10th Apr 2008 07:01
Hardy Oil & Gas plc10 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 productioncompany with interests in India and Nigeria, today announces its PreliminaryResults 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 ourassets. We have made an encouraging start in 2008 with the moving of our sharelisting from AIM to the Main Market of the London Stock Exchange and twodiscoveries on the D3 block. Our exploration success in India underpins our strategy to create shareholdervalue through high impact exploration interests and mitigating risk throughappropriate partnerships. 2008 will be an important year in our exploration,appraisal and development programmes and we look forward to it withanticipation." 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 theresults, after which the lines will be open for questions. For further information please contact Hardy Oil and Gas plc 020 7471 9850Sastry Karra (Chief Executive)Yogeshwar Sharma (Chief Operating Officer)Dinesh Dattani (Finance Director) Arden Partners plc 020 7398 1600Richard DayTom Fyson Buchanan Communications 020 7466 5000Mark EdwardsBen Willey Chairman's Statement Overview 2007 was another successful year for our growing company. The Board remainedfocused on executing the Company's strategy of creating shareholder valuethrough the de-risking of the Company's Indian exploration portfolio, whilstcontinuing production from its development assets. The year commenced with the announcement of the Ganesha discovery on theHardy-operated CY-OS/2 exploration block on the east coast of India. This wasfollowed by the announcement in May of the Dhirubhai 33 gas discovery on theGS-01 exploration block on the West Coast of India. The Company completed a further placing of new Ordinary Shares in June raisingover $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 consecutivediscoveries on the D3 exploration block on the east coast of India and theexpansion of the Company's exploration portfolio with the granting of apetroleum 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'sshares from AIM to the Official List of the London Stock Exchange's market forlisted securities ("Main Market"). The admission of Hardy's shares to the MainMarket should assist in increasing the profile and liquidity of the Company'sOrdinary Shares whilst increasing access to capital to fund its futureexploration and development expenditures. Hardy's shares began trading on the Main Market on 20 February 2008 and witheffect from 26 March 2008 Hardy's shares have been included in the FTSE 250indices. The senior executive team has been strengthened with the appointment of MrDinesh Dattani in July 2007 as Finance Director. Mr Dattani's strong financialbackground in the upstream oil and gas industry provides greater balance to theexecutive team. We will continue to look for appropriate additions to strengthenthe Board and the senior management team. Outlook We will continue to work closely with the Ministry of Petroleum and key industrygroups, in connection with the Government of India's recent intervention in gaspricing and proposed modification to the tax holiday, to help ensure that ourinterests and those of all operators in India are protected. Over the past decade the oil and gas industry in India, in partnership with theGovernment, has invested heavily in various midstream and upstream projects. In2008, the first gas production from the Reliance Industries Limited (Reliance)operated D6 block adjacent to the Company's D9 block in the Krishna Godavaribasin will commence and this will significantly increase the supply of gas intothe energy-constrained Indian market. The infrastructure and market developmentassociated with this east coast domestic gas supply augurs well for rapidexploration and development of the D3 and D9 blocks in the Krishna Godavaribasin in which Hardy has an interest. The Board looks to the balance of 2008 with great anticipation. In 2008, theCompany is planning for the largest drilling programme in its history with sixexploration wells and up to two appraisal wells. Our asset base has alsoincreased in India with the addition of the Assam block providing furtherlong-term growth potential. The Company is in excellent shape and we areenthusiastic 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 willbe further appraised in the latter part of 2008 and early 2009 with the drillingof three wells on the Fan-A discovery. The announced discovery of Dhirubhai 33 on the GS-01 block, with our partnerReliance, also contributed to the growth of our Contingent Resource inventory.An appraisal programme has been proposed by the operator and is currently underreview by the joint venture. Drilling of an additional three exploration wellswill commence in the second quarter of 2008 targeting several other independentprospects. The recent KGV-D3-A1 (Dhirubhai 39) and KGV-D3-B1 (Dhirubhai 41) gas discoverieson the D3 block are an encouraging start to evaluating the prospectivity of thisblock. We anticipate that the newly acquire 3D seismic will identify furtherdrilling 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 expectedincrease in the Government of India's profit oil share, a decrease in productionlevels and an increase in closing inventory. Net profit was $8.3 millioncompared to $10.2 million in 2006. The Company also realised a gain of $10.2million 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. Weanticipate that earnings will continue to fall in 2008 as PY-3 operating andGroup administrative costs have increased while production from PY-3 willdecline from 2007 levels. The active drilling programme in 2007 resulted in capital expenditures of $32.2million compared with $51.6 million in 2006. At the end of 2007, the Company had cash reserves of $31.2 million. In 2007, theCompany raised $40.2 million through a placing of 5,009,541 ordinary shares. TheCompany participated in an HOEC rights issue and also partially liquidated itsinvestment in HOEC resulting in a net addition to cash resources of $7.4 millionduring January 2008. India In 2007 the major focus of the Company was on the Hardy-operated assets, CY-OS/2exploration licence and PY-3 production block. PY-3 - Production from the PY-3 field was lower than expected in 2007 due to theshut-in of the PY-3-3RL well in August 2007. The drilling of two additionalwells (Phase III) is on-track but additional production from this drillingprogramme is not expected until 2009. CY-OS/2 - The Fan-A1 well discovery (Ganesha) was announced at the beginning ofthe year and the focus quickly turned to evaluating results and, subsequently,submitting an appraisal programme to the CY-OS/2 joint venture. The additionalgeological and geophysical work, along with well planning, remains a focus ofthe Group as we move into 2008. We are considering farming-out a portion of ourinterest to be more consistent with the risk profile of the Company's otherexploration assets. Results on our non-operated exploration assets have also been encouraging as wecontinue 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 tobe drilled under this exploration licence. The operator has submitted anappraisal programme which is awaiting approval. A further three explorationwells are scheduled to commence drilling in the second quarter of 2008. The assets that continue to generate the most interest and anticipation are theCompany's Krishna Godavari basin