REG-Salamander EnergyPLC Interim Results - Part 1
Released: 27/08/2009
RNS Number : 0782Y
Salamander Energy PLC
27 August 2009
27 August 2009
Salamander Energy plc
('Salamander', or the 'Group')
Half Year Financial Results
For the six months ended 30 June 2009
Salamander Energy, an independent upstream oil and gas exploration and production company focused on Asia, announces its half year results for the six months ended 30 June 2009.
HIGHLIGHTS
FINANCIAL
*
Revenue of $77.2 million (1H'08: $46.8 million)
*
EBITDAX1 of $42.1 million (1H'08: $30.1 million)
*
Post-tax loss of $14.3 million (1H'08: loss of $6.6 million)
*
Post-tax profit of $2.0 million adjusting for non-cash mark to market hedging charges
*
Cash and cash equivalents at 30 June of $59.2 million (FY '08: $103 million)
*
Net debt at 30 June of $111.5 million (FY '08: $54 million)
*
Fully funded exploration and appraisal programme
OPERATIONAL DELIVERY
*
Average production increased by 56% to 12,800 boepd2 (1H'08: 8,200 boepd)
*
Completion of Phase II of development drilling in Bualuang oil field
*
Kambuna gas-condensate field development progressed to first gas
*
Discovered additional oil pay close to existing infrastructure in B8/38, Gulf of Thailand
*
Completion of seismic programmes in Vietnam, Thailand, Indonesia and Lao PDR
H2 2009 OUTLOOK
*
Kambuna gas-condensate field brought on-stream
*
Forecast average daily production of c.15,000 boepd in 2009
*
Gas discovery in South Sebuku-1, East Kalimantan, Indonesia
*
Currently testing Phu-Kheng-1 prior to drilling Si That-3 appraisal, Khorat Basin, Northeast Thailand
*
Preparations well advanced for 2010 drilling programme in Lao PDR, Thailand, Vietnam and Indonesia
1
EBITDAX is calculated as profit before other financial gains/(losses), finance costs, tax, amortisation and depreciation and exploration expenses
2
All reserves and production are working interest unless otherwise stated
Commenting on the results, Salamander's Chairman Charles Jamieson said:
'We are pleased to report strong underlying financial results for the first half of 2009, a period which saw continued production growth and exploration success for the Group. Having successfully completed our major development programmes, we are looking forward to an active exploration and appraisal programme through 2010. Salamander's sound financial position, together with its increasing production and cash flow profile, provides a strong platform for future value creation and growth.'
An audio recording of the analyst conference call will be made available on the IR section of the company website, http://www.salamander-energy.com/investor-centre.aspx, from Friday 28 August.
Enquiries:
Salamander Energy
020 7960 1580
James Menzies, Chief Executive Officer
Geoff Callow, Head of Corporate Affairs
Pelham PR
020 7337 1500
Mark Antelme
Evgeniy Chuikov
Henry Lerwill
Salamander Energy Plc
Half-year results for six months ended 30 June 2008
Chairman and CEO's Review
We are pleased to report strong underlying financial results for the first half of 2009, a period during which the Group delivered both continued production growth and exploration success with oil and gas discoveries in the Gulf of Thailand and East Kalimantan. The Group's robust financial position allowed continued focus on operational delivery during a period of turbulence and volatility in commodity prices and the wider capital markets.
Financial Results
The Group delivered revenue, cash flow and production growth during the first half of the year. The profit figures were impacted by non cash, mark to market losses of $16.3 million on the Group's hedging activity, resulting in a loss after tax of $14.3 million (1H'08: $6.6 million). The underlying financial performance was healthy with revenues of $77.2 million (1H'08: $46.8 million) and EBITDAX of $42.1 million (1H'08: $29.7 million). Average realisations of $43.33 per bbl (1H'08: $111.31) and $3.69 per Mscf (1H'08: $4.80) were achieved in the period. The Group had net debt of $111.5 million at 30 June 2009 (30 June 2008: net debt of $102.0 million). The exploration and appraisal programme is fully funded.
