Final Agreement for the development project of the Kashagan oilfield
On October 31, 2008, all the international parties to the North Caspian Sea Production Sharing Agreement (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. Eni's management expects to achieve first oil by the end of 2012. Phase-one production plateau is forecast at 300 kbbl/d; the installed production capacity at the end of phase-one is planned at 370 kbbl/d in 2014. Subsequently, production capacity of phase-one is expected to step up to 450 kbbl/d, leveraging on availability of further compressor capacity for gas re-injection associated with the start-up of phase-two offshore facilities.
Portfolio
Finalized an agreement with the British company Tullow Oil Ltd to purchase a 52% stake and the operatorship of fields in the Hewett Unit and relevant facilities in the North Sea in close proximity to the Interconnector pipeline.
Eni plans to upgrade certain depleted fields in the area so as to achieve a gas storage facility with a 177 bcf capacity to support seasonal upswings in gas demand in the UK.
Finalized an agreement to acquire all the common shares of First Calgary Petroleum Ltd, a Canadian oil and gas company with exploration and development activities in Algeria. The acquisition values the fully diluted share capital of First Calgary at approximately €605 million. Production start-up is expected in 2011 with a projected plateau of approximately 30 kboe/d net to Eni by 2012.
Finalized a strategic oil deal with the Libyan national oil company based on the framework agreement of October 2007. This deal effective from January 1, 2008, extends the duration of Eni oil and gas properties until 2042 and 2047 respectively and lays the foundations for a number of projects targeting development of the significant gas potential in the country.
Completed the acquisition of the entire issued share capital of the UK-based oil company Burren Energy Plc, for a total cash consideration amounting to approximately €2.4 billion (including Burren's shares purchased in 2007, for a total amount of €0.6 billion). In 2008 production of Burren assets averaged 25 kbbl/d in Congo and Turkmenistan. Acquired control of the Indian company Hindustan Oil Exploration Limited (Eni 47.18%) pursuant to the acquisition of Burren Energy Plc.
Awarded new exploration leases in Angola, Algeria, Alaska, Gabon, the Gulf of Mexico, Indonesia, Norway and the United Kingdom, with an extension of 57,361 square kilometers (net to Eni, 99% operated).
Partnership Agreement
In 2008 Eni's unique approach to business continued, leveraging on the so-called "Eni co-operation model" integrating sustainable activity in the territory with the traditional business of hydrocarbon exploration and production:
Defined a cooperation agreement with the Republic of Congo for the extraction of unconventional oil from the Tchikatanga and Tchikatanga-Makola oil sands deposits deemed to contain significant amounts of resources based on a recent survey, with over extension of 1,790 square kilometers. Eni plans to monetize the heavy oil by applying its EST (Eni Slurry Technology) proprietary technology intended to convert entirely the heavy barrel into high-quality light products. The agreement also comprises the construction of a new 450 MW electricity generation plant (Eni's share 20%) to be fired by 2009 with the associated natural gas from the operated M'Boundi field and a partnership for the production of bio-diesel.
Signed a Memorandum of Understanding with Sonangol for the definition of an integrated model of cooperation and development. The agreement covers onshore development activities and construction of facilities in Angola designed to monetize flaring gas as well as collaboration in the field of bio-fuels.
Renewed the Memorandum of Understanding with Brazilian oil company Petrobras for the evaluation of joint initiatives in the upstream and downstream sectors, to produce and market renewable fuels and the possible options for the valorisation of the natural gas reserves discovered by Eni offshore Brazil.
Signed new strategic agreements with Petroleos de Venezuela SA (PDVSA) for the definition of a plan to develop a field located in the Orinoco oil belt deemed to contain significant amounts of heavy oil based on a recent survey; and the exploration and development of two offshore fields in the Caribbean Sea with gas resources to be processed potentially in an LNG project.
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.
Signed a partnership agreement with Papua New Guinea for the exploration of oil and gas and identification of opportunities to develop the Country's resources. Eni is also interested to jointly opportunities related to power generation projects and the development of alternative and existing renewable energies.
Finalized a Memorandum of Understanding with Colombia's state oil company Ecopetrol to evaluate joint exploration opportunities.
