Hardy Oil & Gas plc - Preliminary Results

Thu Apr 10, 2008 2:01am EDT

* Reuters is not responsible for the content in this press release.

RNS Number:0336S
Hardy Oil & Gas plc
10 April 2008

For immediate release                                            10 April 2008

                             Hardy Oil and Gas plc

                         ("Hardy" or the "the Company")

                              Preliminary Results

                      for the year ended 31 December 2007

Hardy Oil and Gas plc (LSE: HDY), the oil and gas exploration and production
company with interests in India and Nigeria, today announces its Preliminary
Results for the year ended 31 December 2007.

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

Operational Highlights


   • 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

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

*Includes after-tax gain of $7.4 million from sale of investment

Commenting on the results, Mr E.P. Mortimer, Chairman of Hardy said:

"2007 was a milestone year for Hardy with significant progress made in all our
assets. We have made an encouraging start in 2008 with the moving of our share
listing from AIM to the Main Market of the London Stock Exchange and two
discoveries on the D3 block.

Our exploration success in India underpins our strategy to create shareholder
value through high impact exploration interests and mitigating risk through
appropriate partnerships. 2008 will be an important year in our exploration,
appraisal and development programmes and we look forward to it with

Conference Call

Buchanan Communications will be hosting, on behalf of the management of Hardy,
an analyst conference call today at 09.00 a.m. (UK). Management will present the
results, after which the lines will be open for questions.

For further information please contact

Hardy Oil and Gas plc                                              020 7471 9850
Sastry Karra (Chief Executive)
Yogeshwar Sharma (Chief Operating Officer)
Dinesh Dattani (Finance Director)

Arden Partners plc                                                 020 7398 1600
Richard Day
Tom Fyson

Buchanan Communications                                            020 7466 5000
Mark Edwards
Ben Willey

Chairman's Statement


2007 was another successful year for our growing company. The Board remained
focused on executing the Company's strategy of creating shareholder value
through the de-risking of the Company's Indian exploration portfolio, whilst
continuing production from its development assets.

The year commenced with the announcement of the Ganesha discovery on the
Hardy-operated CY-OS/2 exploration block on the east coast of India. This was
followed by the announcement in May of the Dhirubhai 33 gas discovery on the
GS-01 exploration block on the West Coast of India.

The Company completed a further placing of new Ordinary Shares in June raising
over $40.2 million to fund our ongoing capital programme at 423 pence per share.

2008 has also started well, with the recent announcements of two consecutive
discoveries on the D3 exploration block on the east coast of India and the
expansion of the Company's exploration portfolio with the granting of a
petroleum exploration licence for the AS-ONN-2000/1 onshore block in Assam,


During the year, the Board took the decision to move the listing of Hardy's
shares from AIM to the Official List of the London Stock Exchange's market for
listed securities ("Main Market"). The admission of Hardy's shares to the Main
Market should assist in increasing the profile and liquidity of the Company's
Ordinary Shares whilst increasing access to capital to fund its future
exploration and development expenditures.

Hardy's shares began trading on the Main Market on 20 February 2008 and with
effect from 26 March 2008 Hardy's shares have been included in the FTSE 250

The senior executive team has been strengthened with the appointment of Mr
Dinesh Dattani in July 2007 as Finance Director. Mr Dattani's strong financial
background in the upstream oil and gas industry provides greater balance to the
executive team. We will continue to look for appropriate additions to strengthen
the Board and the senior management team.


We will continue to work closely with the Ministry of Petroleum and key industry
groups, in connection with the Government of India's recent intervention in gas
pricing and proposed modification to the tax holiday, to help ensure that our
interests and those of all operators in India are protected.

Over the past decade the oil and gas industry in India, in partnership with the
Government, has invested heavily in various midstream and upstream projects. In
2008, the first gas production from the Reliance Industries Limited (Reliance)
operated D6 block adjacent to the Company's D9 block in the Krishna Godavari
basin will commence and this will significantly increase the supply of gas into
the energy-constrained Indian market. The infrastructure and market development
associated with this east coast domestic gas supply augurs well for rapid
exploration and development of the D3 and D9 blocks in the Krishna Godavari
basin in which Hardy has an interest.

The Board looks to the balance of 2008 with great anticipation. In 2008, the
Company is planning for the largest drilling programme in its history with six
exploration wells and up to two appraisal wells. Our asset base has also
increased in India with the addition of the Assam block providing further
long-term growth potential. The Company is in excellent shape and we are
enthusiastic about the year ahead.

E.P. Mortimer


9 April 2008

Chief Executive's Review

Summary of the Year

2007 was a landmark year for Hardy. In India, our discovery on CY-OS/2 block
(Ganesha) has increased the Company's Contingent Resource inventory, which will
be further appraised in the latter part of 2008 and early 2009 with the drilling
of three wells on the Fan-A discovery.

The announced discovery of Dhirubhai 33 on the GS-01 block, with our partner
Reliance, also contributed to the growth of our Contingent Resource inventory.
An appraisal programme has been proposed by the operator and is currently under
review by the joint venture. Drilling of an additional three exploration wells
will commence in the second quarter of 2008 targeting several other independent

The recent KGV-D3-A1 (Dhirubhai 39) and KGV-D3-B1 (Dhirubhai 41) gas discoveries
on the D3 block are an encouraging start to evaluating the prospectivity of this
block. We anticipate that the newly acquire 3D seismic will identify further
drilling prospects as we complete the full evaluation of the block.

Key Financial Results

Revenue in 2007, as anticipated, decreased to $11.8 million in 2007 compared to
$21.3 million in 2006. This was due to several factors including the expected
increase in the Government of India's profit oil share, a decrease in production
levels and an increase in closing inventory. Net profit was $8.3 million
compared to $10.2 million in 2006. The Company also realised a gain of $10.2
million from the sale of shares in Hindustan Oil Exploration Company Limited

Diluted earnings per share were $0.13 in 2007 compared to $0.17 for 2006. We
anticipate that earnings will continue to fall in 2008 as PY-3 operating and
Group administrative costs have increased while production from PY-3 will
decline from 2007 levels.

The active drilling programme in 2007 resulted in capital expenditures of $32.2
million compared with $51.6 million in 2006.

At the end of 2007, the Company had cash reserves of $31.2 million. In 2007, the
Company raised $40.2 million through a placing of 5,009,541 ordinary shares. The
Company participated in an HOEC rights issue and also partially liquidated its
investment in HOEC resulting in a net addition to cash resources of $7.4 million
during January 2008.


In 2007 the major focus of the Company was on the Hardy-operated assets, CY-OS/2
exploration licence and PY-3 production block.

PY-3 - Production from the PY-3 field was lower than expected in 2007 due to the
shut-in of the PY-3-3RL well in August 2007. The drilling of two additional
wells (Phase III) is on-track but additional production from this drilling
programme is not expected until 2009.

CY-OS/2 - The Fan-A1 well discovery (Ganesha) was announced at the beginning of
the year and the focus quickly turned to evaluating results and, subsequently,
submitting an appraisal programme to the CY-OS/2 joint venture. The additional
geological and geophysical work, along with well planning, remains a focus of
the Group as we move into 2008. We are considering farming-out a portion of our
interest to be more consistent with the risk profile of the Company's other
exploration assets.

Results on our non-operated exploration assets have also been encouraging as we
continue to pursue our strategy of de-risking this portfolio.

GS-01 - The gas discovery in well GS-01-B1 (Dhirubhai 33) was the second well to
be drilled under this exploration licence. The operator has submitted an
appraisal programme which is awaiting approval. A further three exploration
wells are scheduled to commence drilling in the second quarter of 2008.

The assets that continue to generate the most interest and anticipation are the
Company's Krishna Godavari basin blocks D9 and D3.

D9 - Due to the industry-wide shortage of drilling ships capable of operating in
water depths greater than 2,000 m, delays have been experienced on the D9
exploration licence. We anticipate that drilling of the first well on the D9
block may commence before the end of 2008.

D3 - The drilling phase on D3 began much sooner than expected with the
commencement of drilling of the first well at the end of 2007. Subsequently we
were pleased to announced two successive gas discoveries on the block with
encouraging initial testing results including an observed flow rate of 38.1
MMscfd. We anticipate that the operator will submit an appraisal programme for
approval shortly. Further drilling on the D3 block is not expected to commence
until the first quarter of 2009 as the joint venture evaluates the additional
2,800 km2 of 3D seismic acquired in 2007.

