Hardy Oil & Gas plc - Preliminary Results
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RNS Number:0336S Hardy Oil & Gas plc 10 April 2008 For immediate release 10 April 2008 Hardy Oil and Gas plc ("Hardy" or the "the Company") Preliminary Results for the year ended 31 December 2007 Hardy Oil and Gas plc (LSE: HDY), the oil and gas exploration and production company with interests in India and Nigeria, today announces its Preliminary Results for the year ended 31 December 2007. All financial amounts are represented in US dollars unless otherwise stated. Operational Highlights 2007 • Announced discoveries on CY-OS/2 block (Ganesha) and GS-01 block (Dhirubhai 33) • Acquired additional 2,800 km2 of 3D seismic data on the D3 block • Conducted a successful production flow test of the Oza-4 well • Gross operated production 4,150 stbd (2006: 5,811 stbd) 2008 to date • Announced two discoveries (Dhirubhai 39 and 41) on the D3 block • Granted the onshore petroleum exploration licence AS-OON-2000/1 located in Assam • Completed the acquisition of a further 1,100 km2 3D seismic data on the GS-01 block • Farmed out a portion of Oza field to fund the field development programme Financial Highlights • Net profit of $8.3 million* (2006: $10.2 million) • Capital expenditure of $32.2 million (2006: $51.6 million) • Cash and cash equivalent at 31 December 2007 of $31.2 million (2006: $24.5 million) • Placement of equity shares June 2007 raising $40.2 million (2006: $24.5 million) *Includes after-tax gain of $7.4 million from sale of investment Commenting on the results, Mr E.P. Mortimer, Chairman of Hardy said: "2007 was a milestone year for Hardy with significant progress made in all our assets. We have made an encouraging start in 2008 with the moving of our share listing from AIM to the Main Market of the London Stock Exchange and two discoveries on the D3 block. Our exploration success in India underpins our strategy to create shareholder value through high impact exploration interests and mitigating risk through appropriate partnerships. 2008 will be an important year in our exploration, appraisal and development programmes and we look forward to it with anticipation." Conference Call Buchanan Communications will be hosting, on behalf of the management of Hardy, an analyst conference call today at 09.00 a.m. (UK). Management will present the results, after which the lines will be open for questions. For further information please contact Hardy Oil and Gas plc 020 7471 9850 Sastry Karra (Chief Executive) Yogeshwar Sharma (Chief Operating Officer) Dinesh Dattani (Finance Director) Arden Partners plc 020 7398 1600 Richard Day Tom Fyson Buchanan Communications 020 7466 5000 Mark Edwards Ben Willey Chairman's Statement Overview 2007 was another successful year for our growing company. The Board remained focused on executing the Company's strategy of creating shareholder value through the de-risking of the Company's Indian exploration portfolio, whilst continuing production from its development assets. The year commenced with the announcement of the Ganesha discovery on the Hardy-operated CY-OS/2 exploration block on the east coast of India. This was followed by the announcement in May of the Dhirubhai 33 gas discovery on the GS-01 exploration block on the West Coast of India. The Company completed a further placing of new Ordinary Shares in June raising over $40.2 million to fund our ongoing capital programme at 423 pence per share. 2008 has also started well, with the recent announcements of two consecutive discoveries on the D3 exploration block on the east coast of India and the expansion of the Company's exploration portfolio with the granting of a petroleum exploration licence for the AS-ONN-2000/1 onshore block in Assam, India. Corporate During the year, the Board took the decision to move the listing of Hardy's shares from AIM to the Official List of the London Stock Exchange's market for listed securities ("Main Market"). The admission of Hardy's shares to the Main Market should assist in increasing the profile and liquidity of the Company's Ordinary Shares whilst increasing access to capital to fund its future exploration and development expenditures. Hardy's shares began trading on the Main Market on 20 February 2008 and with effect from 26 March 2008 Hardy's shares have been included in the FTSE 250 indices. The senior executive team has been strengthened with the appointment of Mr Dinesh Dattani in July 2007 as Finance Director. Mr Dattani's strong financial background in the upstream oil and gas industry provides greater balance to the executive team. We will continue to look for appropriate additions to strengthen the Board and the senior management team. Outlook We will continue to work closely with the Ministry of Petroleum and key industry groups, in connection with the Government of India's recent intervention in gas pricing and proposed modification to the tax holiday, to help ensure that our interests and those of all operators in India are protected. Over the past decade the oil and gas industry in India, in partnership with the Government, has invested heavily in various midstream and upstream projects. In 2008, the first gas production from the Reliance Industries Limited (Reliance) operated D6 block adjacent to the Company's D9 block in the Krishna Godavari basin will commence and this will significantly increase the supply of gas into the energy-constrained Indian market. The infrastructure and market development associated with this east coast domestic gas supply augurs well for rapid exploration and development of the D3 and D9 blocks in the Krishna Godavari basin in which Hardy has an interest. The Board looks to the balance of 2008 with great anticipation. In 2008, the Company is planning for the largest drilling programme in its history with six exploration wells and up to two appraisal wells. Our asset base has also increased in India with the addition of the Assam block providing further long-term growth potential. The Company is in excellent shape and we are enthusiastic about the year ahead. E.P. Mortimer Chairman 9 April 2008 Chief Executive's Review Summary of the Year 2007 was a landmark year for Hardy. In India, our discovery on CY-OS/2 block (Ganesha) has increased the Company's Contingent Resource inventory, which will be further appraised in the latter part of 2008 and early 2009 with the drilling of three wells on the Fan-A discovery. The announced discovery of Dhirubhai 33 on the GS-01 block, with our partner Reliance, also contributed to the growth of our Contingent Resource inventory. An appraisal programme has been proposed by the operator and is currently under review by the joint venture. Drilling of an additional three exploration wells will commence in the second quarter of 2008 targeting several other independent prospects. The recent KGV-D3-A1 (Dhirubhai 39) and KGV-D3-B1 (Dhirubhai 41) gas discoveries on the D3 block are an encouraging start to evaluating the prospectivity of this block. We anticipate that the newly acquire 3D seismic will identify further drilling prospects as we complete the full evaluation of the block. Key Financial Results Revenue in 2007, as anticipated, decreased to $11.8 million in 2007 compared to $21.3 million in 2006. This was due to several factors including the expected increase in the Government of India's profit oil share, a decrease in production levels and an increase in closing inventory. Net profit was $8.3 million compared to $10.2 million in 2006. The Company also realised a gain of $10.2 million from the sale of shares in Hindustan Oil Exploration Company Limited (HOEC). Diluted earnings per share were $0.13 in 2007 compared to $0.17 for 2006. We anticipate that earnings will continue to fall in 2008 as PY-3 operating and Group administrative costs have increased while production from PY-3 will decline from 2007 levels. The active drilling programme in 2007 resulted in capital expenditures of $32.2 million compared with $51.6 million in 2006. At the end of 2007, the Company had cash reserves of $31.2 million. In 2007, the Company raised $40.2 million through a placing of 5,009,541 ordinary shares. The Company participated in an HOEC rights issue and also partially liquidated its investment in HOEC resulting in a net addition to cash resources of $7.4 million during January 2008. India In 2007 the major focus of the Company was on the Hardy-operated assets, CY-OS/2 exploration licence and PY-3 production block. PY-3 - Production from the PY-3 field was lower than expected in 2007 due to the shut-in of the PY-3-3RL well in August 2007. The drilling of two additional wells (Phase III) is on-track but additional production from this drilling programme is not expected until 2009. CY-OS/2 - The Fan-A1 well discovery (Ganesha) was announced at the beginning of the year and the focus quickly turned to evaluating results and, subsequently, submitting an appraisal programme to the CY-OS/2 joint venture. The additional geological and geophysical work, along with well planning, remains a focus of the Group as we move into 2008. We are considering farming-out a portion of our interest to be more consistent with the risk profile of the Company's other exploration assets. Results on our non-operated exploration assets have also been encouraging as we continue to pursue our strategy of de-risking this portfolio. GS-01 - The gas discovery in well GS-01-B1 (Dhirubhai 33) was the second well to be drilled under this exploration licence. The operator has submitted an appraisal programme which is awaiting approval. A further three exploration wells are scheduled to commence drilling in the second quarter of 2008. The assets that continue to generate the most interest and anticipation are the Company's Krishna Godavari basin blocks D9 and D3. D9 - Due to the industry-wide shortage of drilling ships capable of operating in water depths greater than 2,000 m, delays have been experienced on the D9 exploration licence. We anticipate that drilling of the first well on the D9 block may commence before the end of 2008. D3 - The drilling phase on D3 began much sooner than expected with the commencement of drilling of the first well at the end of 2007. Subsequently we were pleased to announced two successive gas discoveries on the block with encouraging initial testing results including an observed flow rate of 38.1 MMscfd. We anticipate that the operator will submit an appraisal programme for approval shortly. Further drilling on the D3 block is not expected to commence until the first quarter of 2009 as the joint venture evaluates the additional 2,800 km2 of 3D seismic acquired in 2007. Assam - As announced on 3 April 2008, the pursuit of our Indian strategy resulted in the award of the Assam onshore petroleum exploration licence AS-ONN-2000/1. We are also delighted with the Company's continued partnership with Reliance. This is the fourth block that Hardy holds in partnership with Reliance and the Company's first onshore asset in India. The block provides further long-term potential to create significant shareholder value. Nigeria We observed several key milestones with respect to our Nigerian operations. Oza - Hardy was able to conduct its first full field operation with the well flow test of Oza-4. The initial results are positive and, more importantly, the operator received cooperation and support from the local communities. We have established open channels of dialogue with all stakeholders in the Oza communities and we look for this to continue as we move towards initial field development in the latter part of 2008. As announced on 3 April 2008 the Company entered into an agreement to farm-out a 20 per cent. interest in the Oza block to Emerald Energy Resources Limited (Emerald). Emerald has agreed to assume Hardy's financial obligations in the funding of the Oza field initial development programme. Atala - Securing the necessary equipment for the planned re-entry operating in Atala continues to be difficult. The Company's Nigerian management team have been working closely with a consortium of swamp operators. This group has several options available to them and we anticipate that greater clarity on the timing of operation will be achieved in 2008. 2008 Programme We are looking forward to an active 2008 with the following plan of work: • GS-01 - Drilling of three exploration wells • D3 - Processing and interpretation of acquired 3D seismic data • D3 - Submission of appraisal programme for Dhirubhai 39 and 41 discovery • CY-OS/2 - Commencement of appraisal drilling to assess Ganesha discovery • D9 - Commencement of exploration drilling programme • Assam - Acquisition of 350 line km of 2D seismic data • Oza - Commence field development operations. The Company will continue to focus on organic growth as our primary strategy to create shareholder value. The NELP rounds have become increasingly competitive; however, they still offer the most direct way of acquiring exploration acreage in India. Staff The accomplishments of 2007 would not have been possible without the dedication of the Company's staff in India, Nigeria and London, UK. The India team continues to drive the core of our business. The Nigerian team have reached a key milestone in 2007 despite challenging conditions. The corporate team in London, along with the India team in Chennai, were instrumental in the efficient execution of the Main Market listing. I would like to take this moment to recognise them all for their efforts in the past year. Sastry Karra Chief Executive 9 April 2008 Review of Operations At the beginning of 2007, the Company planned to drill three exploration wells, conduct a production test of two wells in Oza, and acquire 3,288 km2 of 3D data. At the end of 2007, the Company had participated in the drilling of three exploration wells, the production testing of one well and the acquisition of 2,800 km2 of 3D seismic. During 2007, and as part of the process of moving the Company to the Main Market, an independent report was prepared for the Company by Gaffney, Cline & Associates Ltd (GCA) on the reserves and resources inventory of the Company. As at 30 June 2007, GCA estimated 2.69 million barrels of Proved plus Probable (2P) net entitlement reserves in the PY-3 field. The Company's operations in India are conducted through its wholly owned subsidiary Hardy Exploration & Production Inc. (HEPI). The Company's operations in Nigeria are conducted through its wholly owned subsidiary Hardy Oil Nigeria Limited (HON). CAUVERY BASIN - Eastern India Block CY-OS 90/1 (PY-3): Producing Oil Field (Hardy 18% interest - Operator) Production Actual gross field production for the year ended 31 December 2007 was 4,150 stbd (2006: 5,811 stbd). The production facilities' uptime performance was 96.8 per cent. (2006: 96.7 per cent.). The decrease in production was attributable to the seizure of the PY3-3 RL well, due to water loading, in August 2007 and the failure of the Endeavor's (FSO) mooring system in December 2007 (resulting in 11 days' shut-in). The production forecast for 2008 is 2,700 stbd, reflecting the expected continued natural decline of the field. In 2008, around 10 days' downtime is anticipated due to the need to carry out under water inspection and maintenance work on Normor Buoy (SPM) to comply with ABS certification requirements. Increase in PY-3 production is not anticipated until 2009. For the year ended 31 December 2007 the average water injection rate was 5,800 bwpd (2006: 6,678 bwpd) which, at current production levels, is sufficient to maintain voidage replacement. Injection facilities' uptime performance was 86.8 per cent. (2006: 96.7 per cent.). The reduction in uptime was attributable to the scheduled plant shutdown in March 2007 for further the under water inspection and for rectifying the FSO forward mooring system in December 2007. Operations The PY-3 field joint venture has approved a $90.0 million Phase III development programme which provides for the drilling of two additional lateral wells (one producer and one injector) and various gathering lines and facility upgrades. The Company has issued a request for tender for long-lead items such as subsea trees and flow lines. In order to identify a suitable production facility for the operation of the PY-3 field beyond July 2009, Hardy commissioned a Conceptual Field Design study that was undertaken by ODE Ltd, UK. Based on the recommendations obtained from the ODE study, further investigations are in progress to select a suitable production facility. Background The PY-3 field is located off the East Coast of India 80 km south of Pondicherry in water depths of between 40 and 200 m. The Cauvery basin developed in the late Jurassic/early Cretaceous period, and straddles the present-day East Coast of India. The licence, which covers 81 km2, is currently the deepest producing subsea field in India and produces oil of high quality light crude (49degrees API). The field was developed using floating production facilities and subsea wellheads, a first for an offshore field in India. HEPI is the Operator of the PY-3 field, and the participating interests for this licence are as follows: HEPI TATA HOEC ONGC 18% 21% 21% 405 The facility at PY-3 consists of the floating production unit, ''Tahara'', and a 65,000 DWT tanker, ''Endeavor'', which acts as a floating storage and offloading unit. There are four sub-sea wells tied back to Tahara. Tahara has a three-stage crude oil separation system, with the first two stages being three-phase separators and the third stage a two-phase separator. Actual liquid processing capacity on Tahara is 20,000 stbd with 17 MMscfd of gas handling capacity. The field currently produces associated gas in the range of 3.5 MMscfd. This produced gas is used as fuel gas, with excess gas being flared. The stabilised crude oil is pumped from Tahara to Endeavor for storage and offloading to shuttle tankers. Crude oil from the PY-3 field is sold to CPCL at its refinery in Nagapattinam, approximately 70 km south of the PY-3 field. CAUVERY BASIN - Eastern India Block CY-OS/2: Exploration (Hardy 75% interest - Operator) Operations In 2007 HEPI completed the exploration licence's phase III minimum work programme. On 8 January 2007 the Company announced that the Fan-A1 well had discovered hydrocarbons. On 10 August 2007 the Company announced that it would proceed with an appraisal programme to delineate the Cretaceous Fan-A1 discovery to establish the potential commerciality of the Cretaceous with the planned drilling of three further wells. As part of the appraisal programme a number of geological and geophysical studies have been undertaken, including the reprocessing of the 3D seismic data covering the block to improve subsurface imaging. Special studies such as AVO and inversion are ongoing to improve characterisation and delineation of the reservoir. Analysis of oil and gas crude samples and other well data from the Fan-E1 and Fan-A1 wells were also undertaken in 2007, including geochemical studies. HEPI has recently hired a third party to begin the well planning work and to provide well management services and consultation through the entire appraisal drilling programme. Subject to rig availability, the drilling portion of the appraisal programme is expected to start in the fourth quarter of 2008. The Board is presently considering farming out a portion of its participating interest in the licence. Background The CY-OS/2 block is located in the northern part of the Cauvery Basin immediately offshore from Pondicherry and covers approximately 859 km2. The CY-OS/2 licence comprises two retained areas. The