Financial results
Adjusted net profit for the full year was €8,008 million, an increase of €1,517 million from 2007 (up 23.4%) due to a better operating performance driven by higher realizations in dollars and production growth, partially offset by rising operating costs and higher amortization charges.
Return on average capital employed calculated on an adjusted basis was 28.6% in 2008 (30% in 2007).
Liquids and gas realizations for the full year increased on average by 28.1% in dollar terms from 2007, driven by the strong market environment of the first nine months of the year.
Production
Oil and natural gas production for the full year 2008 averaged the record level of 1,797 kboe/d, an increase of 61 kboe/d, or 3.5%, from a year earlier. This improvement mainly benefited from the assets acquired in the Gulf of Mexico, Congo and Turkmenistan, as well as continuing production ramp-up in Angola, Congo, Egypt, Pakistan and Venezuela. Higher oil prices 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%.
Leveraging on organic growth in Africa, Central Asia and Russia, Eni expects to deliver a 3.5% compound average growth rate over the next four-year period, targeting a production level in excess of 2.05 mmboe/day by 2012 under Eni's Brent scenario at $55 per barrel.
Estimated net proved reserves
Estimated net proved reserves at December 31, 2008 were 6.6 bboe (up 3.6% from 2007) determined based on a year-end Brent price of $36.55 per barrel. The year end amounts comprised 30% of proved reserves of the three equity-accounted Russian companies purchased in 2007 as part of a bid procedure for assets of bankrupt Russian company Yukos and participated by Eni with a 60% interest, considering that Gazprom exercises a call option to acquire a 51% interest in these companies. All sources reserve replacement ratio was 135% (136% under SEC reporting standards, based on reserve additions from Eni's consolidated subsidiaries), with an average reserve life index of 10 years (10 years at December 31, 2007). Excluding the price effect, the replacement ratio would be 83%.
Leveraging the high mineral potential of Eni's assets in the Caspian Sea, West Africa, North Africa and the Gulf of Mexico and new high potential areas in the medium term, Eni expects to replace 130% of produced reserves at the Company's long term price deck of $57 per barrel.
Exploration and development expenditures
In 2008, exploration expenditures amounted to €1,918 million (up 15.6% from 2007) to execute a very extensive campaign in well established areas of presence. A total of 111 new exploratory wells were drilled (58.4 of which represented Eni's share), in addition to 21 exploratory wells in progress at year end (12 net to Eni). The overall commercial success rate was 36.5% (43.4% net to Eni). The main discoveries were made in: Angola, Australia, Congo, Croatia, Egypt, the Gulf of Mexico, Italy, Libya, Nigeria, Norway, Pakistan, Tunisia and the United Kingdom.
Development expenditures were €6,429 million (up 38.5% from 2007), in particular in the Gulf of Mexico, Kazakhstan, Italy, Nigeria, Egypt, Australia and Congo.
Reserves
Reserve Governance
The Company has adopted comprehensive classification criteria for proved, proved developed and proved undeveloped oil and gas reserves in accordance with applicable U.S. Securities and Exchange Commission (SEC) regulations, as provided for in Regulation S-X, Rule 4-10. For unproved reserves (probable and possible reserves) and contingent resources (potentially reserves), Eni's resource classification system complies with the classifications and definitions adopted by the Society of Petroleum Engineers, the World Petroleum Congress and the American Association of Petroleum Geologists. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under technical, contractual, economic and operating conditions existing at the time. Year-end liquids and natural gas prices used in the estimate of proved reserves under SEC criteria, are obtained from the official survey published by Platt's Marketwire for liquids; and contractual conditions existing at year-end as applied to reference benchmarks for natural gas. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Engineering estimates of the Company's oil and gas reserves are inherently uncertain. Although authoritative guidelines exist regarding engineering criteria that have to be met before estimated oil and gas reserves can be designated as "proved", the accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Consequently, the estimated proved reserves of oil and natural gas may be subject to future revision and upward and downward revisions may be made to the initial booking of reserves due to analysis of new information concerning production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. Field resources will only be categorized as proved reserves when all criteria for the attribution of proved status has been met, including technical, economic and commercial criteria. Proved reserves to which Eni is entitled under concession contracts are determined by applying Eni's share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right. Proved reserves to which Eni is entitled under Production Sharing Agreements are calculated so that the sale of production entitlements should cover expenses incurred by the Group to develop a field (cost oil) and on the profit oil set contractually. A similar scheme applies to buy-back and service contracts. In a high oil price environment, the volume of entitlements necessary to cover the same amount of expenditures is lower.
