Trading and Operations Update

PREMIER OIL PLC

("Premier" or the "Group")

Trading and Operations Update

16 January 2014

Premier today provides a trading and operations update ahead of its 2013 Preliminary Results which will be announced on Thursday 27 February 2014. A Capital Markets Day will also be held for investors and analysts on 6 February 2014.

Simon Lockett, Chief Executive, commented:

"2013 was a challenging year for Premier and the wider industry as a whole. It is however pleasing that production reached record levels towards the end of the year, that four new projects will achieve first oil and gas in 2014 and that our mid- to longer-term projects, including Bream, Catcher and Sea Lion, have taken significant steps forward. We are also pleased our exploration record improved in 2013 as we refocus on selective new basins with material upside."

Production Operations

During December Premier's average production rate was 69 kboepd with a peak weekly average rate above 75 kboepd. Estimated average production for the full year 2013 was 58.2 kboepd (2012: 57.7 kboepd). Whilst our fields are capable of producing in excess of 75 kboepd, our output in 2014, after taking into account production efficiency and planned maintenance periods, is expected to be in the region of 58-63 kboepd.

Working interest production by region

*Includes Brenda, Nicol and Stirling fields

Production from Premier's UK North Sea fields increased to 14.9 kboepd during 2013 (2012: 12.0 kboepd) with an average rate of 23 kboepd for the month of December. The gas export restrictions imposed by CATS operator BP on Huntington were lifted in December and production has increased to 35kboepd (gross). The Rochelle field was brought onstream in October and the West well has been producing in line with expectations. The East well was successfully completed and tied back to the Scott platform. Wytch Farm has continued to outperform since Premier increased its equity in the project and the change in operatorship. Successful workover programmes and the addition of two new production wells resulted in strong production in the second half of 2013. Production from the Balmoral area was lower mainly due to the temporary shut-in of five wells. Two of these wells have since been reinstated and further work is planned in Q2 2014.

In Indonesia, sales from the Anoa field averaged 126 BBtud (2012: 144 BBtud), capturing 39.9 per cent of GSA1 deliveries, against a contractual share of 36.9 per cent. Natuna Sea Block A's contractual share for 2014 has now been increased to 39.4 per cent. Sales from Gajah Baru, which are dedicated to GSA2, averaged 81 BBtud (2012: 72 BBtud). Both the Gajah Baru and Anoa platforms achieved record production rates in excess of 200 BBtud during 2013. Overall, Premier-operated facilities provided the majority (52 per cent) of the gas to Singapore through the WNTS pipeline. Production from the non-operated Kakap Block contributed a further 34 BBtud (2012: 33 BBtud) and liquids production of 3.6 kbopd (2012: 3.5 kbopd).

In Vietnam, production from the Premier-operated Chim Sáo field averaged 26.5 kboepd in 2013. The price of oil cargoes sold from the field during the year averaged $5.87/bbl over Brent. Following damage to the gas export pipeline by a third party in late August oil production was cut to reduce gas being flared. Gas export recommenced in November and production has since ramped up to above 30 kboepd. Premier is progressing significant upgrades to the FPSO to improve the uptime performance of the field.

Production from Pakistan fell slightly during 2013 to 14.9 kboepd (2012: 15.6 kboepd) as mature field decline at the Zamzama, Bhit and Qadirpur fields was only partially offset by increased production at the Kadanwari field following the successful tie-in of the K-29 and K-32 wells.

Development projects

The Dua development in Vietnam continued to progress with subsea equipment now installed. The drilling rig is expected to be on location shortly with first oil expected in Q3. In Indonesia, the Pelikan and Naga platforms were successfully installed at the end of last year and development drilling is expected to commence in Q2 with first gas expected in the second half of 2014.

Sail away and installation of the subsea storage tank, topsides and jackets of Premier's operated Solan project is planned for the first half of 2014 and first oil is scheduled for Q4. Meanwhile on the Catcher development negotiations with all key service contractors and suppliers are either concluded or in their final stages. Consistent with our previous statements, that first oil would be dependent on the delivery date of the FPSO, Premier confirms start-up for mid-2017. Project sanction, planned for early 2014, is subject to partner approvals and ongoing discussions with the UK government following the proposed tax changes for bareboat charters in the Chancellor's Autumn Statement.

The Bream area transactions were completed and operatorship formally transferred to Premier in December. A formal concept select decision will be taken in Q1 and an investment decision is planned for the second half of the year.

