Wytch Farm 2018 Production

• Wytch Farm 2018 Productions

Premier Oil, UK based oil and gas explorer, has announced its entrance into a sale and purchase agreement to divest its entire interests in a number of licences for a cash consideration of $200 million. The $200 million bid by Versus Petroleum SNS Limited for the sale of Licences PL089 and P534, will include Wytch Farm, a Dorset based on shore oil field currently in operation by Perenco UK.

[Please read the important amendment at the end of this article]

A few months ago, I visited Kimmeridge Bay in Dorset in the south west of the UK. I went to look at the oil well on the cliffs above the beach and wrote about my experience. The Kimmeridge oil reserve is quite small but further east there are huge additional reserves of oil extending for several kilometres under Poole Harbour and Poole Bay. I wanted to write about these much larger deposits and the environmental effects of extraction: my article, which also takes another look at some of the Kimmeridge story, appeared in the May edition of the Marshwood Vale Magazine. Here is the article:

It’s difficult to believe but one of the most beautiful parts of Dorset in the south west of the UK is home to the largest on-shore oil field in Western Europe. And yet the day to day impact on most residents and on the local environment is minimal. Perhaps the Dorset oil experience can help us predict the potential environmental effects of shale gas extraction by fracking in other parts of the UK? Let’s look at the story of oil in Dorset and see what we can learn.

“Kimmeridge Coal”

Medieval times were harsh for most people but if you lived near Kimmeridge Bay in the Isle of Purbeck, you had one thing going for you; some of the rocks exposed in the cliffs would burn so you had a ready-made fuel for heating and cooking. The locals called it “Kimmeridge Coal” and it didn’t matter that it smelt awful, it was available and it was free. The same logic drove Sir William Clavell in the 17th century to set up alum works at Kimmeridge using the fuel. His efforts came to nothing because of patent restrictions so he turned to making salt by boiling sea water and subsequently he set up a glass works, but neither enterprise prospered.

“Kimmeridge Coal” is found in bands of bituminous shale in the cliffs around Kimmeridge Bay but further exploitation of the material had to wait until the 19th century when it was realised that useful hydrocarbons might be extractable. Processing plants were set up at Weymouth and at Wareham making varnish, grease, pitch, naphtha, paraffin and paraffin wax and in 1848 the street lights of Wareham were lit by 130 lamps powered by gas derived from the shale. The industry never prospered, possibly because the high sulphur content made the gas unsuitable for domestic use.

Kimmeridge oil shale is a useful material but it is not a source of conventional crude oil. Ironically, the first discovery of crude oil in Dorset also occurred at Kimmeridge Bay but it comes from rocks lying well below the shale deposits.

The Kimmeridge “nodding donkey”

The search for oil in Dorset began in the 1930s but it was not until 1959 that the first well producing oil and gas was discovered below Kimmeridge Bay. The well is extracted by a single beam “nodding donkey” pump on the cliffs above the Bay that has worked continuously for more than 50 years; it is the oldest working oil well in the UK and the “nodding donkey” is now part of the local scenery. The Kimmeridge well produced 350 barrels of oil a day at its peak but this has now declined to a fifth of that level. Although the Kimmeridge reservoir is not large, the discovery prompted the search for other oil deposits in Dorset.

The largest on-shore oil field in Western Europe – hidden near Poole Harbour

The energy crises of the 1970s led to further exploration in Dorset and in 1974, oil and gas were discovered by the Gas Council at Wytch Farm on the southern side of Poole Harbour. Production started in 1979 and nowadays the Anglo-French company Perenco owns the majority stake in the oil field. There are three large reservoirs of oil 1-2 km below the sea, extending up to 10 km under Poole Harbour, Brownsea Island, Sandbanks and to the south of Bournemouth. Peak production was in 1997 at 110,000 barrels of oil per day; current levels are about 18,000 barrels per day. The field also produces natural gas (for domestic use) and liquid petroleum gas.

There are 12 well sites distributed around Wytch Farm, the Goathorn Peninsula and Furzey island from which more than 100 wells have been drilled. There is also a gathering station where the products of the wells are collected, processed and distributed. This is a large industrial enterprise, the largest on-shore oil field in Western Europe and the second largest consumer of electricity in the South of England (after Heathrow Airport).