Eni has always exercised rigorous control over the booking process of proved reserves. The Reserve Department of the Exploration & Production division is entrusted with the task of continuously updating the Company's guidelines concerning reserve evaluation, classification and monitoring the periodic determination process. Company guidelines have been reviewed by DeGolyer and MacNaughton (D&M), an independent petroleum engineers company which has declared their compliance with applicable SEC rules. D&M has also stated that the company guidelines regulate situations for which the SEC rules lack details, providing a reasonable interpretation in line with the generally accepted practices in international markets.
Eni estimates its proved reserves on the basis of the mentioned guidelines, also when participating in exploration and production activities operated by other entities. The process for evaluating reserves involves: (i) business unit managers (geographic units) and Local Reserve Evaluators (LRE), who perform the evaluation and classification of technical reserves (production profiles, capital expenditure, operating costs and costs related to asset retirement obligations); (ii) geographic area managers at head offices and Division Reserve Evaluators (DRE) checking evaluations carried out by business unit managers; (iii) the Reserve Department, providing independent reviews of the fairness and correctness of classifications carried out by business units, who also aggregates worldwide reserve data and performs economic assessment of reserves, with the support of the Accounting Department, to calculate equity volumes. Moreover, the Reserve Department has the following responsibilities: to ensure the periodic certification process of reserves and to continuously update the Company guidelines on reserves evaluation and classification.
All personnel involved in the process of reserve evaluation are knowledgeable on SEC guidelines for proved reserves classification and have professional abilities adequate to the complexity of the task, expressing their judgment independently and respectful of professional ethics.In addition, a Reserve Evaluator is normally considered professionally qualified with respect to the international standards backed by the Society of Petroleum Engineers. Since 1991, Eni has requested qualified independent oil engineering companies carry out and independent evaluation1 of its proved reserves on a rotation basis.
Eni believes those independent evaluators to be experienced and 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 information and data that were accepted as represented by the independent evaluators. These information were the same used by Eni in determining proved reserves and included: log, directional surveys, core and PVT 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 NPV, actual prices received from hydrocarbon sales, instructions on future prices, and other pertinent information are provided. Accordingly, the work performed by the independent evaluators is an evaluation of Eni's proved reserves carried out in parallel with the internal one. The circumstance that the independent evaluations achieved the same results as those of the Company for the vast majority of fields support the 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. Specifically in 2008 a total of 1.5 billion boe of proved reserves was evaluated, representing approximately 22% of Eni's total proved reserves at December 31, 2008 (calculated including a 60% interest of the proved reserves of the three Russian gas companies). Outcomes of the independent evaluations confirmed Eni's evaluations, as they did in previous years. During the 2006-2008 three year period, independent evaluations covered 77% of Eni's total proved reserves. Further information on reserves is provided in the notes to Eni consolidated financial statements - "Supplementary information on oil and natural gas - Oil and natural gas reserves".
Movements in estimated net proved reserves
Eni's estimated proved reserves were determined taking into account Eni's share of proved reserves of equity-accounted entities. The 2008 year end amounts comprised 30% of proved reserves of the three equity-accounted Russian companies purchased in 2007 as part of a bid procedure for assets of bankrupt Russian company Yukos and participated by Eni with a 60% interest, considering that Gazprom exercises a call option to acquire a 51% interest in these companies. Based on this assumption, movements in Eni's 2008
estimated proved reserves were as follows:
Estimated net proved reserves
Additions to proved reserves booked in 2008 were 856 million boe and derived from: (i) revisions of previous estimates were 751 million boe, partly related to higher entitlements reported in certain PSAs (up 342 million boe) 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. These revisions were reported in Angola, Kazakhstan and Libya; (ii) extensions and discoveries were 71 million boe, with major increases booked in Angola, Egypt, Nigeria, Norway and United States; (iii) improved recovery were 34 million boe mainly reported in Algeria, Angola, Congo and Libya.
Acquisitions amounted to 91 million boe reflecting the contribution of the acquired Burren assets in Congo, Turkmenistan and India. Sales of reserves in place (59 million boe) 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.
