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REG - Hardy Oil & Gas - Preliminary Results - Part 1
Released: 04/03/2010
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RNS Number : 0620I
Hardy Oil & Gas plc
04 March 2010
Immediate Release 4 March 2010
Hardy Oil and Gas plc
("Hardy", "the Company" or "the Group")
Preliminary Results
for the year ended 31 December 2009
Hardy Oil and Gas plc (LSE : HDY), the oil and gas exploration and production company with interests predominantly in
India, today announces its Preliminary Results for the year ended 31 December 2009.
*All financial amounts in US dollars unless otherwise stated.
Operational Highlights
· D3: Drilled the third consecutive gas discovery on the D3 block (Dhirubhai 44)
· D3: Appraisal programme for Dhirubhai 39 and 41 discoveries was submitted to DGH for review
· D3: Completed the acquisition of 1,150 km2 of 3D seismic data (3D seismic data has now been acquired across the
entire block)
· D9: Drilled the first of four exploration wells on the D9 block, which was plugged and abandoned
· Assam: Completed the acquisition of 390 line km of 2D seismic data
· PY-3: Hardy's net entitlement average daily production for 2009 was 276 stbd (2008: 397 stbd)
· PY-3 field was suspended in July 2009 and re-commenced production in January 2010 at an initial stabilised rate of
3,336 stbd
· PY-3: The PY3-PD4-RL well was suspended with a gas lift valve in position for future reactivation with artificial
lift
Financial Highlights
· Loss before taxation of $7.9 million (2008: profit before taxation $12.4 million*)
· Cash deficiency from operations of $4.1 million# (2008: Cash surplus $1.6 million#)
· Capital expenditure of $13.5 million (2008: $31.6 million)
· Equity issue in April 2009 raising net proceeds of $15.2 million
· Cash and short-term investments at 31 December 2009 of $30.5 million (2008: $30.1 million) and no long-term debt
* Including gain of $13 million from sale of investment
# Before changes in non-cash working capital
Management
· Chief Executive Sastry Karra becomes Non Executive Director and Yogeshwar Sharma succeeds Mr Karra as Chief
Executive Officer effective 31 March 2010
Outlook
Exploration
· D3: Commencement of drilling the fourth exploration well on the D3 block expected in the first half of 2010; a
further two exploration wells by the end of the year
· D9: The re-commencement of exploration drilling in the second half of 2010
Appraisal
· D3: The D3 joint venture is considering the drilling of at least one appraisal well in the second half of 2010
Commenting on the results, Paul Mortimer, Chairman of Hardy said:
"Our existing exploration portfolio in the Krishna Godavari Basin and other India basins offer significant organic growth
potential for the Company. The Company is planning the drilling of a further five exploration wells by the end of the
first half of 2011 and we look forward to executing this programme."
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 7614 5917
Richard Day
Matthew Armitt
Buchanan Communications 020 7466 5000
Mark Edwards
Ben Romney
Chairman's Statement
Corporate Overview
2009 was an important year for Hardy as we continued our exploration programme on the Company's portfolio in the Krishna
Godavari Basin. As a result of our activity, we were delighted to announce the third consecutive gas discovery in the D3
block. We also began our four well exploration drilling campaign in the D9 block. The first well was plugged and
abandoned and the data is currently being integrated into the D9 geological model to optimise selection of future drilling
locations. Despite challenging market conditions, the Company was successful in raising $15 million in equity through a
placing in 2009. The placing is testimony to the significant growth potential our asset portfolio offers and highlights
the continued support of our core shareholder base.
India remains a rapid growth story and the demand for energy continues to be robust, mirroring the country's significant
economic growth. Hardy has a clear objective of creating significant shareholder value through an India focused
exploration and development strategy.
Our India focused strategy has produced five gas discoveries from nine exploration wells over the past three years. We
expect to drill a further five exploration wells by the end of the first half of 2011 and we continue to believe that our
existing exploration portfolio in the Krishna Godavari Basin and other India basins offers significant organic growth
potential for the Company.
Key Results
As a result of the reduction in global oil prices and an extended shut-in of our PY-3 field, the Company recorded a 56 per
cent reduction in gross revenue and as a result Hardy recorded a net loss of $6.5 million compared to net income of $7.5
million in 2008. Net income for 2008 included an after tax gain on investment of $8.9 million. The Company's fully
diluted loss per share was $0.10 compared to fully diluted earnings per share of $0.11 in 2008.
The Company's capital expenditure amounted to $13.6 million which was principally on the drilling of one development well,
two exploration wells, the acquisition of seismic data and the pre-drilling of a well on D3. The Company ended 2009 with
$30.5 million in cash and short-term investments and no long-term debt.
Management Change
As announced today, Sastry Karra will be relinquishing his current position as Chief Executive and maintain an ongoing
involvement with the Company as a Non Executive Director. Yogeshwar Sharma, currently Chief Operating Officer, will
succeed Sastry Karra as Chief Executive Officer effective 31 March 2010.
We would like to thank Sastry for his tireless work over the past 12 years as Chief Executive. It was Sastry's vision that
has placed Hardy in the position it is today. The management is determined to fulfil the potential of that vision.
Governance
Following an appraisal of the Board and its members in 2009, the Board considers that its current structure, competencies
and remuneration policies are appropriate for a publicly listed, early stage, oil and gas exploration company. As such we
did not undertake any material changes in 2009. We will continue to periodically review the appropriateness of the Board
composition, structure and internal processes as the Company evolves.
Risk Management
Risk management will continue to be a key focus of the Board in 2010. Given the Company's objective of creating
significant shareholder value, we have chosen an exploration focused strategy. Exploration is intrinsically very uncertain
and whilst substantial improvements in predictive/interpretation technology have reduced this uncertainty, it can not be
eliminated.
