16th Mar 2009 07:00
EMERALD ENERGY Plc
16 March 2009
EMERALD ENERGY Plc ("Emerald" or the "Company"), a United Kingdom based company engaged in exploration for and production of hydrocarbons in South America and the Middle East, announces its final results for the year ended 31 December 2008.
HIGHLIGHTS
OPERATIONS
Commencement of production from the Khurbet East field in Block 26, Syria, on 21 July 2008 with gross production of 1.414 mmbbl of oil (0.417 mmbbl Emerald net entitlement) by the end of 2008;
Discovery of the Yousefieh field in Block 26, Syria;
Discovery of the Capella field in the Ombu block in Colombia, with gross Proved plus Probable reserves of 14.835 mmbbl of oil (12.550 mmbbl Emerald net entitlement) and gross best estimate contingent resources of 42.165 mmbbl of oil (35.672 Emerald net entitlement);
Proved plus Probable working interest reserve addition of 15.004 mmbbl (before deduction of 1.613 mmbbl production);
Working interest production of 4,407 bopd (2007: 2,274 bopd) with Emerald net entitlement of 3,385 bopd (2007: 2,038 bopd).
FINANCIAL
EBITDA of $66 million (2007: $28 million);
Profit after tax of $36 million (2007: $7 million);
Cash and cash equivalents of $74 million as at 31 December 2008 (2007: $40 million).
OUTLOOK
Completion of the Gigante No.2 development well in Colombia and the expansion of the Khurbet East field facilities in Syria expected to lead to a material increase in production before the end of 2009;
Appraisal activities in the Yousefieh field in Syria and the Capella field in Colombia may lead to further increases in production prior to the end of 2009;
Exploration drilling in Block 26, Syria, and in the Gigante No.2 well and two ANH licenses in Colombia, may provide material reserve upside;
Business plan for 2009 supported by strong balance sheet and cash flow generation from producing assets in Colombia and Syria.
CHAIRMAN'S STATEMENT
I am pleased to report the excellent progress Emerald Energy Plc has made in both South America and Syria during 2008.
In Syria, we achieved first production from the Khurbet East field, our first discovery in Block 26. The initial field development programme comprised the drilling of additional wells to add field production capacity and increase our understanding of the Massive reservoir, and the installation of an early production facility, commissioned mid 2008, that is currently gathering and processing over 10,000 bbl per day of production from 5 wells. A project to increase the fluid handling capacity of the facility to 18,000 bbl per day by mid-2009 is progressing and 3 additional production wells are planned to be drilled to increase the field production level to match that of the enlarged facility.
The interpreted 3D seismic data acquired over the Khurbet East field together with well and production data are all being used to optimise the surface and sub-surface designs for full development of the field, with tendering for the permanent production facilities expected to commence in mid-2009. The same dataset, together with new data being gathered from the Khurbet East No.8 well currently being drilled, will be used to complete a revised independent reserves evaluation of the Khurbet East field, expected to be completed in the second quarter of 2009. We believe, from the data gathered so far, that the revised evaluation is unlikely to materially change the volume of Emerald's entitlement reserves from the Massive reservoir.
We have also experienced exploration success in Syria on the Yousefieh prospect. The Yousefieh No.1 discovery well located near the crest of the structure was quickly followed by the No.2 appraisal well located on the eastern limits of the field. The structure has been evaluated by independent consultants who estimate the structure may contain, in a P50 case, some 48.5 million barrels of stock-tank-oil-in-place. Emerald's best estimate is that, using a reasonable recovery factor, some 12 to 15 million barrels of oil may be recoverable. Further work, which may include the results of a second appraisal well, Yousefieh No.3, and possibly a cased hole flow test of Yousefieh No.2 planned for 2009, will be required to independently determine the reserves contained within the Yousefieh structure. The close proximity of the Yousefieh field to the Khurbet East field may lead to joint development of both fields utilising enlarged surface facilities and the sharing of operations personnel. A technical and commercial evaluation report will be prepared for the Yousefieh discovery based on the data acquired from the two wells drilled to date.
In Colombia we discovered the Capella field which may, after completion of the planned appraisal drilling and long term testing operations, prove to be a very material accumulation. The Capella No.1 discovery well, 4 further wells already drilled and a sixth well currently being drilled, are all located in the south-western part of the structure where the existing road infrastructure has facilitated operations. The area explored to date extends over an area of 3,500 acres (14 sq km), whereas the whole Capella structure is believed to extend to some 22,000 acres (89 sq km). An application for an environmental permit to explore the north-eastern part of the Capella structure is in progress and we are planning to commence drilling in this area in the second half of 2009. An independent evaluation of the Capella discovery, of which Emerald holds a 90% working interest, has estimated Proved and Probable reserves of some 15 million barrels plus a best estimate of 42 million barrels of contingent resources. In 2009 we plan to continue the long term production testing programme of the existing and new wells and commence the appraisal drilling in the north-east of the structure. The results of these activities will assist in designing a commercial development of the Capella field. There is potential that the structure extends to the south-west outside the Ombu contract area and we have recently been awarded, by the ANH, the Durillo E&P contract which covers a 110 sq km area adjacent to, and south-west of, the Ombu block making a contiguous area of 410 sq km under contract.
In Colombia, a successful development drilling programme in the Vigia field has resulted in establishing increased production levels from the field which contributed to achieving the gross average rate of 3,500 bopd for our Colombian assets. Several workovers were performed on the Gigante No.1A well to replace the down hole pump that failed after only short run lives. A number of different pump types and configurations have been tried and we shall continue to work to improve the reliability of this, the oldest well in Emerald's portfolio. In December, we commenced drilling the Gigante No.2 well, designed to accelerate production of reserves in the Tetuan reservoir and expected to produce at rates of approximately 3,000 bbl per day, similar to the rates initially seen at Gigante No.1A. The No.2 well will also explore the slightly deeper Caballos horizon which when tested by the No.1A well in 1999 recovered oil at a non-commercial rate. We believe that by designing the new well to penetrate the Tetuan and Caballos at levels structurally higher than the No.1A well we may encounter favourable results from both horizons. The well is currently at 11,000 ft and we estimate results from the well should be available by mid 2009.
Other exploration projects in Colombia have been progressed during 2008. Drilling has now commenced on the Jacinto prospect in the Jacarada block and drilling is expected to commence on the Mirto prospect in the Maranta block during the second quarter. The combined potential of these two prospects is in excess of 20 million barrel of prospective resource and success on either one of these would have a positive material impact on our Colombian reserves.
We have continued to add licenses to the portfolio, creating exploration opportunities for the future. In addition to the recently awarded Durillo contract, the Company has been advised that, in 2008 bidding rounds, it was the successful bidder on Block VSM32 in Colombia and Block 163 in Peru. Both of these E&P contracts are now in the award process. Block VSM32 is adjacent to the Company's Matambo block in the Upper Magdalena Valley in Colombia and Block 163 is located in the Ucayali basin in Peru, an area containing several existing oil and gas fields. Emerald wishes to build a material portfolio in Peru and will continue to look for additional new projects by participation in future bidding rounds, farming into existing projects or by acquisition.
BOARD CHANGES
Fred Ponsonby stepped down as a director in December to devote more of his time and energy to his other business interests. Fred joined the board of Emerald in August 2003, at the time of the rescue rights issue, and I would like to thank Fred for his support during the five years that Emerald has grown from being a small struggling oil company to being a company that now forms part of the FTSE 250.
OUTLOOK
The volatility of the oil price seen in 2008 has now moderated but we now face the uncertainty of the impact from the slowing global economy. These events, whilst unsettling for many in the short term, will not affect our short term plans or longer term aspirations. We have built a portfolio with assets at every stage of the cycle of E&P projects, from exploring new areas with seismic and the drill bit to cost optimisation of operations for the more mature fields that are now considered fully developed. The cash resources we held at the beginning of the year and the cash flow we are generating from operations in Colombia and Syria will allow us to continue building shareholder value using the Company's own resources.
Alastair Beardsall
Executive Chairman
16 March 2009
REVIEW OF OPERATIONS
In the Middle East, Emerald is participating in the contract to explore, develop and produce hydrocarbons in Block 26, Syria. In South America, Emerald is participating in three Association Contracts with Ecopetrol, the Colombian state oil company, in several exploration and production contracts issued by the National Hydrocarbon Agency of Colombia ("ANH"), and is in the process of being awarded its first exploration and production contract in Peru.
SYRIA
Block 26 Production Sharing Contract
Contract for the Exploration, Development and Production of Petroleum ("PSC"), effective August 2003;
Emerald has 50% non-operating working interest in the contract;
Exploration period to August 2010, with option to extend for additional two years;
Exploitation period of up to 25 years for each commercial discovery, with option to extend each for additional 10 years;
Royalty of 12.5%; cost recovery allowance, and profit oil sharing on a sliding scale basis;
Area of 8,300 sq km.
Block 26 is situated in northeast Syria and its boundaries surround existing discovered fields, some of which have been developed and currently produce in excess of 100,000 bopd, including the Souedieh field, the largest oil field in Syria. Production from these fields is from mid-Cretaceous limestone reservoirs that produce medium gravity 20-26° API crude oil. These existing fields are excluded from the PSC.
The PSC grants rights to explore, develop and produce from all stratigraphic levels outside the existing field areas and the deeper stratigraphic levels below the pre-existing discovered field areas.
Activity during the initial phase of exploration that ended in August 2007 resulted in the discovery of the Khurbet East field. The joint venture partners elected to enter the first extension of the exploration period with a duration of three years and a minimum work obligation of 250 sq km of 3D seismic and two exploration wells. All of the minimum work obligations for the current period have been completed. In August 2010 the joint venture partners have the option to enter a second extension period of two years with a minimum work obligation of two exploration wells.
Khurbet East field
Since the discovery of the Khurbet East field with the Khurbet East No. 1 well, announced in June 2007, the field was appraised by the Khurbet East No.2 and No.3 wells and, in February 2008, the Syrian Ministry of Oil and Mineral Resources and the Syrian Petroleum Company ("SPC") granted approval for commercial development of the Khurbet East field and approved a Development Area of approximately 100 sq km covering the field. The development area is operated by Dijla Petroleum Company ("DPC"), a joint operating company set up with SPC.
An independent reserves evaluation, conducted prior to the approval for commercial development, concluded the gross life-of-field Proved plus Probable reserves of the Cretaceous Massive formation to be 65.6 million barrels of oil (11.3 million barrels Emerald net entitlement). This evaluation excluded hydrocarbon in the deeper Butmah and Kurachine Dolomite formations encountered in the Khurbet East No.1 well.
Initial field development commenced with the establishment of early production from the shallow Cretaceous Massive reservoir. The first well to be drilled in the development phase of the field, Khurbet East No.4, reached a total depth of 1,935 metres in March 2008 and was completed as an oil producer. The well is located close to the crest of the structure in the Cretaceous Massive reservoir, approximately 150 metres away from the Khurbet East No.1 well which has not been completed for production from the Massive reservoir as it is intended to be used for further appraisal of the deeper reservoirs.
Khurbet East No.5, the first horizontal development well in the field, was drilled with a 300 metre horizontal section and was flow tested during a 6 hour flow period at an average oil rate, under natural flow and restricted by well testing equipment, of 2,041 bopd through a 24/64 inch choke. Khurbet East No.6, the second horizontal development well in the field, was drilled with a 200 metre horizontal section and well testing operations were not conducted.
Oil production commenced from the Khurbet East field on 21 July 2008 using a newly installed early production facility. Gross oil production to the end of 2008 was 1.414 million barrels of oil (0.417 million barrels Emerald net entitlement). Five producer wells have been available for production during this period, consisting of three vertical producers, Khurbet East No.2, No.3 and No.4, and two horizontal producers, Khurbet East No.5 and No.6. Since the commencement of production, a number of reservoir and pressure monitoring programmes have been conducted in the wells to collect information to optimise the design of the full field development facilities.
