Premier has provided an update on the proposed all share merger between Premier and Chrysaor Holdings Limited (“Chrysaor” and, following completion, the “Combined Group”) and the reorganisation of Premier’s existing debt and cross currency swaps. Premier also issues an update on its and Chrysaor’s trading and operational activities for the first 11 months of the year and reports 2021 guidance for both companies.
A live webcast and conference call for analysts and investors will be held on Thursday 17 December 2020 at 11am (GMT), the details of which can be found on Premier’s website (www.premier-oil.com).
Publication of a shareholder circular and prospectus
Premier is pleased to announce that a shareholder circular and prospectus in relation to the Transaction are expected to be published later today, subject to FCA approvals, and that the General Meeting of Premier’s shareholders to approve the Transaction has been scheduled for 12 January 2021.
The publication of the Circular and Prospectus marks an important milestone for the Transaction which is expected to complete by the end of the first quarter of 2021, as previously guided.
On completion of the Transaction, Premier will be renamed Harbour Energy plc (“Harbour Energy”).
Board and management
As previously announced, it is anticipated that the Board of Harbour Energy will comprise 11 directors: six independent non-executive directors, two non-executive directors appointed by funds managed by EIG Global Energy Partners (“EIG”) and three executive directors.
Blair Thomas, currently CEO of EIG, will be the Chairman of the Combined Group from completion. Blair has over 30 years’ experience in the investment management business, with a focus on energy and energy-related infrastructure and extensive management and board experience.
As previously announced, Linda Cook will be CEO of Harbour Energy and Phil Kirk will be President and CEO Europe from completion. It is expected that a new Chief Financial Officer will be identified prior to completion of the merger.
Harbour Energy’s Board will also include, from completion:
- Simon Henry (Senior Independent Non-Executive Director)
- Anne L Stevens (Independent Non-Executive Director)
- Anne Marie Cannon (Independent Non-Executive Director)
- G. Steven Farris (Non-Executive Director)
It is expected that the three additional independent non-executive directors will be announced prior to completion.
It is expected that each of the current non-executive directors of the Board of Premier Oil, other than Anne Marie Cannon, will step down from the Board with effect from the completion of the Transaction.
Further to the information disclosed in this announcement and the Prospectus that is expected to be published later today, there is no further information to be disclosed pursuant to Listing Rule 9.6.13R.
Creating a strong UK independent oil and gas company of scale with a global footprint
Harbour Energy will be the largest London-listed independent oil and gas company by production and reserves. It will be a resilient business with competitive operating costs. The Combined Group will have a lower carbon intensity than the average UK oil and gas producer, with targets in place for further improvements, and a commitment to achieving ‘Net Zero’ greenhouse gas emissions by 2035.
The Combined Group will have a cash generative, diversified UK business of scale with a significant operated position. It will have a broad set of international growth opportunities with the financial flexibility and capacity to realise value from a top-tier development and exploration portfolio in addition to disciplined M&A.
Harbour Energy will have a strong balance sheet. In addition, the Combined Group is expected to generate sufficient free cash flow to support shareholder returns including via a sustainable dividend which, subject to market conditions and Board approval, is expected to be introduced with respect to the financial year ending December 2021.
ERCE Equipoise Ltd (“ERCE”) Competent Person’s Report (“CPR”)
ERCE has prepared an independent CPR on the Chrysaor assets, which will be included in full in the Prospectus that is expected to be published later today. At 30 June 2020, ERCE has certified that Chrysaor had 491 mmboe of 2P reserves and 388 mmboe of 2C resources. These numbers do not include Premier’s 2P reserves or 2C resources.
Conditions to closing and timetable
The Transaction is subject, amongst other things, to Premier shareholder and creditor consents and regulatory approvals. The General Meeting for Premier’s shareholders to approve the Transaction has been scheduled for 12 January 2021.
As previously announced, Premier has received the requisite level of creditor support for the Transaction and, immediately after the Prospectus is published, expects to launch the restructuring plan processes through the issuance of a practice statement letter. To date, European Commission merger control clearance has been received and regulatory approval from the Norwegian MPE has been, conditionally, received.
The expected timetable of principal events to completion can be found in the Appendix.
Premier provides the following update in relation to its trading and operational activities for the first 11 months of the year and guidance for 2021:
- Production averaged 61.2 kboepd for the 11 month period and Premier is on track to meet its full year guidance of 61-64 kboepd.
- Premier expects 2021 production to be in the range of 61-66 kboepd. This reflects new production from Premier’s operated Tolmount gas field (due on-stream in Q2 2021) offset by natural decline and maintenance shutdowns deferred from 2020.
- Production at Premier’s operated Catcher Area has been restored to rates in excess of 60 kbopd (gross) following a seven day unplanned outage in mid-November.
- The Solan P3 well was brought on-stream in September and subsequently produced at rates of over 10 kbopd in mid-November with the ESP online. In early December, production from the Solan field was shut in following the failure of the emergency generator and Premier is actively progressing its repair.
