ASX Announcement
Activities for the Quarter ended 31 March 2015
(ASX: OSH | ADR: OISHY | POMSoX: OSH)
21 April 2015
Highlights
1Q 2015 4Q 2014 % change
Total production (mmboe) 6.91 7.24 -5%
Total sales (mmboe) 7.04 6.87 +2%
Total revenue (US$m) 472.3 562.1 -16%
• Total production in the first quarter of 2015 was 6.91 million barrels of oil equivalent (mmboe), compared to 7.24 mmboe in the previous quarter. Production net to Oil Search from the PNG LNG Project was 5.27 mmboe (23.1 bcf LNG and 0.75 mmbbl liquids), while the base PNG oil and gas business contributed 1.64 mmboe. The Company remains on track to deliver 2015 production within the 26 - 28 mmboe guidance range.
• Total revenue for the quarter was US$472.3 million, 16% lower than in the previous period, reflecting the impact of the global downturn in oil prices on the Company's LNG, gas, oil and condensate sales revenue. The average realised LNG and gas price was US$12.37/mmBtu, down 14% from the fourth quarter, while the average realised oil and condensate price declined 30%, to US$51.29/barrel.
• The PNG LNG Project achieved financial completion in February, resulting in the release to the Company of more than US$850 million in cash previously escrowed in PNG LNG Project related accounts.
• In February, the PRL 3 Joint Venture submitted a petroleum development licence (PDL) application for the P'nyang field to the PNG Government. This followed the signing of a Memorandum of Understanding (MoU) in January between ExxonMobil PNG Limited and the Government regarding the development of the P'nyang field, to support the potential expansion of the PNG LNG Project and the supply of electricity and gas for domestic power generation.
• In April, a key commitment under the MoU was fulfilled, with the execution of a power sale agreement between ExxonMobil PNG Limited and PNG Power Ltd.
• The Antelope 5 appraisal well reached total depth during the quarter, encountering the gas carbonate reservoir broadly in line with prognosis. Drilling operations at Antelope 4 continued during the period.
• At the end of March 2015, Oil Search had cash of US$1,067.2 million and debt of US$4,331.7 million, comprised entirely of PNG LNG Project finance facility debt following the repayment of US$150 million drawn from its bilateral revolving credit facilities. At the end of the quarter, the Company had
total liquidity of US$1,817.2 million, including US$750 million of undrawn corporate credit facilities.
Oil Search Limited
Incorporated in Papua New Guinea ARBN 055 079 868
Head office Port Moresby Papua New Guinea
Sydney office
1 Bligh Street
Sydney NSW 2000
Australia
Mailing address
GPO Box 2442
Sydney NSW 2001
Australia
Tel: +61 2 8207 8400
Fax: +61 2 8207 8500 www.oilsearch.com
COMMENTING ON KEY ACTIVITIES IN THE FIRST QUARTER OF 2015, OIL SEARCH MANAGING DIRECTOR, PETER BOTTEN, SAID:
"In light of continuing weakness in global oil and gas prices, the Company has carried out a careful re- examination of the results of the 2014 Strategic Review. This has confirmed that the Company's core strategies, focused on LNG growth in PNG, remain sound and have the ability to deliver superior returns to our shareholders. While the business is not immune from the significant decline in oil prices, Oil Search remains in a resilient position, both operationally and financially. Almost all PNG LNG Project construction expenditure has been completed, financial completion was achieved in February and the Project is consistently performing above expectations while delivering strong cash flows. Our operated oil and gas business in PNG also continues to perform reliably.
As indicated at our full year results, we have made material revisions to the capital and operating cost budgets for 2015, to align the work programmes and cost base of the business with our LNG growth priorities and enhance investment returns. While the Company's balance sheet and financial position are strong, in light of the decline in oil price, we believe it is prudent to remove costs from our business and reinforce fiscal discipline to enhance profitability while ensuring we have sufficient financial capacity to pursue our growth opportunities.
