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PREMIER OIL PLC

("Premier" or "the Group")

Trading and Operations Update

12 January 2016

Premier today provides the following Trading and Operations Update ahead of its 2016 Full Year Results which will be announced on Thursday 9 March 2017.

2016 Highlights

Outlook

Refinancing

Tony Durrant, Chief Executive, commented:

"Premier achieved a strong operational performance in 2016, resulting in record production and the successful integration of the ex-E.ON portfolio. The Catcher project continues to progress well and will provide another step change in production, generating enhanced, tax-free cash flows for the Group. Our debt refinancing is nearing completion which, together with the improving commodity price environment, will enable us both to accelerate debt reduction and to progress future growth projects."

Refinancing update

All substantial commercial terms have now been agreed with the Coordinating Committee of the RCF Group and representatives of the other Private Lenders (Term Loan, Schuldschein and USPP noteholders). The long form term sheet, in which these commercial terms are embedded, is at an advanced stage and is expected to be circulated to all lenders for their review and formal approval shortly. At that time, Premier expects to announce the full detail of the commercial terms which Premier anticipates will include equity warrants as part of the economics to lenders. Implementation of the refinancing will not otherwise be conditional upon the issue of new equity.

Premier plans to enter into a lock up agreement in relation to the long form term sheet with Private Lenders during February. Revised refinancing documents will then be finalised along with the documentation for implementation of the refinancing via a court Scheme of Arrangement. 

Substantially the same economic terms will be offered to the retail bondholders as to the Private Lenders and these will also be disclosed at the same time as the terms being offered to the Private Lenders. Negotiations with the advisers to an ad hoc committee of the Group's convertible bondholders are ongoing.

Production operations

Premier delivered record production of 71.4 kboepd in 2016, in line with previously upgraded full year guidance of 68-73 kboepd and up 24% on the prior year (2015: 57.6 kboepd). Production in Q4 2016 averaged over 80 kboepd, reflecting a full contribution from the ex-E.ON assets and new production from the Solan field as well as sustained high production efficiency across the portfolio.

In the UK, production averaged 33.0 kboepd during 2016, double that of 2015, and over 40 kboepd in Q4 2016. The step change in production was helped by the new contributions from the ex-E.ON portfolio and the Solan field.

Production from the ex-E.ON portfolio exceeded expectations, averaging 16.3 kboepd over the 8 months from 31 April to 31 December 2016. The Huntington field averaged 10.8 kboepd during 2016, significantly above budget as a result of high uptime and strong reservoir performance. With further well management, Premier aims to maintain production from the field at these levels during 2017. Production from the Elgin-Franklin field increased during the year benefitting from an ongoing infill drilling programme, averaging 5.0 kboepd for the 8 months from 31 April to 31 December 2016 and 6.5 kboepd in Q4 2016. Further infill wells are planned for 2017. Babbage and Wytch Farm also delivered a strong performance in 2016, underpinned by high facilities uptime of over 90% and continued strong reservoir performance. Premier will also be implementing a not normally manned operation from Q2 2017 at Babbage to reduce operating expenditure for the remainder of the field life and also well intervention activities to maintain production levels. The purchase of the E.ON portfolio, which cost $120 million (before working capital adjustments), is expected to reach pay back during 2017 1H, earlier than anticipated as a result of both the stronger production performance and higher commodity prices.

Production from the Premier-operated Solan field was lower than anticipated as a result of a later start-up and poorer than expected reservoir performance which is limiting water injection and P2 production rates. Actions to address this issue are underway including short term increases in water injection pump capacity (now implemented) and other modifications being considered for later in the year. Premier anticipates that production from the field in 2017 will remain at 10-13 kbopd with any material production uplift from remedial action unlikely before 2018. Production efficiency of the facilities has been good and six oil tanker-off loadings have now been successfully completed.

Premier's operated South East Asia assets outperformed during 2016. High uptime of over 90%, better than expected reservoir performance and a successful well intervention programme helped to mitigate natural decline from the Chim Sáo field in Vietnam. A two well infill drilling programme, scheduled to commence in August 2017, will help to maximise production levels from the field. Across the border in Indonesia, Premier's operated Natuna Sea Block A secured an increased market share within its principal gas contract GSA1 of 44% (2015: 43%) against a contractual share of 41% and delivered record production under GSA2 of 94 BBtud during 2016. Natuna Sea Block A's contractual share of GSA1 has increased to 47% for 2017.

Production from Pakistan and Mauritania averaged 7.9 kboepd for the year, 6% over budget. The decrease compared to the prior year reflects natural decline in all of the fields.

