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PREMIER OIL PLC

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

Trading and Operations Update

17 November 2016

Premier today provides a Trading and Operations Update for the period 1 January to 31 October 2016.

Highlights

Tony Durrant, Chief Executive, commented:

"Against a challenging commodity price backdrop, Premier continues to deliver operationally. The company is benefitting from a step change in production with a significantly lower cost base while excellent progress has been made on the Catcher project, which remains on track for first oil next year. Refinancing of the Group's debt has taken longer than anticipated but will, once completed, put Premier in good stead to reinvest in the business while, at the same, time paying down debt. In the medium term, Premier sees increasing value in the Tolmount area, the Sea Lion projects and its exploration acreage in Mexico." 

Refinancing update

Premier has been in discussions with its lending groups on the terms of its existing financial facilities. Whilst the negotiations have taken longer than the Company initially anticipated, lenders under the company's Revolving Credit Facility, term loan, Schuldschein and US private placement notes (the private lenders) provided a revised term sheet on Friday 11 November the key provisions of which are:

Premier will now engage with its Convertible and Retail bondholders and it is the Company's objective that discussions with all parties will be sufficiently advanced such that the creditors are able to lock up to the terms of a transaction by year-end, following which there will be a process to implement the refinancing during Q1 2017.

As part of the refinancing process, the deferral of the 30 June 2016 financial covenants has been rolled on a monthly basis, most recently on 31 October 2016 when the test was again waived and replaced with a test for the 12 month period ending 30 November 2016. Premier expects to continue to receive monthly deferrals until negotiations with its lending group concludes.

Production operations

Production for the ten months to 31 October averaged 68.2 kboepd (2015: 57.5 kboepd). Production in November month-to-date has averaged c.83 kboepd. The significant increase is driven by new Solan production, a full contribution from the ex-E.ON portfolio (which continues to exceed expectations) and a strong performance from the operated Chim Sáo and Huntington assets. Premier expects to deliver within its previously upgraded full year production guidance of 68-73 kboepd.

Premier's operated Chim Sáo field in Vietnam delivered a strong production performance over the period enhanced by a successful well intervention programme, which included reservoir stimulation of three oil wells and a water injector. Significant upside remains at Chim Sáo and further intervention work and two infill wells are planned for 2017 to help maintain production levels. Production was also robust from Premier's Indonesian assets which delivered 14.0 kboepd, underpinned by Natuna Sea Block A capturing an increased market share of 45% (2015: 43%) within GSA1 and strong Singapore demand for gas deliveries under GSA2.

UK production averaged 30.1 kboepd, up 84% on the prior corresponding period, driven by the new contribution from the E.ON portfolio and the Solan field. Production across the E.ON portfolio has continued to exceed expectations, currently averaging c.17 kboepd versus an acquisition case of 15 kboepd. In particular, the now Premier-operated Huntington field has benefited from high uptime of 95% and reservoir performance exceeding expectations while Elgin Franklin - where there is an on-going infill drilling programme - is currently producing more than 6 kboepd net to Premier. Premier's operated Babbage field has also outperformed, producing consistently at rates of over 3 kboepd (net) driven by high uptime of 93%. The platform is in the process of moving to normally unmanned operations which will further reduce field operating costs in 2017. 

On the Premier-operated Solan field, production from the first producer resumed on 22 June (following a planned shutdown) and the second producer (P2) was brought on-stream on 18 August. While initial production capacity from the field was good, production is currently constrained at 10-13 kbopd due to lower than anticipated water injection capability and linked underperformance from the P2 well. A number of solutions are being studied to increase water injection into the reservoir which is necessary to maintain voidage replacement and reservoir pressure at higher production levels. Meanwhile, four tanker off loadings have been successfully completed to date delivering over one million barrels of oil to market and operating cost reductions continue to be secured through a number of initiatives. 

Production from Premier's Pakistan and Mauritania assets has been strong, averaging 8 kboepd over the period, 5% ahead of budget, driven by a successful well intervention campaign at Zamzama. The reduction on the prior corresponding period reflects natural decline in all of the gas fields.

Development projects

The Premier-operated Catcher project remains on schedule with total project capex now forecast at $1.7 billion, a 24% reduction on the original sanctioned estimate. This further reduction in capex estimate is driven by the weak sterling dollar exchange rate given that 55% of the project's remaining capex is denominated in sterling. Further cost reductions are also anticipated from the release of contingencies and allowances as work-scopes continue to be executed efficiently.