The crude oil produced from the Khurbet East field was determined to have specifications similar to those of the Syrian Heavy crude oil. Under oil marketing arrangements agreed with SPC and the Oil Marketing Bureau of the Syrian Government ("OMB"), oil produced from the Khurbet East field is sold as Syrian Heavy crude oil which has an API of approximately 24.1, and exported through the Mediterranean port of Tartous using SPC's oil handling infrastructure. In the period to September 2009, under the OMB's arrangements for marketing oil produced from newly developed fields in this area, the Company receives 80 per cent of the price of the Syrian Heavy crude oil, with the settlement for the remaining unpaid amount, subject to any adjustments for variations in oil quality, taking place in September 2009. After completion of the initial oil analysis process OMB will then pay, without retention, 100% of the selling price as determined for the measured oil quality.
The first of 2 delineation wells, Khurbet East No.7, was drilled to a total depth of 2,060 metres in the northern part of the field in January 2009, encountering the top of the Cretaceous Massive reservoir at approximately 1,978 metres. Good hydrocarbon shows were encountered across a 7 metre interval while drilling into the reservoir and gradually diminished over the next 13 metres. Reservoir porosities in the range of 5% to 10% were measured, significantly lower than the range of 16 to 20% encountered in the central portion of the field. Although the oil-water contact was not directly determined by the wireline logs, preliminary analysis indicates that the oil-water contact in the field may be slightly deeper than previously interpreted. The well has the potential to be used for future water disposal.
The second delineation well, Khurbet East No.8, commenced drilling in March 2009 and is located 2.3 kilometres to the south of the Khurbet East No.3 production well. The Khurbet East No.8 well is positioned to investigate reservoir properties and determine the oil-water contact in the south of the field and may have the potential to be used as a water disposal well in the future.
As a result of the early field performance, work is now underway to expand the capacity of the field's gathering, processing and loading facilities to 18,000 bfpd as an interim expansion prior to the full field development of the Khurbet East field. This interim expansion of capacity, consisting of the installation of additional surface equipment and the drilling of three further development wells, is expected to be operational in the third quarter of 2009. The Company anticipates that the operating company, DPC, will commit to the full field development, consisting predominantly of additional processing facilities and development drilling, during 2009.
An updated independent reserves evaluation of the Massive reservoir is underway, taking into account seismic, well and production information acquired since the last evaluation, including the results of the Khurbet East No.8 well that is currently being drilled, and is expected to be concluded in the second quarter of 2009. Since the previous independent reserves evaluation, the results of the 3D seismic interpretation across the field and the lower reservoir quality encountered in the Khurbet East No.7 well in the north of the field are expected to reduce the interpreted oil initially in place and the better-than-expected reservoir production experienced from the high quality reservoir combined with the field pressure performance are expected to enhance the interpreted recovery factor.
Yousefieh discovery
The Yousefieh No.1 exploration well, located approximately 3 km from the Khurbet East field processing facilities, was drilled in November 2008 to a total depth of 2,139 metres to evaluate the potential of a new exploration play identified from the 3D seismic survey acquired in 2007 over the Khurbet East field and nearby areas. The well encountered an oil column of approximately 64 metres in the target Cretaceous aged formations, with approximately 63 metres of net oil pay having an average porosity of 18.6%, and during an open-hole test of the top 19 metres of reservoir flowed 23° API oil to surface, under natural flow, at approximately 900 bopd through a 48/64 inch choke. In January 2009 a cased-hole flow test of the Yousefieh No.1 discovery well was performed, effectively testing the whole 63 metre net oil pay interval as an ineffective cement bond behind the casing provided poor vertical isolation over the interval. The well flowed, under natural flow and through a 48/64 inch choke, at an average rate approximately 1,460 bopd over a 4 hour period with a water cut of up 5% comparing favourably with the open-hole test run previously over the top 19 metres of reservoir. Remedial cementation of the production liner is planned to isolate the water producing zone prior to commencement of production from the well.
The Yousefieh No.2 appraisal well, located approximately 1.8 km east of the Yousefieh No.1 discovery well, commenced drilling in January 2009 and reached a total depth of 2,070 metres in February 2009. Based on wireline logging and cores recovered while drilling, the well encountered approximately 16 metres of net potential hydrocarbon pay with an average porosity of approximately 16%. An open-hole production test of the reservoir interval recovered quantities of oil and water but did not establish continuous production at surface. A liner was run in the well and the reservoir interval may be re-tested at a later date. As expected in the pre-drill estimation, the Yousefieh No.2 well encountered the reservoir with less thickness and lower reservoir quality than seen in Yousefieh No.1. This variation is consistent with a stratigraphic carbonate accumulation such as the Yousefieh discovery. The data acquired in this well will be used to refine the understanding of these lateral variations in the geological and reservoir modelling of the accumulation and to assist in development planning.
Based on a preliminary evaluation of the data acquired in the Yousefieh No.1 discovery well and the Yousefieh No.2 appraisal well, the range of oil initially in place, on a gross basis at stock tank conditions, is estimated to be 27.2 (P90), 48.5 (P50) and 73.9 (P10) million barrels. Further work is required to determine the expected range of recovery factors and, hence, reserves.
The Yousefieh discovery is located close to existing infrastructure, with the Yousefieh No.1 surface location approximately 3 kilometres from the early production facilities in the Khurbet East field. The close proximity of the Yousefieh discovery to the intended site for the full field development facilities for Khurbet East may lead to an enlarged shared facility being installed resulting in both capital and operating cost savings.
Exploration
Following the success in the Yousefieh No.1 exploration well, the joint venture has commenced the acquisition of a 850 sq km 3D seismic survey to assist in the identification of further prospects and leads in this new exploration play in the areas surrounding the Khurbet East field and Yousefieh discovery.
COLOMBIA
Campo Rico Association Contract
Emerald 100% operated working interest (50% Ecopetrol back-in right);
Following a discovery, Ecopetrol has the right to participate in the development of the discovery with a 50% working interest and Emerald has the right to recover reimbursable costs from a share of production;
Contract awarded in May 2002. Final exploration relinquishment in March 2010 with exploration and exploitation rights to December 2027 in remaining area;
Area of 268 sq km.
The Campo Rico block is located in the Llanos basin. Emerald discovered and currently operates three fields in the block; the Campo Rico, Vigia and Centauro Sur fields. In addition Emerald has identified opportunities for exploration drilling outside of the existing fields, based on interpretation of the 172 sq km 3D seismic survey acquired in the block. In 2008, the Company relinquished 235 sq km (47%) of the block as part of the exploration terms of the Association Contract, retaining the producing areas and the areas containing the identified exploration drilling opportunities.
Campo Rico field
The Campo Rico field was discovered in March 2004. In December 2005, Ecopetrol granted the Campo Rico field commerciality status. The reimbursable costs on this field have been recovered and future costs and production for this field are shared with Ecopetrol on a 50/50 basis.
The field has five producing wells and produces 16° API crude oil from Mirador sands. The average production rate achieved by the field in 2008 was 1,198 bopd and the cumulative oil production from the field at the end of 2008 was 2.695 million barrels.
The fifth development well, Campo Rico No.5, was drilled and completed in the central portion of the field and commenced production in February 2009.
Vigia field
The Vigia field was discovered in April 2005. In July 2008, Ecopetrol elected not to exercise its 50% back‐in right in the Vigia field and Emerald has elected for sole‐risk field status. Emerald will continue to pay 100% of future costs and benefit from 100% of production until the sole‐risk reimbursable costs on this field have been recovered, currently expected in 2009, after which Ecopetrol will join operations with further costs and production being shared with Ecopetrol on a 50/50 basis.
The field has six production wells and produces 15° API crude oil from the Une and Lower Gacheta sands. The average production rate achieved by the field in 2008 was 1,381 bopd and the cumulative oil production from this field at the end of 2008 was 0.966 million barrels.
Three development wells were drilled in 2008 at structurally high locations in the field to recover reserves from the Une and Gacheta formations that would not be recovered by the existing producing wells. Vigia No.5 was drilled and completed in the central portion of the field and commenced production from the Une formation in June 2008. Vigia No.6 was drilled and completed in the northern portion of the field and commenced production from the Gacheta formation in August 2008. Vigia No.4ST, a new well drilled utilising the existing top section of the unsuccessful Vigia No.4 well, was drilled and completed in the southern portion of the field and commenced production from the Une formation in October 2008.
Centauro Sur field
The Centauro Sur field was discovered in April 2007. The Centauro Sur field development was awarded commerciality status by Ecopetrol in May 2008 and joint operations commenced. The reimbursable costs on this field have been recovered and future costs and production for this field are shared with Ecopetrol on a 50/50 basis.
The field has two producing wells and produces 16° API crude oil from Mirador sands. Field production is transported through a flow line to the Campo Rico field where it is processed using the Campo Rico field facilities. The average production rate achieved by the field in 2008 was 356 bopd and the cumulative oil production from this field at the end of 2008 was 0.486 million barrels.
Matambo Association Contract
Emerald 100% operated working interest (50% Ecopetrol back-in right);
Following a discovery, Ecopetrol has the right to participate in the development of the discovery with a 50% working interest and Emerald has the right to recover reimbursable costs from a share of production;
Contract awarded in November 1996. Exploration and exploitation rights to December 2024;
Area of 69 sq km.
The Matambo block, located in the Upper Magdalena valley, contains the Gigante field, discovered by Emerald in 1999. Emerald operated the Gigante No.1A well on a sole risk basis from February 2003. Emerald has recovered the historic costs on this field and Ecopetrol now participates in joint operations with costs and production being shared with Ecopetrol on a 50/50 basis. When sole risk development commenced, an area of 733 metres radius around the Gigante No.1A well was established by Ecopetrol based on an interpreted drainage area. In 2008, this area was increased to 1,038 metres radius. Since April 2007, Ecopetrol has participated within this joint operations area. Emerald retains exclusive exploration rights in the block, without any additional work obligations.
The field is operated with a single well, Gigante No.1A, producing 32° API gravity crude oil from the Tetuan reservoir at approximately 15,400 feet. The average production rate achieved by the field in 2008 was 548 bopd and the cumulative oil production from the Gigante field at the end of 2008 was 2.789 million barrels.
Drilling of the Gigante No.2 well, planned primarily as a development well in the producing Tetuan reservoir, commenced in December 2008. Located close to the crest of the structure, this well is expected to encounter the top of the Tetuan reservoir approximately 250 feet higher than the existing Gigante No.1A well. The Company expects Gigante No.2 to recover approximately 4 million barrels of existing oil reserves from this reservoir, with initial rates similar to the rate of 3,000 bopd experienced in the early production from the Gigante No.1A well.
The cost of the well to the Tetuan reservoir will be shared equally between Emerald and Ecopetrol. In addition, Emerald will, at its own cost, deepen the well to the prospective Caballos formation approximately 120 feet below the Tetuan reservoir to evaluate the exploration potential of this deeper horizon. The Company estimates the Caballos formation may contain 15 million barrels of unrisked recoverable resources. In the event of success, Ecopetrol has the right, under the Association Contract, to participate at a 50% interest in development of the Caballos formation by reimbursing a 50% share of exploration costs.
Fortuna Association Contract
Emerald 90% operated working interest (20% Ecopetrol back-in right);
Following a discovery, Ecopetrol has the right to participate in the development of the discovery with a 20% working interest and Emerald has the right to recover reimbursable costs from a share of production;
Contract awarded in December 2003. Final exploration relinquishment in March 2012 with exploration and exploitation rights to December 2029 in remaining area;
Area of 53 sq km.
The Fortuna block lies in the Middle Magdalena basin and the contract area includes the Totumal oil field, produced by Ecopetrol until it was abandoned in 1993. In 2008, the Company relinquished 53 sq km (50%) of the block as part of the exploration terms of the Association Contract, retaining the producing areas.