Production in 2017 from Premier's existing producing assets is expected to be around 75 kboepd, before any contribution from the Catcher field and adjusted for revised lower Solan production. The increase in production from Premier's existing producing assets reflects a full year contribution from the ex-E.ON portfolio and the Solan field partially offset by natural decline in the Group's Pakistan fields and in certain of Premier's UK fields. The extent of the contribution to 2017 production from Catcher is dependent upon the timing of first oil.

Development and pre-development projects

In the UK, the Premier-operated Catcher project continues to target oil production start-up later this year. Total capex is now forecast at $1.6 billion, 29% lower than the sanctioned estimate. Eight development wells have now been completed and all have come in at or better than prognosis in terms of reservoir quality and deliverability. Most recently, the second well on the Varadero template (VP3) was completed in December and, while constrained by surface equipment on the rig, achieved 8 kbopd on clean up. Due to these strong well results and well placement optimisation, the well count required to deliver the base plan has reduced to 20 wells, thus delivering further significant reductions to the forecast development cost.

2016 saw the completion of the installation of all of the Catcher subsea equipment. Only short subsea campaigns, commencing in June, will be required in 2017 to tie-in the new wells drilled and to support the hook up of the FPSO. The last of the topside modules was successfully lifted onto the FPSO in November and good progress has been made on the integration of the topsides and turret and with the early stages of yard-based pre-commissioning. Consequently, the focus is now on final mechanical completion and, in parallel, the pre-commissioning work scopes. The sail-away date of the FPSO from Singapore is expected to be around mid-year.

Elsewhere in the UK the Tolmount project will provide the next phase of growth for Premier benefitting from a higher gas price than the E.ON acquisition case. The development concept for the field is at an advanced stage, comprising a standalone NUI platform and a new gas export pipeline to shore, and will be subject to a formal approval process in Q1 2017. FEED contracts for the project are expected to be awarded during the first quarter with a FEED programme commencing immediately thereafter.

In Indonesia, a final investment decision on the development of the Bison, Iguana and Gajah Puteri gas fields, which will support Premier's existing long term contracts into Singapore, is expected later this quarter. Elsewhere in Indonesia, significant progress has been made towards securing a three-year extension to Premier's Tuna exploration licence and formal approval of this is expected imminently.

In the Falkland Islands, FEED for the Premier-operated Sea Lion project progressed well during 2016. Throughout 2016 Premier worked closely with its FEED contractors and also with candidate well services and logistics contractors to optimise the facilities design and installation methodology. As a result of this work, the estimated breakeven price of the project was reduced to $45/bbl compared to $55/bbl at the end of 2015. The focus is now on progressing the commercial and fiscal work streams and securing a financing solution for the development to allow the project to move towards sanction.

Exploration and appraisal

The Ravenspurn North Deep well (Premier carried 5% interest) in the Southern North Sea spudded on 2 December. The well is testing the potential of a deep, Carboniferous age, horizon underlying the Ravenspurn North field; if successful, it could provide material follow-on opportunities for Premier within its Southern Gas Basin portfolio, in addition to helping to prolong the life of the Ravenspurn area fields.

In Mexico, having been carried through to the end of 2016, Premier exercised its option to increase its equity interest in Block 7 to 25% on the 22 December 2016, subject to CNH approval. The recently reprocessed seismic data covering Block 7 confirmed the robustness of the Zama prospect, a three-way dip structure sealed against a salt feature. Encouragement was provided by a flat spot seismic feature resulting in this prospect being classified as low risk. The P90-P10 gross unrisked resource range of the overall Zama structure is estimated at 100-500 mmboe (in line with released CNH estimates). The JV partners plan to spud the Zama prospect in Q2 2017 with initial results expected within 50 days of spudding.

Premier continues to actively manage its exploration portfolio with 16 licences relinquished or sold during 2016. A further 11 licences are scheduled for relinquishment subject to government approvals. In particular, Premier exited its 35% interest in Block FZA-M-90 in the Foz do Amazonas Basin in December (subject to ANP approval) enabling the Group to focus its Brazilian exploration efforts on its core area position in the Ceará basin. 

Portfolio management

As previously announced, Premier reopened the process for the sale of its Pakistan business to a limited group of buyers with an offer deadline for later this month and a new effective date of 1 January 2017.

Premier is also seeking offers for its 30% interest in the Esmond Transportation System (ETS) which it acquired through its acquisition of E.ON's UK North Sea assets. Indicative offers have been received from interested parties with the process expected to conclude during 2017 1H.