During the quarter, gas commercialisation activities in the North-West Highlands and Gulf Province in PNG continued. With our interests in both the P'nyang field and the Elk/Antelope fields, Oil Search is particularly well positioned to participate in the next phase of LNG development in PNG."
PNG LNG Project
"Production from the PNG LNG Project remained strong during the first quarter, totalling 5.27 mmboe net to Oil Search. The Project continued to perform well, with both trains consistently operating above nameplate capacity. Planned maintenance in the LNG plant took place late in the quarter, which had a minor impact on production. This was completed by the end of the period.
During the quarter, 24 LNG cargoes were lifted and 26 sold to the Project's four long-term customers from Japan, China and Taiwan. Of the LNG cargoes sold, 19 were under long-term contracts and seven sold on the spot market. Seven-and-a-half equivalent cargoes of Kutubu Blend, comprising production from the PNG oil fields and condensate from the PNG LNG Project, were also sold, as well as two cargos of naphtha.
In early February, the Project reached financial completion, resulting in Oil Search receiving US$747 million in the Project's first distribution, reflecting our share of Project revenues, net of operating costs and debt service reserve funding requirements, and a further US$107 million that was released from a completion guarantee escrow account."
P'nyang gas development activities
"In January 2015, ExxonMobil PNG Limited and the PNG Government signed an MoU regarding the development of the P'nyang gas field, to support the potential expansion of the PNG LNG Project and the delivery of power to PNG.
In line with the MoU, the PRL 3 Joint Venture submitted a PDL application for the field to the Government in February 2015. Subsequent to the end of the quarter, ExxonMobil PNG Limited executed a power sale agreement with PNG Power Ltd for the supply of up to 25 megawatts of electricity for local use in Port Moresby, fulfilling one of the key commitments made under the MoU. Initial preparations to drill an appraisal well on P'nyang also commenced."
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Elk/Antelope gas development activities
"As previously announced, in early February the International Court of Arbitration released its non- unanimous judgement regarding the PRL 15 arbitration. Subsequent to this decision, interests in the PRL 15 licence were transferred from InterOil to Total and Oil Search proposed the election of Total as operator of PRL 15, which was passed unanimously by the joint venture partners on 27 February.
During the quarter, the PRL 15 parties continued to work constructively in progressing the possible development of the Elk/Antelope fields, with evaluation of the Elk/Antelope gas resource taking place during the period. Drilling operations continued on the Antelope 4 well to appraise the southern extent of the field. Antelope 5, located on the western flank, intersected the top carbonate reservoir at a depth broadly in line with our expectations and reached total depth, with preparations underway for a planned extended well test. Preliminary planning work on a third appraisal well, Antelope 6 and an exploration well, Antelope South (formerly known as Antelope Deep), also progressed. Funding for both wells has now been approved by the PRL 15 Joint Venture.
Information from the drilling and planned testing programme will help delineate the size, reservoir connectivity and productivity of the Elk/Antelope gas field, enabling the PRL 15 Joint Venture to complete resource evaluation. The Joint Venture is presently finalising concept select studies and expects to determine the optimal development concept and move into pre-FEED in 2015."
Power solutions in PNG
"Oil Search is working closely with the PNG Government and power agencies to provide sustainable power solutions to PNG, focusing on the Highlands region and adjacent provinces. We believe this is a political and social priority, particularly since the commencement of LNG exports from the PNG LNG Project.
In addition to the recently signed P'nyang MoU, in April, the Company announced the completion of the first phase of the Ramu Power Project. This long-term, multi-phase power delivery project is aimed at providing access to reliable, affordable power to the approximately three million people who live within 20 kilometres of the Ramu Grid, PNG's largest power grid."
Taza oil field, Kurdistan
"During the quarter, the Taza 2 appraisal well was tested in the deepest interval, the Cretaceous Shiranish Formation and preparations for a second flow test over the shallower Oligo-Miocene, Kirkuk, Euphrates and Jeribe Formations are underway. Drilling operations at Taza 3 remained ongoing."
