Bangchak Corporation Public Company Ltd (BCP) reported on 13 July 2018 that it had executed a sale and purchase agreement to divest its entire stake in SC 14C1 (Galoc), located offshore Northwest Palawan Basin, to Tamarind Galoc Pte Ltd. The deal involves approximately USD 20 million for shares in BCPâs subsidiary Nido Production Galoc (NPG), which owns 55.8% of the Galoc oil field. Part of the payment is due at the closing of the agreement while the remaining will be payable at agreed terms.  BCP owns the stake in NPG through its wholly-owned Nido Petroleum, which was acquired in 2014. Prior to the asset disposal, interests in SC 14C1 were split among Galoc Production Company (GPC) (33%, operator, wholly-owned subsidiary of Nido Petroleum), Kufpec (26.84%), Nido Petroleum (22.88%), Oriental Petroleum (7.79%), Philodrill Corp. (7.21%) and Forum Energy (2.28%).    The Galoc field is expected to deplete after 2020 as more than 80% of the recoverable reserves (approximately 4.7 MMbo) had been produced by end of 2017. The SC 14C1 production period is due to expire in December 2025. Due to that reason, the operator and its venture partners were expected to expand the field by developing the mid-Galoc area (MGA). However, poor results from two appraisal wells which were drilled in April 2017 had downgraded the potential of the area. Galoc 7 and its sidetrack intersected poor reservoir quality in the Galoc clastic units with combined gross thickness of 277 m and combined net reservoir thickness of 20 m.    Tamarind Galoc, a wholly subsidiary of Tamarind Resources, was established to focus on oil and gas in Southeast Asia. The company is currently operating in New Zealand, Australia and Papua New Guinea.  Background Information    SC 14 in the Northwest Palawan Basin has had a complex contractual history since its award to Cities Service for on 17 December 1975. Its original partners include Oriental, Philodrill, PNOC, Husky as well as other local firms. The interest holdings were distributed differently in each of the four sub-blocks (A, B, C and D).   On 17 December 1986, 14% of the original contract area was retained. This includes 12.5% held as Retained Area plus Matinloc/Pandan, Nido and Libro Production Areas.  Cities made oil discoveries at Nido 1, Matinloc 1, Pandan 1, Libro 1, Tara 1 and Galoc 1. In 1982 a four years extension to the exploration period was granted. Alcorn, in its 1989 Annual Report, stated that oil in-place was estimated to range between 80 - 260 MMbo and recoverable reserves between 24 and 102 MMbo, implying a recovery factor between 30 and 40%. In 1990, recoverable reserves were revised to 25 to 40 MMbo.  Unocal initially signed an agreement to carry out a phased study of the Galoc oil and gas field with the intent to determine the field's economic feasibility. In mid-October 2003, Unocal decided not to exercise its option to farm-in to the Service Contract and not to proceed with Phase 2 of the development of the Galoc field. The company considered the 150 MMbo in-place uneconomic. The Joint Venture continues to seek interested partners to develop the Galoc field.   On 24 September 2004, partner Nido Petroleum announced that, subject to the approval of the Philippines Department of Energy (DOE), a farm-in agreement for the development of the Galoc field has been executed. Two previously unknown companies, Cape Energy Pty Ltd and Team Oil Ltd, have farmed-in to "the Philippines Joint Venture partner's share of SC-14C for carrying costs through development". The current partners will maintain their current equity position in the contract until the two companies have earned their respective interests. Although subject to confirmation, it appears that the farm-in is for SC 14C West Linapacan (North-east) only, and does not involve the other areas of SC 14.   On 19 July 2005, the farm-in agreement for the development of the Galoc field was finally approved. Galoc Production Company formed by Vitol Holdings, Granby Oil and Team Oil took over the operatorship of the SC 14C Northeast block by acquiring 75% of the rightholding of the Phillippines Companies.GPC, a Netherlands-based oil investment company, completed a farm-in agreement for a 58.291% operating interest in SC 14C West Linapacan (North-east) on 19 July 2005, including the undeveloped Galoc field.   The Galoc field was discovered by Cities in 1981 with the drilling of wildcat Galoc 1. The well was targeting what was believed to be a carbonate build-up identified from a seismic anomaly, but which turned out to be an unusual turbidite sandstone mound in the Lower Miocene Galoc Unit, which unconformably overlies the Nido Limestone. Galoc 1 was drilled to TD at 3,700m and intersected a 40m oil column. A DST in the Galoc Unit flowed 1,828 bo/d (35.3Â° API). Cities followed the discovery in the same year with the South Galoc 1A step-out, located 5km south of Galoc 1. The well was drilled on a similar but separate anomaly to the discovery and reached TD at 2,614m, encountering five gas bearing intervals in two zones, with a net pay of 15m. The lower zone yielded a flow of 3.77 MMcfg/d plus 280 bc/d while the upper zone tested 3.16 MMcfg/d plus 188 bc/d. South Galoc 1A was plugged and abandoned as a non-commercial gas/condensate discovery.     Galoc lies in 320 m of water at about 2,300 metres below sea level, in a low relief domal structure with an areal extent of about 12 sq km at the oil/water contact. A combination stratigraphic/structural trapping mechanism is formed by the turbiditic sands being draped over a subtle anticlinal structure at Nido Limestone level. The field produced 385,000 barrels on long term test in 1988.     The field was brought onstream on 9 October 2008, with oil flowing to the "Rubicon Intrepid" FPSO. In March 2006, information from DoE (Department of Energy) Petroleum Resources and Development Division indicated that the Galoc and Octon oil fields could likely produce a maximum of 16 MMbbl during a three to ten-year operation.    