In 2008 Eni achieved an all sources reserve replacement ratio2 of 135% (136% under SEC reporting standards, based on reserve additions from Eni's consolidated subsidiaries). The average reserve life index is 10 years (10 years at December 31, 2007). Excluding the price effect, the replacement ratio would be 83%.
Eni's estimated proved reserves would be 6,908 mmboe including the proved reserves of thee Russian gas companies on the basis of Eni's current interest 60%. The average reserve life index is 10.5 years.
Estimated net proved reserves pro-forma
Lybia - Treatment and compression plant at Mellitah.
Mineral right portfolio and exploration activities
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 improvements were partly offset by the implementation of a strategic oil deal 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 release.
In 2008, a total of 111 new exploratory wells were drilled (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). Overall commercial success rate was 36.5% (43.4% net to Eni) as compared to 40% (38% net to Eni) in 2007.
Production
Oil and natural gas production for the full year 2008 averaged the record level of 1,797 kboe/d, an increase of 61 kboe/d, or 3.5%, from a year earlier. This improvement mainly benefited 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. These positives were 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 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, volume entitlements associated with high oil prices were reported in the Company's PSAs.
Production of natural gas for the full year was 4,424 mmcf/d and increased by 310 mmcf/d, or 7.8%, 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 amounted to 632 mmboe. The 25.5 mmboe difference over production (657.5 mmboe) reflected volumes of natural gas consumed in operations (17.9 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.
Daily production of oil and natural gas
Norway (North Sea) - Ekifisk field
Main exploration and development projects
NORTH AFRICA
Algeria In 2008, following an international bid procedure, Eni was awarded the operatorship of the Kerzaz exploration permit (Block 319a-321a) covering a gross acreage of 16,000 square kilometers. Exploration activity start-up is expected in 2009. In Block 404a (Eni's interest 12.25%), the development plan of the BBKS discovery was submitted to the relevant authorities.
In November 2008, Eni completed the acquisition of First Calgary Petroleum Ltd, a Canadian oil and gas company with exploration and development activities in Algeria. The acquisition values the fully diluted share capital of First Calgary at approximately CAN$923 million (equal to €605 million). Assets acquired include the operatorship of Block 405b with a 75% interest. Production start-up is expected in 2011 with a projected production plateau of approximately 30 kboe/d net to Eni by 2012.
Main projects underway are the following: (a) Rom Integrated project, designed to develop the reserves of the ROM, ZEA (Block 403a) and ROM Nord fields. The project provides for the construction of a new oil treatment plant with start-up in 2012. Current production of 14 kboe/d is expected to reach 32 kboe/d by 2012. In 2008 Eni and Sonatrach signed a framework agreement to set out the common contractual ground of the project and to extend the duration of the Rhourde Messaoud and Zemlet Adreg development licences for further 10 years and the Bir Rebaa North licence for further 5 years; (b) El Merk Synergy project (Eni's interest 12.25%), designed to develop the reserves of the new four fields in Block 208/405a. 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.
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.
Egypt - Damietta LNG plant.
Egypt Exploration activities yielded positive results: a) offshore the Nile Delta with the Satis-1 gas discovery (Eni's interest 50%) and the appraisal activity of the Ha'py field; b) onshore with the Eky oil discovery (Eni operator with a 100% interest) and Jasmine Est (Eni's interest 56%).
In 2008 a number of fields started production: (i) the West Ashrafi (Eni's interest 100%) field was completed underwater and linked to existing facilities; (ii) in the Ras el Barr concession (Eni's interest 50%), the Taurt field was linked to the onshore West Harbour treatment plant. Production peaked at approximately 38 kboe/d (13 net to Eni) in 2008. In the el Temsah concession (Eni operator with a 50% interest), development activities progressed at the Denise field started-up in late 2007. The production build-up was reached in 2008 through the completion of phase A of the development plan. Current production amounts to 37 kboe/d (11 net to Eni). The Taurt and Denise fields are expected to ensure natural gas supplies of 23 kboe/d to the first train of the Damietta LNG plant.
In the Gulf of Suez optimization activities progressed at the Belayim field (Eni's interest 100%) by finalizing basic engineering for the upgrading of the water injection system intended to recover residual reserves.