2015 first quarter production and revenue performance
"Total production in the first quarter was 6.91 mmboe compared to 7.24 mmboe in the fourth quarter of 2014. The 5% decline in production was largely in line with expectations, reflecting slightly lower production at the PNG LNG plant due to scheduled maintenance, while stronger than expected well performance partially offset plant and well downtime in the Company's PNG oil business. Production rates had been fully restored by the end of the quarter. 2015 full year production guidance remains unchanged at 26 - 28 mmboe.
Total operating revenue was US$472.3 million compared to US$562.1 million in the previous quarter. The
16% decline reflected an 8% decrease in LNG and gas revenues and a37% fall in oil and condensate
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revenues, driven by the weakness in global oil prices. The average realised oil and condensate price fell
30%, to US$51.29/barrel, while the average realised LNG and gas price fell 14%, to US$12.37/mmBtu.
As noted on page 11, US$164.8 million was spent on exploration, development and production activities, of which more than half was related to exploration and evaluation activities in PNG and Kurdistan (primarily the Antelope 4 and 5 appraisal wells, the exploration component of Hides F1 (Hides Deep) and the Taza 2 and 3 appraisal wells). Development spend on the PNG LNG Project was US$41.2 million, mainly related to development drilling on the Angore field and the development section of the Hides F1 well.
Total liquidity increased from US$1,560.2 million at the end of December 2014 to US$1,817.2 million at the end of March 2015, comprising US$1,067.2 million in cash and US$750 million in undrawn committed funding lines."
2015 FIRST QUARTER PERFORMANCE SUMMARY Production1
Production data
PNG LNG Project2
Quarter End Full Year
Mar 2015 Dec 2014 Mar 2014 Dec 2014
LNG (mmscf) 23,059 23,802 - 52,199
Condensate ('000 bbls) 710 781 - 1,870
Naphtha ('000 bbls) 42 42 - 90 PNG crude oil production ('000 bbls)
Kutubu 921 923 848 3,692
Moran 408 478 492 1,989
SE Mananda - - 4 5
Gobe Main 7 8 8 32
SE Gobe 25 30 35 127
Total oil production ('000 bbls) 1,362 1,438 1,388 5,845 Hides GTE Refinery Products3
|
Sales gas (mmscf)
|
1,263
|
1,418
|
1,349
|
5,675
|
Liquids ('000 bbls) 27 30 29 121
Total barrels of oil equivalent ('000 boe)4 6,909 7,236 1,681 19,274
1. Numbers may not add due to rounding.
2. Production net of fuel, flare and shrinkage.
3. Hides GTE production is reported on a 100% basis for gas and associated liquids purchased by the Hides (GTE) Project Particip ant (Oil Search 100%)
for processing and sale to the Porgera power station. Sales gas volumes are inclusive of approximately 2% unrecovered process gas.
4. Gas and LNG volumes have been converted to barrels of oil equivalent using an Oil Search specific conversion factor of 5,100 scf = 1 boe, which represents a weighted average, based on Oil Search's reserves portfolio, using the actual calorific value of each gas volume at its point of sale. Minor variations to the conversion factors may occur over time.
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Sales1
Sales data
PNG LNG Project
Quarter End Full Year
Mar 2015 Dec 2014 Mar 2014 Dec 2014
LNG (Billion Btu) 27,394 25,492 - 51,922
Condensate ('000 bbls) 683 725 - 1,770
Naphtha ('000 bbls) 61 28 - 53
PNG oil ('000 bbls) 1,262 1,407 1,233 5,759
Hides GTE
Gas (Billion Btu)2 1,355 1,520 1,449 6,090
Condensate and refined products ('000
bbls)3
24 26 25 106
Total barrels of oil equivalent ('000 boe)4 7,039 6,869 1,514 17,762
Financial data (US$ million)
|
LNG and gas sales
|
355.7
|
387.2
|
19.2
|
808.6
|
|
Oil and condensate sales
|
99.8
|
157.2
|
136.7
|
737.1
|
|
Other revenue5
|
16.8
|
17.8
|
14.3
|
64.7
|
Total operating revenue 472.3 562.1 170.2 1,610.4
Average realised oil and condensate price
(US$ per bbl)6
Average realised LNG and gas price
(US$ per mmBtu)
51.29 73.64 110.94 97.79
12.37 14.33 13.25 13.94
Cash (US$m) 1,067.2 960.2 411.2 960.2
Debt (US$m)
PNG LNG financing 4,331.7 4,262.2 3,907.8 4,262.2
Corporate revolving facilities7 - 150.0 200.0 150.0
Net debt (US$m) 3,264.5 3,452.0 3,696.6 3,452.0
1. Numbers may not add due to rounding.
2. Relates to gas delivered under the Hides GTE Gas Sales Agreement.
3. Relates to refined products delivered under the Hides GTE Gas Sales Agreement or sold in the domestic market and condensate.
4. Gas and LNG volumes have been converted to barrels of oil equivalent using an Oil Search specific conversion factor of 5,100 scf = 1 boe, which represents a weighted average, based on Oil Search's reserves portfolio, using the actual calorific value of each gas volume at its point of sale. Minor variations to the conversion factors may occur over time.
5. Other revenue consists largely of rig lease income, infrastructure tariffs and refinery and naphtha sales.
6. Average realised price for Kutubu Blend including PNG LNG condensate.
7. At the end of March 2015, the Company's US$250 million of bilateral revolving facilities and the US$500 million corporate revolving facility were undrawn.
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PRODUCTION PERFORMANCE
Total first quarter production net to Oil Search was 6.91 million barrels of oil equivalent (mmboe), comprising the following:
PNG oil field and gas production from the Hides GTE Project of 1.64 mmboe, produced at an average rate of 18,176 barrels of oil equivalent per day (boepd). This was 6% lower than in the previous quarter, reflecting some plant and well downtime during the quarter.
PNG LNG liquids production of 0.75 mmbbl, including condensate produced during gas processing at the Hides Gas Conditioning Plant and naphtha at the LNG plant.
LNG produced at the PNG LNG plant, net of fuel, flare and shrinkage, of 23,059 mmscf.
PNG LNG Project (29.0%)
First quarter production from the PNG LNG Project was 5.27 mmboe net to Oil Search, comprising 23.1 bcf of gas and 0.75 mmbbl of liquids. This was 4% lower than the previous quarter's production of 5.49 mmboe, mainly due to scheduled maintenance checks at the LNG plant.
Development drilling continued on the Angore field. The first well on the Angore structure, Angore B1, was suspended after encountering higher than expected pressures during drilling. Angore A1 was spudded in March and is drilling ahead. The Hides F1 dual development/exploration well successfully intersected the producing Toro reservoir and was logged and cased as a future producer. However, the deeper exploration target, the Koi-Iange reservoir, was unsuccessful.
Kutubu (PDL 2 - 60.0%, operator)
First quarter oil production net to Oil Search was 0.92 million barrels (mmbbl), similar to production in the fourth quarter of 2014. Gross production rates averaged 17,042 bopd during the period, compared to 16,699 bopd in the previous quarter.
Unplanned downtime at the Agogo Processing Facility and the shut-in of two wells in the Agogo field while integrity checks were carried out was offset by better than expected production from the Kutubu field.
Moran Unit (49.5%, based on PDL 2 - 60.0%, PDL 5 - 40.7% and PDL 6 - 71.1%, operator)
Oil Search's share of Moran 2015 first quarter oil production was 0.41 mmbbl, 15% lower than in the fourth
quarter of 2014. The field produced at a gross average rate of 9,162 bopd, down from the last quarter of
10,487 bopd. This reflected the unplanned shut-in of two wells to undertake integrity checks which were completed by the end of the quarter.
During the quarter, the Moran 16 development well was drilled and completed. The well encountered the targeted Toro and Digimu oil reservoirs close to prognosis, in a down-dip location in the central part of the
field. Final completion and tie-in operations are underway and the well is expected to be online in May.
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Gobe (PDL 3 - 36.4% and PDL 4 - 10%, operator)
Oil Search's share of oil production from the Gobe fields in the first quarter of 2015 was 0.03 mmbbl, down
14% from production levels in the previous quarter. This reflected a scheduled shutdown at the Gobe
Production Facility for routine maintenance and servicing in March.
The gross average production rate for Gobe Main was 12% lower than in the fourth quarter, at 770 bopd while the gross average production rate at SE Gobe was 15% lower than in the previous quarter, at 1,109 bopd.
SE Mananda (PDL 2 - 72.3%, operator)
The SE Mananda field remained shut-in during the first quarter as production is no longer economic in the current oil price environment. Analysis is underway to determine whether the facilities can be preserved for potential future use, should additional development occur in the area.
Hides Gas to Electricity Project - 100%, operator (PDL 1 - 16.7%)
Gas purchased for the Hides Gas-to-Electricity Project in the first quarter of 2015 was 1.26 bcf, produced at an average daily rate of 14 mmscf per day. This was slightly lower than the previous quarter's production of
15 mmscf per day. 26,525 barrels of condensate were produced for use within the Hides facility or transported by truck to the Central Processing Facility at Kutubu.
EXPLORATION AND APPRAISAL ACTIVITY Gas Development
In February, the PRL 3 Joint Venture submitted a PDL application for the P'nyang field in PRL 3 (Oil Search
- 38.51%). Initial preparations have commenced to drill an appraisal well on P'nyang, which will help quantify the 1C contingent resource and 2C resource upside.
In March, the Hides F1 well reached total depth. Substantial sands were encountered in the exploration target, the Koi-Iange interval, but formation evaluation confirmed the sands to be water-bearing. Operations, including the demobilisation of Rig 703, are underway to abandon the exploration section and complete the development section as a gas producer. Work also continued on delineating the volume and distribution of gas reserves on the Hides field following the 2014 development drilling campaign.
The Company's acreage position in the Highlands was expanded with the completion of the acquisition of a
10% interest in PPL 269 and a 100% interest in PPL 402 in March. The 2D seismic data acquisition programme covering 102 kilometres around the Juha and Hides fields in the PNG Highlands remained ongoing. This data will be used to de-risk gas leads and prospects for potential drilling in 2016/17.
In the Gulf Province in PRL 15 (Oil Search - 22.835%), drilling operations continued on the Antelope 4 well, located one kilometre south of Antelope 2, to appraise the southern extent of the field. Antelope 5, located
1.8 kilometres west of Antelope 2, to appraise the western part of the structure, intersected the top carbonate reservoir at a depth broadly in line with the Company's expectations. The well reached total depth during the
quarter, with preparations underway for a planned extended well test.
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Preliminary planning work was undertaken on a further appraisal well, Antelope 6, on the eastern flank of the field and on Antelope South, an exploration prospect in the south of the licence. Funds for both wells have been approved by the PRL 15 Joint Venture.
A seismic acquisition programme, comprising one seismic line, was completed in the onshore Gulf area during the quarter. This assessed the presence of a potential carbonate build-up target recognised on the airborne gravity-gradiometry survey conducted in 2014. The seismic data has since been processed and geological assessment is underway.
Oil Appraisal
In the Kurdistan Region of Iraq, the Taza 2 appraisal well, located in the Taza PSC (Oil Search - 60%, operator), 10 kilometres north-west of the Taza 1 discovery well, was cased to total depth of 4,200 metres. A drill-stem test (DST) was carried out over the deepest interval of interest, the Cretaceous Shiranish Formation, with low rates of oil and water observed. Preparations for a second DST over the Oligo-Miocene, Kirkuk, Euphrates and Jeribe Formations are underway.
Drilling operations at Taza 3, located approximately six kilometres south-east of Taza 1, remained ongoing. At the end of the quarter, the well was at a depth of 3,724 metres, with side-tracking operations taking place.
Processing of 630 square kilometres of 3D seismic data acquired in 2014 is underway. Initial results are of a good quality and will assist in the delineation of the fracture distribution in the Taza structure. The final interpretation of the 3D seismic will be used to select the orientation of the Taza 4 well bore. Taza 4 will target areas of likely greater fracture intensity, to fully appraise the potential of the Taza structure. This could result in materially higher flow rates than those seen at Taza 1 and 2 and those anticipated at Taza 3, which are all located in areas where natural fractures are only lightly developed. The timing of drilling Taza 4 is dependent on the integration of the results of the 3D seismic and the completion and testing of the Taza 3 well.
In Tunisia, processing of data acquired from a 399 kilometre 2D survey over the Tajerouine PSC (Oil Search
- 100%, operator) was completed and interpretation is underway.
Block 7 in Yemen (Oil Search - 34%, operator), remains in a state of force majeure. Shortly after the end of the quarter, Oil Search sold its interest in Block 7 to a subsidiary of Petsec Energy Limited, marking the Company's departure from Yemen. Completion of the sale is subject to a number of conditions including
Government approvals.
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DRILLING CALENDAR
Subject to Joint Venture approvals, the 2015 exploration and appraisal programme is as follows:
Well Well type Licence OSH interest Latitude / Longitude
Rig name Timing
PNG
Antelope 4 Appraisal PRL 15 22.8% N/A WDL Rig 1 Ongoing
Antelope 5 Appraisal PRL 15 22.8% N/A Rig 103 Ongoing
Antelope 6 Appraisal PRL 15 22.8% N/A TBA 2Q/3Q
2015
Antelope South Exploration PRL 15 22.8% N/A TBA 2H 2015
PPL269 well Exploration PPL269 10.0% N/A TBA 2H 2015
Kurdistan Region of Iraq
Taza 2 Appraisal Taza PSC 60.0% (75%
paying interest)
Taza 3 Appraisal Taza PSC 60.0% (75%
paying interest)
35° 4' 36.547" N
44° 45' 9.646" E
35° 0' 27.174" N
44° 49' 51.183" E
Sakson Rig
PR 3
Sakson Rig
SK605
Ongoing
Ongoing
Taza 4 Appraisal Taza PSC 60.0% (75%
paying interest)
N/A TBA Late 2015/
early 2016
Note: Wells, location and timing subject to change. PNG locations reported in AGD66 datum, Kurdistan locations reported in WGS84 datum.
FINANCIAL PERFORMANCE Sales revenue
During the quarter, 28,749 billion Btu of LNG and gas were sold, 6% higher than in the previous quarter. This primarily reflected the timing of LNG deliveries, with 26 LNG cargoes sold during the first quarter compared to 25 cargoes in the fourth quarter of 2014, partly offset by lower Hides GTE gas sales. Oil, condensate and naphtha sales volumes for the period totalled 2.03 mmbbl, 5% lower than the 2.14 mmbbl produced due to the timing of shipments.
The average oil and condensate price realised during the quarter was US$51.29 per barrel, 30% lower than in the previous quarter and less than half the price realised in the previous corresponding period, reflecting the significant downturn in global oil prices. The average price realised for LNG and gas sales declined 14% to US$12.37/mmBtu, reflecting a blend of long-term LNG contract and spot sales from the PNG LNG Project and the approximately three month lag between the spot oil price and LNG contract prices. The Company did not undertake any hedging transactions during the period and remains unhedged.
Total sales revenue from LNG, gas, oil and condensate for the quarter was US$455.5 million, 16% lower than the previous quarter. Other revenue, comprising rig lease income, infrastructure tariffs and refinery and naphtha sales, was US$16.8 million.