Assam - As announced on 3 April 2008, the pursuit of our Indian strategy
resulted in the award of the Assam onshore petroleum exploration licence
AS-ONN-2000/1. We are also delighted with the Company's continued partnership
with Reliance. This is the fourth block that Hardy holds in partnership with
Reliance and the Company's first onshore asset in India. The block provides
further long-term potential to create significant shareholder value.


We observed several key milestones with respect to our Nigerian operations.

Oza - Hardy was able to conduct its first full field operation with the well
flow test of Oza-4. The initial results are positive and, more importantly, the
operator received cooperation and support from the local communities. We have
established open channels of dialogue with all stakeholders in the Oza
communities and we look for this to continue as we move towards initial field
development in the latter part of 2008.

As announced on 3 April 2008 the Company entered into an agreement to farm-out a
20 per cent. interest in the Oza block to Emerald Energy Resources Limited
(Emerald). Emerald has agreed to assume Hardy's financial obligations in the
funding of the Oza field initial development programme.

Atala - Securing the necessary equipment for the planned re-entry operating in
Atala continues to be difficult. The Company's Nigerian management team have
been working closely with a consortium of swamp operators. This group has
several options available to them and we anticipate that greater clarity on the
timing of operation will be achieved in 2008.

2008 Programme

We are looking forward to an active 2008 with the following plan of work:

   • GS-01 - Drilling of three exploration wells
   • D3 - Processing and interpretation of acquired 3D seismic data
   • D3 - Submission of appraisal programme for Dhirubhai 39 and 41 discovery
   • CY-OS/2 - Commencement of appraisal drilling to assess Ganesha discovery
   • D9 - Commencement of exploration drilling programme

• Assam - Acquisition of 350 line km of 2D seismic data

   • Oza - Commence field development operations.

The Company will continue to focus on organic growth as our primary strategy to
create shareholder value. The NELP rounds have become increasingly competitive;
however, they still offer the most direct way of acquiring exploration acreage
in India.


The accomplishments of 2007 would not have been possible without the dedication
of the Company's staff in India, Nigeria and London, UK. The India team
continues to drive the core of our business. The Nigerian team have reached a
key milestone in 2007 despite challenging conditions. The corporate team in
London, along with the India team in Chennai, were instrumental in the efficient
execution of the Main Market listing. I would like to take this moment to
recognise them all for their efforts in the past year.

Sastry Karra

Chief Executive

9 April 2008

Review of Operations

At the beginning of 2007, the Company planned to drill three exploration wells,
conduct a production test of two wells in Oza, and acquire 3,288 km2 of 3D data.
At the end of 2007, the Company had participated in the drilling of three
exploration wells, the production testing of one well and the acquisition of
2,800 km2 of 3D seismic.

During 2007, and as part of the process of moving the Company to the Main
Market, an independent report was prepared for the Company by Gaffney, Cline &
Associates Ltd (GCA) on the reserves and resources inventory of the Company. As
at 30 June 2007, GCA estimated 2.69 million barrels of Proved plus Probable (2P)
net entitlement reserves in the PY-3 field.

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

CAUVERY BASIN - Eastern India

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

(Hardy 18% interest - Operator)


Actual gross field production for the year ended 31 December 2007 was 4,150 stbd
(2006: 5,811 stbd). The production facilities' uptime performance was 96.8 per
cent. (2006: 96.7 per cent.). The decrease in production was attributable to the
seizure of the PY3-3 RL well, due to water loading, in August 2007 and the
failure of the Endeavor's (FSO) mooring system in December 2007 (resulting in 11
days' shut-in).

The production forecast for 2008 is 2,700 stbd, reflecting the expected
continued natural decline of the field. In 2008, around 10 days' downtime is
anticipated due to the need to carry out under water inspection and maintenance
work on Normor Buoy (SPM) to comply with ABS certification requirements.
Increase in PY-3 production is not anticipated until 2009.

For the year ended 31 December 2007 the average water injection rate was 5,800
bwpd (2006: 6,678 bwpd) which, at current production levels, is sufficient to
maintain voidage replacement. Injection facilities' uptime performance was 86.8
per cent. (2006: 96.7 per cent.). The reduction in uptime was attributable to
the scheduled plant shutdown in March 2007 for further the under water
inspection and for rectifying the FSO forward mooring system in December 2007.


The PY-3 field joint venture has approved a $90.0 million Phase III development
programme which provides for the drilling of two additional lateral wells (one
producer and one injector) and various gathering lines and facility upgrades.
The Company has issued a request for tender for long-lead items such as subsea
trees and flow lines.

In order to identify a suitable production facility for the operation of the
PY-3 field beyond July 2009, Hardy commissioned a Conceptual Field Design study
that was undertaken by ODE Ltd, UK. Based on the recommendations obtained from
the ODE study, further investigations are in progress to select a suitable
production facility.


The PY-3 field is located off the East Coast of India 80 km south of Pondicherry
in water depths of between 40 and 200 m. The Cauvery basin developed in the late
Jurassic/early Cretaceous period, and straddles the present-day East Coast of

The licence, which covers 81 km2, is currently the deepest producing subsea
field in India and produces oil of high quality light crude (49degrees API). The
field was developed using floating production facilities and subsea wellheads, a
first for an offshore field in India.

HEPI is the Operator of the PY-3 field, and the participating interests for this
licence are as follows:

     HEPI             TATA                HOEC                   ONGC
     18%               21%                 21%                   405

The facility at PY-3 consists of the floating production unit, ''Tahara'', and a
65,000 DWT tanker, ''Endeavor'', which acts as a floating storage and offloading
unit. There are four sub-sea wells tied back to Tahara. Tahara has a three-stage
crude oil separation system, with the first two stages being three-phase
separators and the third stage a two-phase separator. Actual liquid processing
capacity on Tahara is 20,000 stbd with 17 MMscfd of gas handling capacity.

The field currently produces associated gas in the range of 3.5 MMscfd. This
produced gas is used as fuel gas, with excess gas being flared. The stabilised
crude oil is pumped from Tahara to Endeavor for storage and offloading to
shuttle tankers. Crude oil from the PY-3 field is sold to CPCL at its refinery
in Nagapattinam, approximately 70 km south of the PY-3 field.

CAUVERY BASIN - Eastern India

Block CY-OS/2: Exploration

(Hardy 75% interest - Operator)


In 2007 HEPI completed the exploration licence's phase III minimum work
programme. On 8 January 2007 the Company announced that the Fan-A1 well had
discovered hydrocarbons. On 10 August 2007 the Company announced that it would
proceed with an appraisal programme to delineate the Cretaceous Fan-A1 discovery
to establish the potential commerciality of the Cretaceous with the planned
drilling of three further wells.

As part of the appraisal programme a number of geological and geophysical
studies have been undertaken, including the reprocessing of the 3D seismic data
covering the block to improve subsurface imaging. Special studies such as AVO
and inversion are ongoing to improve characterisation and delineation of the

Analysis of oil and gas crude samples and other well data from the Fan-E1 and
Fan-A1 wells were also undertaken in 2007, including geochemical studies.

HEPI has recently hired a third party to begin the well planning work and to
provide well management services and consultation through the entire appraisal
drilling programme. Subject to rig availability, the drilling portion of the
appraisal programme is expected to start in the fourth quarter of 2008.

The Board is presently considering farming out a portion of its participating
interest in the licence.


The CY-OS/2 block is located in the northern part of the Cauvery Basin
immediately offshore from Pondicherry and covers approximately 859 km2. The
CY-OS/2 licence comprises two retained areas. The northern area includes the
Fan-A1 discovery. The southern area lies immediately adjacent to the HEPI
operated PY-3 field. The PY-1 gas field lies within the southern part of the
acreage and is expected to begin production by the first quarter of 2009.

HEPI is the operator of this licence. The participating interests in licence
CY-OS/2 are as follows:

CY-OS/2                              HEPI     GAIL       ONGC*
Participating interest                75%      25%         -

*In the event of a commercial discovery, ONGC has the option to back into the
CY-OS/2 licence at an interest of 30 per cent.

The PY-3 oil field and PY-1 gas field are both contained within the CY-OS/2
licence but have been ring-fenced out, each with a separate PSC. The CY-OS/2
exploration licence has been under an approved phase III extension which expired
at the end of March 2007. HEPI, as operator of the joint venture, has fulfilled
the exploration phase III commitment work programme of 3D seismic surveys and
drilling of two exploratory wells.