blocks D9 and D3. D9 - Due to the industry-wide shortage of drilling ships capable of operating inwater depths greater than 2,000 m, delays have been experienced on the D9exploration licence. We anticipate that drilling of the first well on the D9block may commence before the end of 2008. D3 - The drilling phase on D3 began much sooner than expected with thecommencement of drilling of the first well at the end of 2007. Subsequently wewere pleased to announced two successive gas discoveries on the block withencouraging initial testing results including an observed flow rate of 38.1MMscfd. We anticipate that the operator will submit an appraisal programme forapproval shortly. Further drilling on the D3 block is not expected to commenceuntil the first quarter of 2009 as the joint venture evaluates the additional2,800 km2 of 3D seismic acquired in 2007. Assam - As announced on 3 April 2008, the pursuit of our Indian strategyresulted in the award of the Assam onshore petroleum exploration licenceAS-ONN-2000/1. We are also delighted with the Company's continued partnershipwith Reliance. This is the fourth block that Hardy holds in partnership withReliance and the Company's first onshore asset in India. The block providesfurther 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 wellflow test of Oza-4. The initial results are positive and, more importantly, theoperator received cooperation and support from the local communities. We haveestablished open channels of dialogue with all stakeholders in the Ozacommunities and we look for this to continue as we move towards initial fielddevelopment in the latter part of 2008. As announced on 3 April 2008 the Company entered into an agreement to farm-out a20 per cent. interest in the Oza block to Emerald Energy Resources Limited(Emerald). Emerald has agreed to assume Hardy's financial obligations in thefunding of the Oza field initial development programme. Atala - Securing the necessary equipment for the planned re-entry operating inAtala continues to be difficult. The Company's Nigerian management team havebeen working closely with a consortium of swamp operators. This group hasseveral options available to them and we anticipate that greater clarity on thetiming 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 tocreate shareholder value. The NELP rounds have become increasingly competitive;however, they still offer the most direct way of acquiring exploration acreagein India. Staff The accomplishments of 2007 would not have been possible without the dedicationof the Company's staff in India, Nigeria and London, UK. The India teamcontinues to drive the core of our business. The Nigerian team have reached akey milestone in 2007 despite challenging conditions. The corporate team inLondon, along with the India team in Chennai, were instrumental in the efficientexecution of the Main Market listing. I would like to take this moment torecognise 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 threeexploration wells, the production testing of one well and the acquisition of2,800 km2 of 3D seismic. During 2007, and as part of the process of moving the Company to the MainMarket, an independent report was prepared for the Company by Gaffney, Cline &Associates Ltd (GCA) on the reserves and resources inventory of the Company. Asat 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 ownedsubsidiary Hardy Exploration & Production Inc. (HEPI). The Company's operationsin Nigeria are conducted through its wholly owned subsidiary Hardy Oil NigeriaLimited (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 percent. (2006: 96.7 per cent.). The decrease in production was attributable to theseizure of the PY3-3 RL well, due to water loading, in August 2007 and thefailure of the Endeavor's (FSO) mooring system in December 2007 (resulting in 11days' shut-in). The production forecast for 2008 is 2,700 stbd, reflecting the expectedcontinued natural decline of the field. In 2008, around 10 days' downtime isanticipated due to the need to carry out under water inspection and maintenancework 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 5,800bwpd (2006: 6,678 bwpd) which, at current production levels, is sufficient tomaintain voidage replacement. Injection facilities' uptime performance was 86.8per cent. (2006: 96.7 per cent.). The reduction in uptime was attributable tothe scheduled plant shutdown in March 2007 for further the under waterinspection 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 developmentprogramme which provides for the drilling of two additional lateral wells (oneproducer and one injector) and various gathering lines and facility upgrades.The Company has issued a request for tender for long-lead items such as subseatrees and flow lines. In order to identify a suitable production facility for the operation of thePY-3 field beyond July 2009, Hardy commissioned a Conceptual Field Design studythat was undertaken by ODE Ltd, UK. Based on the recommendations obtained fromthe ODE study, further investigations are in progress to select a suitableproduction facility. Background The PY-3 field is located off the East Coast of India 80 km south of Pondicherryin water depths of between 40 and 200 m. The Cauvery basin developed in the lateJurassic/early Cretaceous period, and straddles the present-day East Coast ofIndia. The licence, which covers 81 km2, is currently the deepest producing subseafield in India and produces oil of high quality light crude (49degrees API). Thefield was developed using floating production facilities and subsea wellheads, afirst for an offshore field in India. HEPI is the Operator of the PY-3 field, and the participating interests for thislicence are as follows: HEPI TATA HOEC ONGC 18% 21% 21% 405 The facility at PY-3 consists of the floating production unit, ''Tahara'', and a65,000 DWT tanker, ''Endeavor'', which acts as a floating storage and offloadingunit. There are four sub-sea wells tied back to Tahara. Tahara has a three-stagecrude oil separation system, with the first two stages being three-phaseseparators and the third stage a two-phase separator. Actual liquid processingcapacity 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. Thisproduced gas is used as fuel gas, with excess gas being flared. The stabilisedcrude oil is pumped from Tahara to Endeavor for storage and offloading toshuttle tankers. Crude oil from the PY-3 field is sold to CPCL at its refineryin 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 workprogramme. On 8 January 2007 the Company announced that the Fan-A1 well haddiscovered hydrocarbons. On 10 August 2007 the Company announced that it wouldproceed with an appraisal programme to delineate the Cretaceous Fan-A1 discoveryto establish the potential commerciality of the Cretaceous with the planneddrilling of three further wells. As part of the appraisal programme a number of geological and geophysicalstudies have been undertaken, including the reprocessing of the 3D seismic datacovering the block to improve subsurface imaging. Special studies such as AVOand inversion are ongoing to improve characterisation and delineation of thereservoir. Analysis of oil and gas crude samples and other well data from the Fan-E1 andFan-A1 wells were also undertaken in 2007, including geochemical studies. HEPI has recently hired a third party to begin the well planning work and toprovide well management services and consultation through the