On 16 September 2008, an independent reserves certification report indicated that Galoc field's 1P reserves were 15.9 MMbo, a 64% increase over the previous estimate of 9.7 MMbo. On 4 May 2011, partner Otto Energy reported an upgrade in gross remaining 2P reserves as of 1 January 2011, to approximately 7.35 MMbo. The upgrade was due to better than expected reservoir performance and to an extension of field life because of higher prevailing oil price. During 2011, Otto was assessing Phase 2 development which was then expected to unlock contingent resources of 2 to 8 MMbo.    Following an independent assessment by GCA (Gaffney, Cline & Associates) as of 30 June 2011, 1P recoverable reserves increased to 12.4 MMbo, 19.2% higher than the previous estimate of 10.4 MMbo as of 31 December 2010. According to partner Nido, the increase was due to better than expected reservoir performance in the first half of 2011. The 2P and 3P recoverables estimate changed respectively by +1.6% and -2.2% from the previous estimates of 31 December 2010.    An audit by GCA up to 31 December 2011 indicated a new 1P estimate of 14.44 MMbo recoverable, a 16.45% increase from the previous estimate of 12.4 MMbo (as of 30 June 2011). The new 2P recoverable reserves estimate was 22.89 MMbo, a 23.06% increase from the previous estimate of 18.6 MMbo. The new 3P recoverable reserves estimate was 29.44 MMbo, up from the previous 26.3 MMbo (11.94% increase). Nido attributed the increased reserves to a better than expected reservoir performance during the second half of 2011.    Following approval of FID for Phase II field development in September 2012, operator Otto Energy announced an upgrade in reserves according to a third-party assessment as of 1 July 2012. The upgrade was due to higher recovery factors from existing wells and to the booking of new reserves previously classified as contingent. Remaining recoverable reserves have been estimated at 8.9 MMbo on a 1P basis (a 156% increase from a previous estimate as of January 2012) and 13.4 MMbo on a 2P basis (134% increase).    A new reserves assessment was reported by Otto on 14 March 2013. The revision, carried out by advisor RISC, indicated EUR of 21.7 MMbo (1P) and 25.4 MMbo (2P) as of 1 January 2013. These figures mark increments of 13% (for 1P) and 1% (for 2P) from the previous assessment released in July 2012. The increase was attributed to better than expected reservoir performance and to field life extension due to higher prevailing oil prices. Remaining recoverable reserves have been estimated at 11.7 MMbo (1P) and 15.4 MMbo (2P). Reserves replacement ratio in the field has been estimated as 115% on a 1P basis and 98% on a 2P basis.    Otto Energy was evaluating the possibility of a further expansion of the Galoc oil field in late August 2014. Following the first eight months of Phase II production, the operator gained a better understanding of the reservoir distribution between the producing Galoc Central area and the undeveloped Galoc Mid and North areas. Otto expects to issue a recommendation regarding further exploration and development activities between late 2014 and early 2015. Phase II performance has been in line with expectations since its startup in December 2013, with over 2 MMbo produced up to 31 July 2014. The two Phase I wells (Galoc 3ST1 and Galoc 4) continued producing according to forecasts through July 2014. Phase II wells (Galoc 5 and Galoc 6) were producing 4,680 bo/d as at 31 July 2014, contributing to 58% of the total field production.    Otto also released an updated third-party reserves assessment as of 31 July 2014, based on decline curve analysis from Phase II production. Developed field reserves have been estimated at 9.2 MMbo (1P), 11.9 MMbo (2P) and 15.6 MMbo (3P). The updated 2P and 3P estimates are respectively 2% and 4% lower than previous estimates as of 31 December 2013.    First oil production from Phase II development of the Galoc field was achieved on 4 December 2013. The initial output following the commissioning of new wells Galoc 5H and Galoc 6H was 14,500 bo/d. With the new developments, the field is anticipated to produce beyond 2020 with an estimated ultimate recovery of approximately 25 MMbo. Phase II development focused on the refurbishing of the âRubicon Intrepidâ FPSO and the drilling of horizontal production wells Galoc 5H and 6H. The project was completed in approximately 14 months, from FID to first production.    Following the first eight months of Phase II production, the operator gained a better understanding of the reservoir distribution between the producing Galoc Central area and the undeveloped Galoc Mid and North areas. Otto originally expected to issue a recommendation regarding further exploration and development activities between late 2014 and early 2015. Phase II performance has been in line with expectations since its startup in December 2013, with over 2 MMbo produced up to 31 July 2014. The two Phase I wells (Galoc 3ST1 and Galoc 4) continued producing according to forecasts through July 2014. Phase II wells (Galoc 5 and Galoc 6) were producing 4,680 bo/d as at 31 July 2014, contributing to 58% of the total field production    Nido Petroleum acquired the block operatorship from Otto Energy on 17 February 2015. In July 2015, the operator announced that the Mid-Galoc area is estimated to contain gross 1C-2C-3C contingent resources of 6.2-9.5-14.6 Mmstb respectively. In-place oil volumes for that area have been estimated at 52.6 MMbo (P90), 77.3 MMbbl (P50) and 113 MMbbl (P10). Recovery factors range between 12% and 13% and are typical of reservoir performance under a pressure depletion mechanism. Two horizontal development wells were planned to be tied back to the existing Galoc FPSO facilities. First oil production form mid Galoc area is expected to commence on 1 January 2018 with initial peak anticipated at 3,000 stb/d.
Tamarind (->55,8%) has bought a 55% stake in the Galoc field (lies off in SC 14C-1) from partner BCP for US$20 MM. 