Main exploration and development projects
In the Val d’Agri concession (Eni’s interest 60.77%) the development plan is ongoing as agreed with the Basilicata Region in 1998: (i) the construction of a new gas treatment unit progressed, aiming at improving the environmental performance of the treatment unit and achieving a production capacity of 104 kbbl/d; (ii) start-up of Alli 2 producing well; (iii) the Environmental Monitoring Plan is ongoing and represents an environmental protection excellence. Eni implemented an environmental protection standard by means of the Action Plan for Biodiversity in Val d’Agri launched in 2008 and aimed to reduce impacts of associated operations; (iv) continuing improvement and maintenance activities progressed to optimize environmental and production performance of the field.
Other main development activities concerned the maintenance and production optimization at the fields located in the Adriatic offshore and onshore area in Sicily as well as the upgrading of compression and hydrocarbon treatment facilities at the production platforms of the Barbara field.
Rest of Europe
Exploration activities yielded positive results in the: (i) PL 532 license (Eni’s interest 30%) with the oil and gas Skavl discovery, in addition to the recent oil and gas discoveries of Skrugard and Havis. The total recoverable resources of PL 532 license are estimated at over 500 million barrels at 100% and are planned to be put in production by means of fast-track synergic development; (ii) PL 479 license (Eni’s interest 19.6%) with the Smørbukk near field gas and condensates discovery that will leverage on the synergies with the existing production facilities.
During the year, Eni was awarded the operatorship and a 40% interest in the PL 717, PL 712, PL 716 and PL 697 (Eni’s interest 65%) exploration licenses, as well as a 30% stake in the PL 696 and 714 licenses.
The Skuld field (Eni’s interest 11.5%) started up with a production of approximately 30 kboe/d (approximately 4 kboe/d net to Eni).
Development activities progressed at the Goliat field (Eni operator with a 65% interest) in the Barents Sea. Start-up is expected by the end of 2014, with a production plateau at approximately 56 kboe/d net to Eni in 2015.
In 2013 the implementation of oil spill contingency and response was progressed by means of the development of techniques and methodologies to support the oil spill preparedness program which already has been acknowledged by the Norwegian Authorities as the reference standard for all future development projects in the Arctic.
The project was launched by Eni and involved other oil companies operating in the oil and gas exploration in the Barents Sea as well as the Norwegian Clean Seas Association for Operating Companies (NOFO) and International Research Institutes. These results were presented at the Norwegian Environmental Agency, at the local administrations and at all stakeholders and reaffirmed that the Goliat project is characterized by a well-advance emergency system for the management of an oil spill, in terms of organization, consolidation of the emergency apparatus, as well as equipment and technology development. Activities are expected to be completed in 2014.
Other ongoing activities aimed at maintaining and optimizing production at the Ekofisk field (Eni’s interest 12.39%) by means of drilling of infilling wells, upgrading of existing facilities and optimization of water injection. The development of the South Area was completed in the year.
Within its strategy of portfolio optimization, Eni finalized the disposal of 19 development/production fields and 11 exploration licences.
Production started at the oil and gas Jasmine field (Eni’s interest 33%), with the installation activities and linkage to productive and treatment facilities. A peak of approximately 117 kbbl/d (approximately 39 kbbl/d net to Eni) is expected in 2014.
Other development activities concerned the West Franklin field (Eni’s interest 21.87%) with the construction and installation of production platforms and linkage to nearby treatment facilities. Start-up is expected at the end of 2014.
In the year, production started at the MLE-CAFC (Eni’s interest 75%) and El Merk (Eni 12.25%) fields. The natural gas treatment plant of the MLE-CAFC project has a production and export capacity of approximately 320 mmcf/d of gas, 15 kbbl/d of oil and condensates and 12 kbbl/d of LPG. Four export pipelines link it to the national grid system. The integrated project MLE-CAFC targets a production plateau of approximately 33 kboe/d net to Eni by 2017. The El Merk field started up with the construction of a gas treatment plant for approximately 600 mmcf/d, two oil trains for 65 kbbl/d each and three export pipelines linked to the local network. Production peak of 18 kboe/d net to Eni is expected in 2015.