Development activities are underway offshore the Nile Delta: (i) in the Thekah concession (Eni operator with a 50% interest); and (ii) the North Bardawil concession (Eni operator with a 60% interest).
Upgrading of the el Gamil compression plant progressed by adding new capacity.
Eni and the partners of the Damietta LNG plant have planned to double the capacity of this facility through the construction of a second train with a treatment capacity of 265 bcf/y of gas. Eni will provide 88 bcf/y to the second train for a period of twenty years.
The project is awaiting to be sanctioned by the Egyptian authorities. The reserves have been already identified which are destined to feed the second train, including any additional amounts that must be developed to meet the country's domestic requirements under existing laws.
Libya Exploration activities yielded positive results in: a) the offshore Block NC41 (Eni operator with a 100% interest), where the U1-NC41 discovery well showed the presence of oil and natural gas and the D4-NC41 appraisal well showed the presence of natural gas and condensates; b) in former Concession 82 (Eni's interest 50%), the YY-1 discovery well showed the presence of oil.
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 new contracts have incorporated general terms and conditions set in the framework agreement signed in October 2007 3. The terms of Eni properties 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. Also the tax burden on Eni's taxable profit has been determined based on the renewed tax framework applicable to foreign oil companies operating under PSA schemes. This new tax regime was enacted in 2007. 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 €173 million (see Financial Review, below).
Within the Western Libyan Gas project (Eni's interest 50%) upgrading of plants and facilities is underway aimed at increasing gas exports by 106 bcf/y by 2014 and maintaining production profiles at the Wafa oil field. In 2008 exported volumes amounted to 332 bcf, equal to 90% of the total gas production of the two fields. In addition 35 bcf were sold on the Libyan market for power generation.
Other ongoing development activities concern the A-NC118 field (Eni's interest 50%) linking it via pipelines to the Wafa with Mellitah plant and the valorization of associated gas of the Bouri field (Eni's interest 50%). Purified gas will be shipped by sealine to the nearby Sabratha platform and exported through the GreenStream pipeline.
Tunisia Exploration activities yielded positive results in the following permits: a) Adam (Eni operator with a 25% interest), 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 (Eni's interest 50%) where the LASSE-1 well found oil and natural gas; d) El Borma (Eni's interest 50%), where the EB-406 exploratory well showed additional oil resources.
The ongoing development projects mainly regarded the optimization of production at the Adam, Oued Zar (Eni operator with a 50% interest), MLD and El Borma fields.
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.
WEST AFRICA
Angola Exploration activities yielded positive results in: a) Block 15/06 (Eni operator with a 35% interest) with the Ngoma-1 and Sangos-1 oil discoveries.
Both discoveries were declared of commercial interest; b) Block 0 (Eni's interest 9.8%) with the Kambala appraisal well; c) the development area of former Block 14 (Eni's interest 20%) with the Lucapa-5 appraisal well showed the presence of oil; d) the development area of former Block 15 (Eni's interest 20%) with the Mavacola-3 appraisal well containing oil.
In May 2008, Eni acquired a 10% interest in the Cabinda North Block from the state oil company Sonangol.
In August 2008 Eni signed a Memorandum of Understanding with Sonangol for the definition of an integrated model of cooperation and development. The agreement covers onshore development activities and construction of facilities in Angola designed to monetize flaring gas as well as collaboration in the field of bio-fuels.
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 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.
Within the activities for reducing gas flaring, 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 an FPSO vessel. Peak production at 100 kbbl/d (18 net to Eni) was achieved at both fields in 2008.
The projects outlined and other ongoing development activities aim at maintaining current oil production plateau in the area.
In 2008 the final investment decision was achieved regarding development of the satellites Kizomba 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.
Congo In May 2008, Eni defined a cooperation agreement with the Republic of Congo intended to develop the country's mineral potential.
The agreement provides for: (i) development and extraction of unconventional oil from the Tchikatanga and Tchikatanga-Makola oil sands deposits. The two deposits that cover an acreage of approximately 1,790 square kilometers are deemed to contain significant amounts of resources based on a recent survey. Eni plans to monetize the heavy oil by applying its EST (Eni Slurry Technology) proprietary technology intended to fully convert the heavy barrel into high quality light products. The project will also benefit from synergies resulting from the close proximity of the operated M'Boundi oilfield (Eni's interest 80.1%); (ii) collaboration in the use of vegetable oils, aimed at covering domestic demand for food uses and using exceeding amounts for the production of bio-diesel with Eni's proprietary technology Ultra-Bio-Diesel; (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.