entire appraisaldrilling programme. Subject to rig availability, the drilling portion of theappraisal programme is expected to start in the fourth quarter of 2008. The Board is presently considering farming out a portion of its participatinginterest in the licence. Background The CY-OS/2 block is located in the northern part of the Cauvery Basinimmediately offshore from Pondicherry and covers approximately 859 km2. TheCY-OS/2 licence comprises two retained areas. The northern area includes theFan-A1 discovery. The southern area lies immediately adjacent to the HEPIoperated PY-3 field. The PY-1 gas field lies within the southern part of theacreage and is expected to begin production by the first quarter of 2009. HEPI is the operator of this licence. The participating interests in licenceCY-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 theCY-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/2licence but have been ring-fenced out, each with a separate PSC. The CY-OS/2exploration licence has been under an approved phase III extension which expiredat the end of March 2007. HEPI, as operator of the joint venture, has fulfilledthe exploration phase III commitment work programme of 3D seismic surveys anddrilling 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-01block. On 15 May 2007 Hardy announced that the second exploration well,GS-01-B1, had discovered hydrocarbons in the mid-Miocene Limestone (Dhirubhai33). The exploration well was drilled to a depth of 2,282 m MDRT and encounterednatural gas and condensate within the mid Miocene Limestone over an intervalfrom 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 2,019m to 2038 m MDRT respectively. The test produced natural gas at a rate of 18.6MMscfd together with 415 stbd of condensate through a 56/64 " choke with aflowing tubing head pressure of 1,346 psi. The operator has subsequently proposed an appraisal programme involvingadditional 3D seismic data interpretation, development concept studies, reserveassessment and validation, and two contingent appraisal wells. The appraisalwells will be dependent on the findings of the proposed studies. The proposed exploration programme for 2008 comprises of the acquisition of anadditional 1,000 km2 of 3D seismic and the drilling of three further explorationwells which will meet the phase I work commitment for the exploration licence.The 3D seismic acquisition programme was completed in March 2008 covering 1,165km2 and processing and interpretation is expected to be fast-tracked by theoperator. The three-well drilling programme is expected to commence by the endof April 2008. In 2008, the GS-01 joint venture will be required to elect to proceed to phaseIII of the exploration licence or relinquish the block not covered by theappraisal programme. The minimum work programme for phase III stipulates thedrilling of eight exploration wells. Background The GS-01 exploration licence is located in the Gujarat-Saurashtra offshorebasin, off the west coast of India, directly adjacent to the prolific BombayHigh oil field. The licence encompasses 8,841 km2, and water depths vary between80 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 RelianceGS-01 10% 90% Typical trap types within this basin are fault-bound anticline and stratigraphiccarbonate traps (including reefal structures and carbonate build-ups). Theidentified prospects are located in the Miocene, Oligocene and Eocene carbonatesand 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 ofthe current equipment shortage and the priority of the operator to completeoffsetting commercial developments, the Board is of the view that drilling onthe D9 licence is unlikely to commence until the latter part of 2008. However, as experienced with the D3 licence, windows of availability do occurand the Directors will endeavour to ensure that shareholders are notified ofdevelopments on a timely basis. During 2007, the operator continued to interpret and evaluate the 3D seismicdata. PSDM reprocessing 3D seismic data was completed and the data is beingstudied to optimise the selected locations for drilling. Sea-bed logging wasalso conducted and the results provided encouraging results with similarindicators observed in the adjacent D6 block. Background The licence encompasses 11,605 km2 in the Bay of Bengal where water depths varyfrom 2,300 m to 3,100 m. The participating interests for this licence are asfollows: Area HEPI RelianceD9 10% 90% The joint venture has acquired over 4,188 km2 of 3D seismic and leads at UpperMiocene, Middle Miocene and Oligocene have been identified. These leads areareally large structural closures located toward the, relatively shallower-waternorth-western corner of the concession, for which GIIP of many TCF has beencomputed by the operator. A fourth lead is a Pleistocene channel in the southeastern part of the block which is in ultra deep water with a prognosticatedGIIP of a similar order of magnitude to the other leads. Initial exploration will be focused upon amplitude anomalies within closure inthe Miocene and Pliocene rather than a pure structural play. There are manyseismic anomalies within the block and, given its proximity to D6, explorationpotential 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 venturehas also taken the decision to process and evaluate the acquired data prior toacquiring additional data with the intention of modifying the acquisitionparameters to optimise the data quality. The exploration drilling programme commenced earlier than expected on 28December 2007, with the KGV-D3-A1 well which has resulted in the first discoveryon this licence named Dhirubhai 39. The well was drilled to a depth of 1,937 mMDRT and encountered natural gas between 1,513 m and 1,597 m MDRT with a grosssand thickness of 84 m. One interval was selected for cased hole DST covering 1,565 m to 1,585 m MDRTand 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 sandstonereservoirs. On 1 April 2008, the Company announced a second discovery (Dhirubhai41) on the D3 block. The well encountered good quality reservoirs in thePleistocene and Miocene formations. MDT tests were conducted over severalintervals (1,814 to 2,101 m MDRT and 2,119 to 2,463 m MDRT) and confirmed thepresence of hydrocarbons. Several gas samples were collected over both intervalshowever due to poor well bore casing integrity, a decision was taken to notconduct a DST and the well was plugged and abandoned. Although early indications are encouraging, the potential extent andcommerciality 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 thedetails of the tests carried out. It is anticipated that the operator willsubmit 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 licencein the deepwater Krishna Godavari Basin. The D3 licence encompasses an area of3,288 km2, in water depths of 400 m to 2,100 m, and is located approximately 45km from the east coast. Reliance is the operator. The participating interestsfor this licence are as follows: Area HEPI RelianceD3 10% 90% The licence had approximately 410 km2 of existing 3D seismic data, which hasbeen reprocessed. The A-1 and B-1 locations were identified after this data wasinterpreted 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 inthe exploration licence AS-ONN-2000/1. This is the Group's first onshore blockand fourth licence in partnership with Reliance. This block was offered in NELPII but commencement of operations had been delayed