In 2013 production activities at the Blocks 403 a/d (Eni’s interest 100%) and 403 (Eni’s interest 50%) used technical synergies of R&D Integrated Operations program leveraging on the Centre of Excellence for Electrical Submersible Pump (ESP). In particular, leveraging on the real time analysis of performance data at the producing well, operations were performed in time to avoid possible disruptions, with cost and time savings.
Exploration activities yielded positive results in the: (i) Meleiha development lease (Eni’s interest 76%) with three near field oil and gas discoveries and the Rosa North-1X oil discovery, where the drilling activities are underway. Development activities plan to leverage on the existing production facilities; (ii) two near field oil discoveries in the Belayim concession (Eni 100%).
In 2013 Eni was awarded the operatorship and a 100% interest in an exploration block in Egyptian deep waters in the Eastern Mediterranean Sea.
Development activities mainly concerned: (i) infilling activities at the Belayim, Denise (Eni’s interest 50%), Tuna (Eni’s interest 50%) fields and the Western Desert Area to optimize the mineral potential recovery factor; (ii) completion of the drilling activities at the Seth field (Eni’s interest 50%); (iii) development program of the DEKA field (Eni’s interest 50%) and the Emry Deep discovery (Eni’s interest 76%); and (iv) the upgrading of the water injection system at the Abu Rudeis field (Eni’s interest 100%) in the Gulf of Suez. The level of produced water re-injected is 99.5%, corresponding to approximately 1 mmcf/d.
Exploration activities yielded positive results in the Block 15/06 (Eni operator with a 35% interest) with the oil offshore Vandumbu 1 discovery.
The LNG plant managed by the Angola LNG consortium (Eni’s interest 13.6%) started up and delivered its first cargo in June 2013. The plant envisages the development of 10,594 bcf of gas in 30 years.
In 2013 the East Hub project was sanctioned in the Block 15/06, with an estimated mineral potential of over 230 million barrels. The development program includes the drilling of submarine wells that were linked to an FPSO with a capacity of 80 kboe/d. Peak production of 55 kbbl/d is expected in 2017. Development activities progressed at the West Hub project, with start-up expected at the end of 2014.
In Block 0 (Eni’s interest 9.8%), activities progressed to reduce flaring gas at the Nemba field. In 2015 once completed flared gas is expected to decrease by approximately 85% from current level. The development activities of the Mafumeira field included the installation of production and treatment platforms and underwater linkage. Start-up is expected by the end of 2015.
In the Block 14 KA/IMI (Eni’s interest 10%) the development activities progressed at the Lianzi field by means of the linkage to the existing production facilities.
The second phase of Kizomba satellites in the Development Area of former Block 15 (Eni’s interest 20%) progressed as planned. The project provides to put into production three additional discoveries that will be linked to the existing FPSO. Start-up is expected at the end of 2015.
Exploration activities yielded positive results in the offshore block Marine XII (Eni operator with a 65% interest) with the oil and gas discovery and the appraisal of the Nené Marine field and with the appraisal of the gas and condensates Litchendjili discovery. The overall discoveries potential is estimated in 2.5 billion boe in place. The block has a further significant oil and gas residual amount that will be assessed by the next exploratory and delineation campaign. The proximity to existing facilities, good productivity of reservoir and low cost will allow to fast track development, targeting start-up in 2015.
In 2013 Eni acquired the operatorship of Ngolo exploration block, which is part of the Cuvette Basin, in the joint venture with the Congolese state company Société Nationale des Pétroles du Congo (SNPC). Exploration activities will take place over a period of 10 years. The Cuvette Basin is one of the new themes of frontier exploration activities in Africa.
During the year, Eni redefined with the relevant authorities the extension of Madingo, Marine VI and Marine VII exploration and development permits, with the aligning of expiring date within the period 2034-2039, the dilution of Eni’s stake and an acquisition interest of a new high potential exploration permit. The approval of the relevant authorities is in progress.
Activities on the M’Boundi field (Eni operator with an 83% interest) moved forward with the application of Eni advanced recovery techniques and a design to monetize associated gas. Gas is sold under long-term contracts to power plants in the area including the CEC Centrale Electrique du Congo (Eni’s interest 20%) with a 300 MW generation capacity. These facilities will also receive in the future gas from the offshore discoveries of the Marine XII permit. In 2013 M’Boundi contractual supplies were approximately 106 mmcf/d (approximately 17 kboe/d net to Eni). Additional gas production will be re-injected within the Eni’s zero gas flaring programs.
