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Darwin

Fairfield equity = 100% (P184, P474, P1634)

Asset Overview

The Darwin field is located in the Northern North Sea approximately 130 km northeast of the Shetland Islands. The field lies in blocks 211/27a approximately 8 km south of the now-abandoned North West Hutton (‘‘NWH’’) platform location. Darwin is the name Fairfield has given to development of the Southern end of the NWH field in block 211/27a, together with an extension of the field into block 211/27e. Blocks 211/27a and 211/27c were acquired by Fairfield from Amoco (UK), a subsidiary of BP, and partners in December 2009 while block 211/27e was awarded to Fairfield in the 25th Licensing Round in November 2008 with a one well drilling commitment. Fairfield currently has 0.1 per cent. of the equity over the old NWH field area which will become 100 per cent. following the fulfilment of certain conditions precedent and a 100 per cent. interest in Block 211/27e.

Water depth in the Darwin area is around 480ft. Nearby production platforms include TAQA’s Cormorant South Field (13 km), Shell/ExxonMobil’s Brent Field (24 km) and Fairfield’s Dunlin Field (25 km).

Background & Exploration History

NWH was discovered in April 1975 by the 211/27-3 well drilled by Amoco (UK). It was appraised with eight wells drilled and a FDP was submitted in April 1979. Two further appraisal wells, both of which found oil bearing reservoirs, were drilled during the field development programme. The field was developed by a large, fixed steel combined drilling and production platform from which a total of fifty-two development wells were drilled over field life. The platform was situated in the northern part of the NWH field in order to access the crestal areas at the northern margin of the geological structure. Some long reach wells were drilled from the platform, and together with the two most recent appraisal wells, proved produceable oil in the southern part of the field. However, the distance from the platform precluded development of this area at that time. It is this southern part of the old NWH field, together with the prospective area further to the south that Fairfield is planning to develop as a part of Darwin.

NWH production started in April 1983 and reached a peak of 86,500 Boepd later that year. Reservoir development strategy was through gas-lifted production wells with partial reservoir pressure support through targeted water injection. Enhancement of production through water injection was poorer than anticipated for reasons believed at the time to be predominantly due an extensive network of interconnected faults across the field. By March 1988 the original 30 well development scheme was complete and because of the poorer than anticipated production performance from many of the wells, a further seven well infill campaign was completed in September 1988. Additional sidetrack and infill drilling was then conducted in two further drilling campaigns between 1989 and 1992. In the mid-1990s came the last campaign with well abandonments, slot recoveries and a further eight infill targets being completed.

Due to high fixed operating costs associated with the large steel platform, relatively low oil prices and a significant cost of importing gas for fuel, the Cessation of Production (‘‘COP’’) process commenced in July 1999 with the last official production being achieved in 2002. The field has now been almost fully abandoned with all wells plugged and the platform removed. Only some remaining intra-field pipelines remain to be decommissioned at the original owners’ liability.

During its life, NWH produced approximately 120 MMbbls of oil, 5 MMbbls of natural gas liquids and 78 Bcf of gas. Current NWH oil in place estimates have an original STOIIP of 1,206 MMbbls (NWH 820 MMbbls, Darwin 386 MMbbls), indicating the NWH recovery factor is low for Brent province reservoirs and recoveries per well were highly variable. Understanding this variability is the key to successful redevelopment and the Directors believe that the current recovery factor calculated by the Company.

On 25 September 2009, the Group entered into a sale and purchase agreement in respect of certain licenses pertaining to the NWH field with the existing owners. Under the terms of the agreement, there is a two stage transfer of interests in the NWH Licenses in order to allow the Existing NWH Owners to continue to carry out decommissioning work in the NWH field whilst also allowing the Group to carry out oil and gas operations in the area of the NWH Licenses. As such, the Group currently holds only a nominal interest in the NWH Licenses, subject to the fulfilment of certain conditions precedent, upon which the remaining interests in the licenses will be transferred to the Group. The Directors believe that this will occur prior to December 2011.

