Interim results

RNS Number : 3022R

Hardy Oil & Gas plc

19 August 2010

 

For Immediate Release 19 August 2010

 

Hardy Oil and Gas plc

 

("Hardy", "the Company" or "the Group")

 

Interim Results for Six Months Ended 30 June 2010

 

 

Hardy Oil and Gas plc (LSE: HDY), the oil and gas exploration and production company with interests predominantly in India, is pleased to report its Interim Results for the six months ended 30 June 2010.

 

All financial amounts are stated in US dollars unless otherwise indicated.

 

Operational Highlights

 

·; PY-3: Recommenced production on 24 January 2010 at a rate of 3,336 bbld. Gross daily production in the first half of 2010 averaged 2,953 bbld (H1 2009: 3,016 bbld) (net: 532 bbld, H1 2009: 543 bbld). Average gross daily production for the month of July 2010 was 3,441 bbld

·; D3: Drilling of the KGV-D3-W1 exploration well resumed on 10 August 2010. The well was previously suspended due to mechanical issues with the BOP of the drilling ship

·; GS-01: A proposal for declaration of commerciality of the GS-01 Dhirubhai 33 natural gas discovery was submitted to DGH

·; CY-OS/2: The Company initiated a formal dispute resolution process in accordance with the PSC to extend the date of this licence to January 2012

·; Drilling Moratorium: The Government of India granted a three year drilling moratorium on all deepwater blocks including D3 and D9

 

Financial Highlights

 

·; Revenue of $5.5 million (H1 2009: $5.8 million)

·; Cash flow from operating activities (before changes in non-cash working capital) of $0.3 million (H1 2009: Deficiency of $2.6 million)

·; Net loss of $1.3 million (H1 2009: net loss $4.3 million)

·; Capital expenditure of $2.3 million on partial drilling of KGV-D3-W1 well and processing of acquired 3D seismic data

·; Cash and short term investments at 30 June 2010 amounted to $26.6 million; the Company has no long term debt

 

Corporate

 

·; Yogeshwar Sharma assumed the role of Chief Executive Officer effective 1 April 2010. Sastry Karra became a non-executive Director

·; Appointment of William Satterfield as Technical Director of HEPI (wholly owned subsidiary)

·; Published a CPR and an independent assessment report providing an update to the Company's reserves and resources estimates in India and Nigeria

Outlook

 

·; Complete drilling of KGV-D3-W1 exploration well. Planning of further exploration drilling is underway

·; Continue geological and engineering appraisal evaluation of the D3 - Dhirubhai 39 and 41 Plio-Plesitocene gas discoveries

·; Drilling of the second exploration well on D9 expected in the second half of 2010

·; PY-3 gross daily production is projected to average 3,100 bbld in 2010.

 

Commenting on the Results, Paul Mortimer, Chairman of Hardy, said:

 

"We are pleased that exploration drilling on the D3 block has resumed and we are looking forward to completing the initial evaluation of our Krishna Godavari Basin assets. With over $26 million of cash and short term investments, the Company is funded for its planned work programme of high impact exploration drilling."

 

For further information please contact:

 

Hardy Oil and Gas plc	020 7471 9850
Yogeshwar Sharma, Chief Executive Officer Dinesh Dattani, Finance Director
Arden Partners plc	020 7614 5917
Richard Day Matthew Armitt
Buchanan Communications	020 7466 5000
Mark Edwards Ben Romney

CHAIRMAN'S STATEMENT

 

Overview

 

Overall, we are pleased with the progress made by the Company in the first half of 2010. With cash resources of over $26 million, the Company is well positioned to execute our planned high impact exploration drilling programme in the KG Basin off the east coast of India.

 

After a prolonged shut-in, we are pleased to have recommenced production from the Hardy operated PY-3 oil field from 24 January 2010. With continued stable production rates and strong commodity prices, the PY-3 field is contributing free cash flow to the organisation.

 

As previously announced, we have resumed the drilling of the KGV-D3-W1 exploration well on the Company's D3 block. Earlier in the year the W1 exploration well had been suspended due to safety concerns regarding the BOP on the drilling rig. The Macondo well incident, in the Gulf of Mexico, resulted in renewed vigilance in the industry maintaining safety measures for deepwater drilling activities. As a result the deepwater drill-ships, in India waters, have during the past three months experienced periods of inactivity frustrating companies' active drilling programmes.

 

The Government of India's decision to grant a three year drilling moratorium on 8 July 2010 was a welcome development in 2010. This decision eliminates some of the ambiguity surrounding the status of our deep water exploration licences. The Company has noted a renewed commitment by the Government of India to implement energy sector reforms which should facilitate the industry sectors' efforts and ability to meet India's growing demand for energy.

 

Corporate

 

Yogeshwar Sharma assumed the role of Chief Executive Officer effective 1 April 2010. As co-founder and former Managing Director of Hardy, the transition to CEO has been relatively seamless. Sastry Karra became a non-executive Director and the Board continues to benefit from his advice and counsel.

 

The appointment of William Satterfield as HEPI's (wholly owned subsidiary) Technical Director in June 2010 was an important addition to our team. His extensive technical expertise and commercial experience considerably enhances our management capabilities and is expected to compliment the execution of our India focused strategy.

 

In April 2010 the Company published a CPR and an independent assessment report providing an update to the Company's reserves and resources estimates in India and Nigeria. The CPR highlights the significant prospective resource potential of the Company's Krishna Godavari Basin assets.

 

Financial

 

As a result of PY-3 production recommencing, in January, net average daily production for the six months ended 30 June 2010 decreased marginally from 543 bbld to 532 bbld.

 

Revenue for the six months ended 30 June 2010 decreased by five per cent to $5.5 million. The average price realised increased by 63 per cent to $79.12 bbl during the six months ended 30 June 2010. Oil sales in the six months ended 30 June 2010 decreased by 42 per cent to 67,758 bbl compared to the six months ended 30 June 2009, due to the delay in off-take of crude oil in June 2010 and consequent increase in inventory at June 30 2010.

 

The Company generated cash flow from operating activities (before changes in non-cash working capital) of $0.3 million in the first half of 2010 compared with cash flow deficiency of $2.6 million for the same period in 2009. All of the Company's production costs and cash administrative expenses were fully funded by crude oil sales revenues from the PY-3 field during the first half of 2010.

 

The Company recorded a net loss of $1.3 million compared to a net loss of $4.3 million in 2009. The Company's fully diluted loss per share was $0.02 in 2010 compared to fully diluted loss per share of $0.07 reported for the same period in 2009.

 

Total capital expenditures amounted to $2.3 million, principally on the partial drilling of the KGV-D3-W1 exploration well and processing of 3D seismic data.

 

As a result, Hardy's cash resources decreased by $4.0 million, since the year ended 31 December 2009, to $26.6 million at 30 June 2010; the Company has no long-term debt.

 

Independent Review

 

The auditors have provided an emphasis of matter comment in their independent review report with reference to the uncertainty concerning the Group's request for an extension of its exploration licence in block CY-OS/2 as disclosed in note 2 (i) of the consolidated financial statements.

 

Outlook

 

Set out below is our planned operating activity in the coming months;

 

Exploration: 

 

·; D3 - We anticipate the completion of drilling of the W1 well during the third quarter of 2010. Drilling of two additional exploration wells is being planned with the operator.