Silfide field
The Silfide field was discovered in October 2005. In December 2007, Ecopetrol elected not to exercise its 20% back-in right in the Silfide field in the Fortuna Association Contract and Emerald elected to exploit the field under sole risk field status.
The field has one producer well and produces 17° API crude oil from Umir sands. The well, which when producing had a flow rate of 20 bopd, was closed for most of 2008 and the cumulative oil production at the end of 2008 was 6,000 barrels.
Production operations in the Silfide field were temporarily suspended at the end of 2008 due to the low oil price environment.
Aureliano field
The Aureliano field is located to the north of the Totumal field, separated by a fault.
The Aureliano No.1 exploration well on the Fortuna block was completed in late January 2007, encountering the target La Luna limestone formations. A flow rate of 10 bopd of 25° API gravity oil was established during production and stimulation operations. The recovery of oil confirmed the presence of hydrocarbons but the low flow rate indicated that communication with a fracture network was not established.
Production operations in the Aureliano field were suspended in August 2007 due to the low flow rates.
Totumal field
The Totumal field produced over 800,000 barrels of oil from the La Luna formations prior to abandonment in 1993.
The Totumal No.4 and Totumal No.1 wells were re‐entered in 2007 with the aim of recommencing production from the field. The well bores were cleaned out, production tubing with a mechanical pump installed, and the wells recommenced production of 25° API gravity oil. The average production rate achieved by the field in 2008 was 34 bopd and the cumulative oil production from the Totumal field at the end of 2008, since recommencing production in 2007, was 20,000 barrels.
Production operations in the Totumal field were temporarily suspended at the end of 2008 due to the low oil price environment.
Ombu Exploration & Production Contract
Emerald 90% operated working interest (no third party back-in rights);
Contract awarded by the ANH in December 2006 with an exploration period of up to 6 years and exploitation period of up to 24 years for each discovered field;
Third exploration phase with a commitment to drill one well ends in November 2009;
Area of 300 sq km.
The Ombu block lies in the Caguan Putumayo basin to the southwest of the Llanos Basin. Emerald was awarded the contract with 100% working interest and operatorship. Prior to drilling the first exploration well, the Company entered into a farmout agreement under which Canacol Energy Inc. earned a 10% working interest, subject to the approval of the ANH, by paying 100% of the cost of the drilling and production testing of the Capella No.1 well.
The Capella No.1 exploration well was drilled to a total depth of 3,802 feet, discovered oil of approximately 10° API gravity in two intervals in the target Eocene aged Mirador formation, and was flow tested at a combined oil rate of 240 bopd. The lower interval tested at a stabilised rate of approximately 155 bopd with a water cut of approximately 15% over a 6 day period. The upper interval tested at a stabilised rate of approximately 85 bopd with only traces of water over a 4 day period.
The Capella No.2 well, located approximately 1.3 km southwest of Capella No.1, was drilled to a total depth of 3,550 feet, also encountered oil in two intervals in the Mirador reservoir, and was flow tested at a combined oil rate of 345 bopd. The lower interval was flow tested at stabilised rate of approximately 145 bopd with a water cut of approximately 4%. The upper interval flow tested at a stabilised rate of approximately 200 bopd with a water cut of approximately 10% over a period of 2 days.
Capella No.3, the first deviated well drilled in the block, was drilled from a surface location adjacent to the Capella No.1 and penetrated the reservoir approximately 340 metres away. The lower Mirador reservoir was flow tested at a rate of approximately 135 bopd with a water cut of approximately 8%. The upper Mirador reservoir was encountered with similar thickness and petrophysical properties as in the previous wells but was not flow tested.
The Capella No.4 vertical well was drilled approximately 1.6 kilometres to the southwest of the Capella No.1 location and both of the Mirador reservoir intervals were encountered with the upper interval in this well being thinner than in previous wells. However, poor cementing within the well bore, resulted in neither of the Mirador intervals being effectively flow tested.
The Capella No.5 well, located some 3.4 kilometres to the northeast of Capella No.1, also encountered both Mirador reservoirs. The lower Mirador reservoir was flow tested at an average rate of approximately 82 bopd with a water cut of approximately 52% and the upper Mirador reservoir was flow tested at an average rate of approximately 26 bopd with a water cut of approximately 4%.
The intervals flow tested to date in the first five wells drilled have flowed heavy oil in the range of approximately 9° to 11° API gravity. The Company plans to drill up to a further two wells in 2009 and to complete extended production testing of all the wells as part of the appraisal of the southern part of the Capella structure. Extended production testing of Capella wells commenced in February 2009 with an average daily production rate of approximately 400 bopd, comprising of contributions from the Capella No.1 and Capella No.2 wells, and with the water cut for the field steadily reducing to a level of approximately 6%.
Following the environmental permitting of the northern half of the structure, the Company plans further delineation drilling. If Emerald elects to enter the fourth exploration phase, the minimum work programme will include the drilling of one exploration well by November 2010.
An independent resource and reserve evaluation of the Capella structure was conducted by Netherland, Sewell & Associates, Inc ("NSAI") using SPE guidelines. In evaluating the oil in place, NSAI considered two cases; the low (P90) case considered the area of approximately 3,500 acres investigated by the first five wells drilled, and the high (P10) case considered the area of the full structure of approximately 22,000 acres. For these cases, NSAI estimated gross stock tank oil initially in place to be 245 and 1,111 million barrels respectively. NSAI estimated the gross recoverable resource, consisting of reserves plus contingent resources, to be 26.5 million barrels in the low (P90) case and 122.5 million barrels in the high (P10) case. NSAI used a lognormal distribution, commonly used in geological estimation, in determining the P50 gross resource estimate to be 57 million barrels.
For determining the proportion of the above mentioned resources to be classified as reserves, NSAI considered only potential drilling locations up to three well spacings away from the existing five wells, equivalent to a developed area of up to approximately 4,000 acres. The resultant gross reserves distribution is estimated to be 7.3 (Proved), 14.8 (Proved plus Probable), and 23.0 (Proved plus Probable plus Possible) million barrels.
By subtraction of the reserves from recoverable resources NSAI estimates the gross contingent resource of the Capella structure to be 19.2 (low estimate), 42.2 (best estimate), and 99.5 (high estimate) million barrels.
Durillo Exploration & Production Contract
Emerald 100% operated working interest (no third party back-in rights);
Contract awarded by the ANH in January 2009 with an exploration period of up to 6 years and exploitation period of up to 24 years for each discovered field;
First exploration phase of up to 12 months to January 2010 with commitment to acquire 22 km of 2D seismic data;
Area of 110 sq km.
The Durillo block lies in the Caguan Putumayo basin, adjacent to the southwest edge of the Company's Ombu exploration & production contract area. The Company considers that the Durillo block may have potential in the same exploration play as seen at Capella.
If Emerald elects to enter the second exploration phase, the minimum work programme includes the drilling of one well.
Maranta Exploration & Production Contract
Emerald 100% operated working interest (no third party back-in rights);
Emerald has farmed out 20% working interest subject to certain conditions, including the approval by ANH for the assignment of the interest.
Contract awarded by the ANH in September 2006 with an exploration period of up to six years and exploitation period of up to 24 years for each discovered field;
Second exploration phase of 12 months to April 2009 with commitment to drill one well;
Area of 365 sq km.
The Maranta block lies in the Caguan Putumayo basin in the south-west of Colombia. A number of exploration prospects and leads were identified, from existing seismic data, on trend with nearby producing oil fields.
A 71 kilometre 2D seismic data acquisition programme, conducted in 2007, supported the Mirto prospect which Emerald estimates may contain unrisked prospective resources in the range 5 to 15 million barrels. The Company expects that an exploration well will be drilled to a depth of approximately 11,000 feet on this prospect during the first half of 2009.
The Company has entered into a farmout agreement with La Cortez Energy Inc. ("La Cortez") under which La Cortez will earn a 20% working interest in the block, subject to the approval of the ANH, by paying 60% of the historic exploration cost and 65% cost of the drilling and production testing of the Mirto No.1 well.
If Emerald elects to enter the third exploration phase, the minimum work programme includes the drilling of one well.
Jacaranda Exploration & Production Contract
Emerald 100% operated working interest (no third party back-in rights);
Contract awarded by the ANH in March 2007 with an exploration period of up to 6 years and exploitation period of up to 24 years for each discovered field;
Second exploration phase of 12 months to March 2009 with commitment to drill one well;
Area of 235 sq km.
The Jacaranda block lies in the Llanos basin in the south of Colombia.
A single large exploration lead, which the Company estimates may contain unrisked prospective resources of over 10 million barrels, was identified from existing seismic data. A 55 kilometre 2D seismic data acquisition programme, conducted in 2007, matured the identified lead to drill-ready prospect status. The Company commenced drilling the Jacinto No.1 exploration well in March 2009, and the well is expected to be drilled to a depth of approximately 6,400 feet.
If Emerald elects to enter the third exploration phase, the minimum work programme includes the drilling of one well.
Agerato Exploration & Production Contract
Emerald 100% operated working interest (no third party back-in rights);
Contract awarded by the ANH in March 2008 with an exploration period of up to 6 years and exploitation period of up to 24 years for each discovered field;
First exploration phase of up to 18 months to August 2009 with commitment to acquire 35 km of new 2D seismic data and the re-processing 40 km of existing 2D seismic data;
Area of 170 sq km.
The Agerato block lies in the Caguan Putumayo basin in the south-west of Colombia, approximately 75 km to the southeast of the Company's Maranta exploration & production contract area.
The Agerato block lies on trend with existing discoveries in Ecuador. There is very limited existing seismic data in the block and the Company has commenced the acquisition of new 2D seismic data to determine the exploration potential within the block. Emerald expects that if there is exploration potential, the prospective depths will be relatively shallow, at approximately 7,000 ft.
If Emerald elects to enter the second exploration phase, the minimum work programme includes the drilling of one well.
VSM32 Exploration & Production Contract
The Company was informed by the ANH that it was the successful bidder on the VSM32 Block in the 2008 Mini Ronda bidding round completed in December 2008. Subject to completion of the award process, expected in the first half of 2009, Emerald will hold 100% interest and operatorship of the VSM32 Block.
Block VSM32 is located in the Upper Magdalene Valley, adjacent to the company's Matambo block, and the Company believes the block may contain exploration potential analogous to the Gigante field.
The work commitment during the first phase of the ANH exploration and production contract, lasting 36 months, consists of the acquisition of 86 km of new 2D seismic data and the drilling of one exploration well.
PERU
Block 163
The Company was informed by Perupetro S.A., the state company administering the hydrocarbon resources in Peru, that it was the successful bidder on Block 163 in the 2008 Bidding Round completed in September 2008. Subject to completion of the award process, expected in the first half of 2009, Emerald will hold 100% interest and operatorship of Block 163, Emerald's first exploration block in Peru.
Block 163 is located in the Ucayali basin, approximately 440 kilometres to the northeast of Peru's capital, Lima, and has an area of approximately 5,000 square kilometres. The block is in an area containing gas and oil fields producing from Cretaceous aged formations and is traversed by pipelines to a refinery in Pucallpa, the capital of the province. Several leads with depths estimated to be between 9,000 and 12,000 feet have been identified from the existing sparse 2D seismic data.
The work commitment during the first phase of the exploration and production contract, lasting 12 months, consists of technical studies. The second phase of 18 months, if entered, has a minimum work commitment of 300 kilometres of 2D seismic acquisition and processing, and the third phase of 18 months, if entered, has a minimum work commitment of one exploration well. The exploration and production contract is a tax and royalty contract in which the royalty, including additional royalty as part of the bidding process, is 13% up to 5,000 bopd increasing up to 28% for production levels in excess of 100,000 bopd.