Despite the global downturn, demand for upstream oil and gas equipment has remained robust and we continue to operate in a
relatively high-cost environment which magnifies the financial impact of operational delays during drilling and other
operations.
A number of our exploration licences are being held under appraisal and our continued interest in such blocks are
contingent on establishing commerciality. A decision on the commerciality of Dhirubhai 33 gas discovery (GS-01) is
anticipated this year.
With respect to Hardy's Ganesha (CY-OS/2) non-associated natural gas discovery, the Company has presented a case to the
Directorate General of Hydrocarbons that supports our claim of entitlement to a licence extension. In the absence of a
resolution in our favour in the near future, we intend to refer the dispute for sole expert or conciliation and
arbitration.
Year End Audit
The auditors have substantially completed their work in connection with the 2009 financial year and are expected to provide
an unqualified audit opinion on the 2009 financial statements. The auditors are expected to provide an emphasis of matter
comment in their audit 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 notes 2 and 9 to the financial statements.
Outlook
We continue to strive to create significant shareholder value by focusing on high impact exploration in India. The year
2010 should prove to be crucial in the realisation of our vision for Hardy. We expect to drill five further exploration
wells in the Krishna Godavari Basin by the end of the first half of 2011, which will complete the phase one minimum work
programmes for the D3 and D9 exploration blocks.
D3: Exploration drilling on the D3 block is expected to re-commence in the second quarter of 2010. The D3 block is not
operated by Hardy and at this time the schedule of further exploration and appraisal drilling on the block is dependent on
a number of issues outside of the control of the Company.
D9: The Company anticipates the re-commencement of exploration drilling on D9 in the second half of 2010 upon completion of
ongoing geological studies to incorporate data gathered from the KG-D9-A1 well. We anticipate providing an update of the
prospect portfolio of this block prior to the re-commencement of drilling.
PY-3: The PY-3 joint venture is working towards finalising and approving further drilling to increase production and
enhance ultimate recovery. The drilling portion of this programme is currently envisioned to start in first half of 2011.
CY-OS/2 and GS-01: The drilling of an appraisal well on the CY-OS/2 block is dependent on the outcome of our request for an
extension to the CY-OS/2 licence. The GS-01 joint venture will continue various geological and geophysical studies to
determine the commerciality of the Dhirubhai 33 gas discovery.
Assam: The joint venture will continue the prospect development process with the processing and interpretation of acquired
seismic data. Drilling will be dependent on identifying material prospects. However, we expect a drilling programme to be
initiated in phase two, which commences in the first quarter of 2011.
Nigeria: The Company will provide technical assistance to the operators of the Oza and Atala fields to facilitate the
realisation of value.
Given the substantial amount of new data acquired in 2009, the Company intends to publish an update to its past competent
person and technical evaluation reports, on all of its assets, by the end of the first half.
Corporate
Having regard to the Company's existing working capital position and its ability to raise potential financing, the
Directors are of the opinion that the Group has adequate resources to enable it to undertake its planned work programme of
exploration, appraisal and development activities over the next 12 months.
The Board remains committed to its India focused strategy. In the near term, Hardy's Krishna Godavari Basin assets remain
the primary focus of our exploration programme. The recent D3 Dhirubhai 44 gas discovery in the Miocene has proven a
substantial geological fairway. We view D3 with considerable optimism and believe that 2010 will be an important year in
Hardy's development. We remain optimistic about the potential of D9 and look forward to re-commencing the exploration
drilling programme. The Company is well positioned to see itself through its key exploration activities in 2010.
E.P. Mortimer
Chairman
3 March 2010
Chief Executive's Statement
With an active exploration drilling programme and adequate cash reserves, the year 2010 should provide the Company with an
enhanced understanding of the geology of the Krishna Godavari Basin and clarity on the future resource potential of Hardy's
promising D3 and D9 exploration blocks.
Execution of Strategy
The Company remains committed to its India focused strategy with a mandate of creating significant long-term shareholder
value through the exploration and appraisal of our existing exploration portfolio. With the unprecedented volatility of
the global economic landscape and mixed results from our exploration and development drilling, 2009 proved to be a
challenging year on several fronts.
Given India's robust economic growth projections and attractive upstream fiscal and regulatory regime, the Company
continues to view India as an excellent investment opportunity for upstream oil and gas activity. In 2010, we will focus
on maintaining key relationships and enhancing our regional technical and operational expertise.
Exploration Highlights
The highlight of our 2009 exploration programme was the drilling of two deep water wells on the Company's Krishna Godavari
Basin blocks. The third successive discovery on our D3 block has re-enforced our expectations for this block and we
anticipate the completion of the phase one exploration drilling programme, and the advancement of a comprehensive appraisal
programme for the existing discoveries Dhirubhai 39, 41 and 44, in 2010.
The first well on the Company's D9 block (KG-D9-A1) did not provide the anticipated results. In conjunction with the
operator, we are currently incorporating the data from this well to refine the next three exploration well locations on
this block. We expect to provide an updated geological assessment of this block prior to the re-commencement of the
drilling programme.
In 2009, Hardy completed two seismic acquisition programmes: 1,150 km2 of 3D seismic data was acquired over the north east
portion of the D3 block and 390 line km of 2D seismic data was acquired over the onshore Assam block. With the acquisition
on D3, the Company now has 3D seismic coverage over the entire D3 concession.