In the Falkland Islands, the Sea Lion project team, in conjunction with consulting engineering companies, progressed a comprehensive set of studies to refine the development concept. Premier, and its associated stakeholders, have selected a development concept using a Tension Leg Platform (TLP) with an integral drilling rig. This concept offers a more robust and lower cost development scheme than an FPSO-based scheme. Work is ongoing to optimise and prepare the FEED study for the TLP which is expected to begin in Q2 2014 with project sanction expected in 2015.

Exploration and appraisal

Premier plans to drill 13 wells in 2014 targeting more than 160 mmboe of net unrisked prospective resource. These include six exploration wells, two appraisal well and five near-field wells.

Following on from the Anoa Deep success in 2012, Premier will further explore the Lama play in Natuna Sea Block A, Indonesia. The first well, to be drilled in Q1, will test the Ratu Gajah prospect with a gross prospective resource of up to 700 bcf. The Anoa Deep discovery will also be appraised in Q4. Elsewhere in Indonesia, the Kuda/Singa Laut well is scheduled to spud in Q1. The well will initially test the Kuda Laut segment and then sidetrack to test the adjacent Singa Laut segment. In Vietnam, acquisition of 2D seismic data over the deeper water part of Block 121 is planned for Q2. The new seismic data will allow the joint venture to develop the prospectivity of this frontier area which currently has only limited seismic coverage.

In the North Sea, Premier will drill its first exploration well on the Mandal High in Norway. The rig has been contracted with a spud date planned for Q4. The Luno II appraisal well, which will test the central south part of the discovery, is scheduled for Q2 2014. In Pakistan, five near-field exploration wells are planned to be drilled.

Elsewhere in the portfolio, approximately 100km of additional 2D seismic will be acquired on Block 2B, onshore Kenya, in preparation for the drilling of the Pearl prospect. In the Falkland Islands, four exploration prospects (Zebedee, Jayne East, Elaine/Isobel, Chatham) have been matured to drillable status. A rig tender has been issued to drilling contractors with the first well expected to spud late 2014 to early 2015. In Brazil, Premier will acquire 3D seismic across the three blocks secured in the 2013 licence round with a view to drilling the first well in 2016. Similarly in Iraq, seismic acquisition is planned to start in Q3 2014 and a first well expected late 2015/2016.

* Rig to be confirmed

Exploration New Ventures

In early October, Premier and Rockhopper announced the signing of a Heads of Agreement with Desire to farm-in to licences PL004a and PL004c, which was followed by the signing of a binding farm-in agreement in December. It is anticipated that the farm-in will complete in Q1 2014.

In November, Premier announced the farm-in to Block 2B, onshore Kenya, acquiring a 55 per cent participating interest which has successfully completed.

Financial

The estimated average oil price realised for 2013 was $109.0/bbl (2012: $111.4/bbl) (pre hedge) and $109.1/bbl (2012: $107.6/bbl) (post hedge) compared with an average Brent crude price of $108.7/bbl for the year.

Estimated average gas prices (pre hedge) for our principal gas producing areas for 2013 were:

Total revenues for 2013 will be in the order of $1.5 billion (2012: $1.4 billion). Profits for the full year 2013 will reflect updated future abandonment costs and related non-cash impairment costs. An estimated additional $50 million after-tax charge (net) will be recorded in the second half of the year for the impairment of B-Block.

For 2014, the Group has taken advantage of the relatively strong crude market conditions, forward selling approximately 26 per cent of its estimated 2014 production at an average of $103.5/boe.

During the fourth quarter, the Group took advantage of favorable debt market conditions and historically low interest rates, to raise new debt of over $700 million, the proceeds of which was utilised for general corporate purposes and the repayment of existing bank debt. Debt maturities were extended with new debt falling due 2017-2020 whilst average cost of debt across the group continues to be around 4 per cent pre-tax. The Group retains significant cash and undrawn facilities estimated at $450 million and $1.2 billion respectively at year-end. As at 31 December 2013, net debt is estimated to be $1.5 billion (2012: $1.1 billion). Gearing (defined as net debt divided by net assets plus net debt) is estimated at 40 per cent (2012: 36 per cent). Capital spending for the full year 2013 was approximately $850 million (development, includes Chrysaor Loan funding) and $200 million (exploration, pre-tax). Planned spend for 2014 is around $1 billion (development) and $180 million on exploration (pre-tax).

The Group continues to benefit from its substantial UK corporation tax loss and allowance position with an estimated $2.4 billion of losses and allowances carried forward at 31 December 2013.

The Group anticipates announcing its recommended dividend for the year ended 31 December 2013 in conjunction with its Preliminary Results in February 2014.