The paradox is that this industrial complex operates in an Area of Outstanding Natural Beauty so the site has been developed with this is mind. Buildings are on sites that have been excavated to reduce height and are screened by trees. Facilities are painted a dull brown and the number of well sites has been minimised by drilling long distances horizontally away from the well site in to the oil deposits; until 2008 Wytch Farm held the world record for the longest drill extending 10.1 km under Poole Bay. In consequence, this large industrial complex has minimal impact on the surrounding countryside and most people are unaware of the activity.

Lessons from Dorset oil

Wytch Farm is a great success story, both in terms of the oil and gas produced and the minimal environmental impact. Some have used the Wytch Farm experience to suggest that fracking (hydraulic fracturing for shale gas) in other parts of the UK will also have a minimal environmental impact, even suggesting, incorrectly, that fracking has already occurred at Wytch Farm.

Although similar drilling technology is used to extract crude oil and to release shale gas, fracking uses large volumes of high pressure liquid (mostly water) to create fissures in low permeability rock and this has not been carried out at Wytch Farm. Also each potential fracking site is likely to be unique and different from Wytch Farm in terms of the density of wells required, the density of population and the nature of the countryside. Dorset oil has been managed to minimise environmental impact but it would be wrong to use the Dorset oil experience to predict the general environmental impact of fracking elsewhere.

There is, of course, one important issue I have not considered here: should we continue to extract and use oil given the need to prevent global climate change? Take a look at the complementary article for my views on that.

Important amendment: In September 2018 it was revealed that the Kimmeridge oil pump has been legally leaking the powerful greenhouse gas methane into the atmosphere for nearly 60 years. The story is covered here. This disclosure changes very considerably my view of the environmental impact of the Kimmeridge oil pump.

('Premier' or 'the Group')

Trading and Operations Update

11 January 2018

Premier today provides the following Trading and Operations Update ahead of its 2017 Full Year Results which will be announced on Thursday 8 March 2018.

2017 Highlights

· Full year production of 75 kboepd in line with guidance, up 5% on 2016

· First oil achieved from Catcher on 23 December on schedule and under budget

· World class Zama oil discovery, offshore Mexico

· Successful disposal programme generating more than US$200 million of cash receipts in 2017

· Significant progress on next generation of growth projects (BIGP, Tolmount, Sea Lion, Tuna)

· Opex per barrel of US$16.5/bbl

· Estimated total capex of US$305 million, below revised guidance of US$325 million

· Positive free cashflow, net debt down to US$2.7 billion as at 31 December 2017

· Comprehensive refinancing completed

Outlook

· 2018 production guidance of 80-85 kboepd, allowing for the ramp up from Catcher and adjusted for 2017 disposals

· Catcher production planned to ramp up in 1H reaching peak gross production of 60 kbopd, currently producing c20 kbopd in the ramp up phase and ahead of plan

· Tolmount development project sanction expected in 2018, will provide next phase of growth

· Zama appraisal: planning for 2018/19 appraisal programme underway

· 2018 opex per barrel expected to be US$17-18/bbl, reflecting changes in the portfolio

· 2018 development and exploration capex guidance of cUS$300 million

· Debt reduction will accelerate at current oil prices as Catcher production ramps up

Tony Durrant, Chief Executive, commented:

'First oil from Catcher and the completion of the Wytch Farm disposal completed a highly successful year for Premier which included our world class exploration success with the Zama discovery. As Catcher builds up to 60,000 bopd, 2018 will bring higher production and cashflow, continuing the debt reduction programme. Alongside this, our portfolio of future projects is being progressed for selective investment and further growth.'

Production operations

Premier delivered production of 75.0 kboepd in 2017, in line with full year guidance and up 5 per cent on the prior year (2016: 71.4 kboepd). Production in December was impacted by the unplanned shutdown by INEOS of the Forties Pipeline System ('FPS') which has now been resolved.

In the UK, production averaged 39.5 kboepd during 2017, up 20 per cent on the previous year, principally as a result of a full contribution from the E.ON assets, which continue to perform above expectations at the time of the acquisition. The unplanned shutdown due to an integrity issue being identified in the onshore section of FPS in December impacted production from a number of Premier's UK fields principally Elgin-Franklin and the Balmoral area. Following the successful repair of a hairline crack in the onshore section of the pipeline, the system was brought back on line on 30 December and Premier's affected fields are all now back online at pre-shutdown rates.