LICENSE INTERESTS
The table below summarises the Group's worldwide license interests at 31 December 2008.
|
Country |
Block |
License Type |
License Working Interest |
Field |
Field Working Interest |
|
Syria |
Block 26 |
Production Sharing |
50% |
Khurbet East |
50% |
|
Colombia |
Matambo |
Association Contract |
100% |
Gigante |
50% |
|
Campo Rico |
Association Contract |
100% |
Campo Rico |
50% |
|
|
Vigia |
100% |
||||
|
Centauro Sur |
50% |
||||
|
Fortuna |
Association Contract |
90% |
Silfide |
90% |
|
|
Aureliano |
90% |
||||
|
Totumal |
90% |
||||
|
Ombu |
Tax & Royalty |
90%(1) |
Capella |
90%(1) |
|
|
Maranta |
Tax & Royalty |
80%(2) |
|||
|
Jacaranda |
Tax & Royalty |
100% |
|||
|
Agerato |
Tax & Royalty |
100% |
|||
|
Durillo |
Tax & Royalty |
100% |
Assumes approval of the National Hydrocarbon Agency of Colombia ("ANH") for the assignment of a 10% working interest to Canacol Energy Inc.
Assumes La Cortez fulfil their obligations under the Maranta farm-out agreement and the ANH approves the assignment of 20% working interest to La Cortez.
PRODUCTION
In the reporting period, Emerald's production came from its operations in Colombia and Syria. In Colombia, the Campo Rico block (the Campo Rico, Vigia and Centauro Sur fields), the Matambo block (the Gigante field), the Fortuna block (Silfide and Totumal fields) and the Ombu block (Capella field) contributed to production. In 2008, Emerald achieved an average gross field production rate in Colombia of 3,530 bopd, compared to 3,456 bopd in 2007. On the entitlement basis, in 2008 in Colombia, Emerald achieved 2,246 bopd, 64% of the gross field production, compared to 2,038 bopd, or 59%, achieved in 2007. In Syria, the Khurbet East field which commenced production from Block 26 in July 2008, achieved an average annual gross field production rate of 3,863 bopd and net entitlement of 1,139 bopd, equivalent to 59% of the working interest production rate of 1,932 bopd.
|
|
Gross Field Production
|
Working Interest Production
|
Royalty Petroleum
|
Production Sharing
|
Emerald Entitlement Production
|
|
Oil:
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
|
Colombia:
|
|
|
|
|
|
|
Campo Rico
|
438
|
219
|
(18)
|
-
|
201
|
|
Vigia
|
506
|
506
|
(40)
|
-
|
466
|
|
Centauro Sur
|
130
|
65
|
(5)
|
-
|
60
|
|
Gigante
|
200
|
100
|
(20)
|
-
|
80
|
|
Fortuna Block
|
14
|
12
|
(1)
|
-
|
11
|
|
Capella
|
4
|
4
|
-
|
-
|
4
|
|
Colombia - total
|
1,292
|
906
|
(84)
|
-
|
822
|
|
Syria:
|
|
|
|
|
|
|
Khurbet East
|
1,414
|
707
|
(88)
|
(202)
|
417
|
|
Total
|
2,706
|
1,613
|
(172)
|
(202)
|
1,239
|
RESERVES AND CONTINGENT RESOURCES
Colombia
An independent estimate of the reserves at 31 December 2008 in the producing fields in the Campo Rico Association Contract has been made by RPS Energy. In the Matambo Association Contract, adjustments to RPS Energy's previous estimates are made using additional production history. An independent estimate of the reserves at 31 December 2008 in the Capella field under appraisal in the Ombu block has been made by Netherland, Sewell & Associates, Inc.
Proved plus Probable Reserves
|
|
Gross Field as at 31 December 2007(1)
|
Additions and Revisions
|
Production
|
Gross Field as at 31 December 2008(1)
|
Working Interest as at 31 December 2008(2)
|
Net Entitlement as at 31 December 2008(3)
|
|
Oil:
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
|
Campo Rico (4)
|
1,304
|
596
|
(438)
|
1,462
|
731
|
673
|
|
Vigia (4)
|
1,648
|
1,147
|
(506)
|
2,289
|
2,289
|
1,202
|
|
Centauro Sur (4)
|
190
|
382
|
(130)
|
442
|
221
|
203
|
|
Gigante (5)
|
9,878
|
-
|
(200)
|
9,678
|
4,839
|
3,871
|
|
Fortuna Block
|
-
|
14
|
(14)
|
-
|
-
|
-
|
|
Capella (6)(7)
|
-
|
14,839
|
(4)
|
14,835
|
13,351
|
12,550
|
|
Total
|
13,020
|
16,978
|
(1,292)
|
28,706
|
21,431
|
18,499
|
Gross field reserves are the total field reserves during the life of the contract, including royalty and participation of other parties.
Working interest reserves are gross field reserves multiplied by Emerald's working interest in the field.
Net entitlement reserves are the reserves attributable to the Company's interest, after deducting royalty oil and entitlements of other parties to the contract, such as Ecopetrol and other third parties.
Source: Reserves Evaluation of the Campo Rico, Vigia and Centauro Sur fields, by RPS Energy, dated 11 March 2009.
Source: Reserves Evaluation of the Gigante field by RPS Energy, dated 13 March 2008.
Source: Resource and Reserves Evaluation of the Ombu and Fortuna blocks, by Netherland, Sewell & Associates, Inc., dated 11 March 2009.
Based on 90% working interest. The assignment of 10% working interest to Canacol Energy Inc. is subject to the approval of the ANH.
As part of the evaluation of the Capella field, Netherland, Sewell & Associates, Inc. has also made an independent estimate of the contingent resources at 31 December 2008.
Best Estimate Contingent Resources
|
|
Gross Field as at 31 December 2007(1)
|
Additions and Revisions
|
Production
|
Gross Field as at 31 December 2008(1)
|
Working Interest as at 31 December 2008(2)
|
Net Entitlement as at 31 December 2008(3)
|
|
Oil:
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
|
Capella (4)(5)
|
-
|
42,165
|
-
|
42,165
|
37,949
|
35,672
|
|
Total
|
-
|
42,165
|
-
|
42,165
|
37,949
|
35,672
|
Gross field resources are the total field resources during the life of the contract, including royalty and participation of other parties.
Working interest resources are the gross field resources multiplied by Emerald's working interest in the field.
Net entitlement resources are the resources attributable to the Company's interest, after deducting royalty oil and entitlements of other parties to the contract.
Source: Resource and Reserves Evaluation of the Ombu block by Netherland, Sewell & Associates, Inc., dated 11 March 2009.
Based on 90% working interest. The assignment of 10% working interest to Canacol Energy Inc. is subject to the approval of the ANH.
Range of Uncertainty in Reserves
The independent estimates of the reserves at 31 December 2008 in the producing fields in the Campo Rico Association Contract and at 31 December 2007 in the Gigante field, made by RPS Energy, and the independent estimate of the reserves at 31 December 2008 in the Capella field in the Ombu Contract, made by Netherland, Sewell & Associates, Inc., included an evaluation of the range of uncertainty in the estimate of reserves.
|
|
Gross Field as at
31 December 2008 (1)
|
Working Interest as at
31 December 2008 (2)
|
Net Entitlement as at
31 December 2008 (3)
|
||||||
|
|
|
|
|
||||||
|
|
Proved
|
Proved plus Probable
|
Proved plus Probable plus Possible
|
Proved
|
Proved plus Probable
|
Proved plus Probable plus Possible
|
Proved
|
Proved plus Probable
|
Proved plus Probable plus Possible
|
|
Oil:
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
|
Campo Rico(4)
|
828
|
1,462
|
2,083
|
414
|
731
|
1,042
|
381
|
673
|
958
|
|
Vigia(4)
|
1,387
|
2,289
|
3,572
|
1,387
|
2,289
|
3,572
|
803
|
1,202
|
1,725
|
|
Centauro Sur(4)
|
245
|
442
|
672
|
123
|
221
|
336
|
113
|
203
|
309
|
|
Gigante(5)
|
3,888
|
9,678
|
16,439
|
1,944
|
4,839
|
8,220
|
1,555
|
3,871
|
6,576
|
|
Capella(6)(7)
|
7,260
|
14,835
|
23,030
|
6,534
|
13,352
|
20,727
|
6,142
|
12,550
|
19,483
|
|
Total
|
13,608
|
28,706
|
45,796
|
10,402
|
21,432
|
33,896
|
8,994
|
18,499
|
29,051
|
Gross field reserves are the total field reserves during the life of the contract, including royalty and participation of other parties.
Working interest reserves are gross field reserves multiplied by Emerald's working interest in the field.
Net entitlement reserves are the reserves attributable to the Company's interest, after deducting royalty oil and entitlements of other parties to the contract, such as Ecopetrol and other third parties.
Source: Reserves Evaluation of the Campo Rico, Vigia and Centauro Sur fields, by RPS Energy, dated 11 March 2009.
Source: Reserves Evaluation of the Gigante field by RPS Energy, dated 13 March 2008, less the amount of 2008 production.
Source: Resource and Reserves Evaluation of the Capella field, by Netherland, Sewell & Associates, Inc., dated 11 March 2009.
Based on 90% working interest. The assignment of 10% working interest to Canacol Energy Inc. is subject to the approval of the ANH.
Range of Uncertainty in Contingent Resources
The independent estimates of the contingent resources at 31 December 2008 in the Capella field in the Ombu Contract, made by Netherland, Sewell & Associates, Inc., included an evaluation of the range of uncertainty in the estimate of contingent resources.
|
|
Gross Field as at
31 December 2008 (1)
|
Working Interest as at
31 December 2008 (2)
|
Net Entitlement as at
31 December 2008 (3)
|
||||||
|
|
|
|
|
||||||
|
|
Low Estimate
|
Best Estimate
|
High Estimate
|
Low Estimate
|
Best Estimate
|
High Estimate
|
Low Estimate
|
Best Estimate
|
High Estimate
|
|
Oil:
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
|
Capella(4)(5)
|
19,190
|
42,165
|
99,500
|
17,271
|
37,949
|
89,550
|
16,235
|
35,672
|
84,177
|
|
Total
|
19,190
|
42,165
|
99,500
|
17,271
|
37,949
|
89,550
|
16,235
|
35,672
|
84,177
|
Gross field resources are the total field resources during the life of the contract, including royalty and participation of other parties.
Working interest resources are the gross field resources multiplied by Emerald's working interest in the field.
Net entitlement resources are the resources attributable to the Company's interest, after deducting royalty oil and entitlements of other parties to the contract.
Source: Resource and Reserves Evaluation of the Capella field by Netherland, Sewell & Associates, Inc., dated 11 March 2009.
Based on 90% working interest. The assignment of 10% working interest to Canacol Energy Inc. is subject to the approval of the ANH.
Syria
An independent estimate of the reserves at 31 December 2007 in the Khurbet East field was been made by RPS Energy and adjustments to this estimate are made using additional production history.
Proved plus Probable Reserves
|
|
Gross LOF Field as at 31 December 2007(1)(4)
|
Additions and Revisions
|
Production
|
Gross LOF Field as at 31 December 2008(1)
|
Working Interest LOF as at 31 December 2008(2)
|
Net Entitlement as at 31 December 2008(3)
|
|
Oil:
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
mbbl
|
|
Khurbet East
|
65,600
|
-
|
(1,414)
|
64,186
|
32,093
|
10,883
|
|
Total
|
65,600
|
-
|
(1,414)
|
64,186
|
32,093
|
10,883
|
Gross LOF reserves are gross life-of-field Proved plus Probable reserves in Syria, defined as total reserves of the field, including royalty oil, Syrian Petroleum Company entitlements, and participation of other parties forming the Contractor under the terms of the Contract for the Exploration, Development and Production of Petroleum with the Syrian Petroleum Company.
Working interest LOF reserves are the product of the Gross LOF Field reserves and the Company's interest in the Contract for the Exploration, Development and Production of Petroleum. Working Interest LOF reserves exclude effects of contract term.