During the year activities progressed to support the population in M’Boundi area. The social project for 25,000 people provides to improve education, health, access to water and energy.
Development program progressed at the Litchendjili sanctioned project in the block Marine XII. The project provides for the installation of a production platform, the construction of transport facilities and of an onshore treatment plant. The start-up is expected by the end of 2015, with a production plateau of approximately 12 kboe/d net to Eni. Production will also feed the CEC power station.
On July 26, 2013, Eni concluded the sale of a 28.57% interest in Eni East Africa (EEA) to China National Petroleum Corporation (CNPC). EEA retains a 70% interest in the Area 4 mineral property, located offshore of Mozambique. CNPC indirectly acquires, through its equity investment in Eni East Africa, a 20% interest in Area 4, while Eni retains operatorship and a 50% interest through the remaining stake. The total consideration was equal to €3,386 million (for further information see “Financial review”).
The exploration campaign of the year regarded the appraisal of the Mamba and Coral discoveries. In particular, the delineation of Mamba discovery used the results of the implementation of a propriety process, which includes a study on reservoir characterization, data processing (e-dva™) and analyses of seismic scale.
In 2013 Eni made the Agulha discovery, the tenth discovery in a new exploration prospect located in the southern part of Area 4. Management estimates that Area 4 may contain up to 2,650 billion cubic meters of gas in place. In 2014, Eni will continue appraisal activities, particularly regarding the new exploration prospect, where the drilling of two to three additional wells is planned.
Leveraging on Eni’s cooperation model, the construction of a gas fired power plant for domestic consumption is being planned with the support of the Mozambican government.
In addition, a significant program of ecosystems evaluation and the analysis of biodiversity started in the country. This program will be included in the development project of recent discoveries.
Eni continues its recruitment and local training program in order to support the activities of hydrocarbons exploration in the Country. In particular the training program that started with the University of Mozambique involved 75 students during the year.
In the OML 125 block (Eni operator with an 85% interest), the Abo – Phase 3 project started-up, with production of approximately 5 kboe/d net to Eni. This project was sanctioned at the end of 2012 and was used an innovative technology for the installation of the intelligent control at the producing wells for simultaneous production start-up from the different reservoir levels. This technology allowed a fast track installation with significant savings.
Main activities progressed to support gas production to feed the Bonny liquefaction plant: (i) in the OMLs 60, 61, 62 and 63 blocks (Eni operator with a 20% interest), the Ogbainbiri flowstation was completed with a decline in flared gas of approximately 5 mmcf/d. This facility ensured to treat natural gas production of Ogbainbiri field. In the year, flaring down program includes a reduction of approximately 50 mmcf/d of gas flared leveraging on the upgrade of Idu flowstation completed at the end of 2012; as well as flaring down of Akri with a reduction of approximately 25 mmcf/d of gas flared; (ii) in the OML 28 block (Eni’s interest 5%), within the integrated oil and natural gas project in the Gbaran-Ubie area, the drilling campaign was completed. The development plan provides for the construction of a Central Processing Facility (CPF) with a treatment capacity of approximately 1 bcf/d of gas and 120 kbbl/d of liquids. Further development phases are planned to put in production the residual mineral potential in the area.
Other activity during the year concerned: (i) the Forkados-Yokri field (Eni’s interest 5%). The project includes the drilling of 24 producing wells, the upgrading of existing flowstations and the construction of transport facilities; (ii) Bonga NW field in the OML 118 block (Eni’s interest 12.5%). The activities include the drilling and completion of producing and infilling wells; (iii) programs to support local development for improving access to health and education and initiatives in agriculture development; (iv) technical support from the ESP Excellence Centre for data performance analysis in different production site of the country. Real-time monitoring at the producing wells allowed to avoid possible disruptions.
Eni holds a 10.4% interest in the Nigeria LNG Ltd joint venture which runs the Bonny liquefaction plant, located in the Eastern Niger Delta. The plant has a design treatment capacity of approximately 1,236 bcf/y of feed gas corresponding to a production of 22 mmtonnes/y of LNG on six trains. The seventh unit is being engineered as it is in the planning phase. 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 jv (Eni’s interest 5%) and the NAOC JV, the latter operating the OMLs 60, 61, 62 and 63 blocks with an overall amount of approximately 2,825 mmcf/d (approximately 268 mmcf/d net to Eni corresponding to approximately 49 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.