due to the outstanding grantof an onshore petroleum exploration licence from the appropriate state agencies. The proposed 2008 work programme primarily involves the reprocessing of the 124line km (lkm) of existing 2D seismic data. Field operations are expected tocommence in the fourth quarter of 2008 with the acquisition of approximately 350lkm of 2D seismic data. This will meet the phase I minimum work programmecommitment for the block. Background The AS-ONN-2000/1 exploration licence is located in the north eastern state ofAssam, India, and north of Brahmaputra River. The exploration licence covers anarea of 5,754 km2 and falls within the districts of Darrang and Sonitpur. Theblock is in phase I of the three-phase exploration licence. Phase I is overthree years and will expire in the month of January 2011. The participatinginterests for this licence are as follows: Area HEPI RelianceAssam 10% 90% The topography of the area is primarily plain of low relief and there is areasonably established road network across the block. A national highway runsparallel 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 liesnorth of Brahmaputra River while most of the discovered oilfields in the basinare located south of Brahmaputra River over an area of approximately 4,000 km2. Intense exploration activities since 1956 have resulted in the discovery ofseven major fields which include Naharkatiya, Moran, Rudrasagar, Geleki andLokwa. Most of these fields have reached a mature stage of exploration forMio-Pliocene reservoirs and are in the advanced phase of delineation anddevelopment. Very limited seismic data is available only in the eastern-most part of theblock and suggests the presence of subsurface structure. Different play typesexpected 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 theOza 4 well. Oil and gas production rates, reservoir pressures and crude sampleswere obtained during the test. This is a significant step towards fulldevelopment of the field. As technical partner, HON has worked closely with theoperator to design and implement the field operation. The flow rates averagedapproximately 600 stbd of oil with a GOR of 5,466 scf/stb. The operatortransported 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 concludeagreements for crude handling and purchase of Oza 3D seismic with ShellPetroleum Development Company (SPDC). Discussions are ongoing with the operator of an adjacent export facility at anear-by flow station. Current discussions suggest that the initial workprogramme will entail the installation of a 9 km multiphase pipeline to SPDC'sIsimiri flow station. To comply with the Nigerian government's no-flareinitiative, associated gas will need to be exported to an alternative facilitywith a gas export line. Recently HON has entered into a farmout agreement with Emerald Energy ResourcesNigeria Limited (Emerald), a well-known local oil and gas company. Under theterms of the farm-out agreement Emerald assumes HON's obligation to fund theinitial work programme of the Oza field. The capital expenditure is currentlyestimated at approximately $15 million. The farm-out is subject to governmentapproval. Community relations will continue to be a focus of the operator and progress isexpected in discussions regarding a sustainable agreement with the hostcommunities surrounding the Oza field. Emerald has extensive experience andexpertise in community relations and has committed to make available itsexperienced personal to the operator. Background The Oza Field is located on-land in the north-western part of OML 11, near PortHarcourt. The concession area is 20 km2. The participating interests for thislicence are as follows: Area HON Millenium EmeraldOza 20% 60% 20% The Oza field is subject to a farm-out agreement between NNPC, SPDC, ElfPetroleum Nigeria Limited and AGIP as farmor and Milennium as farmee. The termsof this agreement are for an initial five year period from 27 April 2004 subjectto an extension of the Oza Farm-out Agreement if approved by the NigerianDepartment of Petroleum Resources (DPR). The field has cumulatively produced approximately 1.0 MMstb from four open zonesof three wells targeting three reservoirs, M5.0, L9.0 and M2.1, with theprincipal reservoir being M5.0. At present, Oza has three suspended wells in thefield. Since taking over the field in 2004, Millenium, along with HON, has completed anumber of field operations and other studies. The log data of existing wells hasbeen re-analysed both internally and through third party study to identifypotential re-completion targets. There is existing 3D seismic data covering theOza field. Negotiations between SPDC and Millenium for the acquisition of thisdata 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 appropriatedrilling equipment for a planned re-entry and test programme. The operator, withthe help and support of Hardy, has taken the initiative to form a swampoperators group, comprising of several companies with fields in the swamps tocollectively approach potential drilling companies with suitable rigs. Meetingswere held in the latter half of 2007 and potential vendors have been identified. During 2007, a field development plan (FDP) report was completed by localconsultant Eogas with close involvement and inputs from HON. The FDP recommendsa phased approach, initially focusing on oil development with later completionfor gas production and based on initial production from the two wells, drillingof new oil and gas wells. Recently the swamp operators group has identified and commenced negotiationswith several vendors for a swamp barge. It is expected that a rig will beidentified and a contract negotiated in the latter half of 2008 and the Atalaoperations may commence in the first quarter of 2009, with the re-entry ofAtala-1 well. HON is working closely with the operator to finalise the re-entryprogramme, obtain government approvals, appoint competent company forprocurement, logistics and rig management and ensure all long lead items areprocured in timely fashion. The Atala FDP has been presented to the federalgovernment for its approval. Background Atala is located within OML 46 which is located in a mangrove swamp on the DodoRiver, a coastal area of NW Bayelsa State. The concession area is 34 km2. TheAtala field was discovered in 1982 with the drilling of the Atala-1 well to atotal depth of 4,058 m. Hydrocarbons were encountered and the well was cased butnot tested or completed. The participating interests for this licence are asfollows: Area HON Millenium EmeraldAtala 20% 60% 20% The Atala field is subject to a farm-out agreement between NNPC, SPDC, ElfPetroleum Nigeria Limited and Nigerian AGIP Oil Company Limited as farmor andBayelsa as farmee. The terms of this agreement are for an initial five-yearperiod from 27 April 2004, subject to an extension of the term of the AtalaFarm-out Agreement if approved by the Nigerian Department of PetroleumResources. HON entered into a farm-in agreement with Bayelsa pursuant to which Bayelsaagreed to farm out a 20 per cent. participating interest in the Atala field toHON. HON also agreed to act as technical partner for the development andoperation of the Atala field. The proposed development plan involves two phases. The first phase envisages there-entry, testing and completion of the existing Atala-1 well and the drillingof a second lateral well to optimise oil drainage. AGIP operated Clough Creekfield 