rules for the preparation of a storage code"). This code regulates access to and provision of storage services during normal operational conditions, regulates procedures for conferring storage capacities, fees to be charged to customers in case they uplift from or input to storage sites volumes in excess or uses higher input/uplift capacity with respect to scheduled and operating programs. On the basis of these provisions, Eni may incur significant charges for storage services should the Company fail to use storage services in accordance with scheduled operating programs. The code has been in force since November 1, 2006. The storage company offers services according to an access priority established by the Italian Authority for Electricity and Gas as follows:
The modulation storage service is geared towards satisfying modulation needs of natural gas users in terms of peak consumption and daily or seasonal trends in consumption. Final clients consuming less than 200,000 CM on an annual basis are entitled to a priority when satisfying their modulation requirements. To that end, the storage company makes available its capacity for space, injection and off-take on an annual basis in accordance with its storage code. The mineral storage service aims to allow natural gas producers to perform their activity under optimal operating conditions, according to criteria determined by the Ministry of Economic Development. The strategic storage service aims to satisfy certain obligations of natural gas importers from countries not belonging to the EU in accordance with Article 3 of Legislative Decree No. 164/2000. The relevant storage capacity dedicated to this service is determined by the Ministry of Economic Development. Storage capacity is awarded by the storage company for periods no longer than a thermal year by April 1, of each year. The first requests to be met are those for strategic storage and for the operating balancing of the system. The residual capacity available and the maximum daily uplift capacity is awarded according to the following order of priority to: (i) holders of production concessions requesting mineral storage services; (ii) natural gas selling operators who are held to provide a modulation service of their supply to their customers according to Article 18, paragraphs 2 and 3 of Legislative Decree No. 164/2000, for maximum volumes corresponding to a seasonal demand peak with average temperatures, on the terms and conditions established by a procedure to be issued by the Authority for Electricity and Gas; (iii) to the entities mentioned in (ii) above only for those additional maximum volumes related to a seasonal demand peak in case of certain low temperatures measured on a 20-year period, under the terms and conditions of the procedure mentioned in (ii) above; and (iv) the entities requesting access for services different from the ones mentioned above. Eni held natural gas for strategic reserve purposes in its storage business, as established by Decree No. 164. The strategic reserves of gas are defined as "stock destined to meet situations of deficit/decrease of supply or crisis of the gas system". The Ministry of the Economic Development determines quantities and usage criteria of such reserves. As of December 31, 2008 Eni held approximately 179 BCF of strategic reserves of natural gas (179 BCF at year end 2007).
The European Directive on Natural Gas was implemented into Italian legislation through Legislative Decree No. 164 of May 23, 2000 ("Decree No. 164"), effective from June 21, 2000. As concerns natural gas activities carried out by Eni, the most relevant aspects of the decree are as follows: 81 Table of Contents
Year 2008 closed the fifth three-year regulated period for natural gas volumes input in the domestic transport network, for which the allowed average percentage was 63% of domestic consumption of natural gas, and the fourth three-year regulated period for sales volumes to the Italian market. Eni’s presence on the Italian market complied with said limits.
This law provides for:
Law Decree No. 239/2003, converted with amendments into Law No. 290/2003, prohibits compan | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