The Company continued to work with the Ministry of Petroleum and Natural Gas and Directorate General of Hydrocarbons (DGH)
to confirm an extension of the CY-OS/2 block prior to commencement of the appraisal programme for Hardy's Ganesha
non-associated natural gas discovery. In the absence of a resolution in our favour, in the near future, we intend to refer
the dispute for sole expert or conciliation and arbitration.
Appraisal of the Dhirubhai 33 discovery (GS-01) continued in 2010 with further geological and geophysical studies.
Resource Potential
In May 2009, Hardy released the Company's prospective resource potential as evaluated by Gaffney Cline & Associates Ltd for
the two KG Basin blocks, D3 and D9. Of particular note was the play fairway analysis undertaken which highlighted the
significant resource potential of the D3 block (risked prospective natural gas resource of 9.6 TCF). This estimate was
completed prior to the drilling of the KG-D3-R1 discovery.
The Company intends to publish an updated technical evaluation, on all of its assets, by the end of the first half of
2010.
Development and Production
During 2009, the Company's oil production was 0.56 MMstb compared with 0.93 MMstb for 2008. The reduction was a result of
a six month, unplanned, shut-in of the PY-3 field. The field re-commenced production in January 2010 at an initial gross
rate of 3,336 stbd. For 2010, the PY-3 field is forecast to produce at an average rate of 3,000 stbd.
The drilling of an additional lateral well, via the re-entry of the producing PY-3-PD4 well was completed in February 2009.
With the assistance of a nitrogen lift, the well flowed at 700 stbd of oil with 30 per cent water-cut. However, the well
could not be reactivated as a self flowing well. The well has been completed and suspended with a gas lift valve to allow
for future oil production when gas lift compression facilities are installed on the floating-point unit (FPU).
In 2009, the joint venture negotiated a one year contract extension to the PY-3 production facilities effective 24 January
2010, at a 40 per cent reduction in day rate.
PY-3 joint venture partner approval to drill two more production wells is expected in the first half of 2010 with drilling
to take place in the first half of 2011.
Financial Highlights
Revenue was down from $17.3 million in 2008 to $7.7 million in 2009 principally due to an unplanned extended shut-in of the
PY-3 field. Administrative expenses were down by 9 per cent compared to 2008, resulting in an operating loss of $8.1
million in 2009 compared with an operating loss of $1.7 million in 2008.
The Company started 2009 with cash reserves of $30.0 million. Net cash used in operating activities was $1.0 million.
Cash used for investing activities amounted to $13.5 million in 2010 for the drilling of PY3-PD4-RL, KGV-D3-S1, KGV-D3-G1,
KG-D9-A1 wells and additional seismic on the D3 and Assam exploration blocks. An equity issue in April 2009 resulted in
net proceeds of $15.4 million augmenting our working capital. As a result, the Company's cash reserves at the end of 2009
were $30.5 million. The Company remains in a positive financial position and has no long-term debt.
Key Partnerships
Hardy continued to work closely with strategic partners in India. The Company interacts on a regular basis with its
partners at multiple levels, to ensure that our goals and objectives are addressed and to facilitate planning of upcoming
work programme schedules. Maintaining open and substantive relationships with existing partners and other key stakeholders
in the India upstream oil and gas sector are critical to the execution of the Company's strategy.
2010 Programme
As mentioned earlier, the third successive discovery on our D3 block has enhanced expectations as we anticipate the
completion of the phase one exploration drilling programme through the drilling of three further exploration wells. The
next location on this block is expected to be the KGV-D3-W1 exploration well, targeting several high amplitude anomalies in
the Pliocene and Miocene geological horizons. The well is approximately 20 km south east of the Dhirubhai 39 and 41
discoveries. We expect the drilling to commence by the end of the second quarter of 2010.
The timing of re-commencement of the D9 three well exploration drilling programme will be subject to the completion of
ongoing data analysis and updating of the geological model. We anticipate drilling to commence in the second half of 2010
and continue into 2011.
We are enthusiastic about the balance of 2010, as we continue our efforts to de-risk our exploration portfolio in the
Krishna Godavari Basin in India through further exploration drilling. Our disciplined capital allocation strategy will
deliver activities that have the potential to result in a significant increase in shareholder value. Beyond the Company's
existing portfolio, the Company will continue to evaluate and assess potential acquisitions in India via its New
Exploration Licence Policy (NELP) bidding rounds and other conventional means that offer material value creation
opportunities that will complement our existing assets and organisational competencies.
Staff
2009 was a challenging year for the Company and we would not have been able to see it through without the dedication of our
staff in India, Nigeria and the United Kingdom. Our India team continues to drive the core of our business and we will
look to continue to retain and enhance our technical, operational and management expertise in this region. In 2010 we look
to our staff to perform at a high level in the execution of our 2010 work plan and beyond. I would like to take this
opportunity to acknowledge their important contributions in the past year.
Sastry Karra
Chief Executive
3 March 2010
Financial Review
During 2009, the Company had an unplanned extended shut-in of the PY-3 field which had a significant impact on its
financial performance. The absence of production in the second half of 2009 and lower oil prices resulted in a substantial
reduction in revenue. As a result, the Company has recorded a loss for 2009. In April 2009, the Company successfully
placed 6,208,997 Ordinary Shares for net proceeds of $15.2 million. Hardy completed the year with cash and short-term
investments of approximately $30.5 million and no long-term debt.
Key Performance Indicators
Year ended 31 December
2009 2008
Production (barrels of oil per day - net entitlement basis) 276 397
Average realised price per barrel $ 52.96 104.44
Average cost per barrel $ 49.61 54.91
Revenue (thousands of $) 7,687 17,306
Net (loss) profit (thousands of $) (6,517) 7,472
Cash flow from operations* (thousands of $) (4,117) 1,648
Diluted (loss) earnings per share $ (0.10) 0.11
Wells drilled 2 4
Diluted (loss) earnings per share $
(0.10)
0.11
Wells drilled
2
4
*Before changes in non-cash working capital, tax paid, interest and investment income and finance costs.
