Premier Oil Operations Update
Thursday 12 January 2017
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.
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.
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.
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 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.
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.
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.
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.
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.