Nigeria In December 2008 Eni exercised its pre-emption rights on the remaining 49.81% interest of the ABO project in Blocks OMLs 125 and 134 (Eni's interest 50.19%). On the same occasion Eni transferred a 15% stake to the Nigerian company OANDO. This transaction has been approved by relevant authorities.
In Blocks OMLs 60, 61, 62 and 63 (Eni operator with a 20% interest) 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; (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 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.
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. Completion is expected in 2009.
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 (Eni's interest 20%). 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.
NORTH SEA
Norway Exploration activities yielded positive results in: a) the Prospecting License 312 (Eni's interest 17%) with the Gamma gas discovery at a depth of about 2,500 metres. Production will be treated at the nearby Aasgaard facilities (Eni's interest 14.82%); 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; 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. In February 2008, following an international bid procedure, Eni was awarded the operatorship of 2 exploration licences with a 40% and 65% stake, respectively, in the Barents Sea and further 3 licences in the Norwegian Sea with stakes from 19.6% to 29.4%.
Development activities concerned in particular optimization of producing fields, in particular Ekofisk (Eni's interest 12.39%), as well as Aasgaard (Eni's interest 14.82%), Heidrun (Eni's interest 5.12%) and Norne (Eni's interest 6.9%) through infilling activities designed to support production levels.
In May 2008, the relevant authorities sanctioned the development plan of the Morvin discovery (Eni's interest 30%). The basic design provides linkage to existing production facilities that will be upgraded. Production start-up is expected in the first quarter of 2010.
In 2009, production of the Yttergyta field (Eni's interest 9.8%) started-up at 81 mmcf/d after the completion of development activities.
The drilling program progressed at the Tyrihans field (Eni's interest 6.23%) that will be developed through synergies with the production facilities of Kristin (Eni's interest 8.25%). Production is expected to start in 2009, in coincidence with the expected production decline of Kristin which will make spare capacity available to process production from Tyrihans.
In Prospecting Licence 229 (Eni operator with a 65% interest) the appraisal activities of the Goliath oil discovery are underway. The project is progressing according to schedule. Start-up is expected in 2013 with 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.
United Kingdom Exploration activities yielded positive results in: (i) Block 16/23 (Eni's interest 16.67%) with the Kinnoul oil and gas discovery. The discovery 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; (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 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 capacity to support seasonal upswings in gas demand in the UK leveraging on the strategic purchased facilities.
The Bacton terminal, in fact, is the incoming point of the Interconnector pipeline connecting the United Kingdom with Europe. Eni acquired operatorship of the assets with an 89% interest. For this purpose, Eni intend to request a storage licence.
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 23%) and Laggan (Eni's interest 20%) recent gas discoveries in the North Sea.
Pre-development activities are underway at the Burgley (Eni's interest 7.1%) and Suilven (Eni's interest 8.75%) discoveries.
Development activities concerned: (i) optimization of producing fields, in particular the J-Block (Eni's interest 33%) and in the Liverpool Bay area (Eni's interest 53.9%) trough the upgrading of existing facilities; (ii) infilling actions at the Flotta Catchment Area (Eni's interest 20%) and the Mac -Culloch (Eni's interest 40%) field targeting to maintain production levels. Development activities progressed at the West Franklin field (Eni's interest 21.87%) by completing a second development well expected to peak at 20 kboe/d (4 net to Eni).
CASPIAN AREA
Kazakhstan - Kashagan On October 31, 2008, all the international parties to the North Caspian Sea Production Sharing Agreement (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 KazMunaiGas 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-venturers an aggregate amount of $1.78 billion; (ii) a value transfer package to be implemented through changes to the terms of the PSA, 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%); (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 participated by the seven partners of the consortium. As of January 2009 the new venture 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.
Caspian Sea - Kashagan field (D island).
In conjunction with the final agreement, parties also reached a final approval of the revised expenditure budget of phase-one, 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 investments in proportion to its participating interest of 16.81%.