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Capital management
As at 31 March 2015, Oil Search had cash of US$1,067.2 million, compared to US$960.2 million at the end of December 2014 (of which US$803.8 million was previously escrowed in PNG LNG Project related accounts). At the end of the quarter, the Company had drawn down US$4,331.7 million under the PNG LNG Project finance facility (US$4,262.2 million at the end of December 2014). During the quarter, the Company repaid US$150 million of the US$250 million of bilateral revolving credit facilities, which were undrawn as at
31 March 2015. The US$500 million revolving corporate facility also remained undrawn. At the end of March
2015, the Company had total liquidity of US$1,817.2 million (US$1,560.2 million at the end of December
2014).
A final unfranked dividend of eight US cents per share plus an unfranked four US cents per share special dividend was paid on 8 April 2015, funded from the Company's cash balance.
Capital expenditure
During the quarter, exploration and evaluation expenditure totalled US$91.7 million, including US$23.9 million spent on PRL 15, US$8.3 million on the Hides F1 well and US$49.3 million on Taza appraisal activity in Kurdistan. US$22.0 million of exploration costs were expensed, primarily related to the Hides F1 (US$14.5 million) and Usano 5 (US$1.8m) wells in PNG and seismic, geological, geophysical and general and administration expenses in PNG and MENA.
Oil Search's share of PNG LNG Project development costs in the first quarter was US$41.2 million. Since financial completion, development costs have been funded solely from the Project's operating cash flows (previously funded 70% by drawdowns from the project finance facility and 30% from cash). Expenditure on producing assets totalled US$30.1 million, largely attributed to the Moran 16 development well (US$17.2
million), sustaining capital expenditure and well workovers.
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Summary of investment expenditure and exploration and evaluation expensed1
(US$ million) Quarter End Full Year
Investment Expenditure
Mar 2015 Dec 2014 Mar 2014 Dec 2014
Exploration & Evaluation
PNG 41.0 61.7 950.0 1,077.2
MENA 50.7 56.2 27.3 165.6
Total exploration & evaluation 91.7 117.9 977.2 1,242.8
Development 41.2 59.3 189.62 502.62
Production 30.1 31.5 19.6 110.3
PP&E 1.9 5.4 1.1 13.4
Total 164.8 214.1 1,187.5 1,869.1
Exploration & evaluation expenditure expensed3,4
PNG 20.5 74.0 6.9 88.2
MENA 1.6 10.3 3.9 21.0
Total current year expenditures expensed
22.0 84.3 10.9 109.2
Prior year expenditures expensed - - - -
Total 22.0 84.3 10.9 109.2
1. Numbers may not add up due to rounding.
2. Includes capitalised interest and finance fees.
3. Exploration expensed includes costs of unsuccessful wells except where costs continue to be capitalised, certain administration costs and geological and geophysical costs. Costs relating to permit acquisitions, expenditure associated with the drilling of wells that result in a successful discovery of potentially economically recoverable hydrocarbons and expenditures on exploration and appraisal wells pending economic evaluation of recoverable reserves are capitalised.
4. Numbers do not include expensed business development costs of US$2.3 million in the first quarter of 2015 (US$5.6 million in the fourth quarter of 2014).
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Gas/LNG Glossary and Conversion Factors Used
Mmscf Million (106) standard cubic feet mmBtu Million (106) British thermal units Billion Btu Billion (109) British thermal units MTPA (LNG) Million tonnes per annum
Boe Barrel of oil equivalent
1 mmscf LNG Approximately 1.13 billion Btu
1 boe Approximately 5,100 standard cubic feet
1 tonne LNG Approximately 52 mmBtu
Note: Minor variations in conversion factors may occur over time, due to changes in gas composition.
PETER BOTTEN, CBE Managing Director
21 April 2015
For more information regarding this report, please contact:
Ms Ann Diamant
Group Manager, Investor Relations
Tel: +612 8207 8440
Mob: +61 407 483 128
DISCLAIMER
This report contains some forward-looking statements which are subject to particular risks associated with the oil and gas industry. Actual outcomes could differ materially due to a range of operational, cost and revenue factors and uncertainties including oil and gas prices, changes in market demand for oil and gas, currency fluctuations, drilling results, field performance, the timing of well workovers and field development,
reserves depletion and fiscal and other government issues and approvals.
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