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 ReportingStandards ("IFRS") for accounting periods commencing 1 January 2007. In order to comply with IFRS, Hardy has restated consolidated and companyfinancial statements for 2006 and has revised its accounting policies. Hardy hasalso prepared a reconciliation of its consolidated and company financialstatements under UK GAAP to those prepared under IFRS. In addition, Hardy hasprepared 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 entitlementbasis)) 573 844Average realised price per barrel - Dollars 66.65 64.82Average cost per barrel - Dollars 21.19 13.64Revenue (thousands of Dollars) 11,830 21,317Net profit (thousands of Dollars) 8,316 10,233Cash flow from operations (thousands of Dollars) * 2,588 14,555Diluted earnings per share - $ 0.13 0.17Wells 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 5,811Gross Field 747 1,046Participating Interest 573 844Net Entitlement InterestSales (Barrels of Oil per Day) 3,547 5,831Gross Field 638 1,050Participating InterestAverage 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 centparticipating interest. Since August 2007, one of the three producing wells inthe PY-3 field has been shut in due to excessive water production. As a resultof 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 levelof approximately 3,050 stbd. The Company does not expect to recover additionalproduction until the implementation of the PY-3 field's Phase III development. Hardy's net entitlement interest in production is after the Government ofIndia's share of profit oil. Under the terms of the PSC, profit oil increasedfrom 10 per cent to 25 per cent effective 1 April 2005 and was further increasedto 40 per cent on 1 April 2006. On 1 April 2008, profit oil is expected toincrease to 50 per cent. Revenue, after profit oil, declined from $21.3 million in 2006 to $11.8 millionin 2007. The average price realised per barrel increased marginally to $66.65during 2007. No sales took place during the fourth quarter of 2007 and allproduction during that period was held in inventory. Reduced revenue in 2007resulted from lower production levels, higher inventory levels and higher profitoil to the Government of India. Cost of Sales Cost of sales for 2007 increased by $0.6 million during 2007. This resultsprincipally from higher costs of operating the PY-3 field. The contract for thefloating processing and storage systems was renegotiated effective July 2007resulting in a substantial increase in day rates. The increase in operating costwas 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; thereduction principally stemming from lower revenues and higher operating costsfrom July 2007. Other Operating Income An insurance claim of $1.0 million was received for business interruption causedby an operational accident in the year 2002. This has been accounted for asother operating income in 2006 when insurance proceeds were received. Administrative Expenses Administrative expenses increased from $5.7 million in 2006 to $6.9 million in2007. The increase principally results from a higher share based payment expenseby $0.9 million for the stock options granted by the Company to its directorsand employees since 2005. During 2007, costs include those relating to the movefrom AIM to the Main Market, higher manpower costs with the addition of anadditional 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 comparedwith 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 acash consideration of $12.5 million which was received in January 2008. As aresult, the Company recorded a gain on sale of investment of $10.2 million. Theafter-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 millionin 2007. The decline was the result of reduced deposits and lower interest ratesin 2007 compared to 2006. Finance Costs Finance costs principally include the cost of providing bank guarantees to theGovernment of India required in accordance with the provisions of ProductionSharing 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 taxessince the Company's capital expenditure programme is sufficient to shield theCompany from a large portion of current tax liabilities. The group's Indianoperations 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 capitallosses by way of group relief for the capital gain made in sale of investment inHOEC shares. Net Profit As a result, net profit declined from $10.2 million in 2006 to $8.3 million in2007. 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 resultsprincipally from lower revenues arising from lower production volumes and higherprofit 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 wasreceived in January 2008) as a result of lack of sales in the fourth quarter of2007 and a significant reduction in creditors. At the end of 2006, the Companywas in the process of drilling a well on its CY-OS/2 block in which it has a 75per cent. participating interest. Capital Expenditures The Group's capital expenditures amounted to $32.2 million during 2007, comparedto $51.6 million incurred during 2006. Capital expenditures amounting to $21.9million were incurred on the CY-OS/2 block with the drilling of the successfulFan-A1 well. The Company expended $4.2 million with respect to its interest inthe GS-01 block with the drilling of the B-1 discovery well. Expenditures on theD3 block amounted to $4.6 million with the acquisition of 2,800 km2 of 3Dseismic and the commencement of the drilling of the first well on 28 December2007. Approximately $1.0 million was incurred with respect to the Company'soperations in Nigeria, principally with respect to the testing of a well in Ozaand 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 theCY-OS/2 block. As of 31 December 2006, Hardy had invested $59.5 million for itsshare of the drilling and testing of the two wells which included costsassociated with the side track of the second well. In 2006, Hardy alsoparticipated in the drilling of the A-1 well on the GS-01 block. In the KrishnaGodavari Basin on the east coast of India, 3,440 km2 of 3D seismic data has beenacquired over the D9 block during 2006, which has now been processed andinterpreted, 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 inPY-1 (a gas discovery adjacent to PY-3 and ring-fenced by the CY-OS/2exploration licence). In October 2006, HOEC raised approximately $33.0 millionvia a public rights issue in which Hardy took up its pro-rata entitlement at acost of $2.8 million. In December 2007, the Company sold 3,010,000 shares of HOEC for a cashconsideration of $12.5 million. In early January 2008, HOEC completed a rightsoffering with Hardy participating in the rights offering to the extent of itspro rata share investing an additional $13.2 million. In January 2008, theCompany sold a further 1,971,411 shares for a cash consideration of $8.1million. At the present time, the Company has 6,114,745 shares representing 4.7per cent. equity in HOEC. Based on the market value of Rs.134 per share on 8April 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 siterestoration of the PY-3 field. Of this amount, $2.8 million was placed in 2006with 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 cashis invested in short-term deposits generating investment income on a regularbasis. The level of such income was reduced from $2.4 million in 2006 to $1.3million due to reduction in deposit and lower interest rates during 2007. Finance Costs Finance