On the basis of progress to completion (55% of phase 1 of the project) and expertise developed, Eni management expects to achieve first oil by the end of 2012. In the following 12-15 months the treatment and compression plant for gas re-injection will be completed reaching the installed production capacity of 370 kbbl/d in 2014. Subsequently, production capacity of phase-one is expected to step up to 450 kbbl/d, leveraging on availability of further compressor capacity for gas re-injection associated with the start-up of phase-two 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.
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 and subsequently to the production start-up, 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.
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 (€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, 2008, Eni's proved reserves booked for the Kashagan field amounted to 594 mmboe, 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 sale 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).
Kazakhstan - Karachaganak Located onshore in West Kazakhstan, Karachaganak is a giant liquid and gas field with recoverable reserves estimated at 5 bboe. Operations are conducted by the Karachaganak Petroleun 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.
The fourth treatment unit has been progressing to completion and will enable to increase export of oil volumes to European markets. Currently non-stabilized oil production is delivered to Orenburg terminal.
The development activities of the Uralsk Gas Pipeline are ongoing. This new infrastructure, with a length of 150 kilometers, will link the Karachaganak field to the Kazakhstan gas network. Start-up of the first stage is expected in 2009.
The engineering activities of Phase 3 of the Karachaganak project have identified a new design to complete development activities in multiple phases. Start-up is expected in 2013 subject to approval by the relevant authorities. In April 2008, the Kazakh authorities approved a tax decree enacting a new duty tax on crude oil exports. In January 2009 the rate applied for the determination of that charge was cleared. 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 the PSA resulting from lower year end oil prices from a year ago.
Turkmenistan After the purchase of British company Burren Energy Plc, Eni became operator of the Nebit Dag producing block (with a 100% interest). Production derives mainly from the Burun oil field.
Development activities were targeted to optimize production by means of drilling development wells and continuation of the program for water injection and facility upgrading. The drilling activity at Uzboy and Balkan fields, nearby Burun field, progressed. The fields achieved early production in 2006.
REST OF WORLD
Australia 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-1 exploration well showed the presence of oil at a depth of 3,658 metres 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 within 12 months. The final investment decision is expected in 2009.
In 2008 development activities have been completed in the southern area of the Woollybutt field (Eni operator with a 65% interest) with the drilling of a new production well that was linked to an FPSO unit with relevant production ramp-up.
Development activities are underway at the Blacktip gas field (Eni operator with a 100% interest).
The development strategy envisages installation of a platform that will be linked to an onshore treatment plant. Start-up is expected in 2009, peaking at 26,133 mmcf/year in 2010. Natural gas production is destined to supply a power station plant.
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.
Croatia Exploration activities yielded positive results in the Bo?ica (Eni's interest 50%) and the Ika (Eni's interest 50%) gas fields with appraisal activity.
In 2008 the Ana field (Eni's interest 50%) was started-up through linkage to the facilities existing in the area. Development activities are nearing completion in the Irina, Vesna and Annamaria fields. Start-ups are expected in 2009.
India In August 2008, Eni acquired control of the Indian company Hindustan Oil Exploration Limited (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 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; (i) certain fields where appraisal and development activities are underway.
Main development activities concerned the PY1 gas field. Start-up is expected in 2009.
Indonesia 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 activity concerned: (i) in the Krueng Mane permit (Eni operator with a 85% interest), the completion of preliminary drilling activities; (ii) in the Bukat permit (Eni operator with a 66.25% interest), the finalization of a seismic data campaign. Eni's main project in the Bukat permit concerns the development of an oil and gas recent discovery.
Eni holds interests in other projects underway which concern the joint development of five gas discoveries located in the Kutei Deep Water basin (Eni's interest 20%). Production will be treated at the LNG Bontang plant.
Pakistan Main discoveries were made in: a) the Mubarak Block (Eni's interest 38%) with the Saquib gas discovery that yielded 2,472 kcf/d in test production; b) the Latif exploration licence, where the Latif-2 appraisal well allowed confirming the presence of new reserves and the mineral potential of the area.
As part of the development of reserves in the Bhit permit (Eni operator with a 40% interest) the third treatment unit was started and increased the plant capacity by 46 mmcf leading to the start-up of the satellite Badhra field.