On September 11, 2013, following the completion, test and delivery of all infrastructures, the first oil from the giant Kashagan (Eni’s interest 16.81%) field was produced. From October 2013 production has been halted due to a technical issue that occurred to the pipeline transporting acid gas from offshore to onshore facilities, without any impact on the environment and local communities. Recovery activities are ongoing. Management believes that from 2015 field production will recover to the originally expected level and the field contribution to Eni’s production profile for the year 2014 has been prudently assumed to be marginal.
The Phase 1 (Experimental Program) is targeting an initial production capacity of 150 kbbl/d; when the second treatment offshore train and compression facilities for gas reinjection will be completed and put online enabling to increase the production capacity up to 370 kbbl/d. The partners are planning to further increase available production capacity up to 450 kbbl/d by installing additional gas compression capacity for re-injection in the reservoir. The partners submitted the scheme of this additional phase to the relevant Kazakh Authorities.
In 2013 Eni submitted the development program of the Western section of the nearby Kalamkas discovery to the authorities. Sanction is expected in 2014 to start-up with the FEED phase.
Eni continues its commitment in the protection of the environment and ecosystems in the Caspian area with the integrated program for the management of biodiversity in the Ural Delta (Ural River Park Project – URPP). The project is almost completed and Eni’s aim to include it in the Man and Biosphere Program of UNESCO with positive consent of Kazakh Authority.
Within the agreement signed with the relevant authorities, Eni continues its training program for Kazakh resources management positions.
As of December 31, 2013, the aggregate costs incurred by Eni for the Kashagan project capitalized in the financial statements amounted to $8.2 billion (€5.9 billion at the EUR/USD exchange rate of December 31, 2013). This capitalized amount included: (i) $6.1 billion relating to expenditure incurred by Eni for the development of the oilfield; and (ii) $2.1 billion relating primarily to accrue 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, 2013 Eni’s proved reserves booked for the Kashagan field amounted to 565 mmboe, barely unchanged from 2012.
The Expansion Project of the Karachaganak field (Eni’s interest 29.25%) is currently under study. The project is aimed for a further developing gas and condensates reserves by means of the installation, in stages, of gas treatment plants and re-injection facilities to support liquids production plateau and increase gas sales. The development plan to increase re-injection capacity is currently in the phase of technical and marketing discussion to be presented to the relevant Authorities, with FEED expected in 2014.
In 2013 Eni launched an environmental monitoring program to identify the best available monitoring operations for biodiversity protection. Eni continues its commitment to support local communities by means of the construction of schools and educational facilities as well as health assistance for the villages located in the nearby area of Karachaganak.
As of December 31, 2013, Eni’s proved reserves booked for the Karachaganak field amounted to 470 mmboe, barely unchanged from 2012.
Rest of Asia
Development activities progressed at the operated Jangkrik (Eni’s interest 55%) and Jau (Eni’s interest 85%) offshore fields. The Jangkrik project includes linkage of production wells to a Floating Production Unit for gas and condensate treatment and the construction of a transportation facility to the Bontang liquefaction plant. Start-up is expected in 2017 with a production peak of 80 kboe/d (42 kboe/d net to Eni) in 2018. The Jau project provides for the drilling of production wells and the linkage to onshore plants via pipeline. Start-up is expected in 2017.
Development activities are underway at the Indonesia Deepwater Development project (Eni’s interest 20%), located in the East Kalimantan, to ensure gas supplies to the Bontang plant. The project initially provides for the linkage of the Bangka field to existing production facilities, with start-up expected in 2016. Then the project also provides for the integrated development of the first Hub including the Gendalo, Gandang, Maha fields and the second Hub of the Gehem field. Start up is expected in 2018.
The formal hand over of operations to local partners at the Darquain project is almost completed. This was the sole Eni-operated project in the Country. When the final hand over is completed, Eni’s involvements essentially will consist of being reimbursed for its past investments.
In July 2013, Eni signed with the national oil company South Oil Company and the Iraqi Ministry of Oil an amendment to the technical service contract for the development of the Zubair oil field (Eni’s interest 41.6%). The agreement includes a new target plateau at 850 kbbl/d and extends the expiring date of service contract for an additional five years, until 2035.