·; D9 - We anticipate the drilling of the second exploration well prior to the end of 2010 and the D9 joint venture is committed to completing the minimum work programme, of a further two exploration wells, during phase one of the exploration period.

 

Appraisal:

 

·; D3 - The joint venture is continuing geological and engineering appraisal evaluation of the Dhirubhai 39 and 41 gas discoveries.

·; GS-01 - The joint venture is continuing discussions with the Government of India regarding the proposal for commerciality submitted in May of 2010. We do not anticipate any significant expenditure on the GS-01 block in 2010 or 2011.

·; CY-OS/2 - The arbitration process has been initiated to determine the expiry date of this licence. Further drilling, to appraise the Company's Ganesha natural gas discovery, will be contingent on the outcome of the arbitration process.

 

Development:

 

·; PY-3 - We continue to work with partners to secure approval for the drilling of additional wells and the securing of facilities to handle gas compression for gas lift and gas export. The drilling and gas lift installation programme is expected to increase gross daily to over 8,000 bbld in 2012.

Production:

 

·; PY-3 - We expect the field to continue to produce at 3,400 bbld for the remainder of 2010. The joint venture is planning modest downtime during the monsoon season in November and December 2010, resulting in a projected average gross daily production of 3,100 bbld for 2010.

 

We are pleased that exploration drilling on the D3 block has resumed and we are looking forward to completing the initial evaluation of our Krishna Godavari Basin assets. With over $26 million of cash and short term investments, the Company is funded for its planned work programme of high impact exploration drilling.

 

 

E P Mortimer

Chairman

18 August 2010

REVIEW OF OPERATIONS

 

The Company's operations in India are conducted through its wholly owned subsidiary Hardy Exploration & Production (India) Inc (HEPI). The Company's operations in Nigeria are conducted through its wholly owned subsidiary Hardy Oil Nigeria Limited (HON).

 

KRISHNA GODAVARI BASIN - Eastern India

Block KG-DWN-2003/1 (D3): Exploration

(Hardy 10% interest)

 

Operations

 

On 6 April 2010, the Company announced the commencement of drilling the exploration well KGV-D3-W1. Drilling was subsequently suspended at 2,608 m MD due to mechanical issues with the drilling ship's BOP. As announced on 11 August 2010, the D3 joint venture resumed drilling of the KGV-D3-W1 exploration well with the Transocean rig Discoverer 534. The target depth of this well, which aims to explore the hydrocarbon potential of Mio-Pliocene sands, is 3,514 m MD.

 

The joint venture intends to drill a further two exploration wells to meet its phase one minimum work commitments.

 

Processing of the 3D seismic data gathered over the eastern portion of the block ("Toe Thrust Area") continued through the period.

 

Further geological, geophysical, and engineering studies are ongoing regarding the appraisal of the Plio-Pleistocene gas discoveries Dhirubhai 39 and 41. A proposal of commerciality is planned for submission by February 2011. The joint venture is concurrently evaluating the appraisal potential of Dhirubhai 44 (KGV-D3-R1) Miocene gas discovery.

 

In April 2010 the Company published a Competent Person's report prepared by Gaffney Cline & Associates. The net best estimate risked Prospective Resources of D3 is estimated at 390 BCF. The full report can be downloaded from the Company website (www.hardyoil.com).

 

Moratorium

 

On 8 July 2010 The Cabinet Committee on Economic Affairs of the Government of India approved the grant of a drilling moratorium of three years (to the end of 2010) to all deepwater blocks Production Sharing Contracts (PSCs) signed under various NELP rounds up until the NELP-V rounds where drilling commitments were pending as on 1 January 2009. As per the DGH extension policy, the D3 joint venture can extend phase one by up to 18, months subject to penalties and guarantees.

 

Background

 

Situated in the emerging world class petroleum system of the Krishna Godavari Basin on the east coast of India, the D3 exploration licence encompasses an area of 3,288 km2, in water depths of 400 m to 2,200 m, and is located approximately 45 km offshore. The block is operated by Reliance.

 

Exploration: The minimum work programme for phase one of the licence requires the drilling of six exploration wells. To date, three consecutive gas discoveries have been made via KGV-D3-A1, B1 and R1 exploration wells, one well has been pre-drilled (KGV-D3-G1) and a fourth well (KGV-D3-W1) is currently drilling. The joint venture has acquired over 3,250 km2 of 3D seismic data over the block.

 

Appraisal (Dhirubhai 39 and 41): In 2009, the D3 joint venture Operating Committee reviewed and approved an appraisal programme for the evaluation of the Dhirubhai 39 and 41 gas discoveries. The proposed appraisal area comprises 750 km2 covering a large portion of the North West corner of the block. The appraisal programme provides for the initial undertaking of various geological, geophysical and development concept studies by early 2011. 

 

KRISHNA GODAVARI BASIN - Eastern India

Block KG-DWN-2001/1 (D9): Exploration

(Hardy 10% interest)

 

Operations

 

The D9 joint venture is presently integrating the KG-D9-A1 well data analysis into its geological model prior to the drilling of the next exploration well.

 

·; Sedimentological, biostratigraphic and paleontological studies of the side wall cores and drill cuttings are complete and are being integrated with the seismic data.

·; Inversion studies of the 3D seismic incorporating data from the A1 well and nearby D6 block are in progress.

·; The geochemical sample analysis is complete and the geochemical model for understanding the source rock potential is being updated.

 

In April 2010 the Company published a Competent Person's report prepared by Gaffney Cline & Associates. The net best estimate risked Prospective Resources of D9 are estimated at 520 BCF of natural gas and 18 MMbbl of oil. The full report can be downloaded from the Company website (www.hardyoil.com).

 

The D9 licence has a minimum work commitment of four exploration wells. The joint venture expects to drill a second exploration well prior to the end of 2010.

 

Moratorium

 

On 8 July 2010 The Cabinet Committee on Economic Affairs of the Government of India approved the grant of a drilling moratorium of three years up to the end of 2010 to all deepwater block Production Sharing Contracts (PSCs) signed under various NELP rounds up until the NELP- V rounds where drilling commitments are pending as on 1 January 2009. As per the DGH extension policy, the D9 joint venture can extend phase one by up to 18 months subject to penalties and guarantees. The joint venture has previously availed 6 of the 18 months available via the DGH extension policy.

 

Background

 

Situated in the Krishna Godavari Basin in India, the licence encompasses 11,605 km2 in the Bay of Bengal where water depths vary from 2,300 m to 3,100 m. The block is immediately adjacent to the Reliance operated D6 block, where over 2 BCF per day is being produced from Tertiary aged sediments. The joint venture has acquired 4,188 km2 of 3D seismic in the NW quarter of the block and 2,087 km of 2D seismic over the remainder of the block. Subsequent interpretation of the seismic data has identified leads at Pliocene, Miocene, Oligocene and Cretaceous levels. In 2009 the joint venture drilled KG-D9-A1 to a depth of 4,875 m MD in a water depth of 2,754 m. The A1 well did not encounter significant hydrocarbons in the Plio-Miocene section and was subsequently plugged and abandoned. Although disappointing, this first well in the block has provided the joint venture with substantial data that has been integrated with the 3D seismic. This has facilitated a better understanding and relative risk ranking of the block's petroleum systems, plays and prospects.