Operating Results
Year ended 31 December
2009 2008
Production (barrels of oil per day)
Gross field 1,535 2,542
Participating interest 276 458
Net entitlement interest 276 397
Sales (barrels of oil per day)
Gross field 2,209 2,725
Participating interest 398 491
Average realised price per barrel $ 52.96 104.44
2,725
Participating interest
398
491
Average realised price per barrel $
52.96
104.44
Production, Sales and Revenue
The Company operates the PY-3 field in the Cauvery Basin with an 18 per cent participating interest. Gross average daily
field production for the year ended 31 December 2009 amounted to 1,535 stbd compared with 2,542 stbd for 2008. The
decrease in production is due to an unplanned six month shut-in of the field to undertake repair of the offshore
facilities. Hardy profit oil payment to the Government of India (GOI) was nil in 2009 compared to $2.3 million in 2008.
The Company does not anticipate the payment of profit oil to the GOI in 2010 due to substantial unrecovered costs.
Revenue from oil sales (after profit oil) decreased from $16.4 million in 2008 to $7.7 million in 2009. The average price
realised per barrel decreased significantly from $104.44 during 2008 to $52.96 in 2009. Average daily sales amounted to
398 stbd compared with 491 stbd reflecting lower production volumes from the extended shut-in and partially offset by the
sale of inventory during the year.
Cost of Sales
Cost of sales for 2009 decreased from $9.2 million in 2008 to $5.7 million in 2009. This reflects the fact that lease
charges for the production and storage facilities were not incurred during the PY-3 field shut-in period. The contract for
the floating processing and storage systems has been renegotiated effective January 2010 for a period of one year at a
substantially reduced day rate.
Gross Profit
Gross profit decreased from $8.1 million in 2008 to $0.8 million in 2009. The decrease arises principally from lower
revenues as a result of a significant reduction in oil sales and significantly lower average crude oil price in 2009.
Administrative Expenses
Administrative expenses decreased from $9.8 million in 2008 to $9.0 million in 2009. The decrease principally results from
exchange gains of $0.7 million in 2009 compared with an exchange loss of $1.3 million recorded in 2008, offset by
additional costs associated with the drilling of PY3-PD4-RL well in early 2009 of $1.0 million.
Operating Loss
The Company is reporting an operating loss of $8.1 million in 2009 compared with $1.7 million in 2008. The increase in loss
principally results from the shut-down of the PY-3 in the last half of 2009 coupled with lower oil prices.
Interest and Investment Income
Investment and other income in 2009 amounted to $0.3 million compared with $1.3 million in 2008. The decline is primarily
attributable to significantly lower interest rates obtained on cash and short-term investments in 2009 compared to 2008.
The lower realised interest rates are systematic with unprecedented reductions in UK and US central bank rates.
Finance Costs
Finance costs principally include the cost of providing bank guarantees to the GOI required by the provisions of production
sharing contracts and are based on the agreed annual work programme on blocks in India.
Loss Before Taxation
The Company recorded a loss before taxation of $7.9 million compared to a profit before taxation of $12.4 million in 2008.
During 2008, the Company recorded a realised pre-tax gain on investment of $12.9 million arising on the liquidation of its
holding in Hindustan Oil Exploration Company Limited (HOEC).
Taxation
During 2009, the Company did not incur any current tax liability as a result of losses. During 2008, the Company's current
tax liability was $1.6 million comprising of $0.8 million in connection with minimum alternate tax in India and tax on
short-term capital gains of $0.8 million on sale of investments in India.
Tax relief, as a percentage of pre-tax loss amounted to 17.9 per cent in 2009 compared to a tax charge of 39.9 per cent in
2008. The lower rate for tax relief results from no tax relief reflected for Nigeria losses, and the impact of the
non-deductibility of a substantial part of share-based payments. The higher rate reflected in 2008 resulted from the above
factors as well as current tax on short-term capital gains of $0.8 million on investment gain.
Net Profit
Net profit declined from $7.5 million in 2008 to a net loss of $6.5 million in 2009.
Cash Flow from Operating Activities
The Company's cash flow used in operating activities, before changes in non-cash working capital, amounted to $4.1 million
in 2009. This compares with cash flow from operations of $1.6 million for 2008. The decline principally results from
reduced oil sales volumes and related prices in 2009 compared to 2008.
Capital Expenditure
Capital expenditure amounted to $13.6 million during 2009, compared to $31.7 million incurred during 2008. Capital
expenditure amounting to $2.9 million was incurred on the PY-3 block with the drilling of PY3-PD4-RL. Approximately $5.2
million was incurred in the drilling of two exploration wells, pre-drilling of one well, and a 3D seismic programme on the
D3 block in the Krishna Godavari basin. Approximately $3.6 million of expenditures are attributable to the drilling of one
well on the D9 block. As part of the Dhirubhai 31 (GS-01) appraisal programme, the Company incurred $0.4 million on the
GS-01 block, on a number of geological and geophysical studies including reprocessing of the 3D seismic data covering the
block. In addition, $1.2 million was spent on the acquisition of 2D seismic on the Company's onshore Assam block.
Site Restoration Deposit
This represents the deposit for site restoration for future site restoration expenses for the PY-3 field. In 2009, the
Company increased the site restoration deposit by $0.4 million to $3.4 million.