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

(Hardy 10% interest)


To date the GS-01 joint venture has drilled two exploration wells on the GS-01
block. On 15 May 2007 Hardy announced that the second exploration well,
GS-01-B1, had discovered hydrocarbons in the mid-Miocene Limestone (Dhirubhai
33). The exploration well was drilled to a depth of 2,282 m MDRT and encountered
natural gas and condensate within the mid Miocene Limestone over an interval
from 1,988 m to 2,052 m MDRT.

The two intervals selected for cased hole DST were 1,988 m to 1,993 m and 2,019
m to 2038 m MDRT respectively. The test produced natural gas at a rate of 18.6
MMscfd together with 415 stbd of condensate through a 56/64 " choke with a
flowing tubing head pressure of 1,346 psi.

The operator has subsequently proposed an appraisal programme involving
additional 3D seismic data interpretation, development concept studies, reserve
assessment and validation, and two contingent appraisal wells. The appraisal
wells will be dependent on the findings of the proposed studies.

The proposed exploration programme for 2008 comprises of the acquisition of an
additional 1,000 km2 of 3D seismic and the drilling of three further exploration
wells which will meet the phase I work commitment for the exploration licence.
The 3D seismic acquisition programme was completed in March 2008 covering 1,165
km2 and processing and interpretation is expected to be fast-tracked by the
operator. The three-well drilling programme is expected to commence by the end
of April 2008.

In 2008, the GS-01 joint venture will be required to elect to proceed to phase
III of the exploration licence or relinquish the block not covered by the
appraisal programme. The minimum work programme for phase III stipulates the
drilling of eight exploration wells.


The GS-01 exploration licence is located in the Gujarat-Saurashtra offshore
basin, off the west coast of India, directly adjacent to the prolific Bombay
High oil field. The licence encompasses 8,841 km2, and water depths vary between
80 and 150 m. The joint venture has previously acquired 1,216 km2 of 3D seismic.

The participating interests for this licence are as follows:

Area                  HEPI                 Reliance
GS-01                 10%                       90%

Typical trap types within this basin are fault-bound anticline and stratigraphic
carbonate traps (including reefal structures and carbonate build-ups). The
identified prospects are located in the Miocene, Oligocene and Eocene carbonates
and Paleocene Basal clastics.


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

(Hardy 10% interest)


As announced by the Company on 13 February 2008, after careful consideration of
the current equipment shortage and the priority of the operator to complete
offsetting commercial developments, the Board is of the view that drilling on
the D9 licence is unlikely to commence until the latter part of 2008.

However, as experienced with the D3 licence, windows of availability do occur
and the Directors will endeavour to ensure that shareholders are notified of
developments on a timely basis.

During 2007, the operator continued to interpret and evaluate the 3D seismic
data. PSDM reprocessing 3D seismic data was completed and the data is being
studied to optimise the selected locations for drilling. Sea-bed logging was
also conducted and the results provided encouraging results with similar
indicators observed in the adjacent D6 block.


The licence encompasses 11,605 km2 in the Bay of Bengal where water depths vary
from 2,300 m to 3,100 m. The participating interests for this licence are as

Area               HEPI                  Reliance
D9                  10%                      90%

The joint venture has acquired over 4,188 km2 of 3D seismic and leads at Upper
Miocene, Middle Miocene and Oligocene have been identified. These leads are
areally large structural closures located toward the, relatively shallower-water
north-western corner of the concession, for which GIIP of many TCF has been
computed by the operator. A fourth lead is a Pleistocene channel in the south
eastern part of the block which is in ultra deep water with a prognosticated
GIIP of a similar order of magnitude to the other leads.

Initial exploration will be focused upon amplitude anomalies within closure in
the Miocene and Pliocene rather than a pure structural play. There are many
seismic anomalies within the block and, given its proximity to D6, exploration
potential of this large block is regarded with considerable optimism.


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

(Hardy 10% interest)


In 2007 the operator acquired 2,800 km2 of 3D seismic data. The D3 joint venture
has also taken the decision to process and evaluate the acquired data prior to
acquiring additional data with the intention of modifying the acquisition
parameters to optimise the data quality.

The exploration drilling programme commenced earlier than expected on 28
December 2007, with the KGV-D3-A1 well which has resulted in the first discovery
on this licence named Dhirubhai 39. The well was drilled to a depth of 1,937 m
MDRT and encountered natural gas between 1,513 m and 1,597 m MDRT with a gross
sand thickness of 84 m.

One interval was selected for cased hole DST covering 1,565 m to 1,585 m MDRT
and produced natural gas at a rate of 38.1 MMscfd through a 120/64" choke.

The D3 joint venture then moved the rig ''C Kirk Rhein'' to a second location
(KGV-D3-B1) to evaluate the Pleistocene and Late to Mid Miocene sandstone
reservoirs. On 1 April 2008, the Company announced a second discovery (Dhirubhai
41) on the D3 block. The well encountered good quality reservoirs in the
Pleistocene and Miocene formations. MDT tests were conducted over several
intervals (1,814 to 2,101 m MDRT and 2,119 to 2,463 m MDRT) and confirmed the
presence of hydrocarbons. Several gas samples were collected over both intervals
however due to poor well bore casing integrity, a decision was taken to not
conduct a DST and the well was plugged and abandoned.

Although early indications are encouraging, the potential extent and
commerciality of the Dhirubhai 39 and 41 discoveries is yet to be established.
On 31 March 2008 the operator issued a B-1 notification to DGH stating the
details of the tests carried out. It is anticipated that the operator will
submit an appraisal programme for approval in the second half of 2008.


In August 2005, Reliance and HEPI were awarded, under NELP V, a second licence
in the deepwater Krishna Godavari Basin. The D3 licence encompasses an area of
3,288 km2, in water depths of 400 m to 2,100 m, and is located approximately 45
km from the east coast. Reliance is the operator. The participating interests
for this licence are as follows:

Area                       HEPI                         Reliance
D3                          10%                             90%

The licence had approximately 410 km2 of existing 3D seismic data, which has
been reprocessed. The A-1 and B-1 locations were identified after this data was
interpreted and mapped.

ASSAM ARAKAN BASIN - North Eastern India

Block AS-ONN-2000/1: Exploration

(Hardy 10% interest)


On 2 April 2008, Hardy was pleased to announce the award of a 10% interest in
the exploration licence AS-ONN-2000/1. This is the Group's first onshore block
and fourth licence in partnership with Reliance. This block was offered in NELP
II but commencement of operations had been delayed due to the outstanding grant
of an onshore petroleum exploration licence from the appropriate state agencies.

The proposed 2008 work programme primarily involves the reprocessing of the 124
line km (lkm) of existing 2D seismic data. Field operations are expected to
commence in the fourth quarter of 2008 with the acquisition of approximately 350
lkm of 2D seismic data. This will meet the phase I minimum work programme
commitment for the block.


The AS-ONN-2000/1 exploration licence is located in the north eastern state of
Assam, India, and north of Brahmaputra River. The exploration licence covers an
area of 5,754 km2 and falls within the districts of Darrang and Sonitpur. The
block is in phase I of the three-phase exploration licence. Phase I is over
three years and will expire in the month of January 2011. The participating
interests for this licence are as follows:

Area                          HEPI                       Reliance
Assam                          10%                          90%

The topography of the area is primarily plain of low relief and there is a
reasonably established road network across the block. A national highway runs
parallel to river Brahmaputra and passes through the block.

Assam foreland constitutes the shelf part of Assam - Arakan intermontane basin.
It forms a north-east south-west trending, largely alluvium-covered, narrow,
linear tract encompassing an area of 40,000 km2. The exploration block lies
north of Brahmaputra River while most of the discovered oilfields in the basin
are located south of Brahmaputra River over an area of approximately 4,000 km2.

Intense exploration activities since 1956 have resulted in the discovery of
seven major fields which include Naharkatiya, Moran, Rudrasagar, Geleki and
Lokwa. Most of these fields have reached a mature stage of exploration for
Mio-Pliocene reservoirs and are in the advanced phase of delineation and

Very limited seismic data is available only in the eastern-most part of the
block and suggests the presence of subsurface structure. Different play types
expected are as follows:

     • Anticlinal structures within Paleocene - Eocene and Gondwana
     • Fault closures
     • Pinchout / wedgeout
     • Fractured / weathered basement


Block Oza (OML 11): Development

(Hardy 20% interest)


In November 2007 the Oza joint venture successfully executed a flow test of the
Oza 4 well. Oil and gas production rates, reservoir pressures and crude samples
were obtained during the test. This is a significant step towards full
development of the field. As technical partner, HON has worked closely with the
operator to design and implement the field operation. The flow rates averaged
approximately 600 stbd of oil with a GOR of 5,466 scf/stb. The operator
transported and sold the produced fluids without incident.