Other activities were targeted to optimize production from the Kadanwari, Miano, Sawan and Zamzama fields by means of the drilling additional wells and upgrading facilities.
Papua New Guinea In 2008 Eni signed a Partnership Agreement with Papua New Guinea for the start of an exploration program for identifying development opportunities and oil and gas projects. The agreement provides also for projects in electricity generation and in alternative 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.
United States (Gulf of Mexico) - Allegheny production platform.
United States - Gulf of Mexico Offshore exploration activities yielded positive results in the following blocks: a) Block Mississippi Canyon 771 (Eni's interest 25%) with the oil and gas Kodiak discovery close to the operated Devil's Tower platform (Eni's interest 75%); b) Block Walker Ridge 508 (Eni's interest 15%) the Stones-3 discovery well found oil. This discovery is part of the exploration assets acquired from Dominion Resources; c) Block Mississippi Canyon 459 (Eni's interest 100%) with the Appaloosa oil discovery. The final investment decision was reached at the end of 2008; d) Block Keathley Canyon 1008 (Eni's interest 100%) with appraisal activities of the Hadrian oil discovery; e) Block offshore Green Canyon 859 (Eni's interest 12.5%) with the oil and gas Heidelberg - 1 discovery at a depth of 9,163 meters.
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 licences 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 3 underwater wells. Start-up is expected in 2009 with peak production at 29 kboe/d (about 20 net to Eni).
United States - Alaska In February 2008, following an international bid procedure Eni was awarded 18 offshore exploration blocks, 4 of which as operator, in the Chukchi Sea. The acquired acreage is estimated to have significant mineral potential and will strengthen Eni's position in the area.
The phased development plan of the Nikaitchuq field (Eni operator with a 100% interest) was sanctioned. Production is expected to start in 2010 with production plateau at 26 kboe/d.
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.
Venezuela 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 Venezuelan State oil company PDVSA.
As part of improving cooperation with PDVSA, the two partners signed two agreements: (i) a joint study agreement for the development of the Junin Block 5 located in the Orinoco oil belt. This block covering a gross acreage of 670 square kilometers holds a resource potential estimated to be in excess of 2.5 bbbl of heavy oil. 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; (ii) an agreement for the exploration of two offshore areas, Blanquilla a nd 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 Gulf of Paria 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.
Italy Main discoveries were made in offshore Sicily with the operated gas discovery Cassiopea that yielding 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 December 2008 Eni was awarded two onshore exploration blocks in Puglia region.
Italy (Adriatic Sea) - Barbara production platform.
Development activities concerned in particular: (i) optimization of producing fields by means of sidetracking 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; (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. Start-up is expected in 2009 with a peak production of 4 kboe/d at the Annamaria field. Production start-up of the Guendalina field is expected in 2010 with a peaking production of 3 kboe/d.
Capital expenditures
Capital expenditures of the Exploration & Production division (€9,545 million) concerned development of oil and gas reserves (€6,429 million) directed mainly outside Italy, in particular Kazakhstan, Egypt, Angola, Congo and United States. Development expenditures in Italy concerned well drilling program and facility upgrading in Val d'Agri as well as sidetrack and infilling activities in mature fields. About 93% of exploration expenditures that amounted to €1,918 million were directed outside Italy in particular to the United States, Egypt, Nigeria, Angola and Libya. In Italy, exploration activities were directed mainly to the offshore of Sicily.
Acquisition of proved and unproved property concerned mainly the extension of Eni's mineral rights in Libya, following the agreement signed in October 2007 with NOC, the National Oil Corporation (effective from January 1, 2008), and the acquisition of a 34.81% stake in ABO project in Nigeria. As compared to 2007, capital expenditures increased by €2,920 million, up 44.1%, due to higher development expenditures mainly in the Gulf of Mexico, Kazakhstan, Italy, Nigeria, Egypt, Australia and Congo.
In 2008 the Exploration & Production division acquired assets for approximately €2.5 billion concerning mainly the acquisition of the entire issued share capital of Burren Energy Plc and upstream assets of First Calgary in Algeria, Hewett Unit 4 in North Sea and Hindustan Oil Exploration Co in India.
Storage
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 provided 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 10 storage concessions(5) vested by the Ministry of Economic Development.
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%.