 

ASSAM ARAKAN BASIN - North Eastern India

Block AS-ONN-2000/1: Exploration

(Hardy 10% interest)

 

Operations

 

Initial interpretation of the acquired 390 lkm of 2D seismic has been completed and incorporated with the regional geological model. The Assam joint venture has also completed an environmental impact assessment and surface geochemical sample analysis is underway. The Assam joint venture has met the minimum work commitment for phase one.

 

It is envisioned that the joint venture will elect to proceed to phase two which will require a further minimum commitment of one exploration well and the relinquishment of 25 per cent of the block's area. The drilling of one exploration well is expected in the latter part of 2011.

 

Background

 

The AS-ONN-2000/1 exploration licence is located in the north eastern state of Assam, India, north of Brahmaputra River. The exploration licence covers an area of 5,754 km2 in the districts of Darrang and Sonitpur. The block is in phase one of the three-phase exploration licence. Phase one has a three year term which expires in January 2011. The topography of the area is primarily a plain of low relief and there is a reasonably established road network across the block. Hardy holds a 10 per cent participating interest with Reliance holding 90 per cent as operator.

 

GUJARAT-SAURASHTRA BASIN - Western India

Block GS-OSN-2000/1 (GS-01): Exploration

(Hardy 10% interest)

 

Operations

 

In May 2010, the GS-01 joint venture submitted a proposal to DGH for declaration of commerciality for the Dhirubhai 33 natural gas discovery, and discussions have been ongoing to present. Following acceptance of the commerciality proposal by the GS-01 management committee, a development plan will be prepared and submitted to DGH. The GS-01 PSC provides the joint venture 12 months to develop a comprehensive development plan for review and approval.

 

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 original licence encompassed an area of 8,841 km2, with water depths varying between 80 m and 150 m. The joint venture has previously acquired 2,216 km2 of 3D seismic data. In May 2007, the Company announced a discovery from the GS01-B1 exploration well and flow-tested the well at a rate of 18.6 MMscfd gas with 415 bbld of condensate through a 56/64" choke at flowing tubing head pressure of 1,346 psi. The joint venture elected not to enter phase two of the exploration licence and as a result 5,890 km2 of the block has been retained via appraisal of the GS01-B1 discovery.

CAUVERY BASIN - Eastern India

Block CY-OS 90/1 (PY-3): Producing Oil Field

(Hardy 18% interest - Operator)

 

Production

 

After a prolonged shut-in due to unscheduled repair and maintenance of the offshore mooring facility, on 24 January 2010 the PY-3 field recommenced production at an initial rate of 3,336 bbld.

 

Gross daily average production for the six months ended 30 June 2010 was 2,953 bbld (2009: 3,016 bbld). The PY-3 field has been performing as expected. Gross production for the month of July averaged 3,441 bbld. Production is expected to remain around 3,400 bbld through for the remainder of 2010. The joint venture is planning modest downtime during the monsoon season in November and December 2010. As a result the Company anticipates gross production to average 3,100 bbld in 2010.

 

Operations

 

Hardy continues to work closely with its partners to finalise a full field redevelopment plan to enhance production and the ultimate recovery from the PY-3 field, through additional wells and artificial lift facilities. The joint venture is currently considering the drilling of two further lateral production wells and upgrading facilities to include gas compression for gas lift and sales gas evacuation.

 

The timing of commencement of drilling and facilities upgrades has not yet been finalised pending budget approvals from partners and DGH.

 

Background

 

The PY-3 field is located off the east coast of India, 80 km south of Pondicherry in water depths of between 40 m and 450 m. The licence is operated by Hardy, covers 81 km2, and produces high quality light crude oil (49° API). The field was initially developed using floating production facilities and subsea wellheads, a first for an offshore field in India. 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, with one current, naturally flowing producer and two water injection wells.

 

CAUVERY BASIN - Eastern India

Block CY-OS/2: Exploration

(Hardy 75% interest - Operator)

 

Operations

 

The Company holds a 75% participating interest in its offshore block CY-OS/2 on the south east coast of India wherein a gas discovery was announced on 8 January 2007. The exploration period for the block ended on 23 March 2007 and the MOPNG was requested to extend the block for appraisal and declaration of commerciality for its non-associated natural gas (NANG) discovery until January 2012 in accordance with the provisions of the CY-OS/2 production sharing contract.

 

The Company has initiated a formal dispute resolution process in accordance with the PSC with the appointment of three arbitrators to seek to extend the expiry date of the licence to January 2012. The preliminary hearing by the arbitral tribunal is scheduled to commence shortly.

 

In line with the production sharing contract the joint venture continues to own the licence during the arbitration process. Therefore, the intangible assets arising from expenditure on this block continue to be recognised at cost and the Directors do not believe that any impairment of these costs has arisen as at 30 June 2010.

 

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. Hardy is the operator of this block. The CY-OS/2 licence comprises two retained areas. The northern area includes the Ganesha (Fan-A1) non-associated gas discovery. The southern area lies immediately adjacent to the HEPI-operated PY-3 field. The outside operated and producing PY-1 natural gas field lies within the southern part of the acreage. The PY-3 oil field and PY-1 gas field are both contained within the CY-OS/2 licence but have been ring-fenced, each with a separate PSC.

NIGER DELTA BASIN - Nigeria

Block Oza (OML 11): Development

(Hardy 20% interest)

 

Operations

 

Remedial field work was undertaken to progress the first phase of development. The operator continues to experience delays in advancing the approved programme due to funding and approval constraints. In April 2010 the Company published an independent assessment report on the Company's Nigerian assets which had been undertaken by RPS.

 

Background

 

The Oza Field is located on-land in the north western part of OML 11, near Port Harcourt, with three suspended well in the field and a concession area of 20 km2. The Oza field is subject to a farm-out agreement between NNPC, SPDC and Elf Petroleum Nigeria. The cumulative production from the field is approximately 1.0 MMbbl from three zones in three wells. In 2008 Hardy farmed out a 20% working interest in the Oza field to Emerald. Under the terms of the agreement, as consideration for the interest, Emerald assumed the Company's obligation to fund the initial work programme of the Oza field. In December 2009, Millenium, Hardy and Emerald signed a service and financing contract with the Xenergi consortium, a grouping of indigenous service companies, to perform a well work over and install a 10 km multi-phase pipeline to the Isimiri flow station.

 

NIGER DELTA BASIN - Nigeria

Block Atala (OML 46): Development

(Hardy 20% interest)

 

Operations

 

The original marginal field award was subject to review in November 2009. Extension of the Atala licence is contingent on the Nigerian authorities believing that sufficient progress has been made over the initial term to merit an extension. As such, the operator, along with a consortium of other Niger delta marginal field operators, has requested an extension due to equipment constraints and various other circumstances that have frustrated efficient progress of work programmes over the initial term.

 

Background

 

Atala is located within OML 46, which is located in a mangrove swamp on the Dodo River, a coastal area of Bayelsa State. The concession area is 34 km2. Bayelsa Oil Company Limited is the operator with HON as technical partner. 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.

 

FINANCIAL REVIEW

 

The Company's principal source of revenue is from the sale of crude oil production from the PY-3 field.