Net entitlement are the reserves expected to be produced during the term of the contract attributable to the Company's interest, after deducting royalty oil, Syrian Petroleum Company entitlements, and participation of other parties forming the Contractor under the terms of the Contract for the Exploration, Development and Production of Petroleum with the Syrian Petroleum Company.
Source: Independent Estimate of Khurbet East Field Petroleum Reserves as at 31 December 2007 by RPS Energy, dated 18 January 2008. As this estimate was made prior to first production from the field, gross LOF reserves at 31 December 2007 are equivalent to gross estimated ultimate recovery for the Khurbet East field.
Under the terms of the Contract for the Exploration, Development and Production of Petroleum relating to Block 26, the Company's liability for income taxes in Syria, related to the Khurbet East field, is paid on behalf of the Company out of revenue from the Syrian Petroleum Company's share of oil produced from the field.
Angus MacAskill
Chief Executive
16 March 2009
FINANCIAL REVIEW
1. COMPARATIVE FINANCIAL RESULTS AND KEY STATISTICS
|
2008 |
2007 |
|||
|
$ '000 |
$ '000 |
|||
|
Revenue |
(a) |
86,041 |
44,357 |
|
|
Production costs |
(b) |
(12,388) |
(10,924) |
|
|
Expensed exploration costs |
(c) |
(285) |
(50) |
|
|
Administrative expenses - excluding share based payments and depreciation of other property & equipment |
(7,774) |
(4,545) |
||
|
Other operating income |
377 |
1,254 |
||
|
Adjusted EBITDA* |
65,971 |
30,092 |
||
|
Administrative expenses - share based payments |
(242) |
(1,622) |
||
|
EBITDA* |
65,729 |
28,470 |
||
|
Net finance income/(costs) |
(630) |
252 |
||
|
Depletion and depreciation |
(d) |
(12,911) |
(10,299) |
|
|
Write-offs of unsuccessful exploration costs |
(e) |
(3,277) |
(9,834) |
|
|
Impairment reversal |
(d) |
3,541 |
- |
|
|
Profit before tax |
52,452 |
8,589 |
||
|
2008 |
2007 |
|||
|
$/bbl |
$/bbl |
|||
|
Revenue per barrel of entitlement production |
(a) |
69 |
60 |
|
|
Production cost per barrel of entitlement production |
(b) |
(10) |
(15) |
|
|
59 |
45 |
(*) EBITDA is earnings before interest (and other finance income and costs), tax, depreciation, depletion, amortisation and write-offs of oil & gas assets. Adjusted EBITDA is calculated before share based payments, charged to the income statement under IFRS 2. EBITDA increase of 131% year on year is explained in the sections below.
1.a Revenue
Emerald recognises revenues on the entitlement basis, as the entitlement production is delivered to the point of sale and invoiced. The tables below provide the breakdown of invoiced production and revenue by quarter.
|
Total Entitlement |
Increase in Inventories |
Invoiced in Q4 - 2008 |
Invoiced in Q3 - 2008 |
Invoiced in Q2 - 2008 |
Invoiced in Q1 - 2008 |
|
|
PRODUCTION |
mbbl |
mbbl |
mbbl |
mbbl |
mbbl |
mbbl |
|
Colombia |
822 |
18 |
338 |
159 |
151 |
156 |
|
Syria |
417 |
- |
273 |
144 |
- |
- |
|
Total |
1,239 |
18 |
611 |
303 |
151 |
156 |
|
Total 2008 |
Q4 - 2008 |
Q3 - 2008 |
Q2 - 2008 |
Q1 - 2008 |
||
|
REVENUE |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
|
|
Colombia |
60,563 |
15,050 |
15,921 |
16,631 |
12,961 |
|
|
Syria |
25,478 |
12,122 |
13,356 |
- |
- |
|
|
Total |
86,041 |
27,172 |
29,277 |
16,631 |
12,961 |
In Colombia, oil sales prices are referenced to Vasconia blend, which usually trades at a discount to major benchmarks, such as West Texas Intermediate and Brent. In addition to the price of Vasconia blend, pricing formulae incorporate crude quality adjustments and deductions reflecting the cost of transporting crude through the pipeline system.
In Syria, produced oil is sold at the prevailing market price of Syrian Heavy blend, which usually trades at a discount to Brent oil price. Pipeline charges are reflected in production costs, rather than in the realised oil prices. In the reported period, the sale proceeds from the sale of crude oil, produced by the Khurbet East field, were at 80% of the official price of Syrian Heavy, reflecting the marketing arrangements with the Syrian Petroleum Company and the Oil Marketing Bureau of the Syrian Government (for details of these arrangements refer to the Review of Operations). As the settlement of any unpaid amounts is expected by September 2009, revenue is recognised and realised oil prices are expressed on a grossed-up basis showing 100% of the revenue and prices that the Group will have achieved once the final settlement takes place in 2009.
Effective discounts of invoiced production in Colombia and Syria to WTI and Brent, respectively, as experienced in 2008, are provided in the table below:
|
Total 2007 |
Total 2008 |
Q4 - 2008 |
Q3 - 2008 |
Q2 - 2008 |
Q1 - 2008 |
|
|
REALISED OIL PRICE |
$/bbl |
$/bbl |
$/bbl |
$/bbl |
$/bbl |
$/bbl |
|
Colombia |
60 |
75 |
45 |
100 |
110 |
83 |
|
Production Weighted WTI* |
72 |
90 |
60 |
114 |
124 |
98 |
|
Effective Discount |
12 |
15 |
15 |
14 |
14 |
15 |
|
Total 2008 |
Q4 - 2008 |
Q3 - 2008 |
Q2 - 2008 |
Q1 - 2008 |
||
|
$/bbl |
$/bbl |
$/bbl |
$/bbl |
$/bbl |
||
|
Syria |
61 |
44 |
93 |
- |
- |
|
|
Production Weighted Brent* |
72 |
55 |
104 |
- |
- |
|
|
Effective Discount |
11 |
11 |
11 |
- |
- |
(*) Production weighted WTI and Brent oil prices are computed using monthly average WTI and Brent oil prices, which are weighted by monthly invoiced production in Colombia (to compute Production Weighted WTI oil price) and in Syria (to compute Production Weighted Brent oil price).
1.b Production Costs
Production costs are those costs incurred to lift, gather, process and deliver hydrocarbons to the point of sale. The following table provides the segmental analysis of production costs.
|
2008 |
2007 |
|||||
|
|
|
|||||
|
Colombia |
Syria |
Total |
Colombia |
Syria |
Total |
|
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
|
|
Production costs |
11,131 |
1,257 |
12,388 |
10,924 |
- |
10,924 |
|
Production: |
mbbl |
mbbl |
mbbl |
mbbl |
mbbl |
mbbl |
|
Entitlement production |
822 |
417 |
1,239 |
744 |
- |
744 |
|
Production unit costs: |
$/bbl |
$/bbl |
$/bbl |
$/bbl |
$/bbl |
$/bbl |
|
Entitlement basis |
13.5 |
3.0 |
10.0 |
14.7 |
- |
14.7 |
Unit production costs in Colombia were reduced 8% year on year to $13.5 per barrel of oil, reflecting the efficiencies achieved in the Campo Rico block, mostly, in the Vigia field, where increased production allowed for greater economies of scale.
Production costs of $3.0 per barrel of oil in Syria relate entirely to the cost of production of the Khurbet East field. This level of unit cost of production, being substantially lower than that achieved in Colombia, is driven primarily by the excellent reservoir properties of the currently produced Massive formation, where, all of the production was achieved on natural flow and with only traces of water, minimising energy consumption and the need for oil processing and treatment. In addition, relatively high level of entitlement production, at 59% of working interest production, resulting from the contractor's full entitlement to 50% of gross field production available for cost recovery in the reported period, further contributed to reducing the unit cost of production, which is computed on the entitlement basis.
1.c Expensed Exploration Costs
Expensed exploration costs include exploration expenditures incurred prior to grant of exploration and production licenses.
1.d Depletion, Depreciation and Impairment
Depletion and Depreciation
The following table provides the breakdown of depletion and depreciation charges by geographic segments.
|
2008 |
2007 |
|||||
|
|
|
|||||
|
Colombia |
Syria |
Total |
Colombia |
Syria |
Total |
|
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
|
|
Depletion of oil & gas properties |
9,591 |
2,321 |
11,912 |
9,512 |
- |
9,512 |
|
Depreciation of oil & gas properties |
804 |
43 |
847 |
695 |
- |
695 |
|
Depreciation of other properties & equipment* |
98 |
54 |
152 |
92 |
- |
92 |
|
10,493 |
2,418 |
12,911 |
10,299 |
- |
10,299 |
|
|
Production: |
mbbl |
mbbl |
mbbl |
mbbl |
mbbl |
mbbl |
|
Entitlement production |
822 |
417 |
1,239 |
744 |
- |
744 |
|
Applied depletion rates: |
$/bbl |
$/bbl |
$/bbl |
$/bbl |
$/bbl |
$/bbl |
|
Entitlement basis |
11.7 |
5.6 |
9.6 |
12.8 |
- |
12.8 |
(*) Depreciation charge of $16,000 (2007: $25,000) attributable to the head office in London is allocated to Colombia geographic segment.
On the entitlement basis, depletion of oil and gas properties charged in Colombia decreased by 9% year on year to $11.7 per barrel of oil production, reflecting an upward revision of the entitlement reserves in the Campo Rico block.
Impairment
An impairment review of the Group's properties resulted in no impairment charge (2007: Nil). An impairment review of the Vigia field in the Campo Rico block in Colombia resulted in the impairment charge reversal of $3.541 million, relating to the original charge of $5.901 million incurred in 2006 and reflecting the increase in the net entitlement reserves in the field from 0.986 million barrels of oil, as at 31 December 2007, to 1.202 million barrels of oil, as at 31 December 2008, following the successful drilling campaign in 2008. The ceiling test was conducted at WTI prices of $45/bbl in 2009, $50/bbl in 2010 and $60/bbl in 2011 and thereafter. The discount rate applied was 10%.
1.e Write-Offs of Unsuccessful Exploration Costs
Write-offs of unsuccessful exploration costs represent expenditures associated with unsuccessful efforts to find commercial reserves of hydrocarbons. Under the successful efforts based method of accounting adopted by the Group, the costs of exploration efforts, such as geological and geophysical works and drilling activities, are capitalised as intangible assets until it is determined whether these exploration efforts have been successful or not. If the efforts are determined to be unsuccessful, all of the relevant capitalised costs and costs incurred in the period are written off. The table below provides the breakdown of write-offs of unsuccessful exploration costs:
|
2008 |
2007 |
||||
|
Field/prospect |
Block |
$ '000 |
$ '000 |
||
|
Colombia |
|||||
|
Alcaravan prospect |
Campo Rico block |
- |
218 |
||
|
Las Acacias prospect |
Campo Rico block |
30 |
- |
||
|
Silfide field |
Fortuna block |
1,054 |
2,665 |
||
|
Aureliano field |
Fortuna block |
81 |
5,684 |
||
|
Totumal field |
Fortuna block |
1,120 |
- |
||
|
Syria |
|||||
|
Souedieh North prospect |
Block 26 |
992 |
- |
||
|
Tigris prospect |
Block 26 |
- |
1,267 |
||
|
Total write-offs of unsuccessful exploration efforts |
3,277 |
9,834 |
|||
(*) The write-off of exploration costs associated with the Silfide, Aureliano and Totumal fields in the Fortuna block includes $0.667 million of capital expenditure incurred in the block in 2008.