Cash and Short-term Investments
The Company's cash and short-term investments remained essentially unchanged at $30.5 million at the end of 2009. The
Company's capital expenditures were principally funded by proceeds from a placing during 2009. At the end of 2009, the
Company placed $19.9 million and $0.6 million in US dollar and Sterling liquidity funds at HSBC with average underlying
maturity of 43 days and 34 days respectively. The Company does not have any long-term debt.
Summary Balance Sheet
Hardy's non-current assets have increased from $135.8 million at the end of 2008 to $148.4 million at the end of 2009.
This resulted largely from the exploration and development capital expenditure programme, principally the drilling of wells
and seismic acquisition on PY-3, D3, D9, GS-01 and Assam blocks. Current assets represent the Group's cash and short-term
investments, trade and other receivables and inventory. At the end of 2009, of the $36.8 million of current assets, $30.5
million are represented by cash and short-term investments.
Current liabilities are principally trade and other accounts payable. The level of current liabilities is $15.4 million at
the end of 2009 compared with $13.8 million in 2008, reflecting the impact of the drilling operations on the KGV-D3-R1 well
on the D3 block that finished in the last weeks of 2009.
During 2009, the Company issued $15.2 million of equity principally due to a placing. Consequently, the Company's net
assets increased to $155.5 million at the end of 2009 from $144.2 million at the end of 2008.
Liquidity and Capital Resources
The Company has successfully raised financing in the past to provide funding for its ongoing exploration and development
programmes and to augment its working capital. Having regard to Hardy's existing working capital position and its ability
to raise potential financing the Directors are of the opinion that the Company has adequate resources to enable it to
undertake its planned work programme of exploration, appraisal and development activities over the next 12 months.
Dividends
The Company has limited internally generated cash flows and has a planned capital expenditure programme. In the
circumstances, the Directors have chosen to reinvest cash flows and do not recommend the payment of a dividend in the
foreseeable future.
Risk Factors
Hardy is an international business which has to face a variety of strategic, operational, financial and external risks.
Under these distinct classes, the Company has identified certain risks pertinent to its business including: exploration and
reserve risks; loss of key human resources; drilling and operating risks; security risk in area of operations, costs and
availability of materials and services; economic and sovereign risks, market risk, foreign currency risk, loss of or
changes to production sharing or concession agreements, joint venture or related agreements; and volatility of future oil
and gas prices.
Effective risk management is critical to achieving our strategic objectives and protecting our assets, personnel and
reputation. Hardy manages its risks through compliance with the terms of its agreements and application of appropriate
policies and procedures, and through the recruitment and retention of skilled individuals throughout the organisation.
Further, the Company has focused its activities mainly in known hydrocarbon basins in jurisdictions that have previously
established long-term oil and gas ventures with foreign oil and gas companies, existing infrastructure of services and oil
and gas transportation facilities, and reasonable proximity to markets.
A summary of the principal risks facing the Company and the way in which these risks are mitigated is provided in this
report.
The Company's Chairman's Statement, Chief Executive's Statement, Review of Operations, Financial Review, and Risk and
Uncertainties have been prepared to substantially comply with the Accounting Standards Board Operating and Financial Review
Reporting Statement issued in January 2006.
Dinesh Dattani
Finance Director
3 March 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).
2009 Performance
The highlight of 2009 was the KGV-D3-R1 gas discovery (Dhirubhai 44) which is the third consecutive discovery on the
Company's D3 block. Overall 2009 was a challenging year for Hardy with drilling results in PY-3 and D9 coming below
expectations. The Company is now working hard to incorporate the well data to optimise selection of future exploration and
development drilling locations on all of the Company's blocks in India.
At the beginning of 2009 the Company planned to drill two exploration wells, one to two appraisal wells, one development
well and acquire 1,150 km2 of 3D and 450 line km of 2D seismic data in India.
Through 2009, the Company has participated in the drilling of two exploration wells (KG-D9-A1 and KGV-D3-R1), pre-drilled
exploration well KGV-D3-G1, drilled the PY3-PD4-RL development well and acquired 1,150 km2 of 3D seismic data on D3 and 390
line km of 2D data on the Assam exploration block.
In Nigeria, the Company had planned to commence the tie-in of the Oza field and potentially re-enter and test the Atala-1
well. The Company now plans to initiate the installation of the pipeline for the Oza field in the second half of 2010.
The timing of commencement of the Atala-1 re-entry will be subject to securing the appropriate drilling equipment, which
remains a challenge for a number of marginal field operators in the Niger Delta.
The table below provides a brief comparison of our stated operational objectives for 2009 and our subsequent
accomplishments through the year:
Block Projection Execution
D3 Complete acquisition of 1,150 km2 of 3D seismic data in the toe thrust area Completed the acquisition of 1,150 km2 of 3D seismic data
D3 Drill the third exploration well on the block Announced the gas discovery Dhirubhai 44 (KGV-D3-R1); pre-drilled KGV-D3-G1
D9 Drill the first of four exploration wells Drilled the KG-D9-A1 exploration well (P&A)
GS-01 Contingent appraisal well for Dhirubhai 33 gas discovery The joint venture elected to defer the drilling of an appraisal well in 2009
Assam Acquire 450 line km of 2D seismic data Acquired 390 line km of 2D seismic data
PY-3 Drill development well PY3-PD4-RL Drilled the PY3-PD4-RL (suspended)
CY-OS/2 Obtain an extension for the appraisal of Ganesha gas discovery Ongoing discussions with the GOI
Oza Commence field tie-in operations Received 34 km of pipe, ROW, EIA and pipeline FEED studies ongoing
Atala Re-enter and test Atala-1 Securing of equipment required to undertake the re-entry proved to be challenging
CPR Publish an updated technical evaluation report on D9, D3 and Assam blocks Published a technical evaluation report by GCA on D9, D3
Ongoing discussions with the GOI
Oza
Commence field tie-in operations
Received 34 km of pipe, ROW, EIA and pipeline FEED studies ongoing
Atala
Re-enter and test Atala-1
Securing of equipment required to undertake the re-entry proved to be challenging
CPR
Publish an updated technical evaluation report on D9, D3 and Assam blocks
Published a technical evaluation report by GCA on D9, D3
Competent Person's Report Update
Given the substantial amount of new data acquired in 2009, the Company intends to publish an update to its past competent
person and technical evaluation reports, on all of its assets, by the end of the first half of 2010.