 

Key Performance Indicators

	Six months ended 30 June
	2010	2009
Production (stock tank barrels of oil per day - net entitlement basis)	532	543
Average realised price per bbl ($)	79.12	48.44
Revenue ($ 000's)	5,492	5,800
Net loss ($ 000's)	(1,305)	(4,309)
Cash flow (deficiency) from operating activities* ($ 000's)	331	(2,580)
Diluted (loss) per share ($)	(0.02)	(0.07)
Wells drilled	0∆	1

* Before changes in non-cash working capital

∆ KVG-D3-W1 commenced drilling in April 2010 was suspended in May 2010 and recommenced in August 2010.

 

Operating Results

	Six months ended 30 June
	2010	2009
Production (bbld)
Gross	2,953	3,016
Participating interest	532	543
Net entitlement interest	532	543
Sales (bbld)
Gross	2,079	3,590
Participating interest	374	646
Average realised price ($ per bbl)	79.12	48.44

 

Production

 

After a prolonged shut-in period, production from the Company's PY-3 field recommenced on 24 January 2010 at a net daily rate of 600 bbld resulting in average daily production for the six months ended 30 June 2010 decreasing marginally from 543 bbld to 532 bbld.

 

Revenue

 

Revenue for the six months ended 30 June 2010 decreased by five per cent to $5.5 million. The average price realised per bbl increased by 63 per cent to $79.12 during the six months ended 30 June 2010. Oil sales in the six months ended 30 June 2010 decreased by 42 per cent to 67,758 bbl compared to the six months ended 30 June 2009, as a result of 28,358 bbl of production remaining in inventory at 30 June 2010. The decrease in sales oil was offset by the significant increase in oil price realised.

 

Cost of Sales

 

Production cost of sales decreased 64 per cent for the six months ended 30 June 2010 to $1.7 million principally reflecting a substantially lower lease rate for the PY-3 field's offshore production and storage facilities. Actual production cost amounted to $25.11 per barrel in the first half of 2010 compared with $39.28 per barrel for the same period in 2009. Depletion charge increased from $11.00 per barrel in 2009 to $17.21 per barrel principally as a result of an increase in future development costs.

 

Gross Profit

 

As a result, the Company has recorded a gross profit of $2.0 million in the six months ended 30 June 2010 compared to a break-even position in 2009.

 

Administrative Expenses

 

Administrative expenses decreased by 35 per cent to $3.5 million for the six months ended 30 June 2010. The decrease principally results from the providing for a cost of $1.6 million associated with the drilling of the PY3-PD4RL well in 2009 coupled with exchange gains recorded in 2010.

 

Operating Loss

 

As a result, the Company is reporting an operating loss of $1.5 million for the six months ending 30 June 2010 compared with a loss of $5.5 million reported for the same period in 2009.

 

Investment and other Income

 

Investment and other income increased from $0.1 million for the six-month period ended 30 June 2009 to $0.2 million in 2010. The increase is the result of higher interest rates realised in 2010.

 

Taxation

 

Minimal tax relief has been provided against the pre tax loss of $1.3 million recorded for the six months ended 30 June 2010 principally as a result of non deductibility of share based payment charge.

 

Net Loss

 

As a result, the Company recorded a net loss of $1.3 million for the six months ended 30 June 2010 compared to a net loss of $4.3 million reported for the same period in 2009.

 

Cash Flow from Operating Activities

 

The Company generated cash flow from operating activities, before changes in non-cash working capital, of $0.3 million in the first half of 2010 compared with cash flow deficiency of $2.6 million for the same period in 2009. All of the Company's production costs and cash administrative expenses were fully funded by crude oil sales revenues from the PY-3 field. The significant decrease in the lease rate for the PY-3 field's offshore production and storage facility and lower administrative expenses has contributed to the favourable variance in 2010.

 

Capital Expenditures

 

The Group's capital expenditures during the six months ended 30 June 2010 amounted to $2.3 million, compared to $7.0 million incurred for the same period in 2009.

 

Capital expenditures amounting to $2.0 million were incurred on the D3 block with the processing of acquired of 3D seismic and the partial drilling of an exploration well in the second quarter of 2010. Minimal expenditures were incurred on the remaining blocks in India and no expenditures were incurred in Nigeria.

 

Equity Financing

 

The group raised a nominal amount of cash from the issuance of equity as a result of the exercise of employee stock options.

 

Cash and Short Term Investments

 

Total cash and short term investments decreased by $4.0 million to $26.6 million as at 30 June 2010. The drawdown of cash and short term investments from 31 December 2009 was attributable principally to expenditures on the D3 exploration block and changes in working capital.

 

Financial Position

 

Hardy's non-current assets increased from $141.8 million at 31 December 2009 to $149.1 million at 30 June 2010. This resulted principally from the capital expenditure programme on the Company's D3 exploration block offset by depletion charges on PY-3 production.

 

Current assets represent the Group's cash resources, together with trade and other receivables and inventory. As at 30 June 2010, of the $35.0 million of current assets, $26.6 million was represented by cash and short term investments.

 

Current liabilities are principally trade and other accounts payable. The level of current liabilities fluctuates significantly depending upon the timing of capital programmes. As at 30 June 2010, the Company's short term liabilities were relatively unchanged compared to 31 December 2009.

 

During the six months ended 30 June 2010, the Company's equity decreased slightly from $155.5 million at the end of 2009 to $154.2 million at 30 June 2010 reflecting the recorded loss of $1.3 million for the six months ended 30 June 2010.

 

Principal Risks and Uncertainties

 

Any of the risks, as well as the other risks and uncertainties discussed in this document, could have a material adverse effect on the Group's business. In addition, the risks set out below may not be exhaustive and additional risks and uncertainties, not presently known to the Company, or which the Company currently deems immaterial, may arise or become material in the future. In particular, the Company's performance might be affected by changes in market and/or economic conditions and in legal, regulatory and tax requirements.

 

The principle risks and uncertainties facing the Group at the year-end, their potential impact and the mitigation strategies developed were detailed in the Annual Report and Accounts 2009 (available on our website www.hardyoil.com). Most of the risks and uncertainties which were identified at the year-end have not changed and still remain appropriate for the second half of 2010. Key risks relating to the following were identified;

 

·; Strategic risk is generally described as "Ineffective or poorly executed strategy fails to create shareholder value". Ineffective mix of oil and gas interests; Organic and acquisition-led growth; Inefficient capital allocation; Ineffective management processes; Loss of key staff/succession planning.

 

·; Financial risk is generally described as "Assets performance and excessive leverage results in the Group unable to meet its financial obligations". Industry cost inflation; Capital structure; Uninsured events; Underperforming assets; Cost overrun.

 

·; Operational risk is generally described as "Operational events that impact staff, contractors, communities or the environment leading to loss of reputation and/or revenue". HSE incident; Security incident; Key development failure; Failure to secure equipment, services and resources; Long-term planning required to resource projects on a timely basis; Sustained exploration failure.

 

·; External risk is described as "the overall external political, industry or market environment may negatively impact the Company's ability to independently manage and grow its business". Political risk and fiscal change; Lack of control of keys assets; Corporate governance failings; Negative shareholder sentiment; Oil and gas price volatility; Global capital market environment; Capital default of joint venture partners; Hostile acquisition.

 

Key Risks for the second half of 2010

 

The Board has identified the following items as key risks to the Company in the near-term. These risks are presented in no particular order.