Operational Progress
In May 2009 the Group completed the second phase of a drilling programme on the Bualuang oil field, Gulf of Thailand. Two horizontal production wells were completed and brought on-stream during May 2009, helping to boost gross field production from an average of 6,700 bopd in the first quarter to 11,600 bopd in the second quarter 2009.
The Kambuna development, offshore North Sumatra, progressed during the period, with first production achieved in August. The gas is used for power generation, in order to supply power to the city of Medan, the second largest city in Indonesia.
The 2009 exploration and appraisal programme got off to a successful start with the BA-11P oil discovery, offshore Thailand. This was followed in August 2009 by the South Sebuku-1 gas discovery in the Tarakan basin, East Kalimantan.
Meanwhile, we are continuing with our drilling campaign in Northeast Thailand, where the Phu Kheng-1 exploration well is targeting a structure which has the potential to contain c. 1 Tcf of recoverable gas in block L27/43. We will follow this up with the appraisal of the Si That gas discovery in neighbouring block L13/48 using the same drilling rig.
Portfolio Development
In March 2009 the Group announced that it had signed a Production Sharing Contract ('PSC') for Block 31, offshore southern Vietnam. Salamander is the operator of the PSC with a 60% working interest. This is adjacent to the Group's operated DBSCL-01 PSC in the Mekong Delta area. Unusually, the Group acquired in excess of 3,000 line-km of 2D seismic across the acreage prior to signature of the PSC. This accelerated the exploration effort, and having now identified the likely presence of source rocks and confirmed the existence of multiple play types, we are preparing for drilling in the first half of 2010.
Board of Directors
On 15 May 2009 the Group announced that, following the placing of 3i's equity interest in Salamander Energy plc, Mike Sibson had resigned as a Director of the Company. Mike's experience was welcomed by the Board and we would like to thank him for his contribution to the Group.
Current Trading and Outlook
Having completed the most recent phase of the Bualuang field development and brought the Kambuna field on-stream to plan and budget, the Group has achieved two of its key objectives for 2009. These have driven increased production and cash flow. Average production over the past seven days has been 17,600 boepd and the Group expects average annual daily production for 2009 to be c. 15,000 boepd. Salamander currently operates over 55% of total Group production and both this figure and average daily production will increase as volumes from Kambuna build up in the coming weeks.
The 2009 exploration and appraisal programme has started positively and will accelerate in pace with a 2010 programme of at least eight exploration wells in Vietnam, Indonesia, Lao PDR and Thailand.
The Board is confident that, subject to commodity price stability, the Group's increasing production and cash flow profile, coupled with a material and diverse 2010 drilling programme, provide it with an excellent platform for continued growth.
Charles Jamieson
Chairman
26 August 2009
James Menzies
Chief Executive Officer
26 August 2009
Review of Operations
The first half of 2009 was another busy period for the Group with the completion of Phase 2 drilling on the Bualuang field and the progression of the Kambuna development to first gas in August 2009 the most high profile events. The following summary details operational achievements in H1 2009:
*
delivered production growth at the Bualuang oil field following completion of Phase 2 drilling and discovered additional resources above and below the main T4 reservoir of the Bualuang oil field
*
progressed Kambuna development towards first gas, this was completed on budget in August 2009
*
completed seismic surveys in Vietnam, Lao PDR, Indonesia and Thailand in preparation for extensive 2010 exploration drilling programme
*
discovered additional resources above and below the main T4 reservoir of the Bualuang oil field
*
spudded the South Sebuku-1 exploration well in the Bengara I PSC which resulted in a gas discovery that is expected to be commercial
*
completed preparations for drilling of the Phu Kheng-1 and Si That-3 wells in 2H '09
Health, Safety and Environment
Operating activity levels have remained high since the start of the year and the first half saw over 1.2 million man hours worked with no lost time incidents recorded. The Group's HSE management system has been further developed and rolled out to all offices and field locations. Committees have been established in the operating offices to define projects to be undertaken as part of the Group's corporate social responsibility commitment and to review requests from the communities in which the Group operates. These communities are key partners to the Group and local investment has continued with new CSR projects executed in Vietnam and Thailand.