costs essentially represent the cost of bank guarantees provided to theGovernment of India in connection with annual work programmes in India. Equity Financings The Company undertook its initial public offering (IPO) of ordinary shares on 7June 2005 when its shares commenced trading on AIM. The IPO was successfullycompleted 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 anadditional 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 asignificant amount of cash resources to fund its ongoing capital expendituresand work programmes. Total cash increased from $24.5 million at the end of 2006to $31.2 million at the end of 2007. The Company does not have any long-termdebt. Summary Balance Sheets Hardy has continued to grow during 2007. Its non-current assets have increasedfrom $89.1 million at the end of 2006 to $121.4 million at the end of 2007. Thisresults largely from the capital expenditure programme on explorationexpenditures, principally on the drilling of wells on CY-OS/2 and GS-01 blocksas well as expenditure on seismic acquisition. Current assets represent the Group's cash resources, together with trade andother receivables and inventory. At the end of 2007, of the $48.4 million ofcurrent assets, $31.2 million is represented by cash, generated principally fromthe equity issue that was completed in June 2007. The accounts receivable at theend of 2007 included $12.5 million from the sale of shares in HOEC which werereceived in January 2008. Current liabilities are principally trade and other accounts payable. The levelof current liabilities fluctuates significantly depending upon the timing ofcapital programmes. At the end of 2006, the Company was in the process ofdrilling a well on its CY-OS/2 operated block, resulting in a significantincrease in payables. At 31 December 2007, the accounts payable were reduced tomore 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 atthe end of 2007. The increase in the carrying value of net assets results from acombination of new equity placements, earnings that have been retained in thebusiness and the impact of valuation gains with respect to its investment inHOEC. Liquidity and Capital Resources Hardy has been funding its cash requirements from internally generated cashflows and equity capital, principally from institutional investors, in each ofthe years 2005, 2006 and 2007. The Company continues to be an emerging companywith limited cash flows, and as a result, has been principally relying uponequity capital markets to build and grow its asset base. At 31 December 2007, the Company had cash resources of approximately $31.2million 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 whichhas augmented its cash resources and working capital. At 8 April 2008, theCompany's remaining investment in HOEC is worth $20.5 million which if requiredcan be made available to further augment the Company's cash resources andworking capital during 2008. The Company is presently considering farming out a portion of its participatinginterest of 75 per cent. in the CY-OS/2 block. The Company's plans provide forthe drilling of three appraisal wells on the block and the farm-out isanticipated to contribute towards the Company's commitments with respect to itsappraisal programme. At the present time, the Company does not have any short-term or long-term debt,nor does it presently have any bank facilities in place. The Company presentlyproduces from the PY-3 field in India. The Company believes that it may bepossible to secure financing on the strength of this producing block in thefuture. Base on present plans, the Company believes it has adequate financial resourcesto fund its capital expenditure requirements for 2008. Dividends The Company has limited internally generated cash flows and has a significantplanned capital expenditure programme. In the circumstances, the Board ofDirectors has chosen to reinvest cash flows and does not recommend the paymenton a dividend in the foreseeable future. Unaudited Preliminary Statement The preliminary statement of results is unaudited. The Directors anticipate thatthe Group's auditors, Horwath Clark Whitehill LLP, will present an unmodifiedaudit opinion on the financial statements of the Group. Dinesh Dattani FCA Finance Director 9 April 2008 HARDY OIL AND GAS plc Consolidated Income Statement For the year ended 31 December 2007 -------------------------------- ------ --------- --------- 2007 2006 Notes US$ US$ -------------------------------- ------ --------- --------- Revenue 2 11,829,554 21,316,935 Cost of salesProduction 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 16,125,039Other operating income - 1,000,000Administrative expenses (6,865,187) (5,700,416) -------------------------------- ------ --------- ---------Operating (loss) / profit (813,269) 11,424,623Gain on sale of investment 10,243,729 -Interest and investment income 1,381,121 2,288,954Finance 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 shareholdersof the parent company 8,315,978 10,232,768-------------------------------- ------ --------- --------- Earnings per shareBasic 4 0.14 0.18Diluted 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 8,194,489 283,578Unrealized valuationgain/(loss) 3,514,603 (6,910,257) 3,514,603 (6,910,257)Deferred taxasset/(liability) onunrealised valuationgain or loss (966,780) 1,934,872 (966,780) 1,934,872------------------ --------- --------- --------- ---------Total recognisedgains/(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 24,527,092Share 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$ ------------------ ------ --------- --------- --------- ---------AssetsNon-current assetsIntangible assets- exploration 99,284,534 67,216,281 - -Intangible assets- others 246,572 217,198 21,835 65,582Property, plantand equipment 3,375,463 5,064,070 140,927 177,859Investments 15,092,311 13,836,910 74,974,386 40,491,141Site restorationdeposit 3,369,820 2,784,660 - ------------------- ------ --------- --------- --------- --------- 121,368,700 89,119,119 75,137,148 40,734,582 Current assetsInventory 2,703,915 2,729,764 - -Trade and otherreceivables 14,525,440 4,637,062 12,689,331 251,931Cash and cashequivalent 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------------------ ------ ---------- --------- --------- --------- LiabilitiesCurrent liabilitiesTrade and otherpayables (9,857,909) (16,809,807) (567,396) (153,782)------------------ ------ ---------- ---------- ---------- --------- Non-current liabilitiesProvision fordecommissioning (4,500,000) (4,500,000) - -Provision fordeferred 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------------------ ------ ---------- ---------- ---------- --------- EquityCalled-up sharecapital 6 622,625 572,530 622,625 572,530Share premium 93,101,579 52,982,983 93,101,579 52,982,983Shares to beissued 2,501,590 940,093 2,501,590 940,093Other reserves 8,912,532 6,364,709 8,912,532 6,364,709Retained 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 activitiesCash flow fromoperating 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 activitiesExpenditure onintangible assets-exploration (32,068,253) (51,034,004) - -Expenditure onproperty, plant andequipment (147,297) (148,215) - -Purchase ofintangible 5,856 (176,972) - (4,500)fixed assets - otherPurchase of otherfixed (38,753) (247,992) (11,731) (47,938)assetsSale/(purchase) ofinvestment - (2,778,914) - (2,778,914)Site restorationdeposit (585,160) (2,784,660) - ------------------- ------ --------- --------- --------- ---------Net cash (used in)investing activities (32,833,607) (57,170,757) (11,731 (2,831,352) Financing activitiesInterest andinvestment 1,293,104 2,376,072 3,726,459 2,075,877incomeFinance 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 fromfinancing 41,281,395 26,627,736 10,894,856 5,108,773activities Net increase/(decrease)in cash and cash 6,666,109 (6,743,437) 9,152,974 (41,468)equivalents Cash and cashequivalents at thebeginning of the year 24,490,939 31,234,376 19,318,159 19,359,627 ------------------ ------ --------- --------- --------- ---------Cash and cashequivalents at theend 31,157,048 24,490,939 28,471,133 19,318,159of the year ------ --------- --------- --------- --------------------------- 1. Accounting Policies The following accounting policies have been applied in preparation ofconsolidated financial statements of Hardy Oil and Gas plc ("Hardy" or the"Group"). a) Accounting standards Hardy prepares its financial statements in accordance with InternationalFinancial Reporting Standards (IFRS) and interpretations issued by theInternational Accounting Standards Board as adopted by the European Union. Hardy adopted IFRS for the first time in the financial year which ended on 31December 2007. The adoption of these standards and interpretations has resultedin changes to the Hardy's accounting policies. The effect of the adoption ofIFRS 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 followingstandards 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 fundingrequirements 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 infuture 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 Gasplc and its subsidiary undertakings. The consolidated income statement andconsolidated cash flow statements include the results and cash flows ofsubsidiary undertakings up to the date of disposal. The group conducts the majority of its exploration, development and productionthrough unincorporated joint arrangements with other companies. The consolidatedfinancial statements reflect the group's share of production and costsattributable to its participating interests under the proportional consolidationmethod. The Company has taken advantage of the exemption provided under section 3 of theIsle of Man Companies Act 1982 not to publish its individual income statementand 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 theprofit oil sold and paid to the Government as a part of profit sharing in theyear, tariff, and income from technical services to third parties if any.Revenues are recognized when crude oil has been lifted and title has been passedto 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 directlyattributable to the acquisition, exploration and appraisal having regard to therequirements of IFRS 6 "Exploration for and Evaluation of Mineral Resources" areaccumulated and capitalized in two geographical cost pools, which are not largerthan a segment: India and Nigeria. The capitalized exploration and evaluation costs are classified as Intangibleassets - exploration which includes the license acquisition, exploration andappraisal costs relating either to unevaluated properties or properties awaitingfurther evaluation but do not include costs incurred prior to having obtainedlegal right to explore an area, which are expensed directly to the incomestatement as they are incurred. Intangible exploration and evaluation cost relating to each license or blockremain capitalized pending a determination of whether or not commercial reservesexists. Commercial reserves are defined as proven and probable on a netentitlement basis. When a decision to develop these properties is taken or there is evidence ofimpairment, the costs are transferred to the cost pools within development/producing assets when the commercial reserves attributable to the underlyingasset 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 puttingthem on production and the exploration and evaluation costs transferred fromintangible exploration and evaluation assets as stated in policy above. Inaddition, interest payable and exchange differences incurred on borrowingsdirectly attributable to development projects if any and assets in theproduction phase as well as cost of recognizing provision for future restorationand decommissioning are capitalized. iii) Decommissioning At the end of the producing life of a field, costs are to be incurred inremoving, decommissioning facilities, plugging and abandoning wells.Decommissioning costs are estimated and stated at an amount representing thecosts, which would be incurred should decommissioning occur at the balance sheetdate and the estimates are reassessed each year. The provision is assessed atprices ruling at the balance sheet date and, accordingly, it is not appropriateto discount this provision. The decommissioning asset is included within thetangible fixed assets with the cost of the related assets installed and areadjusted for any revision to the decommissioning costs and the provisionthereof. The amortization of the asset, calculated on a unit of production basisbased on proved and probable reserves, is shown as "Decommissioning charge" inthe income statement. iv) Disposal of assets Proceeds from any disposal of assets are credited against the specific tangibleor intangible capitalized costs included in the relevant cost pool and any lossor gain on disposal is recognized in the income statement. Gain or loss arisingon 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 fieldbasis using the unit of production method, based on proved and probable reservestaking into consideration future development expenditures necessary to bring thereserves into production. Hardy periodically obtains an independent third partyassessment 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 costpool and depleted on unit of production. In cases where no such development/producing cost pool exists, the impairment of exploration costs is recognized inthe income statement. Impairment reviews on development / producing oil and gasassets for each field is carried out on each year by comparing the net bookvalue of the cost pool with the associated discounted future cash flows. Ifthere is any impairment in a field representing a material component of the costpool, an impairment test is carried out for the cost pool as a whole. If the netbook value of the cost pool is higher, then the difference is recognized in theincome statement as impairment. e) Property, plant and equipment Property, plant and equipment other than oil and gas assets are measured at costand depreciated over their expected useful economic lives as follows: Annual Rate (%) Depreciation -------------------- ------------ Method ---------------Leasehold improvements over lease Straight line periodFurniture and fixtures 20% Straight lineInformation technology and computers 33% Straight lineOther equipment 20% Straight line-------------------- ------------ --------------- f) Intangible assets Intangible assets other than oil and gas assets are measured at cost anddepreciated 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 andare recognized at fair values based upon the quoted market prices on the balancesheet date. Unrealized gains and losses are recognized under equity - otherreserves. On disposal of an investment, the cumulative gain or loss isrecognized in the income statement. Investments