First oil from the Catcher Area development was successfully delivered on 23 December. The first two production wells from the Catcher field have been cleaned up and tested at rates in excess of 20 kbopd each, in-line with expectations and reflecting initial high productivity. As planned, production will continue to be ramped up in phases over the next few months with first oil from Varadero expected imminently, followed by Burgman. Current production levels are being deliberately constrained at around 20 kbopd which is ahead of plan, while commissioning of the full gas processing modules and the water injection systems on the FPSO are carried out. The first stage in commissioning of the gas systems, flowing gas from the SEGAL pipeline system into and pressurising, the gas import/export line is ongoing. The first export cargo of Catcher oil is expected to be lifted in late January and has been sold at a premium to Brent. Full production from the Catcher Area of 60 kbopd is targeted in the first half of 2018.

The Huntington field remained the highest producer in the UK portfolio in 2017 averaging 13.0 kboepd, significantly above budget, as a result of high FPSO uptime and strong reservoir performance. Production from the Elgin-Franklin field continues to benefit from an ongoing infill drilling programme, averaging 5.4 kboepd. Further infill wells are planned for 2018. Babbage also delivered a strong performance in 2017, averaging 3.1 kboepd underpinned by a successful well intervention programme and continued production optimisation of the existing well stock. Production from the Premier-operated Solan field averaged 5.9 kboepd principally from the P1 well which continues with free flow production. A number of options to improve production levels and reserve recovery at Solan continue to be evaluated.

Premier's operated South East Asia assets performed well during 2017. The Chim Sáo field in Vietnam delivered a strong production performance underpinned by high operating efficiency, better than expected reservoir performance and a successful well intervention programme which helped to mitigate natural decline from the field. In addition, year-end production levels from the field were boosted by approximately 6,500 boepd (gross) following the completion of a successful two well infill drilling programme carried out in the second half of the year. Across the border in Indonesia, Premier's operated Natuna Sea Block A secured an increased market share within its principal gas contract GSA1 of 49.6 per cent (2016: 44.4 per cent) against a contractual share of 47.25 per cent and delivered record production under GSA2 of 91 BBtud during 2017. Natuna Sea Block A's contractual share of GSA1 has increased to 51.7 per cent for 2018.

Production from Pakistan and Mauritania averaged 6.5 kboepd for the year, in line with expectations. The decrease compared to the prior year reflects natural decline in all of the fields.

Production in 2018 from Premier's existing producing assets is expected to be between 80-85 kboepd reflecting the phased ramp up from the Catcher Area, natural decline in certain of Premier's fields and the impact of the 2017 Wytch Farm and Pakistan disposals.

Development projects

Drilling activities on phase 2 of the Catcher Area development wells is ongoing with the 14 well now being completed. Total project capex, including remaining contingency, is forecast at US$1.6 billion, 29 per cent lower than the sanctioned estimate as previously guided.

Elsewhere in the UK, offshore and onshore FEED on the Premier-operated Tolmount field in the Southern Gas Basin is progressing well. Evaluation of the tenders received for the major offshore project scopes including the pipeline and platform is underway. Alongside the FEED process, the environmental assessment for offshore aspects of the project was submitted in December and the onshore assessment is planned to follow in due course. Fully termed agreements with Dana Petroleum and CATS Management Limited in respect of the infrastructure partnership for the Tolmount development are being progressed ahead of Final Investment Decision. Approval of project sanction remains on track for 2018.

In Indonesia, the BIGP development project in Natuna Sea Block A is proceeding well and is on budget and schedule for first gas in 2019 and will backfill our existing Singapore and domestic market contracts. Following the signing of the Memorandum of Understanding between Petrovietnam, Premier and SKK Migas (on behalf of the Indonesian Government) for future gas sales from the Tuna Field (Premier equity share: 65 per cent) in Indonesia into Vietnam, a farm out process has been launched ahead of further appraisal drilling in the area planned for 2019.