Millenium Oil and Gas Limited, the operator for Oza field, with inputs from HON,
continued efforts to obtain additional field data in the field and to conclude
agreements for crude handling and purchase of Oza 3D seismic with Shell
Petroleum Development Company (SPDC).

Discussions are ongoing with the operator of an adjacent export facility at a
near-by flow station. Current discussions suggest that the initial work
programme will entail the installation of a 9 km multiphase pipeline to SPDC's
Isimiri flow station. To comply with the Nigerian government's no-flare
initiative, associated gas will need to be exported to an alternative facility
with a gas export line.

Recently HON has entered into a farmout agreement with Emerald Energy Resources
Nigeria Limited (Emerald), a well-known local oil and gas company. Under the
terms of the farm-out agreement Emerald assumes HON's obligation to fund the
initial work programme of the Oza field. The capital expenditure is currently
estimated at approximately $15 million. The farm-out is subject to government

Community relations will continue to be a focus of the operator and progress is
expected in discussions regarding a sustainable agreement with the host
communities surrounding the Oza field. Emerald has extensive experience and
expertise in community relations and has committed to make available its
experienced personal to the operator.


The Oza Field is located on-land in the north-western part of OML 11, near Port
Harcourt. The concession area is 20 km2. The participating interests for this
licence are as follows:

Area            HON                Millenium                    Emerald
Oza             20%                   60%                         20%

The Oza field is subject to a farm-out agreement between NNPC, SPDC, Elf
Petroleum Nigeria Limited and AGIP as farmor and Milennium as farmee. The terms
of this agreement are for an initial five year period from 27 April 2004 subject
to an extension of the Oza Farm-out Agreement if approved by the Nigerian
Department of Petroleum Resources (DPR).

The field has cumulatively produced approximately 1.0 MMstb from four open zones
of three wells targeting three reservoirs, M5.0, L9.0 and M2.1, with the
principal reservoir being M5.0. At present, Oza has three suspended wells in the

Since taking over the field in 2004, Millenium, along with HON, has completed a
number of field operations and other studies. The log data of existing wells has
been re-analysed both internally and through third party study to identify
potential re-completion targets. There is existing 3D seismic data covering the
Oza field. Negotiations between SPDC and Millenium for the acquisition of this
data are ongoing.


Block Atala (OML 46): Development

(Hardy 20% interest)


In 2007 the Atala joint venture continued to struggle to secure the appropriate
drilling equipment for a planned re-entry and test programme. The operator, with
the help and support of Hardy, has taken the initiative to form a swamp
operators group, comprising of several companies with fields in the swamps to
collectively approach potential drilling companies with suitable rigs. Meetings
were held in the latter half of 2007 and potential vendors have been identified.

During 2007, a field development plan (FDP) report was completed by local
consultant Eogas with close involvement and inputs from HON. The FDP recommends
a phased approach, initially focusing on oil development with later completion
for gas production and based on initial production from the two wells, drilling
of new oil and gas wells.

Recently the swamp operators group has identified and commenced negotiations
with several vendors for a swamp barge. It is expected that a rig will be
identified and a contract negotiated in the latter half of 2008 and the Atala
operations may commence in the first quarter of 2009, with the re-entry of
Atala-1 well. HON is working closely with the operator to finalise the re-entry
programme, obtain government approvals, appoint competent company for
procurement, logistics and rig management and ensure all long lead items are
procured in timely fashion. The Atala FDP has been presented to the federal
government for its approval.


Atala is located within OML 46 which is located in a mangrove swamp on the Dodo
River, a coastal area of NW Bayelsa State. The concession area is 34 km2. The
Atala field was discovered in 1982 with the drilling of the Atala-1 well to a
total depth of 4,058 m. Hydrocarbons were encountered and the well was cased but
not tested or completed. The participating interests for this licence are as

Area             HON                Millenium                   Emerald
Atala            20%                    60%                      20%

The Atala field is subject to a farm-out agreement between NNPC, SPDC, Elf
Petroleum Nigeria Limited and Nigerian AGIP Oil Company Limited as farmor and
Bayelsa as farmee. The terms of this agreement are for an initial five-year
period from 27 April 2004, subject to an extension of the term of the Atala
Farm-out Agreement if approved by the Nigerian Department of Petroleum

HON entered into a farm-in agreement with Bayelsa pursuant to which Bayelsa
agreed to farm out a 20 per cent. participating interest in the Atala field to
HON. HON also agreed to act as technical partner for the development and
operation of the Atala field.

The proposed development plan involves two phases. The first phase envisages the
re-entry, testing and completion of the existing Atala-1 well and the drilling
of a second lateral well to optimise oil drainage. AGIP operated Clough Creek
field is the intended destination of Atala oil for evacuation.

Yogeshwar Sharma

Chief Operating Officer

9 April 2008



Hardy has a mandatory requirement to implement International Financial Reporting
Standards ("IFRS") for accounting periods commencing 1 January 2007.

In order to comply with IFRS, Hardy has restated consolidated and company
financial statements for 2006 and has revised its accounting policies. Hardy has
also prepared a reconciliation of its consolidated and company financial
statements under UK GAAP to those prepared under IFRS. In addition, Hardy has
prepared statements reflecting the revised opening balance s at 1 January 2006.

Key Performance Indicators

                                                                   Year ended 31
                                                             2007         2006
                                                         ----------    ---------
Production (barrels of oil per day - net entitlement
basis))                                                       573          844
Average realised price per barrel - Dollars                 66.65        64.82
Average cost per barrel - Dollars                           21.19        13.64
Revenue (thousands of Dollars)                             11,830       21,317
Net profit (thousands of Dollars)                           8,316       10,233
Cash flow from operations (thousands of Dollars) *          2,588       14,555
Diluted earnings per share - $                               0.13         0.17
Wells drilled                                                   2            2

*Before change in non-cash working capital

Operating Results

(In thousands of Dollars unless otherwise indicated)    Year ended 31 December
                                                            2007          2006
                                                          --------     ---------
Production (Barrels of Oil per Day)                        4,150         5,811
Gross Field                                                  747         1,046
Participating Interest                                       573           844
Net Entitlement Interest
Sales (Barrels of Oil per Day)                             3,547         5,831
Gross Field                                                  638         1,050
Participating Interest
Average Realised Price per Barrel - $                      66.65         64.82

Production, Sales and Revenue

The Company operates the PY-3 field in the Cauvery Basin with an 18 per cent
participating interest. Since August 2007, one of the three producing wells in
the PY-3 field has been shut in due to excessive water production. As a result
of natural decline, PY-3 field crude oil production was lower by 29 per cent.
during 2007 from the same period in 2006. Current oil production is at a level
of approximately 3,050 stbd. The Company does not expect to recover additional
production until the implementation of the PY-3 field's Phase III development.

Hardy's net entitlement interest in production is after the Government of
India's share of profit oil. Under the terms of the PSC, profit oil increased
from 10 per cent to 25 per cent effective 1 April 2005 and was further increased
to 40 per cent on 1 April 2006. On 1 April 2008, profit oil is expected to
increase to 50 per cent.

Revenue, after profit oil, declined from $21.3 million in 2006 to $11.8 million
in 2007. The average price realised per barrel increased marginally to $66.65
during 2007. No sales took place during the fourth quarter of 2007 and all
production during that period was held in inventory. Reduced revenue in 2007
resulted from lower production levels, higher inventory levels and higher profit
oil to the Government of India.

Cost of Sales

Cost of sales for 2007 increased by $0.6 million during 2007. This results
principally from higher costs of operating the PY-3 field. The contract for the
floating processing and storage systems was renegotiated effective July 2007
resulting in a substantial increase in day rates. The increase in operating cost
was offset in part by lower depletion and decommissioning costs.

Gross Profit

Gross profit declined from $16.1 million in 2006 to $6.1 million in 2007; the
reduction principally stemming from lower revenues and higher operating costs
from July 2007.

Other Operating Income

An insurance claim of $1.0 million was received for business interruption caused
by an operational accident in the year 2002. This has been accounted for as
other operating income in 2006 when insurance proceeds were received.

Administrative Expenses

Administrative expenses increased from $5.7 million in 2006 to $6.9 million in
2007. The increase principally results from a higher share based payment expense
by $0.9 million for the stock options granted by the Company to its directors
and employees since 2005. During 2007, costs include those relating to the move
from AIM to the Main Market, higher manpower costs with the addition of an
additional executive director and higher remuneration of executive directors.