northern area includes the Fan-A1 discovery. The southern area lies immediately adjacent to the HEPI operated PY-3 field. The PY-1 gas field lies within the southern part of the acreage and is expected to begin production by the first quarter of 2009. HEPI is the operator of this licence. The participating interests in licence CY-OS/2 are as follows: CY-OS/2 HEPI GAIL ONGC* Participating interest 75% 25% - *In the event of a commercial discovery, ONGC has the option to back into the CY-OS/2 licence at an interest of 30 per cent. The PY-3 oil field and PY-1 gas field are both contained within the CY-OS/2 licence but have been ring-fenced out, each with a separate PSC. The CY-OS/2 exploration licence has been under an approved phase III extension which expired at the end of March 2007. HEPI, as operator of the joint venture, has fulfilled the exploration phase III commitment work programme of 3D seismic surveys and drilling of two exploratory wells. GUJARAT-SAURASHTRA BASIN - Western India Block GS-OSN/2000/1 (GS-01): Exploration (Hardy 10% interest) Operations To date the GS-01 joint venture has drilled two exploration wells on the GS-01 block. On 15 May 2007 Hardy announced that the second exploration well, GS-01-B1, had discovered hydrocarbons in the mid-Miocene Limestone (Dhirubhai 33). The exploration well was drilled to a depth of 2,282 m MDRT and encountered natural gas and condensate within the mid Miocene Limestone over an interval from 1,988 m to 2,052 m MDRT. The two intervals selected for cased hole DST were 1,988 m to 1,993 m and 2,019 m to 2038 m MDRT respectively. The test produced natural gas at a rate of 18.6 MMscfd together with 415 stbd of condensate through a 56/64 " choke with a flowing tubing head pressure of 1,346 psi. The operator has subsequently proposed an appraisal programme involving additional 3D seismic data interpretation, development concept studies, reserve assessment and validation, and two contingent appraisal wells. The appraisal wells will be dependent on the findings of the proposed studies. The proposed exploration programme for 2008 comprises of the acquisition of an additional 1,000 km2 of 3D seismic and the drilling of three further exploration wells which will meet the phase I work commitment for the exploration licence. The 3D seismic acquisition programme was completed in March 2008 covering 1,165 km2 and processing and interpretation is expected to be fast-tracked by the operator. The three-well drilling programme is expected to commence by the end of April 2008. In 2008, the GS-01 joint venture will be required to elect to proceed to phase III of the exploration licence or relinquish the block not covered by the appraisal programme. The minimum work programme for phase III stipulates the drilling of eight exploration wells. Background The GS-01 exploration licence is located in the Gujarat-Saurashtra offshore basin, off the west coast of India, directly adjacent to the prolific Bombay High oil field. The licence encompasses 8,841 km2, and water depths vary between 80 and 150 m. The joint venture has previously acquired 1,216 km2 of 3D seismic. The participating interests for this licence are as follows: Area HEPI Reliance GS-01 10% 90% Typical trap types within this basin are fault-bound anticline and stratigraphic carbonate traps (including reefal structures and carbonate build-ups). The identified prospects are located in the Miocene, Oligocene and Eocene carbonates and Paleocene Basal clastics. KRISHNA GODAVARI BASIN - Eastern India Block KG-DWN-2001/1 (D9): Exploration (Hardy 10% interest) Operations As announced by the Company on 13 February 2008, after careful consideration of the current equipment shortage and the priority of the operator to complete offsetting commercial developments, the Board is of the view that drilling on the D9 licence is unlikely to commence until the latter part of 2008. However, as experienced with the D3 licence, windows of availability do occur and the Directors will endeavour to ensure that shareholders are notified of developments on a timely basis. During 2007, the operator continued to interpret and evaluate the 3D seismic data. PSDM reprocessing 3D seismic data was completed and the data is being studied to optimise the selected locations for drilling. Sea-bed logging was also conducted and the results provided encouraging results with similar indicators observed in the adjacent D6 block. Background The licence encompasses 11,605 km2 in the Bay of Bengal where water depths vary from 2,300 m to 3,100 m. The participating interests for this licence are as follows: Area HEPI Reliance D9 10% 90% The joint venture has acquired over 4,188 km2 of 3D seismic and leads at Upper Miocene, Middle Miocene and Oligocene have been identified. These leads are areally large structural closures located toward the, relatively shallower-water north-western corner of the concession, for which GIIP of many TCF has been computed by the operator. A fourth lead is a Pleistocene channel in the south eastern part of the block which is in ultra deep water with a prognosticated GIIP of a similar order of magnitude to the other leads. Initial exploration will be focused upon amplitude anomalies within closure in the Miocene and Pliocene rather than a pure structural play. There are many seismic anomalies within the block and, given its proximity to D6, exploration potential of this large block is regarded with considerable optimism. KRISHNA GODAVARI BASIN - Eastern India Block KG-DWN-2003/1 (D3): Exploration (Hardy 10% interest) Operations In 2007 the operator acquired 2,800 km2 of 3D seismic data. The D3 joint venture has also taken the decision to process and evaluate the acquired data prior to acquiring additional data with the intention of modifying the acquisition parameters to optimise the data quality. The exploration drilling programme commenced earlier than expected on 28 December 2007, with the KGV-D3-A1 well which has resulted in the first discovery on this licence named Dhirubhai 39. The well was drilled to a depth of 1,937 m MDRT and encountered natural gas between 1,513 m and 1,597 m MDRT with a gross sand thickness of 84 m. One interval was selected for cased hole DST covering 1,565 m to 1,585 m MDRT and produced natural gas at a rate of 38.1 MMscfd through a 120/64" choke. The D3 joint venture then moved the rig ''C Kirk Rhein'' to a second location (KGV-D3-B1) to evaluate the Pleistocene and Late to Mid Miocene sandstone reservoirs. On 1 April 2008, the Company announced a second discovery (Dhirubhai 41) on the D3 block. The well encountered good quality reservoirs in the Pleistocene and Miocene formations. MDT tests were conducted over several intervals (1,814 to 2,101 m MDRT and 2,119 to 2,463 m MDRT) and confirmed the presence of hydrocarbons. Several gas samples were collected over both intervals however due to poor well bore casing integrity, a decision was taken to not conduct a DST and the well was plugged and abandoned. Although early indications are encouraging, the potential extent and commerciality of the Dhirubhai 39 and 41 discoveries is yet to be established. On 31 March 2008 the operator issued a B-1 notification to DGH stating the details of the tests carried out. It is anticipated that the operator will submit an appraisal programme for approval in the second half of 2008. Background In August 2005, Reliance and HEPI were awarded, under NELP V, a second licence in the deepwater Krishna Godavari Basin. The D3 licence encompasses an area of 3,288 km2, in water depths of 400 m to 2,100 m, and is located approximately 45 km from the east coast. Reliance is the operator. The participating interests for this licence are as follows: Area HEPI Reliance D3 10% 90% The licence had approximately 410 km2 of existing 3D seismic data, which has been reprocessed. The A-1 and B-1 locations were identified after this data was interpreted and mapped. ASSAM ARAKAN BASIN - North Eastern India Block AS-ONN-2000/1: Exploration (Hardy 10% interest) Operations On 2 April 2008, Hardy was pleased to announce the award of a 10% interest in the exploration licence AS-ONN-2000/1. This is the Group's first onshore block and fourth licence in partnership with Reliance. This block was offered in NELP II but commencement of operations had been delayed due to the outstanding grant of an onshore petroleum exploration licence from the appropriate state agencies. The proposed 2008 work programme primarily involves the reprocessing of the 124 line km (lkm) of existing 2D seismic data. Field operations are expected to commence in the fourth quarter of 2008 with the acquisition of approximately 350 lkm of 2D seismic data. This will meet the phase I minimum work programme commitment for the block. Background The AS-ONN-2000/1 exploration licence is located in the north eastern state of Assam, India, and north of Brahmaputra River. The exploration licence covers an area of 5,754 km2 and falls within the districts of Darrang and Sonitpur. The block is in phase I of the three-phase exploration licence. Phase I is over three years and will expire in the month of January 2011. The participating interests for this licence are as follows: Area HEPI Reliance Assam 10% 90% The topography of the area is primarily plain of low relief and there is a reasonably established road network across the block. A national highway runs parallel to river Brahmaputra and passes through the block. Assam foreland constitutes the shelf part of Assam - Arakan intermontane basin. It forms a north-east south-west trending, largely alluvium-covered, narrow, linear tract encompassing an area of 40,000 km2. The exploration block lies north of Brahmaputra River while most of the discovered oilfields in the basin are located south of Brahmaputra River over an area of approximately 4,000 