Trading and Operations Update

Source Press Release
Company Premier Oil 
Tags Assets for Sale, Upstream Activities, Financial & Operating Data
Date November 14, 2019

Premier today provides a Trading and Operations Update for the 10 months to 31 October 2019.

Highlights

  • Group production averaged 79.4 kboepd for the period with high operating efficiency of 94%; forecast full year production at upper end of 75-80 kboepd guidance
  • Catcher Area rates of 69 kboepd (gross) and very high operating efficiency of almost 100% maintained; project cash payback reached, 22 months after first oil
  • Near field projects on track: BIG-P (Indonesia) on track for first gas by year-end; formal approval of Catcher Area satellites received with first oil targeted for early 2021
  • Tolmount, Premier’s next UK growth project, on schedule for first gas by the end of 2020 adding a net 20-25 kboepd to Group production once on plateau
  • Significant commercial discovery at Tolmount East (UK); development planning already well advanced with project sanction targeted for 2020 2H
  • Rig contracted to appraise the Malguk-1 discovery (Alaska North Slope); targeting more than 1 bn bbls (gross) of STOIIP, expected spud February 2020
  • Significant industry interest in Premier’s Block 7 Zama (Mexico) sales process; bid deadline extended into December to accommodate levels of interest
  • Forecast 2019 opex (ex-lease costs) unchanged at $12/boe; full year capex guidance reduced to between $300m and $320m from $340m
  • Net debt reduced by $300m to $2.03bn as at 31 October; underpinning full year net debt reduction guidance in excess of $300m

 Tony Durrant, Chief Executive, commented:

“We continue to deliver on our strategic priorities. We are generating significant free cash flow, which is materially deleveraging our balance sheet. At the same time, we are actively managing our portfolio and selectively progressing growth projects at the right exposure. We also continue to create value through the drill bit and to build material new positions in emerging exploration plays at low cost.”

Production operations

Production averaged 79.4 kboepd for the period, underpinned by continued high Group operating efficiency of 94 per cent. Summer maintenance programmes were successfully completed and production has returned to previous levels; October production averaged 78.4 kboepd. Premier expects full-year production to be at the upper end of the 75-80 kboepd guidance range.

Premier’s UK assets averaged 55.3 kboepd, a 27 per cent increase on the prior corresponding period driven by a full contribution from the Catcher Area at higher plateau rates. The Catcher Area averaged 34.5 kboepd (net, Premier 50 per cent), achieving an extraordinary operating efficiency of almost 100 per cent. This continued outperformance resulted in the Group achieving cash payback on the Catcher Area project at the end of October, 22 months after first oil.

The Elgin Franklin Area produced 6 kboepd (net, Premier 5.2 per cent interest), ahead of expectations and supported by on-going well intervention campaigns. Production from the Huntington field averaged 6 kboepd (Premier 100 per cent interest), with a four week scheduled maintenance programme successfully completed at the end of August. Premier is in discussions with the Huntington FPSO provider about options to extend economic production again to beyond April 2020.  Premier’s operated Solan field delivered 3.6 kboepd (Premier 100 per cent interest) and preparations are well advanced for the 2020 Solan P3 drilling campaign. Premier’s other UK assets have performed in line with expectations.

In Asia, Premier’s operated Chim Sao field averaged 11.7 kboepd (net, Premier 53.13 per cent), ahead of budget with natural decline from the existing wells mitigated by four well intervention campaigns during the period. Preparations are underway for a 2021 two well infill drilling programme aimed at maximizing recovery from the Chim Sao field. Chim Sao cargoes remain well bid with an average premium to Brent of more than $4.40/bbl achieved for cargoes lifted over the period.

Premier’s Indonesian gas fields delivered 11 kboepd (net, Premier 28.67 per cent), with offtake under the two gas sales agreements at or around annual take or pay levels. In October, Premier successfully drilled and completed an infill well on the Gajah Baru field targeting incremental reserves from the Middle Arang Ca-3 sand. The well is expected to be tied into production before year-end.

Development activities

The Premier operated 500 Bcf Tolmount development remains on schedule and is tracking below budget. Construction of the platform is progressing to plan:  electrical fit-out of the topsides has commenced and roll-up of the jacket frames is scheduled for early December. Onshore linepipe fabrication is completed while shaft construction at the terminal and landfall earthworks have commenced. Development drilling is on track to start mid-2020.  The Group continues to expect first gas by the end of 2020 with plateau rates of around 50 kboepd (gross, Premier 50 per cent).

In October, Premier announced a significant commercial discovery at Tolmount East. The well, which targeted 220 Bcf of P50 gross resource four kilometres east of Tolmount, penetrated 241 feet of gas bearing high quality Leman sands with a net-to-gross ratio of 71 per cent. The well data is being integrated with the new 3D seismic dataset as part of the fast-track development planning with project sanction targeted for the second half of 2020.