Operating Profit (Loss)

As a result, the Company is reporting an operating loss of $0.8 million compared
with an operating profit of $11.4 million reported in 2006.

Gain on Sale of Investment

During December 2007, the Company sold 3,010,000 ordinary shares of HOEC for a
cash consideration of $12.5 million which was received in January 2008. As a
result, the Company recorded a gain on sale of investment of $10.2 million. The
after-tax gain amounted to $7.4 million or $0.11 per share.

Investment and Other Income

Investment and other income declined from $2.3 million in 2006 to $1.4 million
in 2007. The decline was the result of reduced deposits and lower interest rates
in 2007 compared to 2006.

Finance Costs

Finance costs principally include the cost of providing bank guarantees to the
Government of India required in accordance with the provisions of Production
Sharing Contracts and are based on the agreed work programme on blocks in India.


Most of the provision for taxation is with respect to deferred income taxes
since the Company's capital expenditure programme is sufficient to shield the
Company from a large portion of current tax liabilities. The group's Indian
operations can avail the treaty benefit for the taxes suffered either in India,
the UK or the USA and the group could also benefit from prior year capital
losses by way of group relief for the capital gain made in sale of investment in
HOEC shares.

Net Profit

As a result, net profit declined from $10.2 million in 2006 to $8.3 million in

Cash Flow from Operating Activities

Cash flow from operating activities, before changes in non-cash working capital,
has declined from $14.5 million in 2006 to $2.6 million in 2007. This results
principally from lower revenues arising from lower production volumes and higher
profit oil to the government, and higher operating and administrative costs.

Changes in non-cash working capital principally reflect reduction in debtors
(excluding receivable from the sale of investment of $12.5 million that was
received in January 2008) as a result of lack of sales in the fourth quarter of
2007 and a significant reduction in creditors. At the end of 2006, the Company
was in the process of drilling a well on its CY-OS/2 block in which it has a 75
per cent. participating interest.

Capital Expenditures

The Group's capital expenditures amounted to $32.2 million during 2007, compared
to $51.6 million incurred during 2006. Capital expenditures amounting to $21.9
million were incurred on the CY-OS/2 block with the drilling of the successful
Fan-A1 well. The Company expended $4.2 million with respect to its interest in
the GS-01 block with the drilling of the B-1 discovery well. Expenditures on the
D3 block amounted to $4.6 million with the acquisition of 2,800 km2 of 3D
seismic and the commencement of the drilling of the first well on 28 December
2007. Approximately $1.0 million was incurred with respect to the Company's
operations in Nigeria, principally with respect to the testing of a well in Oza
and ongoing expenditures. The drilling has resulted in discoveries on the CY-OS/
2, GS-01 and D-3 blocks and the test on Oza has been successful as well.

During 2006, Hardy incurred a significant amount of capital expenditures on the
CY-OS/2 block. As of 31 December 2006, Hardy had invested $59.5 million for its
share of the drilling and testing of the two wells which included costs
associated with the side track of the second well. In 2006, Hardy also
participated in the drilling of the A-1 well on the GS-01 block. In the Krishna
Godavari Basin on the east coast of India, 3,440 km2 of 3D seismic data has been
acquired over the D9 block during 2006, which has now been processed and
interpreted, and six prospects have been identified for drilling.

Investment in HOEC

The Company had an investment of approximately 8.5 per cent. in shares of HOEC,
a publicly traded company in India. HOEC's primary assets are a 21 per cent.
participating interest in PY-3 and a 100 per cent. participating interest in
PY-1 (a gas discovery adjacent to PY-3 and ring-fenced by the CY-OS/2
exploration licence). In October 2006, HOEC raised approximately $33.0 million
via a public rights issue in which Hardy took up its pro-rata entitlement at a
cost of $2.8 million.

In December 2007, the Company sold 3,010,000 shares of HOEC for a cash
consideration of $12.5 million. In early January 2008, HOEC completed a rights
offering with Hardy participating in the rights offering to the extent of its
pro rata share investing an additional $13.2 million. In January 2008, the
Company sold a further 1,971,411 shares for a cash consideration of $8.1
million. At the present time, the Company has 6,114,745 shares representing 4.7
per cent. equity in HOEC. Based on the market value of Rs.134 per share on 8
April 2008, this represents an investment value of approximately $20.5 million.

Site Restoration Deposits

As of 31 December 2007, the Company had deposited $3.4 million for site
restoration of the PY-3 field. Of this amount, $2.8 million was placed in 2006
with the remainder of $0.6 million placed in 2007.

Investment and Other Income

The Company has raised equity capital during the past three years. Surplus cash
is invested in short-term deposits generating investment income on a regular
basis. The level of such income was reduced from $2.4 million in 2006 to $1.3
million due to reduction in deposit and lower interest rates during 2007.

Finance Costs

Finance costs essentially represent the cost of bank guarantees provided to the
Government of India in connection with annual work programmes in India.

Equity Financings

The Company undertook its initial public offering (IPO) of ordinary shares on 7
June 2005 when its shares commenced trading on AIM. The IPO was successfully
completed at a placing price of 144 pence per share, raising net proceeds of
$20.8 million. In 2006 and 2007, the Company also successfully completed an
additional equity placement of Ordinary Shares at 276 and 423 pence per share,
raising additional proceeds of $24.5 million and $40.2 million respectively.

Cash Position

As a result of the equity placing, the Company has been able to maintain a
significant amount of cash resources to fund its ongoing capital expenditures
and work programmes. Total cash increased from $24.5 million at the end of 2006
to $31.2 million at the end of 2007. The Company does not have any long-term

Summary Balance Sheets

Hardy has continued to grow during 2007. Its non-current assets have increased
from $89.1 million at the end of 2006 to $121.4 million at the end of 2007. This
results largely from the capital expenditure programme on exploration
expenditures, principally on the drilling of wells on CY-OS/2 and GS-01 blocks
as well as expenditure on seismic acquisition.

Current assets represent the Group's cash resources, together with trade and
other receivables and inventory. At the end of 2007, of the $48.4 million of
current assets, $31.2 million is represented by cash, generated principally from
the equity issue that was completed in June 2007. The accounts receivable at the
end of 2007 included $12.5 million from the sale of shares in HOEC which were
received in January 2008.

Current liabilities are principally trade and other accounts payable. The level
of current liabilities fluctuates significantly depending upon the timing of
capital programmes. At the end of 2006, the Company was in the process of
drilling a well on its CY-OS/2 operated block, resulting in a significant
increase in payables. At 31 December 2007, the accounts payable were reduced to
more normalised levels.

Consequently, the Company has been successful in growing its net asset base,
which has increased from $91.4 million at the end of 2006 to $144.0 million at
the end of 2007. The increase in the carrying value of net assets results from a
combination of new equity placements, earnings that have been retained in the
business and the impact of valuation gains with respect to its investment in

Liquidity and Capital Resources

Hardy has been funding its cash requirements from internally generated cash
flows and equity capital, principally from institutional investors, in each of
the years 2005, 2006 and 2007. The Company continues to be an emerging company
with limited cash flows, and as a result, has been principally relying upon
equity capital markets to build and grow its asset base.

At 31 December 2007, the Company had cash resources of approximately $31.2
million that were available to meet future capital expenditures. In addition,
the Company has realised proceeds (net of participation in the rights offering)
from the sale of a portion of its shareholdings in HOEC of $7.4 million which
has augmented its cash resources and working capital. At 8 April 2008, the
Company's remaining investment in HOEC is worth $20.5 million which if required
can be made available to further augment the Company's cash resources and
working capital during 2008.

The Company is presently considering farming out a portion of its participating
interest of 75 per cent. in the CY-OS/2 block. The Company's plans provide for
the drilling of three appraisal wells on the block and the farm-out is
anticipated to contribute towards the Company's commitments with respect to its
appraisal programme.

At the present time, the Company does not have any short-term or long-term debt,
nor does it presently have any bank facilities in place. The Company presently
produces from the PY-3 field in India. The Company believes that it may be
possible to secure financing on the strength of this producing block in the

Base on present plans, the Company believes it has adequate financial resources
to fund its capital expenditure requirements for 2008.


The Company has limited internally generated cash flows and has a significant
planned capital expenditure programme. In the circumstances, the Board of
Directors has chosen to reinvest cash flows and does not recommend the payment
on a dividend in the foreseeable future.