km2. Intense exploration activities since 1956 have resulted in the discovery of seven major fields which include Naharkatiya, Moran, Rudrasagar, Geleki and Lokwa. Most of these fields have reached a mature stage of exploration for Mio-Pliocene reservoirs and are in the advanced phase of delineation and development. Very limited seismic data is available only in the eastern-most part of the block and suggests the presence of subsurface structure. Different play types expected are as follows: • Anticlinal structures within Paleocene - Eocene and Gondwana • Fault closures • Pinchout / wedgeout • Fractured / weathered basement NIGER DELTA BASIN - Nigeria Block Oza (OML 11): Development (Hardy 20% interest) Operations In November 2007 the Oza joint venture successfully executed a flow test of the Oza 4 well. Oil and gas production rates, reservoir pressures and crude samples were obtained during the test. This is a significant step towards full development of the field. As technical partner, HON has worked closely with the operator to design and implement the field operation. The flow rates averaged approximately 600 stbd of oil with a GOR of 5,466 scf/stb. The operator transported and sold the produced fluids without incident. Millenium Oil and Gas Limited, the operator for Oza field, with inputs from HON, continued efforts to obtain additional field data in the field and to conclude agreements for crude handling and purchase of Oza 3D seismic with Shell Petroleum Development Company (SPDC). Discussions are ongoing with the operator of an adjacent export facility at a near-by flow station. Current discussions suggest that the initial work programme will entail the installation of a 9 km multiphase pipeline to SPDC's Isimiri flow station. To comply with the Nigerian government's no-flare initiative, associated gas will need to be exported to an alternative facility with a gas export line. Recently HON has entered into a farmout agreement with Emerald Energy Resources Nigeria Limited (Emerald), a well-known local oil and gas company. Under the terms of the farm-out agreement Emerald assumes HON's obligation to fund the initial work programme of the Oza field. The capital expenditure is currently estimated at approximately $15 million. The farm-out is subject to government approval. Community relations will continue to be a focus of the operator and progress is expected in discussions regarding a sustainable agreement with the host communities surrounding the Oza field. Emerald has extensive experience and expertise in community relations and has committed to make available its experienced personal to the operator. Background The Oza Field is located on-land in the north-western part of OML 11, near Port Harcourt. The concession area is 20 km2. The participating interests for this licence are as follows: Area HON Millenium Emerald Oza 20% 60% 20% The Oza field is subject to a farm-out agreement between NNPC, SPDC, Elf Petroleum Nigeria Limited and AGIP as farmor and Milennium as farmee. The terms of this agreement are for an initial five year period from 27 April 2004 subject to an extension of the Oza Farm-out Agreement if approved by the Nigerian Department of Petroleum Resources (DPR). The field has cumulatively produced approximately 1.0 MMstb from four open zones of three wells targeting three reservoirs, M5.0, L9.0 and M2.1, with the principal reservoir being M5.0. At present, Oza has three suspended wells in the field. Since taking over the field in 2004, Millenium, along with HON, has completed a number of field operations and other studies. The log data of existing wells has been re-analysed both internally and through third party study to identify potential re-completion targets. There is existing 3D seismic data covering the Oza field. Negotiations between SPDC and Millenium for the acquisition of this data are ongoing. NIGER DELTA BASIN - Nigeria Block Atala (OML 46): Development (Hardy 20% interest) Operations In 2007 the Atala joint venture continued to struggle to secure the appropriate drilling equipment for a planned re-entry and test programme. The operator, with the help and support of Hardy, has taken the initiative to form a swamp operators group, comprising of several companies with fields in the swamps to collectively approach potential drilling companies with suitable rigs. Meetings were held in the latter half of 2007 and potential vendors have been identified. During 2007, a field development plan (FDP) report was completed by local consultant Eogas with close involvement and inputs from HON. The FDP recommends a phased approach, initially focusing on oil development with later completion for gas production and based on initial production from the two wells, drilling of new oil and gas wells. Recently the swamp operators group has identified and commenced negotiations with several vendors for a swamp barge. It is expected that a rig will be identified and a contract negotiated in the latter half of 2008 and the Atala operations may commence in the first quarter of 2009, with the re-entry of Atala-1 well. HON is working closely with the operator to finalise the re-entry programme, obtain government approvals, appoint competent company for procurement, logistics and rig management and ensure all long lead items are procured in timely fashion. The Atala FDP has been presented to the federal government for its approval. Background Atala is located within OML 46 which is located in a mangrove swamp on the Dodo River, a coastal area of NW Bayelsa State. The concession area is 34 km2. The Atala field was discovered in 1982 with the drilling of the Atala-1 well to a total depth of 4,058 m. Hydrocarbons were encountered and the well was cased but not tested or completed. The participating interests for this licence are as follows: Area HON Millenium Emerald Atala 20% 60% 20% The Atala field is subject to a farm-out agreement between NNPC, SPDC, Elf Petroleum Nigeria Limited and Nigerian AGIP Oil Company Limited as farmor and Bayelsa as farmee. The terms of this agreement are for an initial five-year period from 27 April 2004, subject to an extension of the term of the Atala Farm-out Agreement if approved by the Nigerian Department of Petroleum Resources. HON entered into a farm-in agreement with Bayelsa pursuant to which Bayelsa agreed to farm out a 20 per cent. participating interest in the Atala field to HON. HON also agreed to act as technical partner for the development and operation of the Atala field. The proposed development plan involves two phases. The first phase envisages the re-entry, testing and completion of the existing Atala-1 well and the drilling of a second lateral well to optimise oil drainage. AGIP operated Clough Creek field is the intended destination of Atala oil for evacuation. Yogeshwar Sharma Chief Operating Officer 9 April 2008 FINANCIAL REVIEW IFRS Hardy has a mandatory requirement to implement International Financial Reporting Standards ("IFRS") for accounting periods commencing 1 January 2007. In order to comply with IFRS, Hardy has restated consolidated and company financial statements for 2006 and has revised its accounting policies. Hardy has also prepared a reconciliation of its consolidated and company financial statements under UK GAAP to those prepared under IFRS. In addition, Hardy has prepared statements reflecting the revised opening balance s at 1 January 2006. Key Performance Indicators ------------------ Year ended 31 December 2007 2006 ---------- --------- Production (barrels of oil per day - net entitlement basis)) 573 844 Average realised price per barrel - Dollars 66.65 64.82 Average cost per barrel - Dollars 21.19 13.64 Revenue (thousands of Dollars) 11,830 21,317 Net profit (thousands of Dollars) 8,316 10,233 Cash flow from operations (thousands of Dollars) * 2,588 14,555 Diluted earnings per share - $ 0.13 0.17 Wells drilled 2 2 *Before change in non-cash working capital Operating Results --------------- (In thousands of Dollars unless otherwise indicated) Year ended 31 December 2007 2006 -------- --------- Production (Barrels of Oil per Day) 4,150 5,811 Gross Field 747 1,046 Participating Interest 573 844 Net Entitlement Interest Sales (Barrels of Oil per Day) 3,547 5,831 Gross Field 638 1,050 Participating Interest Average Realised Price per Barrel - $ 66.65 64.82 Production, Sales and Revenue The Company operates the PY-3 field in the Cauvery Basin with an 18 per cent participating interest. Since August 2007, one of the three producing wells in the PY-3 field has been shut in due to excessive water production. As a result of natural decline, PY-3 field crude oil production was lower by 29 per cent. during 2007 from the same period in 2006. Current oil production is at a level of approximately 3,050 stbd. The Company does not expect to recover additional production until the implementation of the PY-3 field's Phase III development. Hardy's net entitlement interest in production is after the Government of India's share of profit oil. Under the terms of the PSC, profit oil increased from 10 per cent to 25 per cent effective 1 April 2005 and was further increased to 40 per cent on 1 April 2006. On 1 April 2008, profit oil is expected to increase to 50 per cent. Revenue, after profit oil, declined from $21.3 million in 2006 to $11.8 million in 2007. The average price realised per barrel increased marginally to $66.65 during 2007. No sales took place during the fourth quarter of 2007 and all production during that period was held in inventory. Reduced revenue in 2007 resulted from lower production levels, higher inventory levels and higher profit oil to the Government of India. Cost of Sales Cost of sales for 2007 increased by $0.6 million during 2007. This results principally from higher costs of operating the PY-3 field. The contract for the floating