- The Tolmount platform was installed during October and batch drilling of the four wells is underway. First gas is forecast for Q2 2021 with Tolmount expected to add 20-25 kboepd (net) once on plateau with all four wells completed, anticipated during Q4 2021.
- Premier has retained significant growth optionality within its portfolio
- Zama (Mexico) unitisation and development plan negotiations progressing with Pemex.
- Tuna (Indonesia) farm-out agreement signed with Zarubezhneft in September. Fully-carried two well appraisal programme planned for 2021
- Premier continues to assess the potential of the resources associated with the Sea Lion project (Falkland Islands) which represents a material opportunity for the Group
- Highly encouraging results from new 3D seismic data sets in Mexico and Indonesia
Forecast 2020 opex (ex-lease costs) unchanged at $12/boe and full year capex (including abex) guidance now $315 million, reflecting full year savings and deferrals of over $250 million.
Premier forecasts 2021 operating costs (ex-lease costs) of $15/boe. This includes the tariff to be paid for the Tolmount infrastructure. 2021 total capital expenditure (including abex) is expected to be c. $275 million. 2021 guidance is provided on a standalone basis and does not account for any optimisation that may occur post completion of the Transaction.
Net debt at the end of November was $2.06 billion.
Premier also notes that Tony Durrant stepped down from the Board of Directors on 16 December 2020. As previously announced, Richard Rose will be the Interim Chief Executive until completion of the Transaction, in addition to his current role as Finance Director. Stuart Wheaton, currently Chief Operating Officer, will assume the role of Interim Deputy Chief Executive.
Chrysaor has provided Premier with the following update on its trading and operational activities for the first 11 months of the year and guidance for 2021:
- Production averaged 174 kboepd for the 11 month period and Chrysaor forecasts full year production of 174 kboepd, in line with its full year guidance of 170-180 kboepd.
- Chrysaor expects 2021 production to average in the range of 140-155 kboepd. This reflects an expected 2020 second-half production forecast of c. 160 kboepd and an unusually high level of asset shutdowns during 2021, driven by COVID-19-related 2020 maintenance deferrals. The COVID-19 related suspension of some drilling activities in 2020 has also impacted the 2021 production forecast.
- J-Area averaged 31 kboepd (net), with the impact of water breakthrough in the Palaeocene wells ameliorated by an active drilling and workover programme which is expected to continue into 2021. The joint venture partners are considering adding a second drilling unit in late 2021 to appraise the Talbot discovery and to drill the Dunnottar exploration prospect.
- Greater Britannia Area averaged 40 kboepd (net), benefitting from excellent uptime and better than expected well performance from the Brodgar satellite field. Chrysaor expects first production from the Callanish F5 well in Q1 2021.
- In the AELE (Armada, Everest, Lomond and Erskine) area, production averaged 31 kboepd (net). In December, Chrysaor sanctioned the LAD infill development well at Everest East with drilling scheduled for Q3 2021.
- Non-operated portfolio:
- The Total-operated Elgin Franklin area averaged 19 kboepd (net), ahead of expectations with the fields benefitting from very high production efficiency and an ongoing infill drilling and well intervention programme. The operator is currently planning facilities and integrity work towards a potential extension of field life.
- Production from the Buzzard field averaged 19 kboepd (net). Phase 1 infill drilling has delivered on or above target while Buzzard Phase 2 drilling results have been towards the lower end of expectations. Drilling has now been paused and further wells and side-track activity will wait until after the Phase 2 wells have been brought onto production, now expected in December 2021.
- Beryl Area fields averaged 17 kboepd (net), supported by an ongoing well intervention programme and continued infill drilling. Exploration activity in the Beryl area Tertiary play has been positive so far with two successful wells drilled on the Solar and Corona prospects.
- Chrysaor’s operating costs (including net tariff costs) for the 11 months to the end of November averaged $11.4/boe.
- Chrysaor expects unit operating costs to be higher in 2021 than the 2020 outturn, but below its long-term target of $15/boe (including net tariff costs). This is as a result of lower forecast production and increased maintenance expense in 2021.
- Chrysaor’s total capital expenditure (including exploration and decommissioning) to the end of November 2020 was $651 million.
- Chrysaor expects total capital expenditure for the full year 2020 to be around $718 million. This is approximately $575 million lower than forecast at the outset of the year, reflecting the pause in non-essential platform activity and the suspension of operated drilling activities for nearly six months.
- Chrysaor expects total 2021 capital expenditure to be in the range of $750-850 million, principally relating to drilling and development activities at J-Area, AELE, Beryl and Buzzard field, and including c. $170 million for decommissioning (pre-tax relief).
- Chrysaor benefits from a significant hedging programme with approximately 67 per cent of its 2021 1H oil volumes hedged at an average price of $60/bbl, and 73 per cent of its 2021 1H gas volumes hedged at an average price of 42 pence/therm.