All of the subsea equipment has been installed, including the risers, bundles, towheads, manifolds, midwater arches along with the buoy and mooring system. The final spool tie-ins were completed earlier this month thereby concluding the planned 2016 subsea campaign under budget. The major elements of the subsea campaign are now complete with only short campaigns required in 2017 to tie-in wells as they become available from the drilling programme and to support commissioning operations once the FPSO has been installed. The drilling activities continue to progress well and work is ongoing to assess the possibility of reducing the overall well count without impacting production. Well delivery remains ahead of prognosis in terms of reservoir quality and flow rates and the first well (VP2) on the Varadero template, completed earlier this month, achieved 8 kboepd on clean up. 

The outfitting of the FPSO continues apace in Keppel yard in Singapore with over 2,000 contractors working on the vessel. Fabrication of the topside modules has been completed with 12 out of the 13 modules already lifted onto the FPSO. The final module lift is planned for later this month. The sail-away date of the FPSO from Singapore for a 2017 field start up remains on track.

In Indonesia, a final investment decision on the Bison, Iguana and Gajah Puteri (BIGP) gas field developments, which will support Premier's existing long term gas contracts into Singapore and Indonesia, is targeted for the first quarter of 2017. Work continues on the Tolmount gas field in the UK Southern Gas Basin in which Premier holds a 50% operated interest. Premier is engaging with the contractor market with a view to enhancing returns and reducing further upfront capex on the project. Concept selection is targeted for the end of the year with FEED taking place in 2017. Further upside at Tolmount includes Tolmount East and Tolmount Far East which are estimated to hold c. 250 bcf and c. 150 bcf of unrisked prospective gas resource respectively.

In the Falklands, FEED is continuing on the Premier-operated Sea Lion project and the technical definition of the project is well advanced. Current project breakeven price estimate is US$45/bbl and Premier anticipates securing further reductions in cost estimates through market engagement.

Exploration and appraisal

Premier continues to actively manage its exploration portfolio with 13 licences relinquished or sold so far this year. As part of this process, Premier has sold its interest in the UK Bagpuss licence and continues to high grade the exploration portfolio acquired from E.ON earlier this year.

In the Southern North Sea, Premier has a 5% carried interest in the Ravenspurn Deep North well which is scheduled to spud later this month. The well is testing the deep Carboniferous play underlying the Ravenspurn field and, if successful, will provide material follow-on opportunities for Premier within its Southern Gas Basin portfolio.

The Mexico Joint Venture partners have completed the technical evaluation of its Block 7 acreage including the amplitude supported Zama prospect which has a well-defined flat spot, a potential indicator of hydrocarbons. Premier expects to receive the option notice to increase its equity interest in the licence to 25% shortly with the first well expected to be drilled on the block in mid-2017. 

In Brazil, Premier has successfully applied for an extension of the 1st Phase of Exploration Period for its operated licences to 665 and 717 to 10 July 2019. The extension period will enable Premier to realise cost synergies with other operators in the Equatorial Margin who plan to begin drilling operations in the second half of 2018.

Portfolio Management

As previously announced, Premier had agreed terms with a bidder for the sale of its Pakistan business, with execution of the transaction subject to the bidder putting in place the necessary funding arrangements. The exclusivity period with that bidder has now ended and, while engagement with that bidder continues, Premier has reopened the process to a limited group of potential buyers from whom it has received expressions of interest, with an offer deadline early in the New Year. The Pakistan business has performed significantly ahead of forecast in 2016 with net cash flow anticipated to be more than twice the budgeted level. The economic date of the transaction is now expected to be 1 January 2017 with Premier retaining the 2016 cash flow. 

FinancePremier anticipates 2016 full year operating expenses of $15.9/boe, 10% below budget. This was driven by a weaker sterling exchange rate as well as cost savings across the business. Gross G&A costs are forecast at $196 million for 2016 (lower than 2015 despite the E.ON acquisition) and are expected to be a further 20% lower in 2017.

Premier, in its capacity as operator of Block 12W, has also signed a revised FPSO charter party to secure a reduction in the cost of the Chim Sáo lease rate. Completion is expected by year-end.

2016 full year guidance for exploration and development capital expenditure is now expected to be below previous guidance of $730 million. This was driven by a weaker sterling exchange rate, the ongoing efficient execution of the Catcher project and some deferrals of discretionary spend into 2017. Expenditure related to decommissioning spend is expected to be c. $60 million, as previously guided, and includes a $53 million catch up payment into escrow for future decommissioning of Chim Sáo. 2017 exploration and development capex is anticipated to be materially lower at $300 million (including deferrals from 2016). 2017 abandonment spend is expected to be $50 million. 

Net debt was $2.8 billion, marginally down from Q3 with cash and undrawn facilities of c. $600 million at 31 October. Going forward, Premier plans to be cash flow positive at oil prices above $50/bbl driving debt reduction. 

Future announcements

The next Premier Trading and Operations Update will be provided on 12 January 2017. Premier's Full Year Results for 2016 will be announced on 9 March 2017.