Production
Production for the first half of the year averaged 12,800 boepd, comprising 68% liquids and 32% gas. A significant increase occurred in May 2009 when two horizontal production wells were completed on the Bualuang oil field and immediately put on stream. These wells are highly productive and increased Bualuang production from c.7,000 barrels of oil per day ('bopd') to an average of 11,700 bopd in 2Q 2009. Six wells are now in production on Bualuang and they are performing in line with reservoir simulation models, with water production at or below expectation and comfortably within the capacity of the re-injection facilities.
The second half of the year is expected to see a further step up in production following first gas at the Kambuna field in August 2009. The field is ramping up to full contracted volumes of 40 MMscfd of gas and approximately 4,000 barrels of condensate per day.
Geographical Review
Thailand
Bualuang Oil Field
Operations on the Bualuang oil field in the Gulf of Thailand in the first half of 2009 saw the completion of the phase two drilling programme. This comprised the drilling of an exploration well, two horizontal producers and a water disposal well.
Two horizontal production wells, BA-11H well and BA-12H, were completed in May 2009 in a crestal area of the field and were immediately tied into the production system and put on stream. Horizontal sections measuring 250 metres were drilled in a target zone 2-3 metres below top reservoir. Both wells encountered excellent quality reservoir rock and tested at over 8,000 bopd each. The two wells have been choked back to manage production in line with the reservoir simulation and thereby optimise reserves recovery. The field is currently producing at c.10,500 bopd (gross) and level of water cut is well within the capacity of the water disposal facilities which can handle 20,000 bwpd.
The exploration well, BA-11P, drilled as a pilot hole to guide the first horizontal producer, was completed in April 2009 and encountered a 32 metre oil column in the main T4 reservoir sandstones. This represents the thickest penetration to date in the Bualuang field.
Three additional sandstones were encountered above the T4 reservoir and were found to be oil-bearing, with some 7 metres of net pay over this interval. At the deeper objective below the T4 reservoir, 8 metres of net oil pay was intersected in the T2 Oligocene syn-rift section. Crude oil samples were taken from the T2 interval and analysis shows this to be a 33 degree API oil, while the main T4 reservoir on the Bualuang field is 27 degree API. Studies are underway to determine the reserves potential and exploitation strategy for the additional pay found in BA-11P.
Sinphuhorm field
Onshore northeast Thailand, production from the Sinphuhorm field averaged 77 MMscfd, with nominations from the Nam Phong Power Plant at a reduced level in the early part of the year due to an extensive maintenance programme on the turbines at the power plant. Nominations have since returned to normal levels and the field averaged 92 MMscfd in July 2009.
Exploration and appraisal
The Phu Kheng-1 exploration well spudded in early July 2009. The well is targeting gas in the Jurassic and Triassic sandstones of the Phu Kradung and Nam Phong formations. The mean gross pre-drill estimate of prospective recoverable gas resources is approximately 1 Tcf. The well reached total depth of 2,208 metres sub-sea, logs have been run and a testing programme is underway in the Lower Nam Phong formation. On completion of this well the rig will move to the location of the Si That-3 appraisal well in the adjacent block L13/48. This will appraise a gas bearing structure analogous to the nearby Sinphuhorm field with potential to contain up to 1.3 Tcf of recoverable resources.
Preparations for a 3D seismic survey in Block L15/50 were completed and the survey commenced in July 2009. L15/50 contains a gas discovery called Dao Ruang, thought to have between 600 Bcf and 1 Tcf of resource potential. The high resolution 3D seismic survey has been designed to define the structure and image the Pha Nok Khao carbonate in order to position appraisal wells in optimal locations to encounter good quality reservoir rock. Appraisal drilling is expected to commence in 2H 2010.