processing and storage systems was renegotiated effective July 2007 resulting in a substantial increase in day rates. The increase in operating cost was offset in part by lower depletion and decommissioning costs. Gross Profit Gross profit declined from $16.1 million in 2006 to $6.1 million in 2007; the reduction principally stemming from lower revenues and higher operating costs from July 2007. Other Operating Income An insurance claim of $1.0 million was received for business interruption caused by an operational accident in the year 2002. This has been accounted for as other operating income in 2006 when insurance proceeds were received. Administrative Expenses Administrative expenses increased from $5.7 million in 2006 to $6.9 million in 2007. The increase principally results from a higher share based payment expense by $0.9 million for the stock options granted by the Company to its directors and employees since 2005. During 2007, costs include those relating to the move from AIM to the Main Market, higher manpower costs with the addition of an additional executive director and higher remuneration of executive directors. Operating Profit (Loss) As a result, the Company is reporting an operating loss of $0.8 million compared with an operating profit of $11.4 million reported in 2006. Gain on Sale of Investment During December 2007, the Company sold 3,010,000 ordinary shares of HOEC for a cash consideration of $12.5 million which was received in January 2008. As a result, the Company recorded a gain on sale of investment of $10.2 million. The after-tax gain amounted to $7.4 million or $0.11 per share. Investment and Other Income Investment and other income declined from $2.3 million in 2006 to $1.4 million in 2007. The decline was the result of reduced deposits and lower interest rates in 2007 compared to 2006. Finance Costs Finance costs principally include the cost of providing bank guarantees to the Government of India required in accordance with the provisions of Production Sharing Contracts and are based on the agreed work programme on blocks in India. Taxation Most of the provision for taxation is with respect to deferred income taxes since the Company's capital expenditure programme is sufficient to shield the Company from a large portion of current tax liabilities. The group's Indian operations can avail the treaty benefit for the taxes suffered either in India, the UK or the USA and the group could also benefit from prior year capital losses by way of group relief for the capital gain made in sale of investment in HOEC shares. Net Profit As a result, net profit declined from $10.2 million in 2006 to $8.3 million in 2007. Cash Flow from Operating Activities Cash flow from operating activities, before changes in non-cash working capital, has declined from $14.5 million in 2006 to $2.6 million in 2007. This results principally from lower revenues arising from lower production volumes and higher profit oil to the government, and higher operating and administrative costs. Changes in non-cash working capital principally reflect reduction in debtors (excluding receivable from the sale of investment of $12.5 million that was received in January 2008) as a result of lack of sales in the fourth quarter of 2007 and a significant reduction in creditors. At the end of 2006, the Company was in the process of drilling a well on its CY-OS/2 block in which it has a 75 per cent. participating interest. Capital Expenditures The Group's capital expenditures amounted to $32.2 million during 2007, compared to $51.6 million incurred during 2006. Capital expenditures amounting to $21.9 million were incurred on the CY-OS/2 block with the drilling of the successful Fan-A1 well. The Company expended $4.2 million with respect to its interest in the GS-01 block with the drilling of the B-1 discovery well. Expenditures on the D3 block amounted to $4.6 million with the acquisition of 2,800 km2 of 3D seismic and the commencement of the drilling of the first well on 28 December 2007. Approximately $1.0 million was incurred with respect to the Company's operations in Nigeria, principally with respect to the testing of a well in Oza and ongoing expenditures. The drilling has resulted in discoveries on the CY-OS/ 2, GS-01 and D-3 blocks and the test on Oza has been successful as well. During 2006, Hardy incurred a significant amount of capital expenditures on the CY-OS/2 block. As of 31 December 2006, Hardy had invested $59.5 million for its share of the drilling and testing of the two wells which included costs associated with the side track of the second well. In 2006, Hardy also participated in the drilling of the A-1 well on the GS-01 block. In the Krishna Godavari Basin on the east coast of India, 3,440 km2 of 3D seismic data has been acquired over the D9 block during 2006, which has now been processed and interpreted, and six prospects have been identified for drilling. Investment in HOEC The Company had an investment of approximately 8.5 per cent. in shares of HOEC, a publicly traded company in India. HOEC's primary assets are a 21 per cent. participating interest in PY-3 and a 100 per cent. participating interest in PY-1 (a gas discovery adjacent to PY-3 and ring-fenced by the CY-OS/2 exploration licence). In October 2006, HOEC raised approximately $33.0 million via a public rights issue in which Hardy took up its pro-rata entitlement at a cost of $2.8 million. In December 2007, the Company sold 3,010,000 shares of HOEC for a cash consideration of $12.5 million. In early January 2008, HOEC completed a rights offering with Hardy participating in the rights offering to the extent of its pro rata share investing an additional $13.2 million. In January 2008, the Company sold a further 1,971,411 shares for a cash consideration of $8.1 million. At the present time, the Company has 6,114,745 shares representing 4.7 per cent. equity in HOEC. Based on the market value of Rs.134 per share on 8 April 2008, this represents an investment value of approximately $20.5 million. Site Restoration Deposits As of 31 December 2007, the Company had deposited $3.4 million for site restoration of the PY-3 field. Of this amount, $2.8 million was placed in 2006 with the remainder of $0.6 million placed in 2007. Investment and Other Income The Company has raised equity capital during the past three years. Surplus cash is invested in short-term deposits generating investment income on a regular basis. The level of such income was reduced from $2.4 million in 2006 to $1.3 million due to reduction in deposit and lower interest rates during 2007. Finance Costs Finance costs essentially represent the cost of bank guarantees provided to the Government of India in connection with annual work programmes in India. Equity Financings The Company undertook its initial public offering (IPO) of ordinary shares on 7 June 2005 when its shares commenced trading on AIM. The IPO was successfully completed at a placing price of 144 pence per share, raising net proceeds of $20.8 million. In 2006 and 2007, the Company also successfully completed an additional equity placement of Ordinary Shares at 276 and 423 pence per share, raising additional proceeds of $24.5 million and $40.2 million respectively. Cash Position As a result of the equity placing, the Company has been able to maintain a significant amount of cash resources to fund its ongoing capital expenditures and work programmes. Total cash increased from $24.5 million at the end of 2006 to $31.2 million at the end of 2007. The Company does not have any long-term debt. Summary Balance Sheets Hardy has continued to grow during 2007. Its non-current assets have increased from $89.1 million at the end of 2006 to $121.4 million at the end of 2007. This results largely from the capital expenditure programme on exploration expenditures, principally on the drilling of wells on CY-OS/2 and GS-01 blocks as well as expenditure on seismic acquisition. Current assets represent the Group's cash resources, together with trade and other receivables and inventory. At the end of 2007, of the $48.4 million of current assets, $31.2 million is represented by cash, generated principally from the equity issue that was completed in June 2007. The accounts receivable at the end of 2007 included $12.5 million from the sale of shares in HOEC which were received in January 2008. Current liabilities are principally trade and other accounts payable. The level of current liabilities fluctuates significantly depending upon the timing of capital programmes. At the end of 2006, the Company was in the process of drilling a well on its CY-OS/2 operated block, resulting in a significant increase in payables. At 31 December 2007, the accounts payable were reduced to more normalised levels. Consequently, the Company has been successful in growing its net asset base, which has increased from $91.4 million at the end of 2006 to $144.0 million at the end of 2007. The increase in the carrying value of net assets results from a combination of new equity placements, earnings that have been retained in the business and the impact of valuation gains with respect to its investment in HOEC. Liquidity and Capital Resources Hardy has been funding its cash requirements from internally generated cash flows and equity capital, principally from institutional investors, in each of the years 2005, 2006 and 2007. The Company continues to be an emerging company with limited cash flows, and as a result, has been principally relying upon equity capital markets to build and grow its asset base. At 31 December 2007, the Company had cash resources of approximately $31.2 million that were available to meet future capital expenditures. In addition, the Company has realised proceeds (net of participation in the rights offering) from the sale of a portion of its shareholdings