Unaudited Preliminary Statement

The preliminary statement of results is unaudited. The Directors anticipate that
the Group's auditors, Horwath Clark Whitehill LLP, will present an unmodified
audit opinion on the financial statements of the Group.

Dinesh Dattani FCA

Finance Director

9 April 2008


Consolidated Income Statement

For the year ended 31 December 2007

              --------------------------------  ------     ---------     ---------
                                                              2007          2006
                                                Notes          US$           US$
              -------------------------------- ------      ---------     ---------

Revenue                                            2    11,829,554    21,316,935

Cost of sales
Production costs                                        (4,216,138)   (2,999,086)
Depletion                                               (1,344,101)   (1,887,911)
Decommissioning charge                                    (217,397)     (304,899)
--------------------------------                ------     ---------     ---------
Gross profit                                             6,051,918    16,125,039
Other operating income                                           -     1,000,000
Administrative expenses                                 (6,865,187)   (5,700,416)
              --------------------------------  ------     ---------     ---------
Operating (loss) / profit                                 (813,269)   11,424,623
Gain on sale of investment                              10,243,729             -
Interest and investment income                           1,381,121     2,288,954
Finance costs                                             (180,400)     (275,428)
              --------------------------------  ------     ---------     ---------
Profit on ordinary activities before taxation           10,631,181    13,438,149

Tax on profit on ordinary activities                    (2,315,203)   (3,205,381)
--------------------------------                ------     ---------     ---------

Profit attributable to the equity shareholders
of the parent company                                    8,315,978    10,232,768
--------------------------------                ------     ---------     ---------

Earnings per share
Basic                                              4          0.14          0.18
Diluted                                            4          0.13          0.17
--------------------------------                ------     ---------     ---------


Statement of Changes in Equity

For the year ended 31 December 2007

   ------------------     ---------     ---------     ---------     ---------
                              Group         Group       Company       Company
                             2007          2006          2007          2006
                              US$           US$           US$           US$
   ------------------     ---------     ---------     ---------     ---------

Beginning of year      91,401,836    60,929,902    58,466,526    37,943,782
------------------        ---------     ---------     ---------     ---------
Profit for the year     8,315,978    10,232,768     8,194,489       283,578
Unrealized valuation
gain/(loss)             3,514,603    (6,910,257)    3,514,603    (6,910,257)
Deferred tax
asset/(liability) on
unrealised valuation
gain or loss             (966,780)    1,934,872      (966,780)    1,934,872
------------------        ---------     ---------     ---------     ---------
Total recognised
gains/(losses)         10,863,801     5,257,383    10,742,312    (4,691,807)
New shares issued      40,168,691    24,527,092    40,168,691    24,527,092
Share based payments    1,561,497       687,459     1,561,497       687,459
------------------        ---------     ---------     ---------     ---------

End of year           143,995,825    91,401,836   110,939,026    58,466,526
------------------        ---------     ---------     ---------     ---------


Consolidated Balance Sheet

As at 31 December 2007

      ------------------  ------      ---------      ---------     ---------     ---------
                                          Group          Group       Company       Company
                           Notes         2007           2006          2007          2006
                                          US$            US$           US$           US$
      ------------------  ------      ---------      ---------     ---------     ---------
Non-current assets
Intangible assets
- exploration                      99,284,534     67,216,281             -             -
Intangible assets
- others                              246,572        217,198        21,835        65,582
Property, plant
and equipment                       3,375,463      5,064,070       140,927       177,859
Investments                        15,092,311     13,836,910    74,974,386    40,491,141
Site restoration
deposit                             3,369,820      2,784,660             -             -
------------------        ------      ---------      ---------     ---------     ---------
                                  121,368,700     89,119,119    75,137,148    40,734,582

Current assets
Inventory                           2,703,915      2,729,764             -             -
Trade and other
receivables                        14,525,440      4,637,062    12,689,331       251,931
Cash and cash
equivalent                         31,157,048     24,490,939    28,471,133    19,318,159
------------------        ------     ----------      ---------     ---------     ---------
                                   48,386,403     31,857,765    41,160,464    19,570,090

Total assets                      169,755,103    120,976,884   116,297,612    60,304,672
------------------        ------     ----------      ---------     ---------     ---------

Current liabilities
Trade and other
payables                           (9,857,909)   (16,809,807)     (567,396)     (153,782)
------------------        ------     ----------     ----------    ----------     ---------

Non-current liabilities
Provision for
decommissioning                    (4,500,000)    (4,500,000)            -             -
Provision for
deferred tax                      (11,401,369)    (8,265,241)   (4,791,190)   (1,684,364)
------------------        ------     ----------     ----------    ----------     ---------
                                  (15,901,369)   (12,765,241)   (4,791,190)   (1,684,364)

Total liabilities                 (25,759,278)   (29,575,048)   (5,358,586)   (1,838,146)
------------------        ------     ----------     ----------    ----------     ---------

Net assets                        143,995,825     91,401,836   110,939,026    58,466,526
------------------        ------     ----------     ----------    ----------     ---------

Called-up share
capital                      6        622,625        572,530       622,625       572,530
Share premium                      93,101,579     52,982,983    93,101,579    52,982,983
Shares to be
issued                              2,501,590        940,093     2,501,590       940,093
Other reserves                      8,912,532      6,364,709     8,912,532     6,364,709
Retained earnings                  38,857,499     30,541,521     5,800,700    (2,393,789)
------------------        ------     ----------     ----------    ----------     ---------
Total equity                      143,995,825     91,401,836   110,939,026    58,466,526
------------------        ------     ----------     ----------    ----------     ---------


Consolidated Statement of Cash flows

For the year ended 31 December 2007

   ------------------  ------      ---------      ---------      ---------      ---------
                                       Group          Group        Company        Company
                                      2007           2006           2007           2006
                       Notes           US$            US$            US$            US$
   ------------------ ------       ---------      ---------      ---------      ---------

Operating activities
Cash flow from
operating activities      3     (1,844,914)    23,942,864     (1,730,151)    (2,318,889)
Taxation paid                       63,235       (143,280)             -              -
------------------     ------      ---------      ---------      ---------      ---------
Net cash (used in)
from                            (1,781,679)    23,799,584     (1,730,151)    (2,318,889)
operating activities

Investing activities
Expenditure on
intangible assets
-exploration                   (32,068,253)   (51,034,004)             -              -
Expenditure on
property, plant and
equipment                         (147,297)      (148,215)             -              -
Purchase of
intangible                           5,856       (176,972)             -         (4,500)
fixed assets - other
Purchase of other
fixed                              (38,753)      (247,992)       (11,731)       (47,938)
Sale/(purchase) of
investment                               -     (2,778,914)             -     (2,778,914)
Site restoration
deposit                           (585,160)    (2,784,660)             -              -
------------------     ------      ---------      ---------      ---------      ---------
Net cash (used in)
investing activities           (32,833,607)   (57,170,757)       (11,731     (2,831,352)

Financing activities
Interest and
investment                       1,293,104      2,376,072      3,726,459      2,075,877
Finance costs                     (180,400)      (275,428)             -              -
Inter-corporate loan                     -              -    (33,000,294)   (21,494,196)
Issue of shares                 40,168,691     24,527,092     40,168,691     24,527,092
------------------     ------      ---------      ---------      ---------      ---------
Net cash from
financing                       41,281,395     26,627,736     10,894,856      5,108,773

Net increase/
in cash and cash                 6,666,109     (6,743,437)     9,152,974        (41,468)

Cash and cash
equivalents at the
beginning of the year           24,490,939     31,234,376     19,318,159     19,359,627
   ------------------  ------      ---------      ---------      ---------      ---------
Cash and cash
equivalents at the
end                             31,157,048     24,490,939     28,471,133     19,318,159
of the year            ------      ---------      ---------      ---------      ---------

1.                  Accounting Policies

The following accounting policies have been applied in preparation of
consolidated financial statements of Hardy Oil and Gas plc ("Hardy" or the

a)                  Accounting standards

Hardy prepares its financial statements in accordance with International
Financial Reporting Standards (IFRS) and interpretations issued by the
International Accounting Standards Board as adopted by the European Union.

Hardy adopted IFRS for the first time in the financial year which ended on 31
December 2007. The adoption of these standards and interpretations has resulted
in changes to the Hardy's accounting policies. The effect of the adoption of
IFRS on the results for the year ended 31 December 2006, the comparative year,
are set out in note 32 to the financial statements.