In Block 26/50, a 2D seismic survey was completed in 1Q 2009. Initial interpretation of this data has identified four large potentially gas bearing structures with similar characteristics to the Bang Nouan gas prospect across the Mekong River in Lao PDR, in the Group's operated Savannakhet PSC. These provide follow up drilling targets in the event of a successful exploration well on Bang Nouan in 1Q 2010.
Lao PDR
Exploration
The Group has completed the interpretation of 2D seismic data acquired to delineate the large Bang Nouan anticline in the Savannakhet PSC. In conjunction with geo-chemical sampling and other field surveys this has enabled Salamander to select the drilling location for its first exploration well in Lao PDR. Bang Nouan is estimated to have between 700 Bcf to 1.2 Tcf of resource potential on an extension of the Pha Nok Khao play fairway proven productive in Northeast Thailand.
Gas source rocks are known to be present in the area and several large, undrilled structures have been mapped using the latest seismic data. The principal risks on the play are access to the source rock and an effective reservoir. As such the Bang Nouan 1 well, which will be only the third petroleum exploration well ever drilled in the country, represents a high risk, frontier exploration well that is of potentially high impact to both Salamander and Lao PDR. Site preparations are due to commence in the dry season in September 2009 ahead of exploration drilling in 1Q 2010.
Vietnam
Exploration
Salamander announced in March 2009 that it had signed a Production Sharing Contract ('PSC') for Block 31, offshore southern Vietnam. This acreage is adjacent to Salamander's operated Cuu Long River Delta Block 01 ('DBSCL-01') PSC.
A 2D seismic survey across Block 31 was completed in 4Q 2008. During 2009 this data has been processed and integrated with the DBSCL-01 seismic for interpretation and mapping. The initial interpretation indicates the presence of lacustrine source rocks and a number of different play types in the Vinh Chau graben system. The Vinh Chau graben system is geologically and structurally analogous to the nearby proven and prolific Cuu Long basin and is wholly contained within the Salamander exploration acreage. Further geological and geophysical work continues to high grade prospects, thought to be in the 40-70 MMbo range, ahead of exploration drilling in the middle of 2010 when sea conditions are best suited to activity offshore southern Vietnam.
Indonesia
Kambuna field
The Kambuna gas-condensate development, offshore North Sumatra, has been completed and first gas was produced in August 2009 through early production facilities. As the facility is debottlenecked throughput will rise to reach the full contracted volume of 40 MMscfd. The gas sales have been contracted to Pertiwi and PLN for use in power generation in North Sumatra and will realise an average price of $5.90 per Mscf with a 3% annual inflator.
The focus of the Kambuna development project will now switch to the completion of the permanent onshore receiving facilities at Pangkalan Brandan. These are expected to be finished around the turn of the year and will have the capacity to handle additional volumes above and beyond the level of the current contracted volumes. With this in mind Salamander intends to advance discussions on marketing additional volumes of Kambuna gas as soon as the production history has demonstrated the capacity of the wells to deliver additional volumes on a sustainable basis.
ONWJ & SES
Production from the Offshore North West Java and South East Sumatra PSC's was in line with expectations. These licences continue to produce at a steady rate of c.6,000 boepd net to the Group. Infill development drilling programmes have been conducted on both blocks during the first half of 2009 to maintain the production, to look for new oil and to appraise previously discovered reserves.
Exploration
In East Kalimantan, the Group continued to mature its exploration acreage ahead of 2010 drilling. Additional 2D seismic was recorded over the Bontang PSC and the Angklung prospect has been selected as the first exploration drilling target on this block in 1Q 2010. Angklung is a fault bounded closure with sandstone reservoir targets in the Middle Miocene and is forecast to contain c.70 MMboe of prospective resources. Additional prospects, of similar resource potential, have been identified for drilling later in 2010 and in 2011.