Premier continues to forecast first gas from its operated Bison, Iguana and Gajah Puteri (BIG-P) fields in Indonesia by year-end. The three well development drilling programme, which completed in September, yielded positive results and encountered incremental reserves in excess of pre-drill estimates. Installation of the subsea structures and flexible risers was completed in October and the attachment of the umbilicals is underway, ahead of final hook up and tie-in of the wells.

The two Catcher Area satellite developments, Catcher North and Laverda, were formally approved in September. The Gorrilla V1 rig will drill the two development wells mid-2020 immediately after a Varadero infill well. First oil from Catcher North and Laverda is targeted for early 2021 and, together with the Varadero infill well, will extend plateau oil production across the Catcher FPSO.

Premier’s applications for senior debt financing in relation to its operated Sea Lion development in the North Falkland Basin continue to progress through the export credit agencies’ due diligence processes. Discussions also continue with several interested parties about farming into the project. In November, Premier received approval of an extension to the PL032 Discovery Area licence term to 1 May 2021 from the Falkland Islands Government.

In August, Premier commenced a formal sales process for its interest in the fully-appraised Zama oil field offshore Mexico.  There has been significant industry interest in the process and, as a result, Premier has extended the bid deadline to December to accommodate this.

Exploration and appraisal

In Alaska, the Nordic-3 rig has been contracted to appraise the Icewine Area A Malguk-1 discovery (Premier 60 per cent interest) which Premier estimates could contain over 1 bn bbls of STOIIP. The well, which will be flow tested, is expected to spud in February 2020.

Premier is in the final stages of concluding a rig contract to drill the Berimbau/Maraca stacked prospects on its operated Block 717 in the Ceara Basin in Brazil. The well is scheduled to spud in the third quarter of 2020 and is targeting gross unrisked resource of 300 mmbbls.

In Mexico, Premier expects to receive the Block 30 final processed 3D seismic dataset in the second quarter of 2020 following the acquisition of a 3D seismic survey earlier this year. This will be used to fully delineate the prospectivity on block ahead of drilling in 2021. Premier also expects to receive the reprocessed 3D seismic data across Blocks 11 and 13 in the Burgos Basin during 2020.

In Indonesia, Premier has received the fast track data from the 3D seismic acquisition programme across its Andaman Sea Blocks. These initial processed results are highly encouraging with the prospectivity identified on 2D seismic confirmed. Premier expects to receive the fully processed data during the course of 2020 ahead of a 2021 well programme.

Finance

Premier has hedged 41 per cent of its fourth quarter 2019 oil entitlement volumes at $70/bbl and 29 per cent of its 2020 first half oil entitlement volumes at $64/bbl. Premier has also hedged a significant proportion of its remaining 2019 and 2020 Indonesian and UK gas volumes. The Group’s complete hedging schedule is set out at the end of this release.

Over the period, operating costs and lease costs averaged $12/boe and $6/boe respectively and Premier continues to forecast full year operating costs in line with year-to-date levels.  Forecast 2019 full year development, exploration and abandonment spend is between $300 million and $320 million, reduced from previous guidance of $340 million, due to the release of contingency spend related to the BIG-P drilling programme, which has now completed, and the Tolmount project tracking below budget.

Premier generated $300 million of free cash flow over the period, reducing net debt from $2.33 billion at the end of 2018 to $2.03 billion as at 31 October and underpinning full year net debt reduction guidance in excess of $300 million.  Premier continues to forecast a year-end covenant leverage ratio of 2.3x or less against the covenant level of 3.0x.

Group production breakdown


kboepd 
1 Jan – 31 Oct 2019  1 Jan – 31 Oct 2018 
Indonesia  11.0  13.4 
Pakistan1  1.4  5.2 
UK  55.3  43.5 
Vietnam  11.7  15.6 
Total  79.4  77.7 

1 sold at 26 March 2019

Hedging schedules

Oil


Swaps/forward 
Q4 2019  Q1 2020  Q2 2020 
Volume (mmbbls)  2.0  1.4  1.2 
% of forecast ent. production  41  30  27 
Average price ($/bbl)  70  65  64 

Indonesia gas


Swaps/forward 
Q4 2019  Q1 2020  Q2 2020 
Volume (HSFO k te)  51  63  63 
% of forecast production  40  46  46 
Average price ($/te)  362  385  379 

UK gas


Swaps/forward 
Q4 2019  Q1 2020  Q2 2020 
Volume (million therms)  16.6  19.6  17.7 
% of forecast production  35  40  40 
Average price (p/therm)  64  60  52 

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd