16 May 2018 07:00
("Premier" or "the Group")
Trading and Operations Update
16 May 2018
Premier today provides the following Trading and Operations Update. This is issued in advance of the Company's Annual General Meeting which is being held today at 11.00 at 11 Cavendish Square, London.
Highlights
· Catcher production has reached levels in excess of 60 kbopd (gross) in the last few days, resulting in Group production rates of over 90 kboepd
· Production averaged 74.0 kboepd during Q1 with a robust performance from the underlying portfolio; on track to meet full year guidance of 80-85 kboepd
· Tolmount project sanction scheduled for 2018 2H; contract awards ongoing
· First Zama appraisal well on Block 7 to spud in Q4; Pemex rig tender underway for appraisal drilling in the adjacent block
· Significant licence awards of attractive exploration acreage in Indonesia and Mexico, materially enhancing the Group's portfolio
· Non-core asset disposal programme continues; Babbage Area assets sale announced and ETS sale expected to complete in June
· Q1 free cash flow neutral, as per previous guidance, reflecting the phasing of the 2018 capex programme, Catcher production ramp up and timing of receipt of disposal proceeds
· Significant debt reduction anticipated for 2018 2H; covenant leverage ratio forecast to fall to 3x EBITDA by year end at current oil prices
Tony Durrant, Chief Executive, commented:
"The improved commodity price environment puts us in a strong position to generate significant free cash flow in the second half of the year: the underlying production portfolio is robust, Catcher has reached 60 kbopd, our low cost base has been maintained, capital spend is reducing and we have announced further non-core disposals. We are on track to deliver our plan of material debt reduction in 2018 and 2019 with selective investment in our future growth projects from 2020, once balance sheet strength has been restored."
Enquiries |
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Premier Oil plc | Tel: 020 7730 1111 | |
Tony Durrant, Chief Executive |
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Richard Rose, Finance Director |
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Camarco | Tel: 020 3757 4980 | |
Billy Clegg Georgia Edmonds |
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Production and development operations
Production averaged 74.0 kboepd during the first quarter. The reduction from the prior corresponding period reflects the sale of Wytch Farm, a planned shutdown at the Huntington field and natural decline across the portfolio. This was offset by the new contribution from the Catcher field. Full year guidance of 80-85 kboepd is maintained.
kboepd | 1 January - 31 March 2018 | 1 January - 31 March 2017 |
Indonesia | 14.2 | 14.2 |
Pakistan | 5.3 | 7.11 |
UK | 38.1 | 43.9 |
Vietnam | 16.4 | 16.0 |
Total | 74.0 | 81.2 |
1 Includes 348 boepd from the Chinguetti field in Mauritania which ceased production in December 2017
UK
Production from Premier's UK assets averaged 38.1 kboepd for the first quarter, reflecting constrained Catcher production of 8.5 kboepd (net) as gas plant commissioning continued. Gross oil production from Catcher reached levels in excess of 60 kbopd in the last few days with the export of excess associated gas into the SEGAL gas pipeline system expected to start shortly.
The Burgman production wells came on-stream in May and hydrocarbons are now being produced from all three Catcher Area fields (Catcher, Varadero, Burgman). Initial dynamic data suggests good pressure support and connectivity within the reservoirs. The delivery capacity of the available wells is excellent with aggregate production capacity significantly in excess of the FPSO's plant design. To date, five cargoes have been successfully offloaded and sold, on average, at a premium to Brent to four different buyers.
The results of the ongoing drilling programme have continued to exceed pre-drill estimates with the latest Catcher development well encountering significantly more oil bearing sands than originally prognosed with better than expected reservoir quality. The Catcher Area drilling programme is on track to complete during Q3 2018.
Huntington averaged 8.1 kboepd during the period, reflecting natural decline and a planned shutdown which was extended by the adverse weather conditions in February. Premier is considering converting an obsolete production well into a water injection well to further improve recovery from the field. At the same time, Premier has started discussions with Teekay with a view to extending the FPSO lease beyond April 2019.
Elsewhere in the UK, Premier's assets have performed broadly in line with expectations.
With Catcher now contributing over 30 kbopd (net), production rates from Premier's UK portfolio are currently in excess of 50 kboepd.
Asia
Production from Premier's Asian assets averaged over 30 kboepd during the first quarter.
Premier's operated Chim Sao field in Vietnam produced 16.4 kboepd, up on the prior period and above budget as a result of the successful infill well programme completed in December 2017. In April 2018 Premier commenced a well intervention programme to perforate new production zones in the existing well stock to further mitigate against natural decline. As a result, the field is currently producing over 17 kboepd (net to Premier), a significantly higher run rate than that in the fourth quarter of 2017. Chim Sao cargoes sold year to date have on average commanded a material premium to Brent and higher than that achieved during 2017.
In Indonesia, Premier's operated Natuna Sea Block A increased its market share within its principal gas contract GSA1 to 54 per cent against a contractual share of 51.7 per cent during the first quarter. Elsewhere in Indonesia, first steel for the BIG-P development deck extensions was cut in the Batam fabrication yard. BIG-P is due on-stream in 2019 and will help backfill the Group's contracts into Singapore and maintain production from Natuna Sea Block A.
Pre-developments
On the operated Tolmount gas project, final documentation with selected contractors is being completed with respect to the platform, pipeline and terminal modifications. Project sanction is scheduled for the second half of 2018 and Premier continues to target first gas in Q4 2020.
In the North Falklands basin, Premier remains focused on securing funding for the project ahead of final investment decision. Premier is completing the selection of the main contractors for the project and is finalising letters of intent to underpin the contractual arrangements and the provision of vendor funding for $400 million. Premier expects to appoint a pathfinder bank shortly to assist with the arrangement of senior debt facilities for the project.
Exploration and appraisal
In January 2018, Premier was awarded the Andaman II licence in the underexplored but proven North Sumatra basin offshore Aceh, Indonesia. The PSC was signed by Premier on 5 April. Premier has identified numerous prospects and leads which exhibit direct hydrocarbon indicators on existing 2D seismic across the licence. The forward plan is to acquire 3D seismic in 2018 to further work up these prospects, ahead of entering the next phase of the licence with associated drilling likely in 2021.
In April, Premier and its joint venture partners submitted an appraisal programme for the Zama discovery on Block 7 offshore Mexico to the Government authorities. The objective of the appraisal programme, which comprises two back-to-back wells and one side track, is to confirm the oil water contact as defined by the seismic flat spot and to prove the detailed distribution of the reservoir. The first appraisal well is expected to spud in Q4 2018. Meanwhile, Pemex is in the process of securing a rig for the Asab-1 well which will test the extent of the Zama discovery on the adjacent block.
In March, Premier successfully secured three new blocks in Round 3.1 - Block 30 in the prolific, shallow water Sureste Basin and Blocks 11 and 13 in the Burgos Basin - significantly enhancing the Group's acreage position in Mexico. The forward plan for Block 30 includes 3D seismic acquisition and reprocessing the existing 3D seismic across the Wahoo prospect, which exhibits direct hydrocarbon indicators and is analogous to the Zama discovery. In the Burgos basin, Premier will undertake an environmental base line study across its two new blocks prior to reprocessing the existing seismic data during 2019.
In the UK, Premier's exploration focus is on near field upside in the Greater Tolmount Area. In particular, Premier plans to acquire high resolution 3D seismic this summer over the Greater Tolmount Area in advance of drilling the Tolmount East Appraisal well in 2019.
In Brazil, the ANP has approved a revised well plan for Block 717 (Premier, 50 per cent operator) in the Ceara basin, comprising a single deeper dual-target well to test the Berimbau and deeper Maraca prospects. This replaces the original two well commitment. Drilling is planned in 2020 1H as part of a joint well programme on Block 661 (Premier, 30 per cent) targeting the Itarema/Tatajuba prospects. The two wells will test an aggregate mean resource estimate in excess of 500 mmbbls (gross, unrisked).
Portfolio management
Premier's programme of non-core asset disposals has continued into 2018. On 30 April, Premier announced the sale of its interests in the Babbage Area to Verus Petroleum. Premier expects to receive net cash proceeds of $64 million, before customary working capital adjustments. Verus will also take on exploration commitments estimated at $24 million. Completion of the transaction is expected in 2018 2H. The previously announced sale of Premier's 30 per cent interest in the Esmond Transportation System (ETS) is expected to complete in June.
In Indonesia, Premier completed the sale of its entire 18.75 per cent non-operated interest in the Kakap field to Batavia Oil for $3.2 million, before completion adjustments, on 10 April.
Completion for the sale of the Pakistan business to Al-Haj Group remains subject only to final approvals from the Pakistan authorities. In the meantime Premier continues to collect positive cash flows generated from the assets.
Finance
Premier has taken advantage of the recent strengthening of the oil price to increase its hedging position in 2019 to protect future free cash flow and covenant compliance. The company's current hedge position to the end of 2019 is as follows:
Oil swaps/forwards | Q2 2018 | Q3 2018 | Q4 2018 | Q1 2019 | Q2 2019 | Q3 2019 |
Volume (% budgeted ent. production) | 40% | 40% | 40% | 28% | 28% | 21% |
Average price | $58/bbl | $60/bbl | $60/bbl | $66/bbl | $67/bbl | $67/bbl |
Premier has also hedged around 27 per cent of its remaining 2018 UK gas volumes at an average price of 45 pence/therm.
Full year guidance for operating cost per barrel of $17-$18 is maintained. Over the quarter operating costs averaged $18.8/boe. This reflects a period of constrained production from Catcher. With Catcher at plateau rates, Premier's operating costs on a per barrel basis will be reduced. Guidance for 2018 full year development, exploration and abandonment spend remains unchanged at $380m.
In line with previous guidance, free cash flow during the first quarter was neutral, reflecting the phasing of the 2018 capex programme, Catcher production ramp up and the timing of receipt of disposal proceeds.
Net debt reduced from $2.72 billion at the end of 2017 to $2.65 billion at the end of the first quarter. This reflects an accounting net debt reduction of c. $150 million from the early exchange of the convertible bond, offset by movement in joint venture balances and non-cash foreign exchange movements on non-dollar denominated debt. The subsequent favourable US$/£ exchange rate movement has partially reversed this impact.
At current oil prices, Premier is forecasting significant debt reduction in the second half of 2018 driven by increasing free cash flow generation from our producing portfolio, reduced capital expenditure and cash proceeds from announced disposals. As a result, at current oil prices, Premier anticipates its covenant leverage ratio falling to 3x EBITDA by year end, and reducing further in 2019.