Premier Oil plc

('Premier' or 'the Group')

Trading and Operations Update

17 July 2019

Premier is pleased to provide an update on recent operational activities and guidance in respect of its half year financial results to 30 June 2019.

2019 1H highlights

· 2019 1H production averaged 84.1 kboepd, up 11 per cent on the 2018 corresponding period

· On track to meet previously increased full year production guidance of 75-80 kboepd

· Free cash flow generation of $180m during the period, reducing net debt to $2.15 bn

· Significant resource upgrade at Zama (Mexico) to 670-810-970 mmboe (P90-P50-P10) (gross)

· Tolmount, Premier's next UK growth project, on schedule for first gas end 2020

· Tolmount East appraisal well spud imminent, targeting an additional 220 Bcf (gross)

· Increased Andaman Sea acreage position; significant area potential

· Forecast 2019 opex (ex-lease costs) reduced to $12/boe; capex guidance unchanged ($340m)

· Continue to forecast full year 2019 net debt reduction of over $300m

Tony Durrant, Chief Executive, commented

'We have delivered a strong first half. I am particularly pleased with the continued high operating efficiency from our producing portfolio which has enabled us to reduce our debt by $180 million. This puts us in good stead to meet our debt reduction target for the full year, which remains a top priority for the Group. In addition, we have retained significant optionality with our future developments and an extremely attractive exploration portfolio which together offer substantial upside exposure.'

Enquiries

Premier Oil plc

Tel: 020 7730 1111

Tony Durrant, Chief Executive

Richard Rose, Finance Director

Camarco

Tel: 020 3757 4983

Billy Clegg

James Crothers

Production

Group production averaged 84.1 kboepd for the first six months of 2019, ahead of budget and underpinned by very high operating efficiency. Premier is on track to meet its previously upgraded full year production guidance of 75-80 kboepd.

Premier's UK assets contributed 57.7 kboepd during the period, a 40 per cent increase on the first half of 2018. This was driven by an increased contribution from the Premier-operated Catcher Area which averaged 34.8 kboepd (net, Premier 50 per cent) and achieved 99 per cent operating efficiency.

The Total-operated Elgin Franklin and Premier-operated Huntington fields continue to produce ahead of expectations, averaging 6.5 kboepd (net, Premier 5.2 per cent) and 6.7 kboepd (Premier 100 per cent) respectively during the period. The Solan field also performed well averaging 4.0 kbopd (Premier 100 per cent) during the first half of the year. A new Solan production well (P3) is planned for spring 2020. Premier has reached agreement with Baker Hughes, a GE company, to align payment with milestone dates, reducing Premier's cash outlay prior to the completion of the well.

The Premier-operated Chim Sao field in Vietnam delivered 12.4 kboepd (net, Premier 53.13 per cent), ahead of budget and supported by the completion of two successful well intervention programmes. Chim Sao cargoes remain well bid with an average premium to Brent of more than $4/bbl achieved over the period.

In Indonesia, Natuna Sea Block A averaged 11.5 kboepd (net, Premier 28.7 per cent), lower than the prior corresponding period in 2018 due to low offtake under the second gas sales agreement (GSA2) as cheaper LNG gas was substituted for Natuna Sea pipeline gas. Premier expects higher GSA2 production in the second half of the year as Singapore customers look to meet their annual take or pay obligations. Deliveries under GSA1, the principal gas contract, were above take or pay levels with Natuna Sea Block A capturing a 52 per cent market share of GSA1.

Development activity

Premier continues to expect first gas from the Bison, Iguana and Gajah Puteri fields in Indonesia by year-end. The first two of the three development wells, SBS-1 (Bison) and SIG-1 (Iguana), were completed and successfully flow tested. SBS-1 achieved a rate of 23 mmscfd, ahead of pre-drill expectations of 15 mmscfd, due to thicker sand development and better reservoir properties encountered in the main Middle Arang interval. Additional productive sands were also encountered in the Upper Arang interval which will be completed at a later date. SIG-1 flowed at a rate of 20 mmscfd, in line with expectations.

Formal approval for the two Catcher satellite oil fields, Catcher North and Laverda, is expected next month. Catcher North and Laverda, together with the Varadero infill well (V5) which is scheduled to spud in the second quarter of 2020, will help maintain Catcher Area production at 66 kbopd (gross).

