viewPremier Oil PLC

Premier Oil PLC - Trading and Operational Update

RNS Number : 0511F
Premier Oil PLC
12 November 2020

Premier Oil plc

"Premier" or the "Company" or the "Group"

Trading and Operational Update

12 November 2020


Premier today provides a Trading and Operations Update for the 10 months to 31 October 2020.


§ Proposed merger with Chrysaor announced, creating the largest London listed independent oil and gas company with a strong balance sheet and significant international growth opportunities

-      Combined production to the end of October of 237.5 kboepd

-      Creditor support received. Transaction completion expected by end Q1 2021


§ Premier's production averaged 62.5 kboepd for the 10 month period. Full year production guidance is revised to 61-64 kboepd to take into account recent constraints at Catcher


§ Solan P3 brought on-stream in September as planned, production capacity of more than 10 kbopd from the field in the near term


§ Tolmount: platform installed and drilling of the four development wells commenced. First gas forecast for Q2 2021, adding 20-25 kboepd (net) once at plateau


§ Significant growth optionality maintained:

-      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

-      Highly encouraging results from new 3D data sets in Mexico and Indonesia


§ Forecast 2020 opex (ex-lease costs) unchanged at $12/boe and full year capex guidance now $325 million, reflecting full year savings and deferrals of c. $255 million


§ Net debt of $2.05 billion, as at end of October. Financial covenants waived through to completion of the Transaction

Tony Durrant, Chief Executive, commented:

"The merger with Chrysaor, which will create a Combined Group with diversity, scale and balance sheet strength, is progressing to plan.  We now have creditor approval and we expect to publish the prospectus in December, with completion on track for the first quarter of 2021."



Premier Oil plc                                                                                                 Tel: 020 7824 1116

Tony Durrant (CEO)

Richard Rose (Finance Director)

Camarco                                                                                                              Tel: 020 37575 4983

Billy Clegg, Georgia Edmonds


Notes to Editors


Terms defined in the announcement of 6 October shall have the same meaning in this announcement.


Production operations

Group production averaged 62.5 kboepd to the end of October. Summer maintenance programmes were safely completed.  The additional logistical complexity introduced by COVID-19 continues to be successfully managed.


Premier's operated Catcher Area, the Group's largest producer, averaged 26.5 kboepd (net, Premier operated 50 per cent) to the end of October.  The August shutdown was completed successfully and plateau production was re-established in September, with the Varadero infill well (VP1) now also online.  However, in late September, production was constrained due to the produced water plant being offline while a build-up of calcium naphthenate was removed. This work took longer than originally envisaged and the produced water plant was reinstated in early November.

On 9th November, there was a fire in the electrical equipment (HVAC switchboard) in the main store room on board the FPSO which was swiftly and safely extinguished.  No personnel were injured. The facilities were made safe and production shut in.  BWO, the operator of the Catcher FPSO, is working to reinstate the HVAC which would enable production to restart within the next week.

The third producer (P3) at Solan was successfully brought on-stream on 15 September.  The well free-flowed at rates of up to 9.5 kbopd, demonstrating the successful targeting and delivery of the reservoir by the subsurface and drilling teams.  Production was choked back from these levels to minimise excess flaring while the fuel gas and power system are recommissioned.  Production from the P3 well, with the ESP online, is expected to reach rates in excess of 10 kbopd (Premier 100 per cent).

The Elgin Franklin Area produced 6.8 kboepd (net, Premier 5.2 per cent), which was ahead of budget.  Production continues to be supported by high operating efficiency and an active rig programme with the F13 well brought on-stream in October.

As previously announced, Premier, together with its joint venture partners decided to cease production from certain mature UK fields not generating positive cash flows in the current environment.  At Huntington, which ceased production in April, the first phase of the decommissioning programme was substantially completed with the sailaway of the FPSO and recovery of the riser systems. The second phase, which will entail recovery of the subsea equipment and remaining mooring system, is scheduled for 2022.  Final production from the operated Balmoral Area, which surpassed two years without a lost time injury in September, is planned for November 2020 with sailaway of the FPV scheduled for Q2 next year.

Production from Premier's operated Natuna Sea Block A fields in Indonesia averaged 12.2 kboepd (net, Premier 28.67 per cent interest), in line with budget.  Singapore demand for Premier's Indonesian gas was stable for the period, averaging around take or pay levels under Premier's gas sales contracts, GSA1 and GSA2.  Natuna Sea Block A captured a 55.8 per cent market share of GSA 1, materially above its contractual share of 52.5 per cent.  Government and joint venture approvals have been received for the planned 2021 infill drilling campaign to help maintain deliverability from Natuna Sea Block A.

In Vietnam, Premier's operated Chim Sao field produced 8.7 kboepd (net, Premier 53.125 per cent interest), benefitting from high uptime of over 90 per cent and four well intervention campaigns, with the final campaign being completed in October.  In addition, Premier is in the process of securing the necessary regulatory approvals for a two well infill programme in 2022. Demand for Chim Sao crude remains robust with cargoes sold during the period realising an average premium to Brent in excess of $4/bbl.



The 500 BCF (gross) Tolmount development (Premier-operated, 50 per cent interest) remains on track for first gas in Q2 2021. The platform, which left the yard in Italy in September, was successfully installed over the Tolmount field in the UK Southern Gas basin during October.  A shallow gas survey pilot hole has been successfully completed and the first of the four firm development wells was spudded by the Valaris 123 rig on 10th November.  The Tolmount field is expected to add 20-25 kboepd (net, Premier 50 per cent) to Group production once at plateau rates.