in HOEC of $7.4 million which has augmented its cash resources and working capital. At 8 April 2008, the Company's remaining investment in HOEC is worth $20.5 million which if required can be made available to further augment the Company's cash resources and working capital during 2008. The Company is presently considering farming out a portion of its participating interest of 75 per cent. in the CY-OS/2 block. The Company's plans provide for the drilling of three appraisal wells on the block and the farm-out is anticipated to contribute towards the Company's commitments with respect to its appraisal programme. At the present time, the Company does not have any short-term or long-term debt, nor does it presently have any bank facilities in place. The Company presently produces from the PY-3 field in India. The Company believes that it may be possible to secure financing on the strength of this producing block in the future. Base on present plans, the Company believes it has adequate financial resources to fund its capital expenditure requirements for 2008. Dividends The Company has limited internally generated cash flows and has a significant planned capital expenditure programme. In the circumstances, the Board of Directors has chosen to reinvest cash flows and does not recommend the payment on a dividend in the foreseeable future. Unaudited Preliminary Statement The preliminary statement of results is unaudited. The Directors anticipate that the Group's auditors, Horwath Clark Whitehill LLP, will present an unmodified audit opinion on the financial statements of the Group. Dinesh Dattani FCA Finance Director 9 April 2008 HARDY OIL AND GAS plc Consolidated Income Statement For the year ended 31 December 2007 -------------------------------- ------ --------- --------- 2007 2006 Notes US$ US$ -------------------------------- ------ --------- --------- Revenue 2 11,829,554 21,316,935 Cost of sales Production costs (4,216,138) (2,999,086) Depletion (1,344,101) (1,887,911) Decommissioning charge (217,397) (304,899) -------------------------------- ------ --------- --------- Gross profit 6,051,918 16,125,039 Other operating income - 1,000,000 Administrative expenses (6,865,187) (5,700,416) -------------------------------- ------ --------- --------- Operating (loss) / profit (813,269) 11,424,623 Gain on sale of investment 10,243,729 - Interest and investment income 1,381,121 2,288,954 Finance costs (180,400) (275,428) -------------------------------- ------ --------- --------- Profit on ordinary activities before taxation 10,631,181 13,438,149 Tax on profit on ordinary activities (2,315,203) (3,205,381) -------------------------------- ------ --------- --------- Profit attributable to the equity shareholders of the parent company 8,315,978 10,232,768 -------------------------------- ------ --------- --------- Earnings per share Basic 4 0.14 0.18 Diluted 4 0.13 0.17 -------------------------------- ------ --------- --------- HARDY OIL AND GAS plc Statement of Changes in Equity For the year ended 31 December 2007 ------------------ --------- --------- --------- --------- Group Group Company Company 2007 2006 2007 2006 US$ US$ US$ US$ ------------------ --------- --------- --------- --------- Beginning of year 91,401,836 60,929,902 58,466,526 37,943,782 ------------------ --------- --------- --------- --------- Profit for the year 8,315,978 10,232,768 8,194,489 283,578 Unrealized valuation gain/(loss) 3,514,603 (6,910,257) 3,514,603 (6,910,257) Deferred tax asset/(liability) on unrealised valuation gain or loss (966,780) 1,934,872 (966,780) 1,934,872 ------------------ --------- --------- --------- --------- Total recognised gains/(losses) 10,863,801 5,257,383 10,742,312 (4,691,807) New shares issued 40,168,691 24,527,092 40,168,691 24,527,092 Share based payments 1,561,497 687,459 1,561,497 687,459 ------------------ --------- --------- --------- --------- End of year 143,995,825 91,401,836 110,939,026 58,466,526 ------------------ --------- --------- --------- --------- HARDY OIL AND GAS plc Consolidated Balance Sheet As at 31 December 2007 ------------------ ------ --------- --------- --------- --------- Group Group Company Company Notes 2007 2006 2007 2006 US$ US$ US$ US$ ------------------ ------ --------- --------- --------- --------- Assets Non-current assets Intangible assets - exploration 99,284,534 67,216,281 - - Intangible assets - others 246,572 217,198 21,835 65,582 Property, plant and equipment 3,375,463 5,064,070 140,927 177,859 Investments 15,092,311 13,836,910 74,974,386 40,491,141 Site restoration deposit 3,369,820 2,784,660 - - ------------------ ------ --------- --------- --------- --------- 121,368,700 89,119,119 75,137,148 40,734,582 Current assets Inventory 2,703,915 2,729,764 - - Trade and other receivables 14,525,440 4,637,062 12,689,331 251,931 Cash and cash equivalent 31,157,048 24,490,939 28,471,133 19,318,159 ------------------ ------ ---------- --------- --------- --------- 48,386,403 31,857,765 41,160,464 19,570,090 Total assets 169,755,103 120,976,884 116,297,612 60,304,672 ------------------ ------ ---------- --------- --------- --------- Liabilities Current liabilities Trade and other payables (9,857,909) (16,809,807) (567,396) (153,782) ------------------ ------ ---------- ---------- ---------- --------- Non-current liabilities Provision for decommissioning (4,500,000) (4,500,000) - - Provision for deferred tax (11,401,369) (8,265,241) (4,791,190) (1,684,364) ------------------ ------ ---------- ---------- ---------- --------- (15,901,369) (12,765,241) (4,791,190) (1,684,364) Total liabilities (25,759,278) (29,575,048) (5,358,586) (1,838,146) ------------------ ------ ---------- ---------- ---------- --------- Net assets 143,995,825 91,401,836 110,939,026 58,466,526 ------------------ ------ ---------- ---------- ---------- --------- Equity Called-up share capital 6 622,625 572,530 622,625 572,530 Share premium 93,101,579 52,982,983 93,101,579 52,982,983 Shares to be issued 2,501,590 940,093 2,501,590 940,093 Other reserves 8,912,532 6,364,709 8,912,532 6,364,709 Retained earnings 38,857,499 30,541,521 5,800,700 (2,393,789) ------------------ ------ ---------- ---------- ---------- --------- Total equity 143,995,825 91,401,836 110,939,026 58,466,526 ------------------ ------ ---------- ---------- ---------- --------- HARDY OIL AND GAS plc Consolidated Statement of Cash flows For the year ended 31 December 2007 ------------------ ------ --------- --------- --------- --------- Group Group Company Company 2007 2006 2007 2006 Notes US$ US$ US$ US$ ------------------ ------ --------- --------- --------- --------- Operating activities Cash flow from operating activities 3 (1,844,914) 23,942,864 (1,730,151) (2,318,889) Taxation paid 63,235 (143,280) - - ------------------ ------ --------- --------- --------- --------- Net cash (used in) from (1,781,679) 23,799,584 (1,730,151) (2,318,889) operating activities Investing activities Expenditure on intangible assets -exploration (32,068,253) (51,034,004) - - Expenditure on property, plant and equipment (147,297) (148,215) - - Purchase of intangible 5,856 (176,972) - (4,500) fixed assets - other Purchase of other fixed (38,753) (247,992) (11,731) (47,938) assets Sale/(purchase) of investment - (2,778,914) - (2,778,914) Site restoration deposit (585,160) (2,784,660) - - ------------------ ------ --------- --------- --------- --------- Net cash (used in) investing activities (32,833,607) (57,170,757) (11,731 (2,831,352) Financing activities Interest and investment 1,293,104 2,376,072 3,726,459 2,075,877 income Finance costs (180,400) (275,428) - - Inter-corporate loan - - (33,000,294) (21,494,196) Issue of shares 40,168,691 24,527,092 40,168,691 24,527,092 ------------------ ------ --------- --------- --------- --------- Net cash from financing 41,281,395 26,627,736 10,894,856 5,108,773 activities Net increase/ (decrease) in cash and cash 6,666,109 (6,743,437) 9,152,974 (41,468) equivalents Cash and cash equivalents at the beginning of the year 24,490,939 31,234,376 19,318,159 19,359,627 ------------------ ------ --------- --------- --------- --------- Cash and cash equivalents at the end 31,157,048 24,490,939 28,471,133 19,318,159 of the year ------ --------- --------- --------- --------- ------------------ 1. Accounting Policies The following accounting policies have been applied in preparation of consolidated financial statements of Hardy Oil and Gas plc ("Hardy" or the "Group"). a) Accounting standards Hardy prepares its financial statements in accordance with International Financial Reporting Standards (IFRS) and interpretations issued by the International Accounting Standards Board as adopted by the European Union. Hardy adopted IFRS for the first time in the financial year which ended on 31 December 2007. The adoption of these standards and interpretations has resulted in changes to the Hardy's accounting policies. The effect of the adoption of IFRS on the results for the year ended 31 December 2006, the comparative year, are set out in note 32 to the financial statements. As at the date of approval of these financial statements, the following standards and interpretations were in issue but not yet effective: IFRS 2 (amendment) Share based payments IFRS 3 (revised) Consolidated financial statements IFRS 8 Operating Segments IFRIC 12 Service concession arrangements IFRIC 13 Customer loyalty programmes IFRIC 14 IAS19 - The limit on a defined benefit asset, minimum funding requirements and their interaction IAS 1 (revised) Presentation of financial statements IAS 23 (revised) Borrowing costs IAS 27 (revised) Consolidated and separate financial statements The Directors do not anticipate that the adoption of these interpretations in future reporting periods will have a material impact on the Group's results. b) Basis of consolidation The