Company Announcements

Premier Oil plc

("Premier" or "the Group" or "the Company")

Trading and Operations update

15 July 2020

Premier today provides an update on recent operational activities and guidance in respect of its half year financial results to 30 June 2020.

·    Production averaged 67.3 kboepd to the end of June; 2020 guidance of 65-70 kboepd (before any contribution from the proposed acquired BP assets) reiterated

·    Solan P3 successfully drilled and due on-stream in September; forecast to add c.10 kbopd to Group production rates in Q4

·    Tolmount: final onshore commissioning of topsides underway prior to August sailaway; on track to meet previously revised Q2 2021 first gas date, adding 20-25 kboepd (net, Premier 50 per cent)

·    Forecast 2020 total capex ($340 million), opex ($12/boe) and lease costs ($6/boe), reflecting $240 million of savings and deferrals secured

·    Amended BP acquisitions approved by creditors, subject to agreed refinancing terms and equity funding; adds 17 kboepd (net) from targeted completion date of  30 September

·    Discussions with a subset of Premier's creditors regarding a long term extension to the Group's credit maturities underway; aim to agree terms which can be recommended to the full lender group by the end of July

·    Net debt reduced to $1.97 billion as at the end of June (31 December 2019: $1.99 billion), financial covenants waived through to end September; forecast free cash flow positive for full year 2020 at current forward curve

Tony Durrant, Chief Executive, commented:

"The continued underlying performance of our core assets along with the decisive action we have taken to reduce our expenditure during the first half has resulted in our net debt remaining broadly flat despite significantly weaker commodity prices during the period.  This, together with the expected agreement on the amendments to our credit facilities and the completion of the value-accretive BP acquisitions, positions us well to benefit from a recovering oil price."

Production operations

Premier remains extremely vigilant and focussed on the welfare, health and safety of all of its staff and contractors.  Production operations have continued safely and largely uninterrupted by COVID-19 as a result of reduced manning on the Group's installations, pre-mobilisation screening measures, including testing, and additional passenger protocols, which are well established and working well. 

Group production averaged 67.3 kboepd to the end of June. Full year guidance is reiterated at 65 to 70 kboepd. 

Premier's UK assets produced 45.0 kboepd during the first six months of the year, underpinned by the Group's operated Catcher Area fields which remain on plateau.  The Catcher Area fields averaged 28.4 kboepd (net, Premier 50 per cent) over the period, impacted by an unplanned 20 day outage in the second quarter. It also reflects lower gas production with some gas being reinjected into the reservoir prior to the reinstatement of the full gas train in August. The well data collected during gas reinjection will be used to evaluate the opportunity for improved oil recovery from the fields.  Drilling operations are ongoing at the Varadero infill well (VP1) which is planned to be brought on to production in September and will help maintain plateau oil rates of 66 kbopd (gross).

West of Shetlands, Premier's operated Solan field delivered 1.7 kboepd (Premier 100 per cent) over the period. Production was impacted by a planned shutdown for P3 platform modifications in May and the second producer (P2) being on free flow from March.  In June the Solan P3 vertical pilot well was successfully side-tracked horizontally, encountering more than 2,300 feet of net sand with reservoir properties at the higher end of expectations.  P3, which is scheduled to be brought on-stream by the end of September, is expected to boost production rates from the Solan field by c. 10 kbopd. 

The Elgin-Franklin Area produced 7.3 kboepd (net, Premier 5.2 per cent interest), which was ahead of budget.  Production continues to be supported by high operating efficiency and an active rig programme with the next infill well scheduled to come on-stream during the fourth quarter.

In conjunction with its joint venture partners, Premier has taken the decision to cease production from certain low rate fields not generating positive cash flows in the current environment. During the first half of 2020, Huntington and Kyle ceased production and final production from the operated Balmoral Area is now planned for October 2020.  Abandonment expenditure on these fields, which comprise floating production facilities, is not expected to be material in the near term, with related well abandonment expenditure spread over a number of years.

In Vietnam, Premier's operated Chim Sáo field averaged 9.1 kboepd (net, Premier 53.13 per cent interest), in line with budget.  A well intervention programme is scheduled for later this month to further help support production from the field. Demand for Chim Sáo crude remains strong with cargoes sold during the first half realising an average premium to Brent of over $5/bbl.  Production from Premier's operated Natuna Sea Block A ("NSBA") fields in Indonesia averaged 13.2 kboepd (net, Premier 28.67 per cent), with Singapore offtake above take or pay levels for both of Premier's gas sales agreements (GSA1 and GSA2).  NSBA captured a 57 per cent market share of GSA1 deliveries during the period, higher than its 53 per cent contractual share.    

Development activities

The 500 Bcf Tolmount development is on track to deliver first gas in the second quarter of 2021. The jacket and topsides, which are being built in Rosetti's yard in Italy, will be loaded out later this month prior to sailaway in August. The offshore installation of the platform is planned to take place in late September/early October with the drilling rig to mobilise thereafter to drill the initial four development wells. The pipe lay is progressing well with the shoreline and inshore pipeline crossings successfully completed.  The Tolmount field will add 20-25 kboepd (net, Premier 50 per cent interest) to Group production once on plateau later in 2021.