2. FINANCIAL PERFORMANCE OF BUSINESS SEGMENTS
Currently, the Group is comprised of three business segments: Colombia, Syria and London Head Office. The tables below summarises the financial performance of the Group by business segment.
|
Colombia |
Syria |
Head Office |
Group |
||
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
||
|
Revenue from oil sales |
60,563 |
25,478 |
- |
86,041 |
|
|
Production costs |
(11,131) |
(1,257) |
- |
(12,388) |
|
|
Expensed exploration costs |
(63) |
(33) |
(189) |
(285) |
|
|
General and administrative expenses, excluding depreciation |
(1,350) |
(1,991) |
(4,675) |
(8,016) |
|
|
Other operating income |
377 |
- |
- |
377 |
|
|
EBITDA |
48,396 |
22,197 |
(4,864) |
65,729 |
|
|
Net finance income/(cost) |
53 |
(50) |
(633) |
(630) |
|
|
Depletion and depreciation |
(10,477) |
(2,418) |
(16) |
(12,911) |
|
|
Write-offs of unsuccessful exploration costs |
(2,285) |
(992) |
- |
(3,277) |
|
|
Impairment reversal |
3,541 |
- |
- |
3,541 |
|
|
Profit before tax |
39,228 |
18,737 |
(5,513) |
52,452 |
|
|
Tax charge for the period |
(a) |
(9,924) |
- |
(434) |
(10,358) |
|
Deferred tax |
(a) |
(1,096) |
(5,353) |
- |
(6,449) |
|
Period profit/(loss) |
28,208 |
13,384 |
(5,947) |
35,645 |
|
|
Colombia |
Syria |
Head Office |
Group |
||
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
||
|
Capital expenditure |
|||||
|
Investment in oil & gas assets: |
|||||
|
- Property, plant & equipment |
(b) |
25,469 |
6,104 |
- |
31,573 |
|
- Intangible assets |
(b) |
2,834 |
2,181 |
- |
5,015 |
|
Investment in other property & equipment |
88 |
762 |
- |
850 |
|
|
Total capital investment |
28,391 |
9,047 |
- |
37,438 |
|
2.a Tax Charge for the Period
All of the deferred tax relates to the taxable temporary difference between the net book value of the Group's assets, allowable for tax, and the tax written down value of those assets.
Under the terms of the Contract for the Exploration, Development and Production of Petroleum for Block 26, Syria, the Group pays its corporation tax by way of production sharing with the Government of Syrian Arab Republic and Syrian Petroleum Company.
2.b Investment in Tangible and Intangible Oil & Gas Assets
The table below provides the breakdown of capital expenditure on tangible and intangible oil and gas assets by block.
|
Year ended 31 December 2008 |
Total |
Colombia |
Syria |
||
|
Tangible |
Intangible |
Tangible |
Intangible |
||
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
|
|
Matambo block |
4,669 |
4,039 |
630 |
- |
- |
|
Campo Rico block |
15,276 |
14,802 |
474 |
- |
- |
|
Fortuna block |
667 |
- |
667 |
- |
- |
|
Ombu block |
6,628 |
6,628 |
- |
- |
- |
|
Maranta block |
293 |
- |
293 |
- |
- |
|
Jacaranda block |
200 |
- |
200 |
- |
- |
|
Agerato block |
570 |
- |
570 |
- |
- |
|
Block 26, Syria |
8,285 |
- |
- |
6,104 |
2,181 |
|
36,588 |
25,469 |
2,834 |
6,104 |
2,181 |
|
|
Year ended 31 December 2007 |
Total |
Colombia |
Syria |
||
|
Tangible |
Intangible |
Tangible |
Intangible |
||
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
|
|
Matambo block |
1,016 |
1,016 |
- |
- |
- |
|
Campo Rico block |
3,410 |
3,410 |
- |
- |
- |
|
Fortuna block |
4,618 |
59 |
4,559 |
- |
- |
|
Ombu block |
135 |
- |
135 |
- |
- |
|
Maranta block |
1,241 |
- |
1,241 |
- |
- |
|
Jacaranda block |
569 |
- |
569 |
- |
- |
|
Block 26, Syria |
14,137 |
- |
- |
12,870 |
1,267 |
|
25,126 |
4,485 |
6,504 |
12,870 |
1,267 |
|
3. PROPERTY, PLANT & EQUIPMENT AND INTANGIBLE ASSETS
|
As at 31 December, |
2008 |
2007 |
|||||
|
Property, Plant & Equipment |
Intangible Assets |
Total |
Property, Plant & Equipment |
Intangible Assets |
Total |
||
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
||
|
Oil & Gas Assets: |
|||||||
|
Colombia: |
|||||||
|
Matambo block |
16,713 |
630 |
17,343 |
14,003 |
- |
14,003 |
|
|
Campo Rico block |
26,102 |
444 |
26,546 |
16,934 |
- |
16,934 |
|
|
Fortuna block |
41 |
- |
41 |
53 |
1,588 |
1,641 |
|
|
Ombu block |
6,742 |
- |
6,742 |
- |
135 |
135 |
|
|
Maranta block |
- |
1,536 |
1,536 |
- |
1,243 |
1,243 |
|
|
Jacaranda block |
- |
769 |
769 |
- |
569 |
569 |
|
|
Agerato block |
- |
570 |
570 |
- |
- |
- |
|
|
49,598 |
3,949 |
53,547 |
30,990 |
3,535 |
34,525 |
||
|
Syria: Block 26 |
39,391 |
2,181 |
41,572 |
35,651 |
992 |
36,643 |
|
|
Other Property & Equipment |
916 |
- |
916 |
218 |
- |
218 |
|
|
89,905 |
6,130 |
96,035 |
66,859 |
4,527 |
71,386 |
||
4. CAPITAL STRUCTURE
Issue of Convertible Bonds
In July 2007, the Group diversified its capital structure through the issuance of senior unsecured convertible bonds with an aggregate nominal value of $30 million. Issued at par value and structured in two tranches of equal nominal value, Series A and Series B bonds pay a coupon of 5.875% and 4.875% and mature in January 2012 and January 2013, respectively. Series A and Series B bonds are convertible into ordinary shares of the Company at 290p and 270p, respectively, at any time prior to maturity at the option of the bondholders. The Company has an option to redeem the bonds at their nominal value from July 2010, subject to certain conditions relating to the Company's share price performance.
Capital Employed
|
As at 31 December |
2008 |
2007 |
|
|
$ '000 |
$ '000 |
||
|
Debt: |
|||
|
Recognised debt portion of convertible bonds |
25,313 |
24,269 |
|
|
Equity: |
|||
|
Share capital: |
|||
|
Issued share capital |
9,843 |
9,825 |
|
|
Share premium |
50,359 |
50,359 |
|
|
Total share capital |
60,202 |
60,184 |
|
|
Retained earnings and reserves: |
|||
|
Retained earnings and reserves, excluding recognised equity portion of convertible bonds |
60,078 |
24,461 |
|
|
Recognised equity portion of convertible bonds |
5,005 |
5,005 |
|
|
Total retained earnings and reserves |
65,083 |
29,466 |
|
|
Total equity |
125,285 |
89,650 |
|
|
Total capital employed |
150,598 |
113,919 |
|
5. GOING CONCERN
The Directors confirm that in their opinion the Company has adequate resources to continue in operational existence for the foreseeable future and therefore Directors continue to adopt a going concern basis in preparing the financial statements of the Company and the Group.
Edward Grace
Finance Director
16 March 2009
STATEMENT OF DIRECTORS' RESPONSIBILITIES
The Directors are responsible for keeping proper accounting records which disclose with reasonable accuracy at any time the financial position of the Group and Company and enable them to ensure that the financial statements comply with the requirements of the Isle of Man Companies Acts 1931 to 2004. They are also responsible for safeguarding the assets of the company, for taking reasonable steps for the prevention and detection of fraud and other irregularities.
The Directors are also required to prepare financial statements for the group in accordance with International Financial Reporting Standards ("IFRS") and Article 4 of the International Accounting Standard ("IAS") Regulation. The Directors have chosen to prepare the Company's financial statements in accordance with IFRS.
IAS 1 requires that financial statements present fairly for each financial year the Group's financial position, financial performance and cash flows. This requires the faithful representation of the effects of transactions, other events and conditions in accordance with the definitions and recognition criteria for assets, liabilities, income and expenses set out in the International Accounting Standards Board's 'Framework for the preparation and presentation of financial statements'. In virtually all circumstances, a fair presentation will be achieved by compliance with all applicable IFRS. A fair presentation also requires the Directors to:
consistently select and apply appropriate accounting policies;
present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information;
provide additional disclosures when compliance with the specific requirements in IFRS is insufficient to enable users to understand the impact of particular transactions, other events and conditions on the entity's financial position and financial performance; and
state that the group has complied with IFRS, subject to any material departures disclosed and explained in the financial statements.
Financial statements are published on the Group's website. The maintenance and integrity of the Group's website is the responsibility of the Directors. The Directors' responsibility also extends to the ongoing integrity of the financial statements contained therein.
The Directors confirm that they have complied with these requirements, and, having a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future, continue to adopt the going concern basis in preparing the financial statements.
The Directors confirm that to the best of their knowledge:
The Group financial statements have been prepared in accordance with IFRS as adopted by the European Union in Article 4 of the IAS Regulation and give a true and fair view of the assets, liabilities, financial position and profit and loss of the Group; and
The annual report includes a fair review of the development and performance of the business and the financial position of the Group and the parent company, together with a description of the principal risks and uncertainties that they face.