Field Development Plan

Fairfield’s technical work on NWH has been directed towards understanding its reservoir performance as an analogue of what may be expected in the undeveloped southern part of NWH and further to the south in 211/27e. New 3D seismic was shot across the entire area in 2009 to better define the top and base Brent envelope and improve and rationalise the structural fault pattern. Contrary to the original interpretation of the 1980’s-vintage seismic data, the new data shows significantly less faulting and a much better defined structural grain. This is consistent with the inferred structural history and the observations from the stratigraphy and production history in the wells. This work helps to explain the poor water-flood response observed in many of the producing wells on NWH and highlights the importance of reservoir management and completion strategy.

Detailed petrophysical, stratigraphic and reservoir quality analyses have been completed based on the log and core data, together with a thorough review of all the NWH production data, well histories and production logs. A comprehensive new static model has been constructed to assist in understanding the reserves distribution, reservoir performance, optimum perforation strategy and water injection pattern design. This has resulted in the identification of a phased development concentrating initially on the proven, but undeveloped oil accumulations in the South of NWH (‘‘Phase 1 development’’) and then the prospective but potentially larger accumulations further to the south within 211/27e (‘‘Phase 2’’). Phase 2 is intended to occur after completion of Phase 1 but is contingent upon successful appraisal drilling of one or two appraisal locations within 211/27e (currently being planned for 2012).

Development in both phases will be achieved by the optimised placement of subsea producers and supporting water injectors in individual fault-panels. These fault panels are now well defined on the new seismic data meaning that with an appropriate completion and well management philosophy, producers will receive dedicated water injection support and reservoir sweep on a layer-by-layer basis from their respective injectors. This in-turn implies that the recoveries per well in the Fairfield development plan will be comparable with the upper-limit of what has already been proven to be achievable in the best of the original NWH development wells where good producer-injector pairing was achieved. Evaluation of alternative hosting options for the subsea development are ongoing with comparison economics being run for stand-alone FPSO units and fixed-hosting provided by nearby platforms. Requests for service have been issued to prospective hosting service providers and commercial and technical feasibility studies are ongoing. In the case of FPSOs, market enquiries have been issued and a market survey completed.

Although other hosting options are being considered, a draft FDP has been drawn up for the current base-case development scheme which is based on a tieback to the Fairfield -owned and operated Dunlin platform approximately 25 km away. A conceptual engineering study has been completed to define the size, scope and likely cost of the necessary topside modifications which will consist of installing gas compression facilities, reception tie-ins, metering, controls, and chemical injection facilities. Water injection would be supplied from Dunlin’s existing system. In this scenario, oil would be transported via Dunlin’s own export line in the Brent/Sullom Voe systems, and Darwin gas would be used for fuel on Dunlin with the excess being exported via Dunlin’s new pipeline link into the NLGP system. The quoted capital costs and reserves are based on this Dunlin tieback development scenario. It is envisaged there will be two drill centres, one each for Phase 1 and Phase 2. Wells will receive artificial lift either by gas lift or ESPs depending on the host facility chosen for the development. Subsea multiphase pumping is also an option for the longer tiebacks under consideration.

Phase 1 Development Planning

Development planning is ongoing but at present the Phase 1 development scheme will consist of 9 wells (4 water injectors, 5 producers) in 3 distinct fault panels in the southern part of NWH targeting a combined STOIIP of 144 MMbbls. Phase 1 project sanction is anticipated in late 2011, host modifications and infrastructure development through late 2011 to 2013, and development drilling commencing mid-year 2013. First oil from Phase 1 is anticipated in early 2014. Total anticipated development capital costs for Phase 1 are estimated at US$616 million.

Phase 2 Development Planning

Phase 2 will consist of a further 12 wells in two large fault panels in Darwin, together with a fault panel already tested and proven by the final appraisal well (211/27-12) on NWH.

Phase 2 sanction will be contingent upon the outcome of two appraisal wells provisionally planned for mid 2011. Phase 2 sanction would follow in mid-2012. Phase 2 development drilling is intended to occur after Phase 1 and commence at the start of 2015 with first oil being delivered in the third quarter of the same year. Total anticipated development capital costs for Phase 2 are estimated at US$555 million. The Directors anticipate production in relation to the Darwin field (Phase 2) to commence in 2015, and anticipate production will increase to over 12 MMboed in 2016 and will peak at almost 16 MMboed in 2017.

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