Following unsolicited offers of interest from a number of parties, Premier has also instigated a process to identify possible investors for a 20% interest in its currently operated 50% Tolmount project.

Finance

Total revenues for 2016 will be of the order of $980 million (2015: $1.1 billion) with higher production partially offsetting the effect of lower realised commodity prices. 

The estimated average oil price realised for 2016 was $43.1/bbl (2015: $52.6/bbl) (pre-hedge) and $51.0/bbl (2015: $79.0/bbl) (post-hedge) compared with an average Brent crude price of $43.7/bbl (2015: $52.4/bbl).

Estimated average gas prices for Premier's principal gas producing areas for 2016 were: 

Premier has currently hedged 33% of its 2017 oil entitlement production through a mixture of swaps, options and fixed price term sales. Specifically, 12% of Premier's 2017 oil production is covered by options with a floor price of $50.7/bbl and 21% of Premier's 2017 oil production has been hedged through swaps and fixed price term sales at an average price of $50.8/bbl. To date, the Group has also hedged around 40% of its 2017 UK gas entitlement production through fixed price term sales at an average price of 50p/therm.

As a result of the weaker sterling exchange rate and continued cost savings across the business, 2016 full year operating costs are estimated to have been $15.7/boe, 11% below budget. In 2017, it is anticipated that these levels of operating costs per barrel can be maintained. In November, Premier in its capacity as operator of Block 12W in Vietnam signed a revised FPSO charter party agreement securing a reduction in the Chim Sáo FPSO lease rate effective from 1 November 2015 and an extension to the firm charter period. Completion was achieved on 19 December 2016. 

Development, exploration and abandonment spend for the full year 2016 was around $690 million, below previous guidance of $730 million as a result of the weaker sterling exchange rate, continued savings secured on the Catcher project and some deferrals of discretionary spend into 2017. 2017 development, exploration and abandonment spend is expected to be $350 million (including deferrals from 2016), of which $130 million relates to the Catcher development, $50 million to exploration and $50 million to abandonment costs. The abandonment spend principally relates to the Chinguetti field in Mauritania which is expected to cease production in Q2 2017 and the Caister field in the Southern North Sea.

2016 payments into escrow in relation to future decommissioning was in the order of $60 million, as previously guided, and includes a $53 million catch up payment into escrow for future decommissioning of Chim Sáo. A $15 million payment into escrow is forecast for 2017 in relation to future decommissioning of the Chim Sáo and Natuna Sea Block A fields. 

Premier continues to benefit from its substantial UK corporation tax loss and allowance position with estimated losses and allowances of $4 billion carried forward at 31 December 2016. Cash taxes are expected to be of the order of $60 million across the Group.

Net debt was $2.8 billion, with cash and undrawn facilities of around $600 million at 31 December. Going forward, Premier expects to be cash flow positive after capex at oil prices above $50/bbl, driving debt reduction.

2017 Board Changes

As already announced, following the completion of the external auditor tender process in Q4 2016 and after serving nine years as a non-executive member of the Board, David Lindsell will retire at the next AGM in May. Iain Macdonald, who joined the Board in May 2016 will assume David Lindsell's role as Chairman of the Audit and Risk Committee.

In accordance with Premier's existing succession planning and current Corporate Governance guidelines, Joe Darby, Senior Independent Director, who will complete 10 years as a Board member during 2017 has indicated that he will step down from the Board at the upcoming AGM in May. 

In addition, Mike Welton, Chairman, has indicated to the Board that he will step down as Chairman - after serving eight years in the role - on completion of the current refinancing programme and identification of a suitable replacement. Recruitment processes for a new Senior Independent Director and Chairman are underway.

Forward Looking Statements

Certain statements in this announcement are forward looking statements. These forward looking statements can be identified by the use of forward looking terminology including the terms "believes", "expects", "estimates", "anticipates", "intends", "may", "will" or "should" or in each case, their negative, or other variations or comparable terminology. These forward looking statements reflect Premier's current expectations concerning future events. They involve various risks, uncertainties and other factors which may cause the actual results, performance or achievements of the Group, third parties or the industry to be materially different from any future results, performance or achievements expressed or implied by such forward looking statements. Such risks, uncertainties and other factors include, amongst other things, general economic and business conditions, industry trends, competition, changes in regulation, currency fluctuations, the Group's ability to recover its reserves or develop new reserves and to implement expansion plans and achieve cost reductions and efficiency measures, changes in business strategy or development and political and economic uncertainty. There can be no assurance that the results and events contemplated by these forward looking statements will in fact occur.