 

General exploration, development and production risks - The Group's strategy is predominantly driven by the exploration, appraisal, development and production of its existing assets. There are risks inherent in the exploration, appraisal, development and production of oil and gas reserves and resources. Whilst the rewards can be substantial, there is no guarantee that exploration will lead to further commercial discoveries. Exploration and production activities by their nature involve significant risks.

 

Exploration drilling programme execution - The Group's exploration plans comprise activities primarily on non-operated blocks. The timing of execution of activities may not commence as currently forecasted and significant delays may be experienced. As well, the exploration focus of the Group's 2010 work programme may result in the failure to discover hydrocarbons in commercial quantities.

 

CY-OS/2 block arbitration - With respect to the Group's Ganesha (CY-OS/2) non-associated natural gas discovery (NANG), HEPI and the Government of India have initiated formal dispute resolution process in accordance with the CY-OS/2 PSC. Intangible assets include an amount of $83.5 million with respect to exploration expenditures on the block wherein a gas discovery was announced on 8 January 2007. The exploration period for the block ended on 23 March 2007 and the Company had submitted a request for the GOI to extend the block for appraisal and declaration of commerciality for its gas discovery until 7 January 2012. Provisions of the PSC provide for an appraisal period of 60 months from the date of discovery. For an oil discovery, this period is limited to 24 months. The MOPNG has informed HEPI that in their opinion the discovery is classified as an oil discovery and not a NANG discovery. In the event that the arbitration ruling for an extension of the CY-OS/2 licence is unsuccessful, the Company will no longer hold a commercial interest in the exploration licence and the related intangible asset will be subject to impairment testing.

 

Nigeria assets extension - The status of the Group's licences in Nigeria have exceeded the initial contracted term. These licences can be extended through various government approvals but there is no certainty that these extensions will be granted. Should an extension not be received then the Group will no longer have a commercial interest in the blocks.

 

Unplanned shut-in of the PY-3 field - The Company's revenue is principally generated from a single offshore oil field which is producing from a single well. In the past the field has experienced extended unplanned shut-ins due to facility and weather related issues. In the event that the PY-3 field experiences an unplanned shut-in due to subsurface or surface issues the Company's revenue may be significantly impacted.

 

Commodity price risk - Historically, oil prices have fluctuated widely and are affected by numerous factors over which the Group has no control, including world production levels, international economic trends, exchange rate fluctuations, expectations for inflation, speculative activity, consumption patterns and global or regional political events. The Company's revenue is principally generated by the sale of oil. Should there be a significant fall in global oil prices the Company's revenue may be significantly impacted.

 

Foreign exchange risk - The proceeds of the Group's domestic oil and gas sales in India are received in US dollars. The majority of the Group's expenditure requirements are in US dollars. The Group has general and administrative expenditure with respect to offices in India, United Kingdom, and Nigeria; therefore the Group is exposed to foreign exchange risk against Indian Rupees, UK Sterling and Nigerian Naira.

 

Liquidity risk management and going concern

 

At 30 June 2010, the Company had liquid resources of approximately $26.6 million, in the form of cash and short term investments, which, together with production revenue from the PY-3 field, are available to meet ongoing capital, operating and administrative expenditures. At the present time, the Company does not have any short-term or long-term debt.

 

Status of CY-OS/2 Discovery Block

 

The auditors have provided an emphasis of matter comment in their independent review report with reference to the uncertainty concerning the Group's request for an extension of its exploration licence in block CY-OS/2 as disclosed in note 2 (i) of the interim consolidated financial statements.

 

RESPONSIBILITY STATEMENT

 

We confirm that to the best of our knowledge:

 

• the interim consolidated financial statements have been prepared in accordance with International Accounting Standards 34, Interim Financial Reporting, as adopted by the EU; and

 

• give a true and fair view of the assets, liabilities and loss of the group; and

 

• the interim report includes a fair review of the information required by DTR 4.2.7R of the Disclosure and Transparency Rules, being an indication of important events that have occurred during the first six months of the financial year and their impact on the set of interim consolidated financial statements; and a description of the principal risks and uncertainties for the remaining six months of the year.

 

 

On behalf of the Board

 

 

 

 

Dinesh Dattani FCA

Finance Director

18 August 2010

INDEPENDENT REVIEW REPORT TO HARDY OIL and GAS plc

 

Introduction

We have been engaged by the company to review the interim consolidated financial statements in the half yearly management report for the six months ended 30 June 2010 which comprises the consolidated income statement, the consolidated statement of changes in equity, the consolidated balance sheet, the consolidated cash flow statement and the related explanatory notes. We have read the other information contained in the half yearly management report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the interim consolidated financial statements.

 

Directors' Responsibilities

The half yearly management report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half yearly management report in accordance with the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.

As disclosed in note 1, the annual consolidated financial statements are prepared in accordance with IFRS as adopted by the European Union. The interim consolidated financial statements included in this half yearly management report have been prepared in accordance with International Accounting Standard 34, Interim Financial Reporting, as adopted by the European Union.

 

Our Responsibility

Our responsibility is to express to the Company a conclusion on the interim consolidated financial statements in the half yearly management report based on our review.

 

Scope of Review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, Review of Interim Financial Information Performed by the Independent Auditor of the Entity issued by the Auditing Practices Board for use in the United Kingdom. A review of interim consolidated financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

 

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the interim consolidated financial statements in the half yearly management report for the six months ended 30 June 2010 are not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.

Emphasis of matter - Request for an extension of an exploration licence

In forming our conclusion on the interim consolidated financial statements, which is not qualified, we have considered the adequacy of the disclosures made in note 2 (i) to the interim consolidated financial statements concerning the group's request for an extension of its exploration licence in block CY-OS/2. The matter of this request has been referred to arbitration.

 

In the event that the group's request for an extension of this licence was to be unsuccessful, then the exploration expenditure capitalised in respect of this block would be subject to impairment testing. No adjustment has been made to the carrying value of this capitalised expenditure.

 

 

 

HORWATH CLARK WHITEHILL LLP

London

18 August 2010

HARDY OIL AND GAS plc

Consolidated Statement of Comprehensive Income

 

	Six months ended 30 June 2010 (Unaudited) US$	Six months ended 30 June 2009 (Unaudited) US$	Year ended 31 December 2009 (Audited) US$
Revenue	5,491,775	5,799,789	7,687,355
Cost of sales
Production costs	(1,701,590)	(4,677,125)	(5,661,574)
Depletion	(1,655,843)	(1,016,009)	(1,078,839)
Decommissioning charge	(94,290)	(102,190)	(104,859)
Gross profit	2,040,052	4,465	842,083
Administrative expenses	(3,531,256)	(5,455,885)	(8,974,255)
Operating (loss)	(1,491,204)	(5,451,420)	(8,132,172)
Interest and investment income	180,157	91,839	261,672
Finance costs	(36,060)	(33,257)	(71,378)
(Loss) before taxation	(1,347,107)	(5,392,838)	(7,941,878)
Taxation	41,886	1,083,508	1,424,702
(Loss and comprehensive loss) for the period	(1,305,221)	(4,309,330)	(6,517,176)
(Loss) per share
Basic	(0.02)	(0.07)	(0.10)
Diluted	(0.02)	(0.07)	(0.10)