As at the date of approval of these financial statements, the following
standards and interpretations were in issue but not yet effective:

IFRS 2 (amendment) Share based payments

IFRS 3 (revised) Consolidated financial statements

IFRS 8 Operating Segments

IFRIC 12 Service concession arrangements

IFRIC 13 Customer loyalty programmes

IFRIC 14 IAS19 - The limit on a defined benefit asset, minimum funding
requirements and their interaction

IAS 1 (revised) Presentation of financial statements

IAS 23 (revised) Borrowing costs

IAS 27 (revised) Consolidated and separate financial statements

The Directors do not anticipate that the adoption of these interpretations in
future reporting periods will have a material impact on the Group's results.

b)                 Basis of consolidation

The consolidated financial statements include the results of Hardy Oil and Gas
plc and its subsidiary undertakings. The consolidated income statement and
consolidated cash flow statements include the results and cash flows of
subsidiary undertakings up to the date of disposal.

The group conducts the majority of its exploration, development and production
through unincorporated joint arrangements with other companies. The consolidated
financial statements reflect the group's share of production and costs
attributable to its participating interests under the proportional consolidation

The Company has taken advantage of the exemption provided under section 3 of the
Isle of Man Companies Act 1982 not to publish its individual income statement
and related notes. The Company's profit for the year was $8,194,489 (2006:

Revenue and other income

Revenue represents the sale value of the group's share of oil which excludes the
profit oil sold and paid to the Government as a part of profit sharing in the
year, tariff, and income from technical services to third parties if any.
Revenues are recognized when crude oil has been lifted and title has been passed
to the buyer or when services are rendered.

c)  Oil and gas assets

i)  Exploration and evaluation assets

Hardy follows the full cost method of accounting for its oil and gas assets.
Under this method, all expenditures incurred in connection with and directly
attributable to the acquisition, exploration and appraisal having regard to the
requirements of IFRS 6 "Exploration for and Evaluation of Mineral Resources" are
accumulated and capitalized in two geographical cost pools, which are not larger
than a segment: India and Nigeria.

The capitalized exploration and evaluation costs are classified as Intangible
assets - exploration which includes the license acquisition, exploration and
appraisal costs relating either to unevaluated properties or properties awaiting
further evaluation but do not include costs incurred prior to having obtained
legal right to explore an area, which are expensed directly to the income
statement as they are incurred.

Intangible exploration and evaluation cost relating to each license or block
remain capitalized pending a determination of whether or not commercial reserves
exists. Commercial reserves are defined as proven and probable on a net
entitlement basis.

When a decision to develop these properties is taken or there is evidence of
impairment, the costs are transferred to the cost pools within development/
producing assets when the commercial reserves attributable to the underlying
asset have been established.

ii)  Oil and gas development and producing assets

Development and production assets are accumulated on a field by field basis.
These comprise of the cost of developing commercial reserves discovered putting
them on production and the exploration and evaluation costs transferred from
intangible exploration and evaluation assets as stated in policy above. In
addition, interest payable and exchange differences incurred on borrowings
directly attributable to development projects if any and assets in the
production phase as well as cost of recognizing provision for future restoration
and decommissioning are capitalized.

iii)  Decommissioning

At the end of the producing life of a field, costs are to be incurred in
removing, decommissioning facilities, plugging and abandoning wells.
Decommissioning costs are estimated and stated at an amount representing the
costs, which would be incurred should decommissioning occur at the balance sheet
date and the estimates are reassessed each year. The provision is assessed at
prices ruling at the balance sheet date and, accordingly, it is not appropriate
to discount this provision. The decommissioning asset is included within the
tangible fixed assets with the cost of the related assets installed and are
adjusted for any revision to the decommissioning costs and the provision
thereof. The amortization of the asset, calculated on a unit of production basis
based on proved and probable reserves, is shown as "Decommissioning charge" in
the income statement.

iv)  Disposal of assets

Proceeds from any disposal of assets are credited against the specific tangible
or intangible capitalized costs included in the relevant cost pool and any loss
or gain on disposal is recognized in the income statement. Gain or loss arising
on disposal of a subsidiary is recorded in the income statement.

d) Depletion and impairment

i)   Depletion

The net book values of the producing assets are depreciated on a field by field
basis using the unit of production method, based on proved and probable reserves
taking into consideration future development expenditures necessary to bring the
reserves into production. Hardy periodically obtains an independent third party
assessment of reserves which is used as a basis for computing depletion.

ii)   Impairment

Exploration assets are reviewed regularly for indications of impairment, if any,
where circumstances indicate that the carrying value might not be recoverable.
In such circumstances, if the exploration asset has a corresponding development
/ producing cost pool, then the exploration costs are transferred to the cost
pool and depleted on unit of production. In cases where no such development/
producing cost pool exists, the impairment of exploration costs is recognized in
the income statement. Impairment reviews on development / producing oil and gas
assets for each field is carried out on each year by comparing the net book
value of the cost pool with the associated discounted future cash flows. If
there is any impairment in a field representing a material component of the cost
pool, an impairment test is carried out for the cost pool as a whole. If the net
book value of the cost pool is higher, then the difference is recognized in the
income statement as impairment.

e)  Property, plant and equipment

Property, plant and equipment other than oil and gas assets are measured at cost
and depreciated over their expected useful economic lives as follows:

                                             Annual Rate (%)        Depreciation
                     --------------------       ------------              Method
Leasehold improvements                            over lease       Straight line
Furniture and fixtures                                  20%        Straight line
Information technology and computers                    33%        Straight line
Other equipment                                         20%        Straight line
--------------------                            ------------     ---------------

f)   Intangible assets

Intangible assets other than oil and gas assets are measured at cost and
depreciated over their expected useful economic lives as follows:

                                   Annual Rate (%)                  Depreciation
        ---------------            ---------------                        Method
Computer software                             33 %                 Straight line
-------------                     ----------------            ------------------

g)  Investments

Investments in publicly traded securities are treated as available for sale and
are recognized at fair values based upon the quoted market prices on the balance
sheet date. Unrealized gains and losses are recognized under equity - other
reserves. On disposal of an investment, the cumulative gain or loss is
recognized in the income statement. Investments in subsidiary companies are
carried at cost in the financial statements of the parent company.

h) Inventory

Inventory of crude oil is valued at lower of average cost and market. Average
cost is determined based on actual production cost for the year. Inventories of
drilling stores and are accounted at cost including taxes duties and freight.
Provision is made for obsolete, or defective items where appropriate based on
technical evaluation.

i) Financial instruments

Financial assets and financial liabilities are recognized at fair value on
group's balance sheet based on the contractual provisions of the instrument.

Trade receivables do not carry any interest and are stated at their nominal
value as reduced by necessary provisions for estimated irrecoverable amounts.

Trade payables are not interest bearing and are stated at their nominal value.

j) Equity

Equity instruments issued by Hardy and the group are recorded at net proceeds
after direct issue costs.

k)  Taxation

The tax expense represents the sum of current tax and deferred tax.

The current tax is based on the taxable profit of the year. Taxable profit
differs from net profit as reported in the income statement as it excludes
certain item of income or expenses that are taxable or deductible in years other
than the current year and it further excludes items that are never taxable or
deductible. The current tax liability is calculated using the tax rates that
have been enacted or substantively enacted by the balance sheet date.

Deferred tax is the tax expected to be payable or recoverable on differences
between the carrying amounts of assets and liabilities in the financial
statements and the corresponding tax bases used in the computation of taxable
profit, and is accounted for using the liability method.

Deferred income tax liabilities are recognized for all taxable temporary
differences and deferred tax assets are recognized to the extent that it is
probable that taxable profits will be available against which deductible
temporary differences can be utilized.

Deferred income tax liabilities are recognized for all temporary differences
except in respect of taxable temporary differences associated with investment in
subsidiaries, associates and interest in joint ventures where the timing of the
reversal of the temporary differences can be controlled and it is possible that
the temporary differences will not reverse in the foreseeable future.

Deferred tax is recognized in respect of all temporary differences that have
originated but not reversed at the balance sheet date where transactions or
events have occurred at that date that will result in an obligation to pay more
or a right to pay less or to receive more tax.

Deferred tax assets and liabilities are measured on an undiscounted basis at the
tax rates that are expected to apply in the periods in which temporary
differences reverse, based on tax rates and laws enacted or substantively
enacted at the balance sheet date.

l)   Foreign currencies

Hardy maintains its accounts and the accounts of its subsidiary undertakings in
US dollars. Foreign currency transactions are accounted for at the exchange rate
prevailing on the date of the transaction. At the year end, all foreign currency
assets are restated at the average of the buying and the selling exchange rates
prevailing at the balance sheet date. Exchange difference arising out of actual
payments / realizations and from the year end restatement are reflected in the
income statement.