For and on behalf of the Board
Alastair Beardsall
Chairman
16 March 2009
GROUP INCOME STATEMENT
For the year ended 31 December
|
2008 |
2007 |
|||
|
$ '000 |
$ '000 |
|||
|
Revenue from oil sales |
86,041 |
44,357 |
||
|
Cost of sales |
||||
|
Production costs |
(12,388) |
(10,924) |
||
|
Expensed exploration costs |
(285) |
(50) |
||
|
Depletion and depreciation of oil and gas assets |
(12,759) |
(10,207) |
||
|
Write-offs of unsuccessful exploration costs |
(3,277) |
(9,834) |
||
|
Reversal of impairment |
3,541 |
- |
||
|
Total cost of sales |
(25,168) |
(31,015) |
||
|
Gross profit |
60,873 |
13,342 |
||
|
Other income |
377 |
1,254 |
||
|
Administrative expenses |
||||
|
General and administrative expenses before share-based payments |
(7,926) |
(4,637) |
||
|
Share-based payments |
(242) |
(1,622) |
||
|
Total administrative expenses |
(8,168) |
(6,259) |
||
|
Profit from operations |
53,082 |
8,337 |
||
|
Finance costs |
(2,792) |
(1,372) |
||
|
Finance income |
2,162 |
1,624 |
||
|
Profit before tax |
52,452 |
8,589 |
||
|
Tax expense |
(16,807) |
(2,038) |
||
|
Profit for the year attributable to equity holders of the parent |
35,645 |
6,551 |
||
|
Basic earnings per ordinary share |
59.77c |
11.21c |
||
|
Diluted earnings per ordinary share |
56.91c |
10.94c |
||
GROUP AND COMPANY BALANCE SHEETS
As at 31 December
|
Group |
Company |
||||
|
2008 |
2007 |
2008 |
2007 |
||
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
||
|
Non-current assets |
|||||
|
Property, plant and equipment |
89,905 |
66,859 |
89,905 |
31,208 |
|
|
Intangible assets |
6,130 |
4,527 |
6,130 |
3,535 |
|
|
Deferred tax |
20 |
127 |
20 |
127 |
|
|
Investments in subsidiaries |
- |
- |
- |
40,625 |
|
|
96,055 |
71,513 |
96,055 |
75,495 |
||
|
Current assets |
|||||
|
Inventories |
7,853 |
6,241 |
7,853 |
5,592 |
|
|
Trade and other receivables |
14,944 |
4,715 |
14,944 |
4,694 |
|
|
Prepayments |
408 |
132 |
408 |
132 |
|
|
Corporation tax debtor |
- |
824 |
- |
824 |
|
|
Restricted cash collateral |
255 |
3,493 |
255 |
243 |
|
|
Cash and cash equivalents |
74,447 |
40,169 |
74,447 |
40,169 |
|
|
97,907 |
55,574 |
97,907 |
51,654 |
||
|
Total assets |
193,962 |
127,087 |
193,962 |
127,149 |
|
|
Current liabilities |
|||||
|
Trade and other payables |
17,697 |
4,321 |
17,697 |
4,321 |
|
|
Accruals |
5,666 |
2,017 |
5,666 |
2,017 |
|
|
Provisions |
410 |
410 |
410 |
410 |
|
|
Corporation tax creditor |
6,829 |
- |
6,829 |
- |
|
|
30,602 |
6,748 |
30,602 |
6,748 |
||
|
Non-current liabilities |
|||||
|
Deferred tax |
12,762 |
6,420 |
12,762 |
6,420 |
|
|
Debt component of convertible bonds |
25,313 |
24,269 |
25,313 |
24,269 |
|
|
38,075 |
30,689 |
38,075 |
30,689 |
||
|
Equity attributable to the shareholders |
|||||
|
Issued share capital |
9,843 |
9,825 |
9,843 |
9,825 |
|
|
Share premium |
50,359 |
50,359 |
50,359 |
50,359 |
|
|
Retained earnings |
60,078 |
24,461 |
60,078 |
24,523 |
|
|
Equity portion of convertible bonds |
5,005 |
5,005 |
5,005 |
5,005 |
|
|
125,285 |
89,650 |
125,285 |
89,712 |
||
|
Total liabilities and shareholders' equity |
193,962 |
127,087 |
193,962 |
127,149 |
|
GROUP AND COMPANY CASH FLOW STATEMENT
For the year ended 31 December
|
Group |
Company |
||||
|
2008 |
2007 |
2008 |
2007 |
||
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
||
|
Cash flow from operating activities |
|||||
|
Profit before tax |
52,452 |
8,589 |
52,452 |
8,598 |
|
|
Adjusted for: |
|||||
|
Share based payments |
242 |
1,622 |
242 |
1,622 |
|
|
Depletion and depreciation |
12,911 |
10,299 |
12,911 |
10,299 |
|
|
Write-offs of unsuccessful exploration costs |
3,277 |
9,834 |
3,277 |
8,567 |
|
|
Impairment charge/(reversal) |
(3,541) |
- |
(3,541) |
1,267 |
|
|
Finance income |
(2,162) |
(1,220) |
(2,162) |
(1,220) |
|
|
Finance costs |
2,792 |
1,372 |
2,792 |
1,363 |
|
|
Disposals |
143 |
- |
143 |
- |
|
|
Operating profit before changes in working capital |
66,114 |
30,496 |
66,114 |
30,496 |
|
|
Movement in inventory |
(1,612) |
(1,592) |
(1,612) |
(943) |
|
|
Movement in operating receivables |
(6,487) |
(3,377) |
(6,487) |
(161) |
|
|
Movement in operating payables |
9,350 |
(1,899) |
9,350 |
(1,858) |
|
|
Cash flow from operating activities |
67,365 |
23,628 |
67,365 |
27,534 |
|
|
Income tax paid |
(2,705) |
(2,016) |
(2,705) |
(2,016) |
|
|
Net cash flow from operations |
64,660 |
21,612 |
64,660 |
25,518 |
|
|
Cash flow from investing activities |
|||||
|
Investment in property, plant and equipment |
(29,764) |
(26,327) |
(29,764) |
(12,189) |
|
|
Investment in subsidiaries |
- |
- |
- |
(18,053) |
|
|
Interest received |
1,382 |
1,220 |
1,382 |
1,220 |
|
|
Net cash flow from investing activities |
(28,382) |
(25,107) |
(28,382) |
(29,022) |
|
|
Cash flow from financing activities |
|||||
|
Gross proceeds from issue of convertible bonds |
- |
30,000 |
- |
30,000 |
|
|
Costs relating to issue of convertible bonds |
- |
(1,268) |
- |
(1,268) |
|
|
Cash paid on settlement of options |
(252) |
(252) |
|||
|
Interest paid and banking charges |
(1,748) |
(830) |
(1,748) |
(821) |
|
|
Net cash flow from financing activities |
(2,000) |
27,902 |
(2,000) |
27,911 |
|
|
Net change in cash and cash equivalents |
34,278 |
24,407 |
34,278 |
24,407 |
|
|
Cash at period start |
40,169 |
15,762 |
40,169 |
15,762 |
|
|
Period cash flow |
34,278 |
24,407 |
34,278 |
24,407 |
|
|
Cash and cash equivalents at period end |
74,447 |
40,169 |
74,447 |
40,169 |
|
STATEMENT OF CHANGES IN EQUITY
GROUP
|
|
Share Capital(1)
|
Share Premium(2)
|
Shares to Be Issued(3)
|
Equity Portion of Convertible Bonds(4)
|
Retained Earnings (5)
|
Total
|
|
|
$ '000
|
$ '000
|
$ '000
|
$ '000
|
$ '000
|
$ '000
|
|
Balance at 31 December 2006
|
9,216
|
40,838
|
10,130
|
-
|
16,288
|
76,472
|
|
Changes in equity:
|
|
|
|
|
|
|
|
Income for the period
|
-
|
-
|
-
|
-
|
6,551
|
6,551
|
|
Total recognised income for the year
|
-
|
-
|
-
|
-
|
6,551
|
6,551
|
|
Issue of new share capital
|
609
|
9,521
|
(10,130)
|
-
|
-
|
-
|
|
Issue of convertible bonds
|
-
|
-
|
-
|
5,005
|
-
|
5,005
|
|
Share based payments
|
-
|
-
|
-
|
-
|
1,622
|
1,622
|
|
Balance at 31 December 2007
|
9,825
|
50,359
|
-
|
5,005
|
24,461
|
89,650
|
|
Changes in equity:
|
|
|
|
|
|
|
|
Income for the period
|
-
|
-
|
-
|
-
|
35,645
|
35,645
|
|
Total recognised income and expense for the year
|
-
|
-
|
-
|
-
|
35,645
|
35,645
|
|
Issue of new share capital
|
18
|
-
|
-
|
-
|
(18)
|
-
|
|
Share based payments
|
-
|
-
|
-
|
-
|
(10)
|
(10)
|
|
Balance at 31 December 2008
|
9,843
|
50,359
|
-
|
5,005
|
60,078
|
125,285
|
COMPANY
|
|
Share Capital(1)
|
Share Premium(2)
|
Shares to Be Issued(3)
|
Equity Portion of Convertible Bonds(4)
|
Retained Earnings (5)
|
Total
|
|
|
$ '000
|
$ '000
|
$ '000
|
$ '000
|
$ '000
|
$ '000
|
|
Balance at 31 December 2006
|
9,216
|
40,838
|
10,130
|
-
|
16,340
|
76,524
|
|
Changes in equity:
|
|
|
|
|
|
|
|
Income for the period
|
-
|
-
|
-
|
-
|
6,561
|
6,561
|
|
Total recognised income and expense for the year
|
-
|
-
|
-
|
-
|
6,561
|
6,561
|
|
Issue of new share capital
|
609
|
9,521
|
(10,130)
|
-
|
-
|
-
|
|
Issue of convertible bonds
|
-
|
-
|
-
|
5,005
|
-
|
5,005
|
|
Share based payments
|
-
|
-
|
-
|
-
|
1,622
|
1,622
|
|
Balance at 31 December 2007
|
9,825
|
50,359
|
-
|
5,005
|
24,523
|
89,712
|
|
Changes in equity:
|
|
|
|
|
|
|
|
Income for the period
|
-
|
-
|
-
|
-
|
35,583
|
35,583
|
|
Total recognised income and expense for the year
|
-
|
-
|
-
|
-
|
35,583
|
35,583
|
|
Issue of new share capital
|
18
|
-
|
-
|
-
|
(18)
|
-
|
|
Share based payments
|
-
|
-
|
-
|
-
|
(10)
|
(10)
|
|
Balance at 31 December 2008
|
9,843
|
50,359
|
-
|
5,005
|
60,078
|
125,285
|
The following describes the nature and purpose of each reserve within shareholders' equity:
|
Share capital (1) |
Nominal value of amounts subscribed for share capital |
|
Share premium (2) |
Amounts subscribed for share capital in excess of nominal value |
|
Shares to be issued (3) |
Shares issued to Soyuzneftegas Limited pursuant to the SNG Overseas Limited Share Purchase Agreement |
|
Equity portion of convertible bonds (4) |
Portion of convertible bonds recognised as equity on issuance of Series A and Series B senior unsecured convertible bonds |
|
Retained earnings (5) |
Cumulative net gains and losses recognised in the income statement. Retained earnings include fair value of the share options issued under the Company's discretionary share option plan and recognised on the date of the grant and cumulative effect of historical differences arising from conversion of reserves from source to reporting currency |
NOTES TO THE FINANCIAL STATEMENTS
BASIS OF ACCOUNTING
The financial information contained in this statement does not constitute the Group's statutory accounts for the years ended 31 December 2008 or 2007, but is derived from those accounts. Statutory accounts for 2007 have been delivered to the Registrars of Companies in the Isle of Man and those for 2008 which were approved by the Board on 16 March 2009 will also be lodged there following the Company's Annual General Meeting to be held on 24 April 2009. The auditors have reported on those accounts; their reports were unqualified and did not include references to any matters to which the auditors drew attention by way of emphasis without qualifying their reports.
BASIS OF PREPARATION
The Group follows the International Financial Reporting Standards as the basis for preparation of its financial statements. These financial statements are prepared on the historical cost basis as modified by the requirement of IFRS to present certain financial assets and financial liabilities at fair value, making the required adjustment through the income statement.
BASIS OF CONSOLIDATION
Where the Company has the power, either directly or indirectly, to govern the financial and operating policies of another entity or business so as to obtain benefits from its activities, it is classified as a subsidiary. The consolidated financial statements present the result of the Company and its subsidiaries (the "Group") as if they formed a single entity. Intercompany transactions and balances between group companies are therefore eliminated in full.
BUSINESS COMBINATIONS
The consolidated financial statements incorporate the results of business combinations using the purchase method. In the consolidated balance sheet, the acquiree's identifiable assets, liabilities and contingent liabilities are initially recognised at their fair values at the acquisition date. The results of acquired operations are included in the consolidated income statement from the date on which control is obtained.
Jointly Controlled Operations
The Group includes the assets it controls, its share of any income and the liabilities and expenses of jointly controlled operations and jointly controlled assets in accordance with the terms of underlying contractual agreements.
OIL AND GAS ASSETS
The Group applies the successful efforts based method of accounting for oil and gas operations.
Under the successful efforts based method of accounting, costs are capitalised if they lead to or represent the development of the oil and gas assets that either have to be appraised or have been appraised as successful. If evaluation of the oil and gas asset leads to the conclusion that the asset is not economic, the costs incurred acquiring this asset are expensed through the income statement. If evaluation of the oil and gas asset leads to the conclusion that the asset has economic value but the costs incurred acquiring and developing this asset exceed this value, the excess costs are expensed through the income statement. The costs incurred to evaluate potential assets prior to grant of exploration and production ("E&P") licenses are expensed.
Tangible Oil and Gas Assets
For evaluated properties with economic values exceeding the exploration and development costs incurred after the grant of the license, these costs, which may include geological and geophysical costs, costs of drilling exploration and development wells, costs of field production facilities, including commissioning and infrastructure costs, are capitalised. These expenditures are combined into asset groups reflecting the anticipated useful lives of individual assets and subsequently are depreciated over the expected economic lives of those asset groups. The expenditure within the asset group with a useful life equal to the producing life of the field is depleted on a unit-of-production basis. The assets formed by capitalisation of these costs are referred to as tangible oil and gas assets.