On the proposed Tolmount East development, Premier is now in final negotiations with its selected contractors ahead of making a final investment decision on the project.  Once on-stream, Tolmount East will help extend plateau production from the Tolmount Area.  In addition, in September, Premier was awarded two licences directly adjacent to its Tolmount Field Development Area and is in the process of maturing a number of leads and prospects which, in the success case, could be developed via the Tolmount infrastructure. 


In Mexico, negotiations between the Block 7 partners and PEMEX regarding the Zama field development plan and the unitisation of the Zama field are progressing and are expected to conclude in Q1 2021.  FEED on the Zama project scheme (two platforms plus FSO) is reaching a conclusion and pending progress on the unitisation and other approvals a final investment decision would be made later in 2021.


In the Falkland Islands, the 250 mmbbl Sea Lion Phase 1 project is currently on hold.  In the meantime, Premier continues to work with the Falkland Islands Government (FIG) on licensing, fiscal and regulatory matters.  The proposed farm-out of the Sea Lion licences to Navitas is subject to FIG and, pursuant to the Merger Agreement, Chrysaor's approval.

Exploration and appraisal

In Indonesia, the farm out agreement with Zarubezhneft for a 50 per cent interest in the Tuna discoveries was signed in September.   Premier and Zarubezhneft are now in the process of securing Indonesian government approval for the farm out agreement and a one year extension to the Tuna PSC to March 2022.  Zarubezhneft will carry Premier for its share of a two well appraisal programme targeted for mid-2021 with the rig procurement process well-advanced.


Premier continues to mature its highly prospective portfolio of opportunities on the new 3D data sets in Mexico and the Andaman Sea, Indonesia, ahead of drilling campaigns targeted for 2022. Premier also plans to drill the stacked Berimbau/Maraca prospect on its operated Block 717 (Premier 50 per cent interest) in Brazil in 2022.



Premier's operating costs and lease costs averaged $12/boe and $7/boe respectively for the first 10 months of the year. The Group continues to forecast $110 million of opex savings for the full year.


Premier now forecasts 2020 full year total capex, including abandonment expenditure, of $325 million, compared to previous guidance of $340 million, reflecting total capex savings and deferrals of $145 million.


Net debt as at the end of October was $2.05 billion (30 June 2020: $1.97 billion). The cash outflow during the third quarter reflects the impact of the summer maintenance period together with constrained production at Catcher.  As previously announced, the Group's financial covenants have been waived through to completion of the Transaction, which is expected by the end of Q1 2021.



Board and management changes

As previously announced Tony Durrant will step down as Chief Executive by the end of the year.  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.


Proposed merger with Chrysaor

In October, Premier announced the proposed merger of Premier and Chrysaor Holdings Limited and the reorganisation of Premier's existing financing arrangements.  Premier has subsequently received the requisite level of support from each class of its creditors for the Transaction.  As a result, the merger agreement between Premier, Harbour, funds managed by EIG and Chrysaor was released from escrow on 2nd November.


Premier plans to publish a prospectus, which will include an independent valuation of Chrysaor's 2P reserves, and a shareholder circular by the end of the year.  The shareholder circular will include details of the shareholder meeting to approve the Transaction, which is anticipated to take place in January. 


Premier will launch the Court-approved restructuring plan processes, to implement the repayment and cancellation of its existing debt, through the issuance of a practice statement letter, immediately after the Prospectus for the Transaction is published.


The Transaction is expected to complete by the end of Q1 2021.


Chrysaor update

The following information has been provided by Chrysaor for the period to the end of October. 


Chrysaor's production averaged 175 kboepd to the end of October.  This was split 84 kboepd from liquids and 91 kboepd from gas; operated assets 103 kboepd and non-operated assets 72 kboepd. Chrysaor's full-year forecast remains unchanged and in the range of 170-180 kboepd, with reduced levels of drilling and rephrasing of operational activities offset by a shortening of planned shutdowns.


Chrysaor's operated drilling programme, which had been suspended in March, resumed in September with the Valaris 120 heavy duty jack up over the Jasmine wellhead platform to drill the Joanne Chalk S16 well.  This well has been successfully drilled to depth and completion operations continue with first production expected before the year end.  The Transocean Paul B Lloyd Jnr also commenced drilling operations in September and has successfully drilled the Greater Britannia Area - Callanish F5 well to depth.  First production from this well is expected in Q1 2021.

Operating costs (including net tariff costs) for the period were $11.5/boe, below Chrysaor's benchmark of $15/boe.  Chrysaor's total capex (including abandonment expenditure) to the end of October was $605 million. Chrysaor currently expects capital, decommissioning and operating expenditure for 2020 to be around $600 million lower than forecast at the outset of the year, reflecting continued cost control, the pause in non-essential platform activity and the suspension of operated drilling activities for nearly six months.


Chrysaor benefits from a significant hedge programme with c. 85 per cent of its Q4 2020 oil production hedged at $62/bbl and c.44 per cent of its Q4 2020 gas production at 49 pence/therm.  In addition, Chrysaor has hedged approximately 67 per cent of its 2021 1H oil volumes at an average price of $60/bbl and 73 per cent of its 2021 1H gas volumes at an average price of 42 pence/therm.


Additional information on Chrysaor can be found at www.chrysaor.com.



Premier Group production breakdown


1 January - 31 October 2020

1 January - 31 October 2019
















1 Sold as at 26 March 2019



The information contained within this announcement is deemed by Premier to constitute inside information as stipulated under the Market Abuse Regulation. By the publication of this announcement via a Regulatory Information Service, this inside information is now considered to be in the public domain. The person responsible for arranging for the release of this announcement on behalf of Premier is Andy Gibb (Group General Counsel).


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