The Premier-operated Tolmount development remains on schedule and budget. In Italy, Rosetti are erecting the steel frame of the topsides and the construction of the jacket is well advanced. In the UK, fabrication of the pipeline to shore is expected to commence shortly while engineering and procurement for the Easington terminal modifications are underway with civil works having commenced at site.

A comprehensive set of independent expert reports on the Sea Lion project in the North Falklands Basin has now been completed. These, together with the Preliminary Information Memorandum, will form the basis of a loan application package which Premier plans to submit imminently to export credit agencies for the senior debt component of the project financing structure.

The Block 7 appraisal programme in Mexico proved better than expected reservoir properties and, together with the progress made on development engineering, has resulted in a significant upgrade to the gross resource estimate of the Zama structure to 670-810-970 mmboe (P90-P50-P10). The joint venture focus is on concluding the unitisation discussions with Pemex and on agreeing the optimal development for the field ahead of final investment decision scheduled for 2020.

Exploration and appraisal

In the UK Southern North Sea, drilling of the Tolmount East appraisal well, which has the potential to add significantly to the Tolmount resource, will commence shortly. Data from the Greater Tolmount Area 3D seismic survey, which completed in April, is being processed to define additional prospectivity in the area, such as Tolmount Far East.

In Mexico, the 3D seismic survey acquisition across Block 30 (Premier 30 per cent) was completed in July. The data will be processed to delineate the full extent of the Wahoo prospect, which exhibits analogous direct hydrocarbon indicators (DHIs) to the Zama discovery, in preparation for 2020 drilling, as well as to mature other prospectivity on the Block, including the Cabrilla prospect. Elsewhere in Mexico, Premier's exploration plan for its Burgos Blocks 11 and 13 (Premier 100 per cent) were approved by CNH. Reprocessing of 3D seismic will be completed ahead of a drilling decision.

In Brazil, Premier is actively engaging rig contractors with available units in country for a rig to drill its Berimbau/Maraca prospect on Block 717 (Premier 50 per cent) in 2020.

Post period-end, Premier farmed in for a 20 per cent interest in the South Andaman and Andaman I blocks, offshore Aceh in Indonesia. Completion of the transaction is subject to government approvals. The blocks are located within the South Andaman Sea gas play fairway directly adjacent to Premier's existing Andaman II acreage. This expands Premier's collaboration with Mubadala Petroleum, who are the operator of the South Andaman and Andaman I blocks and also the Group's joint venture partner in Andaman II, which Premier operates. A 3D seismic acquisition programme across the Andaman I, Andaman II and South Andaman licences was completed earlier this year and will be used to mature the prospect inventory identified on the earlier 2D data.

Finance

Premier has hedged 43 per cent of its second half 2019 oil entitlement volumes at $69/bbl and 14 per cent of its 2020 oil entitlement volumes at $66/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.

Operating costs and lease costs to the end of June averaged $10.4/boe and $6.3/boe respectively, reflecting strong production and continued tight cost control across the Group. As a result, Premier now forecasts full year operating costs of $12/boe, reduced from $13/boe. Full year guidance of $7/boe lease costs is maintained. Guidance for 2019 full year development, exploration and abandonment spend remains unchanged at $340 million.

Net debt reduced from $2.33 billion at the end of 2018 to $2.15 billion at the end of June as a result of free cash flow generation of $180 million, ahead of budget due to strong production. Premier's covenant leverage ratio (covenant net debt/EBITDA) at the end of June was 2.4x, down from 3.1x at the end of 2018. At current oil prices, Premier forecasts 2019 full year net debt reduction in the upper half of $250m to $350m guidance and continues to expect a year-end 2019 covenant leverage ratio (covenant net debt/EBITDA) of less than 2.3x.

Group production breakdown

2019 1H

2018 1H

UK

57.7

41.1

Vietnam

12.4

16.2

Indonesia

11.5

13.5

Pakistan1

2.5

5.3

Total

84.1

76.1

1sold at 26 March 2019

Hedging schedules

Oil

Swaps/forward

2019 2H

2020

Volume (mmbbls)

3.99

2.21

% of forecast entitlement production

43

14

Average price ($/bbl)

69

66

Indonesia gas

Swaps/forward

2019 2H

2020

Volume (HSFO k te)

102

252

% of forecast production

40

39

Average price ($/te)

381

361

UK gas

Swaps/forward

2019 2H

2020

Volume (million therms)

16

42

% of forecast production

16

22

Average price (p/therm)

62

51

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Disclaimer

Premier Oil plc published this content on 17 July 2019 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 17 July 2019 06:09:13 UTC