Block KG-DWN-2003/1 (D3): Exploration
(Hardy 10 per cent interest)
2009 Operations
For the second year in a row the Company's D3 block provided the highlight of Hardy's exploration programme with the
discovery of gas on the Company's D3 block (Dhirubhai 44). The primary results of operations undertaken on this block in
2009 are listed below:
KGV-D3-R1: On 22 December 2009, the Company announced a third discovery on the D3 block (Dhirubhai 44). The well
KGV-D3-R1, was drilled in a water depth of 1,982 m to a total measured depth of 4,113 m. Three reservoir zones were
encountered at Miocene Level having gross thicknesses of 4, 23 and 16 m. The potential of these zones were evaluated
through a wire-line based technology called Reservoir Characterization Instrument (RCI). The evaluation and incorporation
of the data obtained from the D3 discoveries is ongoing.
KGV-D3-G1: Hardy commenced the drilling of a fourth exploration well KGV-D3-G1. Drilling was subsequently suspended after
setting of 20" casing at 1,625 m total vertical depth (TVD). The joint venture intends to re-enter the well at a later
date to drill to TD @ 2,510 m sub-sea (ss) and test prospective geological horizons.
The Company acquired a further 1,150 km2 of 3D seismic data in 2009. With the completion of this programme, the joint
venture now has 3D seismic data coverage over the entire block. Additional interpretation and processing was completed on
previously acquired data, including PSTM, PSDM and AVO/inversion studies.
Prior to the drilling of KGV-D3-R1, the Company published a third party technical evaluation report which provides the
Prospective Resource potential of the block and the geological chance of success of various prospects. Play-based
exploration methodology was employed to address both the current prospect inventory and the 'yet to find' resource
potential of the D3 block. Using the play based exploration methodology, the potential gross risked Best Estimate
Resources for the D3 block was estimated at 9.5 TCF (Effective May 2009). This includes identified prospects and leads and
a number of postulated prospects based on the play-based exploration methodology and field size distribution. A summary
report can be found on the Company's website www.hardyoil.com.
2010 Outlook
Exploration: The joint venture is planning for the drilling of three further exploration wells by the second quarter of
2011. The drilling of these exploration wells will meet the blocks phase one minimum work programme commitments for the
block.
Appraisal of 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, following which two appraisal wells could
be drilled prior to February 2011. The joint venture is planning to complete an electro magnetic (EM) survey prior to the
drilling appraisal wells.
Background
The D3 block is situated in the emerging world class Krishna Godavari Basin in India, encompasses an area of 3,288 km2, is
in water depths ranging from 400 m to 2,200 m, and is located approximately 45 km offshore. The block is operated by
Reliance.
The minimum work programme for phase one of the licence requires the drilling of six exploration wells. To date, three
exploration wells have been drilled and one well has been pre-drilled. In its technical evaluation report, GCA noted that
the presence of an unconventional biogenic gas petroleum system in deepwater offshore India has been proven in the D3
block.
Block KG-DWN-2001/1 (D9): Exploration
(Hardy 10 per cent interest)
2009 Operations
2009 marked the commencement of the drilling phase of the block's exploration programme. There are three play types
postulated to be present in the block: structural (anticlines- northern, central and southern) strati-structural; and
stratigraphic. The D9 joint venture has initially focused exploration efforts in the north west corner of the block
covering an area of approximately 3,640 km2.
The first exploratory well in the D9 block, KG-D9-A1, was to evaluate the prospectivity of the Middle and Lower Miocene
sands deposited in the lower slope regime in a distal toe thrust structural play in the central anticline.
Observations from A1 Well Data
# In the interval 3,235-3,242 m from rotary table (RT) from the Early Pliocene section, observed resistivity up to 30
ohms in the pilot hole where no samples could be collected.
# In the interval of 3,500-3,650 m RT of Upper Miocene age, several thin sandstone and siltstone units having
thickness of 1-3 m were encountered with a total gas > 2 per cent with mostly C1 component. The maximum Resistivity of up
to 3 ohm was observed in the interval 3,510-3,515 m RT with total gas of 1 per cent.
# The first target in the Middle Miocene level encountered siltstone in the interval 4,160-4,185 m RT and 4,370-4,500
m RT with low resistivities and insignificant gas shows.
# The deeper target in the Lower Miocene section encountered limestone in the interval 4,695-4,710 m RT contrary to
the expected (prognosed) coarse clastic. No significant gas shows were observed in this interval.
Inference from A1 Well Results
# In the Upper Miocene, the KG-D9-A1 well encountered several thin sandstone units with good gas shows (C1 dominant)
suggesting the possibly a biogenic source. Studies are being conducted to identify the likely thick reservoir prone areas
based on the detailed sedimentological studies of KG-D9-A1 well cores and cuttings, and D6 block subsurface data. These
reservoirs are likely to be on the flanks of anticlines in the mini-basin set up.
# In the Middle Miocene, the KG-D9-A1 well encountered siltstone with low resistivity and insignificant gas shows.
This zone needs to be thoroughly re-evaluated to identify the probable reservoir entry directions.
# Tight limestone was encountered in the Lower Miocene level in the well. The data suggests this limestone package was
transported from the shelf area to the north through a slope channel system. This will be confirmed by side wall core and
cutting sample analysis data.
# The remaining prospectivity of all the anticlinal closures (north and central) cannot be ruled out because presence
of effective reservoirs and biogenic source will make them viable targets.
# The KG-D9-A1 well drilled into the Lower Miocene section did not penetrate the Cretaceous and Palaeocene sections
thus their prospectively remains unchanged.
2010 Outlook
The data obtained from the KG-D9-A1 well is currently being integrated with the existing geological model to improve the
understanding of the geology and petroleum systems within the block before drilling subsequent wells. Some specific
activities planned for 2010 are listed below:
# complete sedimentological and paleontological studies of the side wall cores and drill cuttings to understand the
presence of limestone in the block;
# carry out inversion studies of the 3D seismic based on the new data from the A1 well and nearby D6 block data to
identify the reservoirs; and
# refine the geochemical model for understanding the source rock potential.
The D9 block's exploration drilling programme is expected to re-commence in the second half of 2010.
Background
The licence encompasses 11,605 km2 in the Bay of Bengal where water depths vary from 2,300 m to 3,100 m. The joint venture
has acquired over 4,188 km2 of 3D seismic data. Regarding the status of the D9 block, the operator submitted a proposal
requesting the grant of a drilling moratorium for three years from January 2008 to December 2010 on the basis that the
Operator has not been able to complete the minimum work obligations of exploratory drilling in view of non-availability of
suitable deep water rigs in the international market. Similar proposals were also submitted by other operators including
the national oil company ONGC. The D9 operator is in receipt of a letter from DGH that the blocks, inter alia, have been
recommended by DGH to GOI for the grant of a drilling moratorium. The proposal is under active consideration by the GOI.
Should the Drilling Moratorium not be granted, there are provisions for availing extension of the phase one period based on
statutory delays and the other allowable extensions as per a DGH extension policy.
Block GS-OSN-2000/1 (GS-01): Appraisal
(Hardy 10 per cent interest)
2009 Operations
The GS-01 joint venture continued various geological and geophysical studies in relation to the appraisal of the GS01-B1
gas and condensate discovery (Dhirubhai 33). The licence is currently active under an adopted appraisal programme. The
appraisal area comprises 5,890 km2 with a term through to May 2010.
2010 Outlook
A decision on the drilling of an appraisal well is expected to be made prior to the end of the first half of 2010. The
joint venture is considering whether an additional well is required to declare commerciality.
Background
The GS-01 exploration licence is located in the Gujarat-Saurashtra offshore basin off the west coast of India, north west
of the prolific Bombay High oil field. The original licence encompassed 8,841 km2 (5,890 km2 post relinquishment) and
water depths vary between 80 m and 150 m.
The joint venture has previously acquired 2,216 km2 of 3D seismic data. As announced on 15 May 2007, the Dhirubhai 33
discovery (GS01-B1) flow-tested at a rate of 18.6 MMscfd gas with 415 stbd of condensate through a 56/64" choke at flowing
tubing head pressure of 1,346 psi. Upon completion of phase one of the exploration programme the joint venture elected not
to proceed to the second phase of exploration.
Block AS-ONN-2000/1 (Assam): Exploration
(Hardy 10 per cent interest)
2009 Operations
In 2009 the Company acquired 390 line km of 2D data. The majority of the exploration block's phase one minimum work
programme has now been completed. GCA's technical evaluation report noted that they consider 'the Assam opportunity as a
challenging, potentially attractive play extension and possible new play(s) opportunity with neighbouring oil discoveries
in the sub-regional context'.
2010 Outlook
Further field operations will be based on the results and interpretation of the 2D data and other ongoing geological
studies. Drilling will be planned with the commencement of phase two in 2011.
Background
The AS-ONN-2000/1 exploration licence is located in the north eastern state of Assam, India and north of the 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 one of a three phase exploration licence. Phase one (three years) will expire 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. A national highway runs parallel to the Brahmaputra River and passes through the block. Different play types
expected are structural (anticlinal and fault closures), stratigraphic (pinchout/wedgeout) within Palaeocene-Eocene and
Gondwana packages and unconventional fractured/weathered basement.
Block CY-OS 90/1 (PY-3): Producing Oil Field
(Hardy 18 percent interest - Operator)
2009 Production
Gross average daily field production for the year ended 31 December 2009 was 1,535 stbd (2008: 2,550 stbd). The production
facilities' uptime performance was 51.0 per cent (2008: 88.2 per cent). The decrease in production was the result of an
extended shut-in to repair the field's offshore mooring facility. Adverse marine conditions compounded the time taken to
finish the repairs. The field recommenced production on 24 January 2010 at a rate of 3,336 stbd.
In 2009 the joint venture extended the contract of the PY-3 field's production facility for one year up to 24 January 2011.
The new contract provides for a 40 per cent reduction from the previously contracted rate.
Gross average daily production for January and February 2010 was 835 stbd and 3,450 stbd respectively. We anticipate that
the PY-3 field will average gross daily production of 3,000 stbd for 2010. Currently the field is producing at a gross
rate of 3,400 stbd.
2009 Operations
In February 2009, the Company completed the re-entry and drilling of an extended lateral section in the PY3-PD4-RL well.
With the assistance of nitrogen lift, the well flowed at 700 stbd of oil with 30 per cent water-cut. However, the well was
unable to be reactivated as a self flowing well. The well has been completed as a producer with a gas lift valve to allow
for future production when gas lift compression facilities are installed on the FPU.
Hardy has subsequently revised its geological and reservoir simulation models to incorporate new data gathered from the
PY3-PD4-RL well. The revised model will be used to plan future in-fill drilling and production facility requirements.
2010 Outlook
The Company expects gross daily production of the PY-3 field to average 3,000 stbd in 2010. The PY-3 field joint venture's
Technical Committee has recommended the drilling of two additional lateral wells and various facility upgrades including
gas compression for gas lift and sales gas. Drilling of these wells is expected to commence by the first quarter of 2011
and additional production from the wells is expected to commence in the second half of 2011.
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 Cauvery Basin was developed in the late Jurassic/early Cretaceous period and straddles the present-day east coast of
India. The licence, which covers 81 km2, produces high quality light crude oil (49° API).
The field was 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. 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.
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.
Block CY-OS/2: Exploration
(Hardy 75 per cent interest - Operator)
2009 Operations
In 2009 the joint venture applied to the Ministry of Petroleum and Natural Gas of the GOI to establish commerciality of the
Ganesha gas discovery during an appraisal period ending January 2012 as provided for in the production sharing contract
(PSC).
On 20 February 2009 HEPI received a communication from DGH to establish commerciality within 15 days or relinquish the
block. We believe that this action was taken by DGH on the assumption that the Ganesha discovery was an oil discovery. As
Ganesha is a non-associated gas discovery, the CY-OS/2 PSC provides for an appraisal programme to establish commerciality
by January 2012. Hardy has subsequently presented a case to the DGH that supports its claim that the CY-OS/2 joint venture
is entitled to a licence extension as the result of a non-associated gas discovery. In the absence of a resolution in our
favour in the near future, the group intends to refer the dispute for sole expert or conciliation and arbitration.
2010 Outlook
Should the joint venture receive confirmation of the extension period in a timely manner, Hardy will undertake the
activities necessary to fully appraise the Ganesha discovery. It is unlikely that an appraisal well will be drilled in
2010.
Background
Licence block CY-OS/2 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 A-1 discovery
and the southern area lies immediately adjacent to the HEPI operated PY-3 field. The PY-1 gas field, a separate
ring-fenced licence, lies within the southern part of the acreage and commenced production in the third quarter of 2009.
Ganesha: On 8 January 2007 the Company announced that the Fan A-1 exploration well had discovered hydrocarbons. In August
2007 the Company announced that it would proceed to the appraisal phase of the Ganesha non-associated gas discovery to
establish the potential commerciality.
Block Oza (Within OML 11): Development
(Hardy 20 per cent interest)
2009 Operations
The Oza joint venture has made some progress in 2009. The joint venture received delivery of over 34 km length of pipe for
the tie-in of the Oza field to the SPDC operated Isimiri flow station. The operator is in advanced stages of completing
the final FEED study and other regulatory and community approvals. Field operations are expected to commence in the first
half of 2010.
Background
The Oza Field is located onshore in the north western part of OML 11, near Port Harcourt and covers an area of 20 km2. 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 subject to an extension of the Oza
farm-out agreement approved by the Nigerian Department of Petroleum Resources (DPR).
The Oza field has cumulatively produced approximately 1.0 MMstb from four open zones in three wells targeting three
reservoirs, M5.0, M1.0 and M2.2, with the principal reservoir being M5.0. At present, Oza has three suspended wells in the
field. In 2007 the Oza joint venture successfully executed a flow test of the Oza 4 well. The flow rates averaged
approximately 600 stbd of oil with a gas to oil ration (GOR) of 5,466 scf/stb.
Block Atala (Within OML 46): Development
(Hardy 20 per cent interest)
2009 Operations
In 2009, the Atala joint venture continued to struggle to secure the appropriate equipment to undertake the planned
re-entry programme for the Atala-1 well.
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 situated within a mangrove swamp on the Dodo River, a coastal area of north west
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 Atala
field is subject to a farm-out agreement between NNPC, SPDC, Elf Petroleum Nigeria Limited and Nigerian AGIP Oil Company
Limited as farmor and Bayelsa as farmee. The terms of this agreement are for an initial five-year period from 27 April
2004, subject to an extension of the term of the Atala Farm-out Agreement if approved by the Nigerian Department of
Petroleum Resources.
Yogeshwar Sharma
Chief Operating Officer
and Chief Executive Officer Designate
3 March 2010
Risk and Uncertainties
As an oil and gas exploration and production company with operations concentrated in India, Hardy is subject to a variety
of business risks. Outlined below is a description of the principal risk factors that may affect the Group's business.
Such risk factors are not presented in any assumed order of priority. Any of the risks, as well as the other risks and
uncertainties discussed in this document, could have a material adverse effect on our 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.
General Exploration, Development and Production Risks
The Group's strategy is predominantly driven by the exploration, exploitation, appraisal, development and production of its
existing assets. There are risks inherent in the exploration, exploitation, 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
commercial discoveries. Risks such as cost overruns in drilling, delays in execution, technical difficulties, lack of
access to key infrastructure, adverse weather conditions, environmental hazards, industrial accidents, occupational and
health hazards, technical failures, labour disputes, unusual or unexpected geological formations, explosions and other acts
of God are inherent to the business. Although in some cases these represent insurable risks, the Group may also become
subject to other hazards (including pollution and oil seepage liability) against which it is not insured or is under
insured. The occurrence of any of these incidents can result in the Group's current or future project target dates for
drilling or production being delayed or
- More to follow, for following part double click [ID:nRSD0620Ib]
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