Rates of exchanges are as follows:

         -----------------           ---------------             ---------------
                                         31 December                 31 December
                                              2007                        2006
           ---------------          ----------------           -----------------
£ to US$                                    1.9828                      1.9658
US$ to Indian Rupees                        39.420                     44.1700
---------------                     ----------------           -----------------

m) Estimation uncertainty

i) Decommissioning

The liability for decommissioning is based on the best estimate of the costs of
decommissioning that will arise at some point in the future. Significant changes
in costs or technological advancement could result in a material change to this

ii) Depletion

Depletion calculations are based on the best estimate of commercial reserves
existing as at the balance sheet date. The determination of commercial reserves
is based on assumptions which include those relating to the future price of
crude oil, capital expenditure plans and the costs of production. Any changes in
these assumptions could result in a material change in the depletion charge or
the carrying value of associated assets.

n) Leasing commitments

Rental charges or charter hire charges payable under operating leases are
charged to the income statement as part of production cost over the lease term.

o) Share based payments

Hardy issues share options to directors and employees, which are measured at
fair value at the date of grant. The fair value of the equity settled options
determined at the grant date is expensed on a straight line basis over the
vesting period based on the actual number of shares vested in the accounting
period. In performing the valuation of these options, only conditions other than
the market conditions are taken into account. Fair value is derived by use of
the binomial model. The expected life used in the model is based on estimates of
the management considering non-transferability, exercise restrictions and
behavioural considerations.

2. Revenue and other income

            -------------            -----------------         -----------------
                                                2007                      2006
                                                 US$                       US$
                                    India           UK         India          UK
            -------------      ----------    ---------     ---------  ----------

Oil sales                    15,531,311            -    24,731,952           -
Profit oil to government     (4,268,322)           -    (4,714,128)          -
Other income                          -      566,565           154   1,298,957
-------------                  ----------    ---------     ---------  ----------
                             11,262,989      566,565    20,017,978   1,298,957
            -------------      ----------    ---------     ---------  ----------

The Directors do not consider there to be more than one class of business or
more than one disclosable geographic segment for the purposes of reporting. The
Group is engaged in one business activity, the production of and exploration for
oil and gas. The revenue, segment result and assets of the geographic segments,
other than India, are nil or less than 10 per cent of the total for all
segments. Other income relates to technical services to third parties, overhead
recovery from joint venture operations and miscellaneous receipts if any.
Revenue arises from sale of oil produced from the contract area CY-OS-90/1-India
and the revenue by destination is not materially different from the revenue by

3. Reconciliation of operating profit to operating cash flows

                               ---------------            ----------------
                                    Group                      Company
                             ---------      --------     ---------      --------
                                2007          2006          2007          2006
                                 US$           US$           US$           US$
      -------------------    ---------      --------     ---------      --------
Operating loss (profit)     (813,269)   11,424,623    (3,639,865)   (2,583,100)
Depletion and
depreciation               1,622,030     2,137,699        92,410        98,721
Decommissioning charge       217,397       304,899             -             -
Share based payments
charges                    1,561,497       687,459     1,333,947       459,540
-------------------          ---------      --------     ---------      --------
                           2,587,655    14,554,680    (2,213,508)   (2,024,839)
(Increase )/ decrease
in inventory                  25,849    (2,379,835)            -             -
Decrease /(increase) in
debtors                    2,720,211       225,800        69,743       (73,030)
Increase /(decrease) in
creditors                 (7,178,629)   11,542,219       413,614      (221,020)
-------------------          ---------      --------     ---------      --------
Net cash
(outflow)/inflow from
operating activities      (1,844,914)   23,942,864    (1,730,151)   (2,318,889)
-------------------          ---------      --------     ---------      --------

The decrease (increase) in debtors reported above for 2007 for the group and the
company excludes an amount of US$ 12,502,931 due from the sale of investment in
Hindustan Oil Exploration Company ("HOEC") during the year.

4. Earnings per share

Earnings per share are calculated on a profit of US$ 8,315,978 for the year 2007
(2006: US$ 10,232,768) on a weighted average of 60,117,416 ordinary shares for
the year 2007 (2006: 56,695,898).

The diluted earnings per share are calculated on a profit of US$ 8,315,978 for
the year 2007 (2006: US$ 10,232,768) on a weighted average of 64,469,515
ordinary shares for the year 2007 (2006: 59,367,997). The weighted average
shares are arrived after giving impact to dilutive potential ordinary shares of
4,352,099 as on 31 December 2007 (2006: 2,672,099) relating to share options.

5. Members of the Group

The group comprises the parent company - Hardy Oil and Gas plc - and the
following subsidiary companies, all of which are wholly owned:

   • Hardy Exploration & Production (India) incorporated under the Laws of
    State of Delaware, United States of America.
   • Hardy Oil (Africa) Limited registered under the laws of the Isle of Man.
   • Hardy Oil Nigeria Limited, owned by Hardy Oil (Africa) Limited,
    registered under the laws of Nigeria.

All members of the group are engaged in the business of exploration and
production of oil and gas and all are included in the consolidation.

6. Share capital

                   -----------------------------       -----------    ----------
                                                            Number         US$
                                                    $0.01 Ordinary
                                                      Shares "000"
                   -----------------------------       -----------    ----------
Authorized ordinary shares
At 1 January 2006                                        200,000     2,000,000
At 1 January 2007                                        200,000     2,000,000
At 31 December 2007                                      200,000     2,000,000
-----------------------------                          -----------    ----------
                   -----------------------------       -----------    ----------
Allotted, issued and fully paid ordinary shares
At 1 January 2006                                     52,046,667       520,467
Share options exercised during the year                    1,667            16
Shares issued during the year                          5,204,660        52,047
-----------------------------                          -----------    ----------
At 1 January 2007                                     57,252,994       572,530
Share options exercised during the year                   45,001           450
Shares issued during the year                          4,964,540        49,645
-----------------------------                          -----------    ----------
At 31 December 2007                                   62,262,535       622,625
-----------------------------                          -----------    ----------


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

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

Dhirubhai 33       gas discovery on GS-01-B1 well

Dhirubhai 39       gas discovery on KGV-D3-A1 well

Dhirubhai 41       gas discovery on KGV-D3-B1 well

DPR                Nigerian Department of petroleum Resources

Emerald            Emerald Energy Resources Limited

Eogas              EOGAS Petroleum & Geosciences Nigeria Ltd.

FDP                field development plan

FSO                floating Storage and offloading vessel

GAIL               gas Authority of India Limited

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

GCA                Gaffney, Cline & Associates Ltd.

Group              the Company and its subsidiaries

GS-01              licence GS-OSN-2000/1 awarded under NELP II

Hardy              Hardy Oil and Gas plc

HEPI               Hardy Exploration & Production Inc

HOEC               Hindustan Oil Exploration Company Limited

HON                Hardy Oil Nigeria Limited

IFRS               International Financial Reporting Standards

IPO                initial public offering

London Stock 
Exchange           London Stock Exchange plc

Main Market        Official List of the London Stock Exchange's market for 
                   listed securities

Millenium          Millenium Oil and Gas Company Limited

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

NNPC               Nigerian National petroleum Company

OML                Oil mining licence

ONGC               Oil and Natural Gas Corporation Limited

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

Phase III          the PY-3 development plan comprising the drilling of two 
                   further wells one intended for production and one for water 

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

Resources          those quantities of petroleum estimates, as of a given
                   date, to be potentially recoverable from known 
                   accumulations by application of development projects, 
                   but which are not currently considered to be 
                   commercially recoverable due to on or more contingencies

DST                drill stem test

DWT                dead weight tonne

FDP                field development plan

GIIP               gas initially in place

GOR                gas to oil ratio

km                 kilometre

km2                kilometre squared

lkm                line kilometre

m                  metre

MDRT               measured depth from the rotary table

MDT                modular formation dynamics tester

MMscfd             million standard cubic feet per day

MMstbd             million stock tank barrels per day

PSDM               pre-stack depth migration

psi                pounds per square week

scf                standard cubic feet

scfd               standard cubic feet per day

SPM                single point mooring

stb                stock tank barrel

stbd               stock tank barrel per day

TCF                trillion cubic feet

                      This information is provided by RNS
            The company news service from the London Stock Exchange

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