consolidated financial statements include the results of Hardy Oil and Gas plc and its subsidiary undertakings. The consolidated income statement and consolidated cash flow statements include the results and cash flows of subsidiary undertakings up to the date of disposal. The group conducts the majority of its exploration, development and production through unincorporated joint arrangements with other companies. The consolidated financial statements reflect the group's share of production and costs attributable to its participating interests under the proportional consolidation method. The Company has taken advantage of the exemption provided under section 3 of the Isle of Man Companies Act 1982 not to publish its individual income statement and related notes. The Company's profit for the year was $8,194,489 (2006: $283,578). Revenue and other income Revenue represents the sale value of the group's share of oil which excludes the profit oil sold and paid to the Government as a part of profit sharing in the year, tariff, and income from technical services to third parties if any. Revenues are recognized when crude oil has been lifted and title has been passed to the buyer or when services are rendered. c) Oil and gas assets i) Exploration and evaluation assets Hardy follows the full cost method of accounting for its oil and gas assets. Under this method, all expenditures incurred in connection with and directly attributable to the acquisition, exploration and appraisal having regard to the requirements of IFRS 6 "Exploration for and Evaluation of Mineral Resources" are accumulated and capitalized in two geographical cost pools, which are not larger than a segment: India and Nigeria. The capitalized exploration and evaluation costs are classified as Intangible assets - exploration which includes the license acquisition, exploration and appraisal costs relating either to unevaluated properties or properties awaiting further evaluation but do not include costs incurred prior to having obtained legal right to explore an area, which are expensed directly to the income statement as they are incurred. Intangible exploration and evaluation cost relating to each license or block remain capitalized pending a determination of whether or not commercial reserves exists. Commercial reserves are defined as proven and probable on a net entitlement basis. When a decision to develop these properties is taken or there is evidence of impairment, the costs are transferred to the cost pools within development/ producing assets when the commercial reserves attributable to the underlying asset have been established. ii) Oil and gas development and producing assets Development and production assets are accumulated on a field by field basis. These comprise of the cost of developing commercial reserves discovered putting them on production and the exploration and evaluation costs transferred from intangible exploration and evaluation assets as stated in policy above. In addition, interest payable and exchange differences incurred on borrowings directly attributable to development projects if any and assets in the production phase as well as cost of recognizing provision for future restoration and decommissioning are capitalized. iii) Decommissioning At the end of the producing life of a field, costs are to be incurred in removing, decommissioning facilities, plugging and abandoning wells. Decommissioning costs are estimated and stated at an amount representing the costs, which would be incurred should decommissioning occur at the balance sheet date and the estimates are reassessed each year. The provision is assessed at prices ruling at the balance sheet date and, accordingly, it is not appropriate to discount this provision. The decommissioning asset is included within the tangible fixed assets with the cost of the related assets installed and are adjusted for any revision to the decommissioning costs and the provision thereof. The amortization of the asset, calculated on a unit of production basis based on proved and probable reserves, is shown as "Decommissioning charge" in the income statement. iv) Disposal of assets Proceeds from any disposal of assets are credited against the specific tangible or intangible capitalized costs included in the relevant cost pool and any loss or gain on disposal is recognized in the income statement. Gain or loss arising on disposal of a subsidiary is recorded in the income statement. d) Depletion and impairment i) Depletion The net book values of the producing assets are depreciated on a field by field basis using the unit of production method, based on proved and probable reserves taking into consideration future development expenditures necessary to bring the reserves into production. Hardy periodically obtains an independent third party assessment of reserves which is used as a basis for computing depletion. ii) Impairment Exploration assets are reviewed regularly for indications of impairment, if any, where circumstances indicate that the carrying value might not be recoverable. In such circumstances, if the exploration asset has a corresponding development / producing cost pool, then the exploration costs are transferred to the cost pool and depleted on unit of production. In cases where no such development/ producing cost pool exists, the impairment of exploration costs is recognized in the income statement. Impairment reviews on development / producing oil and gas assets for each field is carried out on each year by comparing the net book value of the cost pool with the associated discounted future cash flows. If there is any impairment in a field representing a material component of the cost pool, an impairment test is carried out for the cost pool as a whole. If the net book value of the cost pool is higher, then the difference is recognized in the income statement as impairment. e) Property, plant and equipment Property, plant and equipment other than oil and gas assets are measured at cost and depreciated over their expected useful economic lives as follows: Annual Rate (%) Depreciation -------------------- ------------ Method --------------- Leasehold improvements over lease Straight line period Furniture and fixtures 20% Straight line Information technology and computers 33% Straight line Other equipment 20% Straight line -------------------- ------------ --------------- f) Intangible assets Intangible assets other than oil and gas assets are measured at cost and depreciated over their expected useful economic lives as follows: Annual Rate (%) Depreciation --------------- --------------- Method ----------------- Computer software 33 % Straight line ------------- ---------------- ------------------ g) Investments Investments in publicly traded securities are treated as available for sale and are recognized at fair values based upon the quoted market prices on the balance sheet date. Unrealized gains and losses are recognized under equity - other reserves. On disposal of an investment, the cumulative gain or loss is recognized in the income statement. Investments in subsidiary companies are carried at cost in the financial statements of the parent company. h) Inventory Inventory of crude oil is valued at lower of average cost and market. Average cost is determined based on actual production cost for the year. Inventories of drilling stores and are accounted at cost including taxes duties and freight. Provision is made for obsolete, or defective items where appropriate based on technical evaluation. i) Financial instruments Financial assets and financial liabilities are recognized at fair value on group's balance sheet based on the contractual provisions of the instrument. Trade receivables do not carry any interest and are stated at their nominal value as reduced by necessary provisions for estimated irrecoverable amounts. Trade payables are not interest bearing and are stated at their nominal value. j) Equity Equity instruments issued by Hardy and the group are recorded at net proceeds after direct issue costs. k) Taxation The tax expense represents the sum of current tax and deferred tax. The current tax is based on the taxable profit of the year. Taxable profit differs from net profit as reported in the income statement as it excludes certain item of income or expenses that are taxable or deductible in years other than the current year and it further excludes items that are never taxable or deductible. The current tax liability is calculated using the tax rates that have been enacted or substantively enacted by the balance sheet date. Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the liability method. Deferred income tax liabilities are recognized for all taxable temporary differences and deferred tax assets are recognized to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilized. Deferred income tax liabilities are recognized for all temporary differences except in respect of taxable temporary differences associated with investment in subsidiaries, associates and interest in joint ventures where the timing of the reversal of the temporary differences can be controlled and it is possible that the temporary differences will not reverse in the foreseeable future. Deferred tax is recognized in respect of all temporary differences that have originated but not reversed at the balance sheet date where transactions or events have occurred at that date that will result in an obligation to pay more or a right to pay less or to receive more tax. Deferred tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply in the periods in which temporary differences reverse, based on tax rates and laws enacted or substantively enacted at the balance sheet date. l) Foreign currencies Hardy maintains its accounts and the accounts of its subsidiary undertakings in US dollars. Foreign currency transactions are accounted for at the exchange rate prevailing on the date of the transaction. At the year end, all foreign currency assets are restated at the average of the buying and the selling exchange rates prevailing at the balance sheet date. Exchange difference arising out of actual payments / realizations and from the year end restatement are reflected in the income statement. Rates of exchanges are as follows: ----------------- --------------- --------------- 31 December 31 December 2007 2006 --------------- ---------------- ----------------- £ to US$ 1.9828 1.9658 US$ to Indian Rupees 39.420 44.1700 --------------- ---------------- ----------------- m) Estimation uncertainty i) Decommissioning The liability for decommissioning is based on the best estimate of the costs of decommissioning that will arise at some point in the future. Significant changes in costs or technological advancement could result in a material change to this provision. ii) Depletion Depletion calculations are based on the best estimate of commercial reserves existing as at the balance sheet date. The determination of commercial reserves is based on assumptions which include those relating to the future price of crude oil, capital expenditure plans and the costs of production. Any changes in these assumptions could result in a material change in the depletion charge or the carrying value of associated assets. n) Leasing commitments Rental charges or charter hire charges payable under operating leases are charged to the income statement as part of production cost over the lease term. o) Share based payments Hardy issues share options to directors and employees, which are measured at fair value at the date of grant. The fair value of the equity settled options determined at the grant date is expensed on a straight line basis over the vesting period based on the actual number of shares vested in the accounting period. In performing the valuation of these options, only conditions other than the market conditions are taken into account. Fair value is derived by use of the binomial model. The expected life used in the model is based on estimates of the management considering non-transferability, exercise restrictions and behavioural considerations. 2. Revenue and other income ------------- ----------------- ----------------- 2007 2006 US$ US$ India UK India UK ------------- ---------- --------- --------- ---------- Oil sales 15,531,311 - 24,731,952 - Profit oil to government (4,268,322) - (4,714,128) - Other income - 566,565 154 1,298,957 ------------- ---------- --------- --------- ---------- 11,262,989 566,565 20,017,978 1,298,957 ------------- ---------- --------- --------- ---------- The Directors do not consider there to be more than one class of business or more than one disclosable geographic segment for the purposes of reporting. The Group is engaged in one business activity, the production of and exploration for oil and gas. The revenue, segment result and assets of the geographic segments, other than India, are nil or less than 10 per cent of the total for all segments. Other income relates to technical services to third parties, overhead recovery from joint venture operations and miscellaneous receipts if any. Revenue arises from sale of oil produced from the contract area CY-OS-90/1-India and the revenue by destination is not materially different from the revenue by origin. 3. Reconciliation of operating profit to operating cash flows --------------- ---------------- Group Company ------------------- --------- -------- --------- -------- 2007 2006 2007 2006 US$ US$ US$ US$ ------------------- --------- -------- --------- -------- Operating loss (profit) (813,269) 11,424,623 (3,639,865) (2,583,100) Depletion and depreciation 1,622,030 2,137,699 92,410 98,721 Decommissioning charge 217,397 304,899 - - Share based payments charges 1,561,497 687,459 1,333,947 459,540 ------------------- --------- -------- --------- -------- 2,587,655 14,554,680 (2,213,508) (2,024,839) (Increase )/ decrease in inventory 25,849 (2,379,835) - - Decrease /(increase) in debtors 2,720,211 225,800 69,743 (73,030) Increase /(decrease) in creditors (7,178,629) 11,542,219 413,614 (221,020) ------------------- --------- -------- --------- -------- Net cash (outflow)/inflow from operating activities (1,844,914) 23,942,864 (1,730,151) (2,318,889) ------------------- --------- -------- --------- -------- The decrease (increase) in debtors reported above for 2007 for the group and the company excludes an amount of US$ 12,502,931 due from the sale of investment in Hindustan Oil Exploration Company ("HOEC") during the year. 4. Earnings per share Earnings per share are calculated on a profit of US$ 8,315,978 for the year 2007 (2006: US$ 10,232,768) on a weighted average of 60,117,416 ordinary shares for the year 2007 (2006: 56,695,898). The diluted earnings per share are calculated on a profit of US$ 8,315,978 for the year 2007 (2006: US$ 10,232,768) on a weighted average of 64,469,515 ordinary shares for the year 2007 (2006: 59,367,997). The weighted average shares are arrived after giving impact to dilutive potential ordinary shares of 4,352,099 as on 31 December 2007 (2006: 2,672,099) relating to share options. 5. Members of the Group The group comprises the parent company - Hardy Oil and Gas plc - and the following subsidiary companies, all of which are wholly owned: • Hardy Exploration & Production (India) incorporated under the Laws of State of Delaware, United States of America. • Hardy Oil (Africa) Limited registered under the laws of the Isle of Man. • Hardy Oil Nigeria Limited, owned by Hardy Oil (Africa) Limited, registered under the laws of Nigeria. All members of the group are engaged in the business of exploration and production of oil and gas and all are included in the consolidation. 6. Share capital ----------------------------- ----------- ---------- Number US$ $0.01 Ordinary Shares "000" ----------------------------- ----------- ---------- Authorized ordinary shares At 1 January 2006 200,000 2,000,000 At 1 January 2007 200,000 2,000,000 At 31 December 2007 200,000 2,000,000 ----------------------------- ----------- ---------- ----------------------------- ----------- ---------- Allotted, issued and fully paid ordinary shares At 1 January 2006 52,046,667 520,467 Share options exercised during the year 1,667 16 Shares issued during the year 5,204,660 52,047 ----------------------------- ----------- ---------- At 1 January 2007 57,252,994 572,530 Share options exercised during the year 45,001 450 Shares issued during the year 4,964,540 49,645 ----------------------------- ----------- ---------- At 31 December 2007 62,262,535 622,625 ----------------------------- ----------- ---------- DEFINITIONS & GLOSSARY OF TERMS: ABS The American Bureau of Shipping AGIP Nigerian AGIP Oil Company Limited AIM the market of that name operated by the London Stock Exchange Assam block licence AS-ONN-2000/1 Bayelsa Bayelsa Oil Company Limited Board the Board of Directors Hardy Oil and Gas plc the Company Hardy Oil and Gas plc CPCL Chennai Petroleum Company Limited, formerly known as Madras Refinery Limited D3 licence KG-DWN-2003/1 awarded in NELP V D9 licence KG-DWN-2001/1 awarded in NELP III Dhirubhai 33 gas discovery on GS-01-B1 well Dhirubhai 39 gas discovery on KGV-D3-A1 well Dhirubhai 41 gas discovery on KGV-D3-B1 well DPR Nigerian Department of petroleum Resources Emerald Emerald Energy Resources Limited Eogas EOGAS Petroleum & Geosciences Nigeria Ltd. FDP field development plan FSO floating Storage and offloading vessel GAIL gas Authority of India Limited Ganesha gas discovery on Fan-A1 well located in CY-OS/2 GCA Gaffney, Cline & Associates Ltd. Group the Company and its subsidiaries GS-01 licence GS-OSN-2000/1 awarded under NELP II Hardy Hardy Oil and Gas plc HEPI Hardy Exploration & Production Inc HOEC Hindustan Oil Exploration Company Limited HON Hardy Oil Nigeria Limited IFRS International Financial Reporting Standards IPO initial public offering London Stock Exchange London Stock Exchange plc Main Market Official List of the London Stock Exchange's market for listed securities Millenium Millenium Oil and Gas Company Limited NELP New Exploration Licensing Policy of the Ministry of Petroleum and Natural Gas of India NNPC Nigerian National petroleum Company OML Oil mining licence ONGC Oil and Natural Gas Corporation Limited Ordinary Shares the ordinary share of US$ 0.01 each in the capital of the Company Phase III the PY-3 development plan comprising the drilling of two further wells one intended for production and one for water injection PSC production sharing contract PY-3 licence CY-OS-90/1 Reliance Reliance Industries Limited SPDC Shell Petroleum Development Company of Nigeria UK United Kingdom $ United States dollars 2D/3D two dimensional/three dimensional 2P proven plus probable API degrees American Petroleum Institute gravity AVO amplitude variations with offset bwpd barrels of water per day Contingent Resources those quantities of petroleum estimates, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to on or more contingencies DST drill stem test DWT dead weight tonne FDP field development plan GIIP gas initially in place GOR gas to oil ratio km kilometre km2 kilometre squared lkm line kilometre m metre MDRT measured depth from the rotary table MDT modular formation dynamics tester MMscfd million standard cubic feet per day MMstbd million stock tank barrels per day PSDM pre-stack depth migration psi pounds per square week scf standard cubic feet scfd standard cubic feet per day SPM single point mooring stb stock tank barrel stbd stock tank barrel per day TCF trillion cubic feet This information is provided by RNS The company news service from the London Stock Exchange END FR UUUGUCUPRPGB
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