The Group continues to evaluate the options for the Tutung discovery and is currently awaiting the results of seismic reprocessing and a local gas marketing study before deciding whether to pursue a mini-development or return for further appraisal work.
A 2D seismic survey has been completed in the Kutai PSC. The operator expects to commence an exploration drilling with two onshore wells, and two contingent offshore wells, in 2010.
Further north, in the Tarakan Basin, an auction process was conducted to find a buyer for gas from the South Sembakung field in the Simenggaris PSC. A consortium of PLN and Medco Gas won the bidding and heads of agreement have been signed for the supply of gas from the field to the nearby Bunyu Methanol plant. The base gas price will be $3 per Mscf escalating at 3% per annum with an uplift component relating to prevailing methanol prices. This price will sustain an economic development of the South Sembakung field and work on the field development itself is scheduled to commence by year end.
The South Sebuku-1 exploration well in the Bengara-1 PSC, also in the Tarakan basin, was spudded in June 2009 and encountered gas in four zones. Two of these were tested and flowed at a cumulative rate of 10.9 MMscfpd. Discussions are in progress with the Indonesian authorities to facilitate appraisal of the discovery. Assuming successful appraisal the South Sebuku gas discovery is expected to be tied in to the South Sembakung field, located only 15 km away.
Mike Buck
Chief Operating Officer
26 August 2009
Financial Review
Key Performance Indicators
The Group's performance against its key performance indicators for the period is summarised below:
Unit
First Half 2009
First Half 2008
FY'08
Lost Time Incidents
Nil
Nil
Nil
Production (working interest basis)
Boepd
12,800
8,200
9,600
Production (entitlement basis)
Boepd
10,700
5,000
6,700
Realised Price per barrel of oil
$
43.33
111.31
60.52
Realised Price per Mscf of gas
$
3.69
4.80
4.99
Operating Cost per boe
$
10.86
9.53
10.64
Operating Cash Flow per entitlement boe(1)
$
20.55
25.84
17.03
Gearing(2)
%
23
26
21
1.
Operating cash flow per entitlement boe is calculated as operating cash flow prior to working capital divided by entitlement interest production
2.
Gearing is calculated as debt divided by debt plus equity
Overview
The first half of 2009 saw continued commodity price volatility with Brent falling to a low of $44/bbl during February and closing the period at $72/bbl. There was also much uncertainty in the banking sector and across capital markets. The Group maintained a healthy financial position due to its 2008 capital raisings, and its rising production and cash flow levels. The Group took a number of measures, including interest rate hedging, and a reduction in discretionary capital expenditure, during early 2009 to respond to the volatile market conditions.
Group production rose to 12,800 boepd in the first half of 2009 following completion in April of two horizontal infill wells on the Bualuang oil field, Thailand.
The Group hedges a proportion of its production to reduce the impact of oil price volatility and protect the Group's capital programmes. In November 2008 the Group purchased $45.00/bbl puts for volumes of 2,500 bpd for first half 2009 increasing to 4,000 bpd for second half 2009. As crude prices stabilised, these hedges were then replaced from February 2009 onwards by a forward sale (swap) of 2,500 bpd at an average of $53.83/bbl for the period February to December 2009 plus the purchase of 1,500 bpd of put options at $54.00/bbl for the period July to December 2009. This programme hedged 33% of the Group's 2009 first half entitlement oil production. In addition, 62% of the Group's gas production was protected from price volatility due to fixed price gas contracts.
The Group also took out a hedge for its full year 2010 production: a zero cost collar for 2,500 bpd at a put and call strike of $60.00/bbl and $78.15/bbl respectively. A second zero cost collar for 1,500 bpd at a put and call strike of $60.00/bbl and $90.50/bbl respectively was completed in July 2009. The accounting effect of the hedging programme is set out below.
The Group's realised oil price for the first half of 2009 including the impact of the 2009 hedges, was $43.33/bbl (1H'08: $111.31/bbl) and for gas was $3.69/Mscf (1H'08 - $4.80/Mscf).
During the first half of 2009, the Group also took advantage of what were considered low Libor rates by historical standards to execute a swap for approximately 50% of its interest rate exposure for a three year period commencing April 2009, swapping Libor for the period at 2.17%.
During the first half of 2009, the Group generated $40.5 million of operating cash flow (prior to working capital adjustments), a 70% increase on the comparative period in 2008 (1H '08: $23.8 million). This translated into a pre tax loss of $5.8 million (1H'08: profit of $3.8 million) principally due to the non-cash charges for amortisation of $29.2 million (1H'08: $9.8 million) and the mark to market adjustments on the Group's oil and interest rate hedges of $16.3 million (1H'08: Nil). With taxation charges of $8.6 million, (1H'08: $10.5 million), the Group reported a post tax loss for the period of $14.3 million (1H'08: $6.6 million).
During December 2008, the Group completed the redetermination of its $200 million seven year Reserve Based Lending Facility. This resulted in a further drawdown against the facility of $15.6 million in January 2009, increasing the total drawn amount to $176.5 million. Under the terms of the facility, the Group was required to repay $2.1 million of the facility at the end of June. Despite significant development expenditure on the Kambuna and Bualuang fields in the period, the Group remains in a healthy financial position with cash and cash equivalents at 30 June 2009 of $59.2 million (FY'08: $103.0 million) and net debt of $111.5 million (FY'08: $54.0 million), and is fully financed to fund its future commitments.
Income Statement
The first half of 2009 saw Group revenues increase to $77.2 million (1H'08 2008: $46.8 million) driven by higher production volumes from the Bualuang oil field in Thailand. The revenue growth was achieved despite lower prevailing commodity prices, with the Group realising $43.33 per bbl (1H'08: $111.31) for oil and liquids and $3.69 per Mscf (1H'08: $4.80) for gas during the period. Gross profit in the period was $15.6 million (1H'08: $21.1 million).
Other operating charges for the period totalled $5.2 million (1H'08: $18.0 million) and comprised exploration expenses of $1.6 million (1H'08: $13.4 million) and administrative expenses of $3.6 million (1H'08: $4.6 million). Exploration expenses for the period were pre-licence exploration costs to secure new acreage in Asia, whereas 1H'08 and FY'08 included written off exploration costs of $10.2 million and $39.1 million respectively following unsuccessful wells in Indonesia and the Philippines.
Interest revenue of $0.9 million (1H'08: $3.9 million) was derived from the Group's investment of surplus cash, down on last year partly due to the reduced deposit interest rates available during the period. The finance costs of $0.8 million (1H'08: $2.7 million) were principally interest payable in respect of the Group's Reserves Based Lending facility.
Other financial losses of $16.3 million (1H'08: $0.5 million) during the first half of 2009 comprised non-cash mark to market charges against the Group's commodity price and interest rate hedges as follows:
$'millions
*
Reversal of gain to 31 December 2008 in respect of 2009 hedges (put of 2,500 bpd for 1H'09 and 4,000 bpd for 2H'09 45.00/bbl)
4.4
*
2H'09 oil price hedges (swap of 2,500 bpd at $54.00/bbl and put of 1,500 bpd at $54.00/bbl)
7.4
*
2010 oil price hedges (zero cost collar of 2,500 with put of $60.00/bbl and call of $78.15/bbl)
3.9
*
Libor interest rate swap at 2.17% for approximately 50% of interest rate exposure
0.6
TOTAL
$16.3m
Taxation of $8.6 million (1H'08: $10.5 million) arose on the Group's foreign income from production in Thailand and Indonesia which is taxable at 50% and 41.5% respectively. The half year 2009 charge also included a deferred tax credit of $6.4 million (1H'08: $1.8 million).
As a result of the above, the Group reported a loss after tax of $14.3 million (after non-cash mark to market losses of $16.3 million) compared to the six months ended 30 June 2008 loss of $6.6 million. This position would have been a profit after tax of $2 million if adjusted for mark to market charges relating to the Group's hedging activities. Despite these losses, the Board believes the action taken was appropriate in view of continuing oil price volatility.
Cash Flow Statement
Cash flow from operating activity for the period increased to $19.8 million (1H'08: $15.4 million) despite lower comparative commodity prices, due to a full period of contribution from the Bualuang oil field. Net operating cash flow from operations in Thailand was $10.8 million (1H'08: $5.3 million) and Indonesia was $10.3 million (1H'08: $12.7 million). These were partially offset by administrative and other operating expenditures of $1.3 million (1H'08: $2.6 million).
As planned, the majority of the 2009 capital investment has been completed in the first half of the year. Cash flow used in investing activities of $74.4 million (1H'08: $161.9 million,) included investments in Thailand of $15.5 million (1H'08: $37.1 million), in Indonesia of $53.6 million (1H'08: $52.8 million) and in Vietnam of $4.7 million (1H'08: $1.9 million). This was partly offset by the farmout in respect of Lao PDR with a recovery of $ 3.3 million (1H'08: $2.5 million).
Activities in Thailand included the acquisition of seismic in Block L26/50 and the drilling of the Bualuang infill horizontal wells. Activities in Indonesia included the continued development of the Kambuna gas-condensate field of $36.9 million (1H'08: $16.2 million). Activities in Vietnam included the acquisition of seismic in Block 31 and in Lao comprised the preparations for the 2010 drilling programme.
Cash inflow from financing activities for the period was $10.7 million (1H'08: $85.6 million). This included: net proceeds from borrowings of $13.4 million (1H'08: $90.8 million) with the incremental drawdown against the Group's seven year Reserves Based Lending facility; and interest payments of $2.7 million (1H'08: $1.7 million).
The predominance of the Group's 2009 investment programme occurred in the first half of the year with the Group spending cash of $43.9 million (1H'08: $60.8 million). This resulted in cash and cash equivalents at the end of the period of $59.2 million (1H'08: $55.6 million, FY'08: $103.0 million).
Post Balance Sheet Events
On 24 July 2009, the Group further purchased commodity price hedges, a zero cost collar for 1,500 bpd with a put and call strike price of $60.00/bbl and $90.50/bbl respectively.
On 11 August 2009, the Kambuna gas-condensate field in Indonesia came on stream.
On 13 August 2009, the Group announced it had completed drilling operations on the South Sebuku-1 exploration well. The well tested gas at a rate of 10.9 MMscfd and has been suspended as a potential future producer pending further appraisal work expected in 2010.
Risk Management
The identification and mitigation of risks are of critical importance to the Group as it continues to expand and increasingly moves to operate its activities. The Group's Executive Directors constantly monitor the Group's risk exposures and report to the Audit Committee on a six monthly basis, with more frequent updates on particular risks as required. The Audit Committee provides oversight whilst ultimate authority remains with the Group's Board.
The principal risks for the Group remain as previously detailed on pages 18 and 19 of the 2008 Annual Report and Accounts and can be summarised as:
*
Strategic risks: portfolio management and mix; capital allocation; macro markets.
*
Operational risks: HSE and CSR; asset management and performance
*
Financial risks: liquidity, markets and cost management.
*
Other risks: fiscal, investor relations and governance.
Further to the detailed disclosure provided in the 2008 Annual Report and Accounts:
*
the commencement of Kambuna production in the second half of 2009 requires the management of additional development and operating risks as the Group expands its operated production base. Kambuna is expected to have a significant influence on the Group's financial results in the second half of the year and subsequent periods;
*
the economic environment and volatility in oil price remains challenging. In order to manage volatility, the Group entered into a series of hedges during 2009 as set out in the Interim Report;
*
authority to enter into interest rate hedging remains with Board of Directors. In April 2009, the Group took advantage of what were considered low Libor rates by historical standards to execute an interest swap for approximately 50% of its current and future interest rate exposure for a three year period commencing April 2009.
Nick Cooper
Chief Financial Officer
26 August 2009
Responsibility Statement
We confirm that to the best of our knowledge:
(a)
the condensed set of financial statements has been prepared in accordance with IAS 34 'Interim Financial Reporting';
(b)
the interim management report includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and
(c)
the interim management report includes a fair review of the information required by DTR 4.2.8R (disclosure of related party transactions and changes therein).
By order of the Board,
James Menzies
Chief Executive Officer
26 August 2009
Nick Cooper
Chief Financial Officer
26 August 2009
INDEPENDENT REVIEW REPORT TO SALAMANDER ENERGY PLC
We have been engaged by the Company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2009 which comprises the condensed consolidated income statement, the condensed consolidated statement of changes in equity, the condensed consolidated balance sheet, the condensed consolidated cash flow statement and related notes 1 to 13. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.
This report is made solely to the Company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Auditing Practices Board. Our work has been undertaken so that we might state to the Company those matters we are required to state to them in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company, for our review work, for this report, or for the conclusions we have formed.
Directors' responsibilities
The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.
As disclosed in note 2, the annual financial statements of the group are prepared in accordance with IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, 'Interim Financial Reporting,' as adopted by the European Union.
Our responsibility
Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.
Scope of Review
We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
Conclusion
Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2009 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.
Deloitte LLP
Chartered Accountants and Statutory Auditors, London, UK
26 August 2009
CONDENSED CONSOLIDATED INCOME STATEMENT
Six months ended 30 June 2009
Six months
ended 30 June
2009
Unaudited
Six months
ended 30 June
2008
Unaudited
Year ended
31 December 2008
Note
$'000s
$'000s
$'000s
CONTINUING OPERATIONS
Revenue
4.
77,151
46,845
100,753
Cost of sales
Impairment
-
-
(55,000)
Other cost of sales
(61,515)
(25,757)
(70,552)
Total cost of sales
5.
(61,515)
(25,757)
(125,552)
Gross profit/(loss)
15,636
21,088
(24,799)
Exploration expenses:
Exploration costs written off
-
(10,226)
(39,065)
Pre-licence exploration expenses
(1,599)
(3,129)
(7,981)
Profit on disposal of assets
-
-
807
Total exploration expenses
(1,599)
(13,355)
(46,239)
Administration expenses
(3,601)
(4,601)
(10,859)
Operating profit/(loss)
10,436
3,132
(81,897)
Interest revenue
906
3,865
5,814
Finance costs
(783)
(2,687)
(2,953)
Other financial (losses)/gains
6.
(16,330)
(466)
3,564
(Loss)/Profit before tax
(5,771)
3,844
(75,472)
Current tax
(14,993)
(8,688)
(14,651)
Deferred tax:
Impairment
-
-
27,500
Other
6,422
(1,800)
(3,872)
Total tax
7.
(8,571)
(10,488)
8,977
Loss for the period
(14,342)
(6,644)
(66,495)
Loss per ordinary share
$'s
$'s
$'s
Basic and Diluted
8.
(0.09)
(0.06)
(0.53)
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Six months ended 30 June 2009
Share
Capital
Share Premium
Other Reserves
Retained Earnings
Total
$'000s
$'000s
$'000s
$'000s
$'000s
1 January 2008
17,271
202,345
67,996
(4,450)
283,162
Shares Issued:
Ordinary shares issued in business combination
6,172
-
178,064
-
184,236
Share issue costs
-
(3,489)
-
-
(3,489)
Share based payments
-
-
950
-
950
Loss for the period
-
-
-
(6,644)
(6,644)
30 June 2008
23,443
198,856
247,010
(11,094)
458,215
Shares issued:
Ordinary shares issued for cash
6,401
185,618
-
-
192,019
Share issue costs
-
(5,789)
(3,574)
-
(9,363)
Share based payments
-
-
1,083
-
1,083
Loss for the period
-
-
-
(59,851)
(59,851)