The Rural Support Project to support farms and communities in the area of Zubair field was completed during the year. The program in accordance with the Zubair Agricoltural Department, Farmers Association and with the monitoring of Local Authorities, involved 165 farms during 2012-2013 agricultural season.
Eni divested to certain Gazprom subsidiaries its 60% interest in Artic Russia, the subsidiary owing a 49% stake of Severenergia, which holds four licenses for the exploration and production of hydrocarbons in the region of Yamal Nenets (Siberia), among which in particular the on-stream field of Samburgskoye, Eni’s first development in the Russian upstream. On January 15, 2014, the consideration for the disposal equal to €2.16 billion ($2,940 million) was cashed in (for further information see the “Financial review”). With this disposal, Eni monetized a mature investment, but maintains a strong commitment in the Russian upstream through the partnership with Rosneft, the projects for exploration in the Russian section of the Black Sea and in the Barents Sea.
In June 2013, Eni and Rosneft signed the completion deed relating to the agreements for the joint development of exploration activities in the Russian Barents Sea (Fedynsky and Central Barents licenses, Eni’s interest 33.33%) where seismic surveys have been started, and in the Black Sea (Western Chernomorsky license, Eni’s interest 33.33%). Seismic surveys will be performed under the provisions of Russian environmental legislation.
In March 2013 Eni was the highest bidder in five offshore exploration blocks located in the Mississippi Canyon and Desoto Canyon areas within the Central Gulf of Mexico Lease Sale 227. Relevant authorities approved the bid of one of five blocks.
In November, 2013, Eni signed an agreement with the American company Quicksilver, for explorating and developing an area with unconventional oil reservoirs (shale oil), onshore the United States. Eni is expected to acquire a 50% interest in the Leon Valley area (West Texas). The work plan provides for the drilling of up to five exploration wells and the geophysical survey, aiming at determining the hydrocarbon potential of the area and the subsequent development plan. Eni will invest up to $52 million, for the completion of the project’s exploration activities. The agreement also establishes that Eni will obtain 50% of another area located in the Leon Valley owned by Quicksilver, without additional costs.
Phase 1 of the development plan was sanctioned at the Heidelberg field (Eni’s interest 12.5%) in the deep offshore of the Gulf of Mexico. The project provides for the drilling of 5 producing wells and the installation of a producing platform. Start-up is expected at the end of 2016 with a production of approximately 9 kboe/d net to Eni.
Development activities in the Gulf of Mexico mainly concerned: (i) drilling and completion activities at the Hadrian South (Eni’s interest 30%), Lucius/Hadrian North (Eni’s interest 5.4%) and St. Malo (Eni’s interest 1.25%) fields; (ii) infilling activities at the producing operated fields of Appaloosa (Eni’s interest 100%), Longhorn (Eni’s interest 75%), Pegasus (Eni’s interest 58%) and at the non-operated Front Runner field (Eni’s interest 37.5%); and (iii) maintenance of the pipeline linking to the Corral production platform.
Drilling activities progressed at the Nikaitchuq (Eni operator with a 100% interest) and Oooguruk (Eni’s interest 30%) fields in Alaska.
In March 2013, production (accelerated early production) started up at the giant Junin 5 field (Eni’s interest 40%), located in the Orinoco oil belt and containing 35 bbbl of certified heavy oil in place. Early production of the first phase is expected to reach a plateau of 75 kbbl/d by the end of 2015, targeting a long-term production plateau of 240 kbbl/d. The project provides for the construction of a refinery with a capacity of approximately 350 kbbl/d. Eni agreed to finance part of PDVSA’s development costs for the early production phase and engineering activity of refinery plant up to $1.74 billion. Drilling activities and installation of the transport and treatment facilities are ongoing.
The sanctioned development plan progressed at the Perla gas discovery, located in the Cardon IV Block (Eni’s interest 50%), in the Gulf of Venezuela. PDVSA exercised its 35% back-in right. Eni will retain the 32.5% joint controlled interest in the company, at the execution of the transfer stake. The early production phase includes the utilization of the existing discovery/appraisal wells and the installation of production platforms linked by pipelines to the onshore treatment plant. Target production of approximately 450 mmcf/d is expected in 2015. The development program will continue with the drilling of additional wells and the upgrading of treatment facilities to reach a production plateau of approximately 1,200 mmcf/d.