Intangible Oil and Gas Assets
Intangible oil and gas assets represent costs that have been incurred after the grant of the license where the properties still have to be evaluated and where production of hydrocarbons has yet to commence. Costs related to such unevaluated properties are not amortised until such time as the related property has been appraised and put on production.
Other Tangible Fixed Assts
Other tangible fixed assets, currently comprising furniture and fittings, communications equipment and computer equipment, are depreciated on a straight-line basis over five, three and two years, respectively.
Impairment Review
Impairment reviews of development and/or producing assets are carried on a field-by-field basis. At each reporting date, the net book values of the development and/or producing assets are compared to the net present values of expected future cash flows from the relevant fields. If the net book value is higher than the underlying economic value of the asset, then the difference is written off to the income statement as impairment. Expected future cash flows are calculated using production profiles and costs determined on a field-by-field basis by in-house engineers, using appropriate petroleum engineering techniques, and using oil price forecasts which are developed by the Group for business planning purposes.
Exploration and appraisal assets are regarded as intangible fixed assets until it has been established whether they are associated with commercially producible reserves of hydrocarbons or not. If the efforts associated with the costs of these assets are successful, these assets are reclassified into development and/or producing assets, which are subject to regular impairment reviews on a field-by-field basis. If the efforts associated with the costs of these assets are unsuccessful, the carrying cost of these assets is written off to the income statement in accordance with the successful efforts based accounting method.
CONVERTIBLE BONDS
Convertible bonds equity and debt elements are classified separately as their component parts in the financial statements. The method used is as follows:
The fair value of the liability component is calculated, and this fair value establishes the initial carrying amount of the pure liability component; and
The fair value of the pure liability component is deducted from the fair value of the instrument as a whole, with the resulting residual amount being the equity component.
The equity element is the difference between the proceeds of the bond issue and the present value of the liability component using a hypothetical debt rate. The proceeds represent the fair value of the bonds as a whole. The financial liability component is then accreted up to the redemption amount accordingly each year using the effective interest rate method.
SEGMENT INFORMATION
The Group is engaged in oil and gas exploration and production activities only. As the operating businesses are organised and managed separately on a country-by-country basis, segment information is reported geographically only.
Geographic Segments
|
Year ended 31 December 2008 |
Colombia |
Syria |
Head Office |
Group |
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
|
|
Revenue from oil sales |
60,563 |
25,478 |
- |
86,041 |
|
Depletion and depreciation of oil & gas assets |
(10,395) |
(2,364) |
- |
(12,759) |
|
Write-offs of unsuccessful exploration efforts |
(2,285) |
(992) |
- |
(3,277) |
|
Impairment reversal/(charges) |
3,541 |
- |
- |
3,541 |
|
Gross profit |
40,230 |
20,832 |
(189) |
60,873 |
|
Profit/(loss) from operations before tax and finance income |
39,175 |
18,786 |
(4,879) |
53,082 |
|
Finance costs |
(117) |
(13) |
(2,662) |
(2,792) |
|
Profit/(loss) before tax |
39,228 |
18,737 |
(5,513) |
52,452 |
|
Profit/(loss) after tax |
28,208 |
13,384 |
(5,947) |
35,645 |
|
Other segment information: |
||||
|
Segment assets: |
||||
|
Oil and gas assets |
53,547 |
41,572 |
- |
95,119 |
|
Other tangible and non-current assets |
213 |
708 |
15 |
936 |
|
Current assets |
22,490 |
13,910 |
61,507 |
97,907 |
|
Total assets |
76,250 |
56,190 |
61,522 |
193,962 |
|
Capital expenditure: |
||||
|
Oil and gas assets |
28,303 |
8,285 |
- |
36,588 |
|
Other tangible assets |
88 |
762 |
- |
850 |
|
Total capital expenditure |
28,391 |
9,047 |
- |
37,438 |
|
Total liabilities |
32,635 |
7,307 |
28,735 |
68,677 |
|
Year ended 31 December 2007 |
Colombia |
Syria |
Head Office |
Group |
|
$ '000 |
$ '000 |
$ '000 |
$ '000 |
|
|
Revenue from oil sales |
44,357 |
- |
- |
44,357 |
|
Depletion and depreciation of oil & gas assets |
(10,207) |
- |
- |
(10,207) |
|
Write-offs of unsuccessful exploration efforts |
(8,567) |
(1,267) |
- |
(9,834) |
|
Impairment charges |
- |
- |
- |
- |
|
Gross profit |
14,647 |
(1,267) |
(38) |
13,342 |
|
Profit/(loss) from operations before tax and finance income |
13,118 |
(1,267) |
(3,514) |
8,337 |
|
Finance costs |
(22) |
(9) |
(1,341) |
1,372 |
|
Profit/(loss) before tax |
13,535 |
(1,276) |
(3,670) |
8,589 |
|
Profit/(loss) after tax |
11,497 |
(1,276) |
(3,670) |
6,551 |
|
Other segment information: |
||||
|
Segment assets: |
||||
|
Oil and gas assets |
34,525 |
36,643 |
- |
71,168 |
|
Other tangible and non-current assets |
315 |
- |
30 |
345 |
|
Current assets |
14,518 |
3,921 |
37,135 |
55,574 |
|
Total assets |
49,358 |
40,564 |
37,165 |
127,087 |
|
Capital expenditure: |
||||
|
Oil and gas assets |
10,988 |
14,138 |
- |
25,126 |
|
Other tangible assets |
49 |
- |
- |
49 |
|
Total capital expenditure |
11,037 |
14,138 |
- |
25,175 |
|
Total liabilities |
11,441 |
- |
25,996 |
37,437 |
FINANCE INCOME AND COST
|
Group |
Company |
|||
|
2008 |
2007 |
2008 |
2007 |
|
|
Finance income |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
|
Interest receivable on cash deposits and investments in money markets |
1,521 |
1,220 |
1,521 |
1,220 |
|
Accreted income, calculated using effective interest rate method |
- |
- |
- |
- |
|
Total interest income |
1,521 |
1,220 |
1,521 |
1,220 |
|
Exchange gain |
639 |
404 |
639 |
404 |
|
Other finance income |
2 |
- |
2 |
- |
|
Total |
2,162 |
1,624 |
2,162 |
1,624 |
|
Group |
Company |
|||
|
2008 |
2007 |
2008 |
2007 |
|
|
Finance cost |
$ '000 |
$ '000 |
$ '000 |
$ '000 |
|
Interest payable |
(1,617) |
(760) |
(1,617) |
(760) |
|
Accretion expense, calculated using effective interest rate method |
(1,044) |
(542) |
(1,044) |
(542) |
|
Total interest expense |
(2,661) |
(1,302) |
(2,661) |
(1,302) |
|
Banking charges and other finance costs |
(131) |
(70) |
(131) |
(61) |
|
Total |
(2,792) |
(1,372) |
(2,792) |
(1,363) |
TAXATION
Reconciliation of the Total Tax Charge
The expense in the income statement for the year is higher than the standard rate of corporation tax in the UK of 28% (2007: 30%). As an international business, the company is exempt from paying Isle of Man tax. The company is UK resident therefore expects to incur tax at the UK corporation tax rate. The differences are reconciled below:
|
2008 |
2007 |
|
|
$ '000 |
$ '000 |
|
|
Current income tax |
10,358 |
2,097 |
|
Deferred tax: |
||
|
Temporary differences on Colombian income and costs |
(495) |
627 |
|
Accelerated capital allowances |
6,944 |
(686) |
|
Total deferred tax (credit) / charge |
6,449 |
(59) |
|
Total tax expense |
16,807 |
2,038 |
|
2008 |
2007 |
|
|
$ '000 |
$ '000 |
|
|
Profit before tax |
52,452 |
8,589 |
|
Accounting profit multiplied by the UK standard rate of corporation tax of 30% to 31 March 2008 then at 28% |
14,949 |
2,577 |
|
Tax Effects of: |
||
|
Higher taxes on overseas earnings |
3,470 |
444 |
|
Reversal of historical inflation adjustments and exchange rate timing differences(*) |
(1,940) |
(2,353) |
|
Expenses not deductible for tax purposes |
2,451 |
743 |
|
Utilisation of historical losses |
(1,765) |
- |
|
Other temporary differences |
(358) |
627 |
|
Total tax reported in the income statement |
16,807 |
2,038 |
(*) Reversal of historical inflation adjustment to foreign earnings in 2007 represents a one-off adjustment to the Company's profit before tax in Colombia, relating to introduction of a new statutory requirement to reverse historical inflation adjustments in the computation of profit and loss. Exchange rate timing differences in 2008 arise from the differences in exchange rates used for translation of corporation profit tax from local currencies to US dollars and exchange rates used to translate income and expenditures from local currencies to US dollars throughout the year.
Overseas Taxation
Effective corporation tax rates, applicable to the Group's activities in Colombia and Syria of 33% and 37.6% respectively, exceed the applicable rate of corporation tax in the UK. In the UK, as at the date of the last UK tax return, Emerald had available unutilised tax written down value of assets of $91 million. The deferred tax asset of $25 million (2007: $18 million) relating to these allowances is not recognised, as the Group does not expect to be generating taxable income in the UK against which these allowances could be offset.
|
Historical Losses and Disallowed Costs Brought Forward |
Deferred Tax Asset |
2008 Deferred Tax Charges |
||
|
$ '000 |
$ '000 |
$ '000 |
||
|
As at 31 December 2007 before utilisation of tax losses |
387 |
127 |
||
|
Utilisation of tax losses in 2007 |
- |
- |
||
|
As at 31 December 2007 after utilisation of tax losses |
387 |
127 |
||
|
Utilisation of tax losses in 2008 |
- |
- |
- |
|
|
Disallowed costs generated in 2008 |
(327) |
(107) |
(107) |
|
|
As at 31 December 2008 |
60 |
20 |
||
|
Temporary Differences |
Deferred Tax Liability |
|||
|
$ '000 |
$ '000 |
|||
|
As at 31 December 2007 |
(19,455) |
(6,420) |
||
|
Movement in liability due to change in tax rate |
- |
176 |
176 |
|
|
Disallowed income generated in 2008 |
1,825 |
602 |
602 |
|
|
Movement in temporary differences in 2008 |
(19,756) |
(7,120) |
(7,120) |
|
|
As at 31 December 2008 |
(37,386) |
(12,762) |
Total: |
(6,449) |
EARNINGS PER ORDINARY SHARE
Basic earnings per share amounts are calculated by dividing profit for the period attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year.
Diluted earnings per share amounts are calculated by dividing the profit for the period attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of ordinary shares that would be issued on the conversion of all the dilutive potential ordinary shares into ordinary shares.
The following reflects the income and share data used in the basic and diluted earnings per share computations:
|
2008 |
2007 |
|
|
$ '000 |
$ '000 |
|
|
Net profit for the period attributable to equity holders |
35,645 |
6,551 |
|
2008 |
2007 |
|
|
Basic weighted average number of shares |
59,641,920 |
58,432,720 |
|
Dilutive potential ordinary shares: |
||
|
Shares to be issued on conversion of convertible bonds* |
723,496 |
- |
|
Employee share options |
2,264,365 |
1,441,588 |
|
Diluted weighted average number of shares |
62,629,781 |
59,874,308 |
(*) Series A bonds are convertible into 2,564,282 ordinary shares of the Company at 290 pence per share and Series B bonds are convertible into 2,754,229 ordinary shares of the Company at 270 pence per share. As the average share price in 2007 was below either of the conversion prices, the shares potentially issuable on conversion of the bonds did not contribute to the computation of diluted weighted average number of shares.
There have been no other transactions involving ordinary shares or potential ordinary shares between the reporting date and completion of these financial statements.
DIVIDENDS
The Directors do not recommend payment of an ordinary dividend.
Related Shares:
Emerald Energy