in subsidiary companies arecarried 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. Averagecost is determined based on actual production cost for the year. Inventories ofdrilling stores and are accounted at cost including taxes duties and freight.Provision is made for obsolete, or defective items where appropriate based ontechnical evaluation. i) Financial instruments Financial assets and financial liabilities are recognized at fair value ongroup's balance sheet based on the contractual provisions of the instrument. Trade receivables do not carry any interest and are stated at their nominalvalue 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 proceedsafter 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 profitdiffers from net profit as reported in the income statement as it excludescertain item of income or expenses that are taxable or deductible in years otherthan the current year and it further excludes items that are never taxable ordeductible. The current tax liability is calculated using the tax rates thathave been enacted or substantively enacted by the balance sheet date. Deferred tax is the tax expected to be payable or recoverable on differencesbetween the carrying amounts of assets and liabilities in the financialstatements and the corresponding tax bases used in the computation of taxableprofit, and is accounted for using the liability method. Deferred income tax liabilities are recognized for all taxable temporarydifferences and deferred tax assets are recognized to the extent that it isprobable that taxable profits will be available against which deductibletemporary differences can be utilized. Deferred income tax liabilities are recognized for all temporary differencesexcept in respect of taxable temporary differences associated with investment insubsidiaries, associates and interest in joint ventures where the timing of thereversal of the temporary differences can be controlled and it is possible thatthe temporary differences will not reverse in the foreseeable future. Deferred tax is recognized in respect of all temporary differences that haveoriginated but not reversed at the balance sheet date where transactions orevents have occurred at that date that will result in an obligation to pay moreor a right to pay less or to receive more tax. Deferred tax assets and liabilities are measured on an undiscounted basis at thetax rates that are expected to apply in the periods in which temporarydifferences reverse, based on tax rates and laws enacted or substantivelyenacted at the balance sheet date. l) Foreign currencies Hardy maintains its accounts and the accounts of its subsidiary undertakings inUS dollars. Foreign currency transactions are accounted for at the exchange rateprevailing on the date of the transaction. At the year end, all foreign currencyassets are restated at the average of the buying and the selling exchange ratesprevailing at the balance sheet date. Exchange difference arising out of actualpayments / realizations and from the year end restatement are reflected in theincome statement. Rates of exchanges are as follows: ----------------- --------------- --------------- 31 December 31 December 2007 2006 --------------- ---------------- -----------------£ to US$ 1.9828 1.9658US$ 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 ofdecommissioning that will arise at some point in the future. Significant changesin costs or technological advancement could result in a material change to thisprovision. ii) Depletion Depletion calculations are based on the best estimate of commercial reservesexisting as at the balance sheet date. The determination of commercial reservesis based on assumptions which include those relating to the future price ofcrude oil, capital expenditure plans and the costs of production. Any changes inthese assumptions could result in a material change in the depletion charge orthe carrying value of associated assets. n) Leasing commitments Rental charges or charter hire charges payable under operating leases arecharged 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 atfair value at the date of grant. The fair value of the equity settled optionsdetermined at the grant date is expensed on a straight line basis over thevesting period based on the actual number of shares vested in the accountingperiod. In performing the valuation of these options, only conditions other thanthe market conditions are taken into account. Fair value is derived by use ofthe binomial model. The expected life used in the model is based on estimates ofthe management considering non-transferability, exercise restrictions andbehavioural 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 ormore than one disclosable geographic segment for the purposes of reporting. TheGroup is engaged in one business activity, the production of and exploration foroil 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 allsegments. Other income relates to technical services to third parties, overheadrecovery from joint venture operations and miscellaneous receipts if any.Revenue arises from sale of oil produced from the contract area CY-OS-90/1-Indiaand the revenue by destination is not materially different from the revenue byorigin. 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 anddepreciation 1,622,030 2,137,699 92,410 98,721Decommissioning charge 217,397 304,899 - -Share based paymentscharges 1,561,497 687,459 1,333,947 459,540------------------- --------- -------- --------- -------- 2,587,655 14,554,680 (2,213,508) (2,024,839)(Increase )/ decreasein inventory 25,849 (2,379,835) - -Decrease /(increase) indebtors 2,720,211 225,800 69,743 (73,030)Increase /(decrease) increditors (7,178,629) 11,542,219 413,614 (221,020)------------------- --------- -------- --------- --------Net cash(outflow)/inflow fromoperating 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 thecompany excludes an amount of US$ 12,502,931 due from the sale of investment inHindustan 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 forthe year 2007 (2006: 56,695,898). The diluted earnings per share are calculated on a profit of US$ 8,315,978 forthe year 2007 (2006: US$ 10,232,768) on a weighted average of 64,469,515ordinary shares for the year 2007 (2006: 59,367,997). The weighted averageshares are arrived after giving impact to dilutive potential ordinary shares of4,352,099 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 thefollowing 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 andproduction of oil and gas and all are included in the consolidation. 6. Share capital ----------------------------- ----------- ---------- Number US$ $0.01 Ordinary Shares "000" ----------------------------- ----------- ----------Authorized ordinary sharesAt 1 January 2006 200,000 2,000,000At 1 January 2007 200,000 2,000,000At 31 December 2007 200,000 2,000,000----------------------------- ----------- ---------- ----------------------------- ----------- ----------Allotted, issued and fully paid ordinary sharesAt 1 January 2006 52,046,667 520,467Share options exercised during the year 1,667 16Shares issued during the year 5,204,660 52,047----------------------------- ----------- ----------At 1 January 2007 57,252,994 572,530Share options exercised during the year 45,001 450Shares 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 LimitedD3 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 ExchangeRelated Shares:
HDY.L