In Mexico, the unitisation of the Zama field and the sales process for Premier's 25 per cent interest in Block 7 are ongoing.  The National Hydrocarbon Commission (CNH) declared Zama a shared reservoir in May and, in July, the Mexican Ministry of Energy (SENER) issued the instruction to unitise the Zama field, triggering 120 working days within which the Block 7 partners and Pemex are required to deliver a Unitization and Unit Operating Agreement ("UUOA") to SENER for approval.

As previously announced, at the end of the first quarter, Premier took the decision to suspend the operated Sea Lion Phase 1 project in the Falkland Islands until the macroeconomic outlook improves. In the meantime, a small core team is progressing the commercial and regulatory work streams, including the farm out to Navitas for a 30 per cent interest in the Sea Lion licences.  Premier, Rockhopper and Navitas are finalising the farm out documentation, and discussions have commenced with the Falkland Islands Government to obtain approval for Navitas's entry onto the Sea Lion licences.

Exploration and appraisal

In April, Premier drilled the Charlie-1 well in Area A on the Alaska North Slope.  As previously announced, the well encountered non-commercial gas condensate rather than the targeted light oil and Premier is in the process of exiting the licence.

During the first half of the year, market conditions resulted in Premier deferring drilling activity across its exploration portfolio to reduce expenditure.  New seismic datasets across the Group's Andaman Sea acreage, Mexico Block 30 and the Greater Tolmount Area were received during the second quarter and Premier's exploration teams are now maturing the prospectivity of these licences to confirm well locations ahead of future drilling.

In May, Premier agreed a fully termed farm down agreement with Zarubezhneft for a 50 per cent interest in the Premier-operated Tuna discoveries offshore Indonesia.  Under the farm down agreement, which remains subject to government approvals, Zarubezhneft will carry Premier for its share of a two well appraisal campaign now expected to take place in 2021.

Finance

Total revenues for the first six months of the year will be in the order of $530 million, reflecting lower commodity prices over the period partially offset by the Group's hedging programme.  Premier continues to seek to protect its revenues through its hedging programme with just over 20 per cent of its second half 2020 entitlement volumes hedged at an oil equivalent price of $56/boe.  

Operating costs and lease costs to the end of June averaged $11/boe and $7/boe respectively. With savings and deferrals of $110 million, full year costs are expected to be $18/boe ($12/boe field opex and $6/boe FPSO lease costs). This reflects cessation of production from higher cost fields as well as savings and deferrals realised in ongoing operations across the Group. 

Total capex, including abandonment expenditure, was approximately $195 million during the first six months of the year.  Forecast full year total capex of $340 million reflects total capex savings and deferrals of c.$130 million.

Premier expects to write off c.$200 million of exploration expenditure relating to its acreage in the North Falklands basin which will not be developed as part of its Sea Lion Phase 1 project.  

Premier continues to have full access to its $4.1 billion of UK tax losses and allowances. The value of these are recognised in the balance sheet as a deferred tax asset which is reviewed at each period end in light of fluctuating oil and gas prices.  As a result of the lowering of the Company's assumption on future long term commodity prices, which will be finalised with the Group's half year results, the Company expects to derecognise a portion of the value of these losses and allowances leading to a non-cash charge in the half year results of between $300 million and $500 million. In addition, the Company expects to recognise a non-cash post-tax impairment of between $50 million and $100 million on other assets.  

Net debt reduced over the period to $1.97 billion (31 December 2019: $1.99 billion). This excludes c.$55 million of hedging receipts in relation to the first half which were received post period end.  As at 30 June, the Group retained adequate liquidity with unrestricted cash of c.$100 million and access to undrawn facilities through the Stable Platform Agreement.

As a result of the recent improvement in commodity prices together with the action taken by Premier during the first half of the year to reduce its 2020 expenditure, the Group now expects to be free cash flow positive (after interest) for full year 2020 based on the current forward curve.

Refinancing and funding of BP acquisition

As previously announced, post period-end, the Group's creditors approved the proposed acquisition of the Andrew Area and Shearwater assets under the amended terms, subject to finalisation of the sale and purchase agreements with BP, agreed refinancing terms and equity funding.  In addition, the Stable Platform Agreement, under which the Group's financial covenants are waived through to 30 September, was also approved by the Company's creditors post period-end.

As per the Stable Platform Agreement, Premier is working with a subset of its creditors to agree revised terms for a long term extension to Premier's credit maturities which can be recommended to the full creditor group by the end of July.  The terms of the equity funding for the BP acquisition will be announced following creditor approval of the refinancing terms.

As previously announced, Premier will not be pursuing the purchase of the additional 25 per cent interest in Tolmount from Dana Petroleum, following the termination of the Escrow Agreement on 30 June 2020.

Appendix

Group production breakdown

¹ sold at 26 March 2019

The information contained within this announcement is deemed by Premier to constitute inside information as stipulated under the Market Abuse Regulation. By the publication of this announcement via a Regulatory Information Service, this inside information is now considered to be in the public domain. The person responsible for arranging for the release of this announcement on behalf of Premier is Andy Gibb (Group General Counsel).