 

HARDY OIL AND GAS plc

Consolidated Statement of Changes in Equity

 

 

	Share capital US$	Share premium US$	Shares to be issued US$	Retained earnings US$	Total US$
At 1 January 2009	623,210	93,351,938	3,926,870	46,329,855	144,231,873
Total comprehensive loss	-	-	-	(4,309,330)	(4,309,330)
Share-based payments	-	-	1,639,103	-	1,639,103
Issue of share capital	62,090	15,764,184	-	-	15,826,274
Issue expenses	-	(640,198)	-	-	(640,198)
At 30 June 2009	685,300	108,475,924	5,565,973	42,020,525	156,747,722
Total comprehensive loss	-	-	-	(2,207,846)	(2,207,846)
Share-based payments	-	-	991,735	-	991,735
At 1 January 2010	685,300	108,475,924	6,557,708	39,812,679	155,531,611
Total comprehensive loss	-	-	-	(1,305,221)	(1,305,221)
Share-based payments	-	-	(9,089)	-	(9,089)
Share options exercised	50	10,904	-	-	10,954
At 30 June 2010	685,350	108,486,828	6,548,619	38,507,458	154,228,255

 

HARDY OIL AND GAS plc

Consolidated Statement of Financial Position

As at 30 June 2010

 

 

	30 June 2010 (Unaudited)	30 June 2009  (Unaudited)	31 December 2009 (Audited)
	US$	US$	US$
Assets
Non-current assets
Property, plant and equipment	8,287,349	10,279,579	10,046,762
Intangible assets - exploration	137,020,344	128,026,323	134,725,547
Intangible assets - others	20,957	71,332	46,144
Site restoration deposit	3,781,859	3,451,332	3,630,471
Total non-current assets	149,110,509	141,828,566	148,448,924
Current assets
Inventories	3,135,409	3,470,843	2,453,998
Trade and other receivables	5,288,979	3,692,002	3,822,520
Short term investments	14,384,412	12,864,667	20,505,130
Cash and cash equivalents	12,177,677	19,873,428	10,036,678
Total current assets	34,986,477	39,900,940	36,818,326
Total assets	184,096,986	181,729,506	185,267,250
Equity and Liabilities
Equity attributable to owners of the parent
Share capital	685,350	685,300	685,300
Share premium	108,486,828	108,475,924	108,475,924
Shares to be issued	6,548,619	5,565,973	6,557,708
Retained earnings	38,507,458	42,020,525	39,812,679
Total equity	154,228,255	156,747,722	155,531,611
Non-current liabilities
Provision for decommissioning	4,500,000	4,500,000	4,500,000
Provision for deferred tax	9,603,255	10,214,111	9,872,917
Total non-current liabilities	14,103,255	14,714,111	14,372,917
Current liabilities
Trade and other payables	15,765,476	10,267,673	15,362,722
Total current liabilities	15,765,476	10,267,673	15,362,722
Total liabilities	29,868,731	24,981,784	29,735,639
Total equity and liabilities	184,096,986	181,729,506	185,267,250

HARDY OIL AND GAS plc

Consolidated Statement of Cash Flows

 

 

	Six months ended 30 June 2010 (Unaudited) US$	Six months ended 30 June 2009  (Unaudited) US$	Year ended 31 December 2009 (Audited) US$
Operating activities
Operating (loss)	(1,491,204)	(5,451,420)	(8,132,172)
Depletion and depreciation	1,723,452	1,116,745	1,252,869
Decommissioning charge	94,290	102,190	104,859
Share-based payments charges	4,278	1,652,470	2,657,572
Cash flow from operating activities (before non cash working capital changes)	330,816	(2,580,015)	(4,116,872)
(Increase)/decrease in inventory	(681,411)	265,594	1,282,439
Decrease/(increase) in trade and other receivables	(1,712,360)	361,826	228,933
(Decrease)/ increase in trade and other payables	402,754	(3,490,426)	1,604,623
Cash flow from operating activities	(1,660,201)	(5,443,021)	(1,000,877)
Taxation paid	(1,986)	(6,626)	(10,088)
Net cash (used in) operating activities	(1,662,187)	(5,449,647)	(1,010,965)
Investing activities
Expenditure of property, plant and equipment	(20,344)	(2,981,107)	(2,853,122)
Expenditure on intangible assets - exploration	(2,294,797)	(4,013,062)	(10,712,286)
Purchase of other property, plant and equipment	(12,798)	-	(8,773)
Site restoration deposit	(151,388)	(239,502)	(418,641)
Short-term investments	6,120,718	9,145,624	1,505,161
Net cash generated from (used in) investing activities	3,641,391	1,911,953	(12,487,661)
Financing activities
Interest and investment income	186,901	118,989	281,292
Finance costs	(36,060)	(33,257)	(71,378)
Issue of shares	10,954	15,186,076	15,186,076
Net cash from financing activities	161,795	15,271,808	15,395,990
Net increase in cash and cash equivalents	2,140,999	11,734,114	1,897,364
Cash and cash equivalents at the beginning of the period	10,036,678	8,139,314	8,139,314
Cash and cash equivalents at the end of the period	12,177,677	19,873,428	10,036,678

HARDY OIL AND GAS plc

Notes to Interim Consolidated Financial Statements (Unaudited)

 

 

1. Accounting Policies

 

Basis of preparation

 

These interim consolidated financial statements are for the six months ended 30 June 2010 and have been prepared in accordance with International Accounting Standard 34 "Interim Financial Statements". The accounting policies applied are consistent with International Financial Reporting Standards (IFRS) adopted for use by the European Union. The accounting policies and methods of computation used in the interim consolidated financial statements are consistent with those used in the Annual Report for 2009 and are expected to be applied for the year ended 31 December 2010.

 

The interim results for the six months ended 30 June 2010 are not necessarily indicative of the results to be expected for the full year 2010.

 

2. Critical Accounting Estimates and Judgments

 

Estimates and judgments are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. The Group makes estimates and assumptions concerning the future. The resulting accounting estimates may differ from the related actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below.

 

(i) Intangible assets - exploration

 

The Group holds a 75 per cent participating interest in the block CY-OS/2 offshore the south east coast of India. Intangible assets include an amount of US$ 83,530,141 with respect to exploration expenditures on the block wherein a gas discovery was announced on 8 January 2007. The exploration period for the block ended on 23 March 2007 and the Government of India (GOI) has been requested to extend the block in terms of the production sharing contract for appraisal and declaration of commerciality for its Non-Associated Natural Gas ("NANG") discovery until 7 January 2012.

 

This request was not accepted by GOI and the matter has been referred to arbitration. Hardy and GOI have appointed their respective arbitrators and the third arbitrator has been appointed by the two arbitrators. Accordingly, it is expected that the Arbitral tribunal process will commence shortly.

 

The Group believes that in line with article 30.5 of the production sharing contract, the termination being the subject matter of proceedings before the Arbitral tribunal under article 33, the termination shall not take place so long as the proceedings continue and thereafter the arbitral award will make a determination with respect to the issue. Furthermore the Group has received third party legal and technical advice which supports its position with respect to the NANG discovery. Therefore, the intangible assets arising from expenditures on this block continue to be recognised at cost and the Directors do not believe that there is any indication of impairment of these costs as at 30 June 2010.

HARDY OIL AND GAS plc

Notes to Interim Consolidated Financial Statements (Unaudited)

 

 

(ii) Decommissioning

 

The liability for decommissioning is based on estimates of the costs of decommissioning that will arise in the future. Significant changes in future costs as a result of technical advancement and other factors can result in a material change to this provision.

 

(iii) Depletion

 

Depletion calculations are based on best estimates 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 prices of crude oil and natural gas, capital expenditure plans, cost of production and other factors. Any changes in these assumptions could result in a material change in the depletion charge or the carrying value of associated assets.

 

3. Loss Per Share

 

The calculation of basic loss per share is based on the loss of US$ 1,305,221 (June 2009: US$ 4,309,330; December 2009: US$ 6,517,176) and a weighted average number of ordinary shares outstanding of 68,497,770 (June 2009: 64,538,546; December 2009: 66,502,242).

 

The diluted loss per share is calculated on the loss of US$ 1,305,221 for the period ended 30 June 2010 (June 2009: US$ 4,309,330; 31 December 2009: US$ 6,517,176) and a weighted average of 71,098,535 ordinary shares for the period ending on 30 June 2010 (June 2009; 69,295,647; December 2009: 71,258,343). The outstanding share options as at 30 June 2010 were 4,655,767, of which the exercise price of 2,043,668 share options exceeded the market price as at 30 June 2010. Accordingly, the potential share options in the money were 2,612,099 as at 30 June 2010.

 

4. Segment Analysis

 

The Group is organised into three business units: India, Nigeria and the United Kingdom. The India business unit is operated by its subsidiary undertaking Hardy Exploration & Production (India) Inc. The Nigeria business unit is operated by Hardy Oil Nigeria Limited. Hardy Oil and Gas plc operates in the United Kingdom.

 

India business unit focuses on exploration and production of oil and gas assets in India. The Nigeria business unit focuses on exploration and production of oil and gas in Nigeria. Management monitors these business units separately for resource allocation, decision-making and performance assessment.

HARDY OIL AND GAS plc

Notes to Interim Consolidated Financial Statements (Unaudited)

	June 2010 US$
	India	Nigeria	UK	Inter-segment eliminations		Total
Revenue oil sales	5,360,870	-	-	-	5,360,870
Other income	-	-	130,905	-	130,905
Management fees	-	-	90,000	(90,000)	-
	5,360,870	-	220,905	(90,000)	5,491,775
Operating profit (loss)	664,648	(366,438)	(1,789,414)		(1,491,204)
Interest income	156,244	-	673,342	(649,429)	180,157
Finance costs	(602,392)	(83,097)	-	649,429	(36,060)
Profit (loss) before taxation	218,500	(449,535)	(1,116,072)	-	(1,347,107)
Taxation	(288,955)	-	330,841	-	41,886
(Loss) for the period	(70,455)	(449,535)	(785,231)	-	(1,305,221)
Segment assets	159,674,662	4,477,811	20,093,713	(149,200)	184,096,986
Inter-corporate loan	-	-	102,826,000	(102,826,000)	-
Segment liabilities	(26,933,601)	(28,872)	(3,055,458)	149,200	(29,868,731)
Inter-corporate borrowings	(95,118,000)	(7,708,000)	-	102,826,000	-
Capital expenditure	2,325,218	-	2,721	-	2,327,939
Depletion, depreciation and amortisation	1,787,086	12,877	17,779	-	1,817,742

 

HARDY OIL AND GAS plc

Notes to Interim Consolidated Financial Statements (Unaudited)

 

 

	June 2009 US$
	India	Nigeria	UK	Inter-segment eliminations	Total
Revenue oil sales	5,666,516	-	-	-	5,666,516
Other income	-	-	133,273	-	133,273
Management fees	-	-	90,000	(90,000)	-
	5,666,516	-	223,273	(90,000)	5,799,789
Operating profit (loss)	(2,987,550)	(264,276)	(2,199,594)	-	(5,451,420)
Interest income	34,611	-	690,861	(633,633)	91,839
Finance costs	(593,898)	(72,992)	-	633,633	(33,257)
Profit (loss) before taxation	(3,546,837)	(337,268)	(1,508,733)	-	(5,392,838)
Taxation	863,225	-	220,283	-	1,083,508
(Loss) for the period	(2,683,612)	(337,268)	(1,288,450)	-	(4,309,330)
Segment assets	149,011,917	4,263,531	28,561,314	(107,256)	181,729,506
Inter-corporate loan	-	-	96,398,000	(96,398,000)	-
Segment liabilities	(21,037,186)	(12,534)	(4,039,320)	107,256	(24,981,784)
Inter-corporate borrowings	(89,700,000)	(6,698,000)		96,398,000	-
Capital expenditure	6,994,169	-	-	-	6,994,169
Depletion, depreciation and amortisation	1,175,446	19,797	23,692	-	1,218,935
	2009 US$
	India	Nigeria	UK	Inter-segment eliminations		Total
Revenue oil sales	7,687,355	-	-	-		7,687,355
Management fees	-	-	180,000	(180,000)		-
	7,687,355	-	180,000	(180,000)		7,687,355
Operating loss	(2,967,105)	(590,071)	(4,574,996)	-		(8,132,172)
Interest income	142,801	-	1,401,316	(1,282,445)		261,672
Finance costs	(1,202,591)	(151,232)	-	1,282,445		(71,378)
Loss before taxation	(4,026,895)	(741,303)	(3,173,680)	-		(7,941,878)
Taxation	323,233	-	1,101,469	-		1,424,702
Loss for the year	(3,703,662)	(741,303)	(2,072,211)	-		(6,517,176)
Segment assets	154,454,229	4,407,428	26,405,593	-		185,267,250
Inter-corporate loan	-	-	97,576,000	(97,576,000)		-
Segment liabilities	(26,392,711)	(9,708)	(3,333,220)	-		(29,735,639)
Inter-corporate borrowings	(90,368,000)	(7,208,000)	-	97,576,000		-
Capital expenditure	13,566,820	-	7,361	-		13,574,181
Depletion, depreciation and amortisation	1,279,846	33,926	43,956	-		1,357,728

HARDY OIL AND GAS plc

Notes to Interim Consolidated Financial Statements (Unaudited)

 

 

5. Taxation

 

	Six months ended 30 June 2010 US$	Six months ended 30 June 2009 US$	Year ended 31 December 2009  US$
Current tax charge
Foreign Tax - India	(227,776)	-	-
Current tax charge	(227,776)	-	-
Deferred tax credit	269,662	1,083,508	1,424,702
Taxation on (loss)	41,886	1,083,508	1,424,702

 

The Group's Indian operations are subject to a tax rate of 42.23 per cent which is higher than UK and US corporation tax rates. To the extent that the Indian profits are taxable in the US and/or the UK, then those territories should provide relief for Indian taxes paid, principally under the provisions of double taxation agreements. Based on the current expenditure plans, the Group anticipates that the tax allowances will continue to exceed the depletion charge of each year, though the timing of related tax relief is uncertain.

 

6. Intangible Assets - Exploration

 

	India US$	Nigeria US$	Total US$
Cost and net book value At 1 January 2009 Additions	120,915,740   4,013,062	3,097,521   -	124,013,261   4,013,062
At 30 June 2009 Additions	124,928,802  6,699,224	3,097,521 -	128,026,323 6,699,224
At 1 January 2010 Additions	131,628,026 2,294,797	3,097,521 -	134,725,547 2,294,797
At 30 June 2010	133,922,823	3,097,521	137,020,344

 

Reference is made to Note 2 - Critical Accounting Estimates and Judgments - Intangible Assets - Exploration.

 

 

 

 

 

 

HARDY OIL AND GAS plc

Notes to Interim Consolidated Financial Statements (Unaudited)

 

 

7. Property, Plant and Equipment

 

Oil and gas assets represent interests in producing oil and gas assets falling under the India Cost pool. There are no oil and gas assets currently in the Nigerian cost pool. Other fixed assets consist of office furniture, computers, workstations and office equipment.

 

	Oil and gas assets US$	Other fixed assets US$	Total US$
Cost At 1 January 2009 Additions Deletions	32,798,667 2,981,107 -	2,689,803 - (87,560)	35,488,470 2,981,107 (87,560)
At 30 June 2009 Additions Deletions	35,779,774 (127,985) -	2,602,243 8,773 (1,744)	38,382,017 (119,212) (1,744)
At 1 January 2010 Additions Deletions	35,651,789 20,344 -	2,609,272 12,798 (15,921)	38,261,061 33,142 (15,921)
At 30 June 2010	35,672,133	2,606,149	38,278,282
Depletion, depreciation and amortisation At 1 January 2009 Charge for the period Deletions	24,576,755 1,118,199 -	2,434,616 60,428 (87,560)	27,011,371 1,178,627 (87,560)
At 30 June 2009	25,694,954	2,407,484	28,102,438
Charge for the period	65,499	48,106	113,605
Deletions	-	(1,744)	(1,744)
At 1 January 2010	25,760,453	2,453,846	28,214,299
Charge for the period	1,750,133	42,422	1,792,555
Deletions	-	(15,921)	(15,921)
At 30 June 2010	27,510,586	2,480,347	29,990,933
Net book value at 30 June 2010	8,161,547	125,802	8,287,349
Net book value at 30 June 2009	10,084,820	194,759	10,279,579
Net book value at 1 January 2010	9,891,336	155,426	10,046,762

 

HARDY OIL AND GAS plc

Notes to Interim Consolidated Financial Statements (Unaudited)

 

 

8. Share Capital

 

The Company has authorised share capital of 200 million US $0.01 ordinary shares.

 

Changes in issued and fully paid ordinary shares during the six months ended 30 June 2010 are as follows:

 

	Number of US$0.01 Ordinary Shares	US$
Beginning of the period	68,530,044	685,300
Shares issued during the period	5,000	50
End of period	68,535,044	685,350

 

 

9. Share Options

 

Changes in outstanding share options during the six months ended 30 June 2010 are summarised below:

 

	Number of options	Weighted average price £
Outstanding at beginning of the period	4,752,101	2.92
Forfeited during the period	(91,334)	3.00
Exercised during the period	(5,000)	1.44
Outstanding at the end of period	4,655,767	2.92
Exercisable at the end of period	4,040,434	2.37

 

 

10. Contingent Liabilities

Bank guarantees totalling US$ 3,644,445 have been issued to the Government of India as at 30 June 2010. The guarantees were obtained by placing a fixed deposit of Rs 26,926,293 (US$ 579,559) with a bank with an interest rate of 6.50 per cent.

 

11. Approval of Interim Consolidated Financial Statements

 

These interim consolidated financial statements have been approved by the Board of Directors on 18 August 2010.

 

 

Assam block licence AS-ONN-2000/1

Board the Board of Directors of Hardy Oil and Gas plc

Bayelsa Bayelsa Oil and Gas Company Limited

the Company Hardy Oil and Gas plc

CPR Competent Persons Report

D3 licence KG-DWN-2003/1 awarded in NELP V

D9 licence KG-DWN-2001/1 awarded in NELP III

DGH Director General of hydrocarbons of the Government of India

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

Dhirubhai 41 gas discovery on KGV-D3-R1 well

DPR Nigerian Department of Petroleum Resources

Emerald Emerald Energy Resources Limited

DGH Directorate General of Hydrocarbons of the MOPNG

Ganesha gas discovery on Fan-A1 well located in CY-OS/2

GCA Gaffney, Cline & Associates Ltd.

GOI Government of India

Group the Company and its subsidiaries

GS-01 licence GS-OSN-2000/1

Hardy Hardy Oil and Gas plc

HEPI Hardy Exploration & Production (India) Inc

HON Hardy Oil Nigeria Limited

HSE Health Safety and Environment

LSE London Stock Exchange

Millenium Millenium Oil and Gas Company Limited

MOPNG Ministry of Petroleum and Natural Gas of the Government of India

NELP New Exploration Licensing Policy of the Ministry of Petroleum and Natural Gas of India

NNPC Nigerian National Petroleum Corporation

OML Oil mining licence

Ordinary Shares the ordinary share of US$ 0.01 each in the capital of the Company

PSC production sharing contract

PY-3 licence CY-OS-90/1

Reliance Reliance Industries Limited

RPS RPS Energy Group

SPDC Shell Petroleum Development Company of Nigeria

 

Glossary of terms:

$ United States dollars

2D/3D two dimensional/three dimensional

API° American Petroleum Institute gravity

BOP blow out preventer

DST drill stem test

DWT dead weight tonne

GOR gas to oil ratio

km kilometre

km2 kilometre squared

lkm line kilometre

m metre

MD measured depth

MMscfd million standard cubic feet per day

MMbbl million stock tank barrels

MMbbld million stock tank barrels per day

NANG non associated natural gas

Prospective Resources those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations

psi pounds per square inch

scf standard cubic feet

scfd standard cubic feet per day

bbl stock tank barrel

bbld stock tank barrel per day

NOTES TO THE EDITORS

 

Hardy Oil and Gas plc is an upstream international oil and gas company whose assets are principally in India. Its portfolio includes a blend of exploration, appraisal, development, and production assets. Hardy's goal is to evaluate and exploit its asset base with a view to creating significant value for its shareholders.

 

Hardy has existing production from an offshore field in India's Cauvery Basin. Hardy also has interests in four offshore exploration blocks in India's Krishna Godavari, Saurashtra, and Cauvery Basins and one onshore exploration block in the Assam Basin and two development licences in Nigeria.

 

Hardy is incorporated under the laws of the Isle of Man and headquartered in London, UK. Ordinary shares of Hardy were admitted to the Official List and the London Stock Exchange's market for listed securities effective 20 February 2008 under the symbol HDY.

 

The Company's Indian assets are held through the wholly owned subsidiary Hardy Exploration & Production (India) Inc, located in Chennai, India. The Company's Nigerian assets are held through wholly owned subsidiary Hardy Oil Nigeria Limited, located in Lagos, Nigeria.

 

For further information please refer to our website at www.hardyoil.com

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Hardy Oil and Gas plc

2nd Floor Lincoln House

137 - 143 Hammersmith Road

London W14 0QL

Tel: +44 (0) 207 471 9850

Fax: +44 (0) 207 471 9851

Investors Relations Contact Dinesh Dattani

[email protected]

This information is provided by RNS

The company news service from the London Stock Exchange