In the Falkland Islands, work continues on the commercial and fiscal work streams and on securing a financing solution for the Premier-operated Sea Lion project. The latest draft of the Field Development Plan was submitted to the Falkland Islands Government in November 2017 and the public consultation for the Environmental Impact Statement is expected to commence shortly. Premier is in discussions with contractors for the provision of a range of services including vendor finance in respect of the Sea Lion Phase 1 Development and letters of intent are being signed.

Exploration and appraisal

Premier continues to work with both its joint venture partners Talos Energy (Operator) and Sierra Oil & Gas and with PEMEX in the neighbouring block, to progress the appraisal programme for the world class oil discovery at the Zama-1 well in Block 7 Sureste Basin offshore Mexico. Plans are progressing well and it is anticipated that the appraisal programme will commence in 2H 2018 or early in 2019.

In the UK, well operations on the Ravenspurn North Deep well (Premier carried 5 per cent interest), are now complete. The well has been plugged and abandoned and the drilling rig (Rowan Gorilla VII) has been demobilised.

Portfolio management

As previously announced, the sale of Premier's interests in Licences PL089 and P534 (containing the Wytch Farm field) to Perenco UK Limited completed on 21 December generating a pre-tax profit on disposal of approximately US$135 million.

Premier has also continued its programme of non-core asset disposals principally from the E.ON portfolio acquired in 2016. On 11 December the sale of its 30 per cent interest in the Esmond Transportation System (ETS) was announced and is expected to complete in the first half of 2018. In addition, on 20 December, Premier completed the transfer of its 5.12 per cent non-operated interest in the Arran gas discovery to Dyas UK Limited for repayment of costs incurred. A further payment of US$2.5 million will be received on the approval of a Field Development Plan by the Oil and Gas Authority.

In Indonesia, Premier signed a sale and purchase agreement with Batavia Oil on 19 December to sell its entire 19.75 per cent non-operated interest in the Kakap field for a consideration of US$3.2 million. Completion is subject to receiving approval from the Government of Indonesia.

Completion of the sale of the Pakistan business to Al-Haj Group announced in April is subject only to final approvals from the Pakistani authorities. The process is ongoing and in the meantime Premier continues to collect the cashflows generated from the Pakistan assets.

Finance

Total revenues for 2017 will be of the order of US$1,090 million (2016: US$983 million) reflecting both higher production and realised commodity prices.

2017 full year operating costs are estimated to have been US$16.5/boe. In 2018, operating costs per barrel will be US$17-18/boe reflecting the impact of the 2017 disposals and the ramp up of production from the Catcher Area. It is anticipated that these levels of operating costs per barrel will be maintained in the medium term.

An impairment charge of US$200-250 million (post-tax) in respect of the Solan field in the UK North Sea is expected to be recognised in the 2017 Income Statement. The impairment charge is driven by a reduction in the 2P reserves expected to be recovered from the asset over its economic life. This does not take account of any upside from the deeper Triassic play on the Solan licence or the impact of any potential third party volumes across the Solan infrastructure.

Development and exploration spend for the full year 2017 was around US$280 million as a result of savings secured on the Catcher project and in the Mexican drilling campaign and the deferral of spend into 2018. 2018 development and exploration spend is expected to be around US$300 million, of which cUS$170 million relates to the Catcher development (including a cUS$55 million one off first oil payment to the FPSO provider BW Offshore) and US$45 million to exploration. Capex will be weighted to the first half of 2018 as the spending on the Catcher project completes. Abandonment spend in 2017 was US$25 million and is expected to be approximately US$80 million in 2018, before taking into account the benefits of cost recovery and tax relief.

A US$17 million payment into escrow is forecast for 2018 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 over US$4 billion carried forward at 31 December 2017.

Net debt at the year-end was US$2.7 billion, reflecting positive free cashflow generation including disposals offset by the impact of the refinancing and non-cash foreign exchange movements on non-dollar denominated debt. Net debt reduction would have been even greater but for the phasing of certain liftings across the portfolio following lower production in Q4 which results in cash proceeds moving into 2018. The net debt number also does not include the full impact of the announced Pakistan and ETS disposals which are expected to complete in 2018. Cash and undrawn facilities were around US$550 million at 31 December. This includes net proceeds from the Wytch Farm disposal of approximately US$180 million which will be used to pay down and cancel super senior debt facilities. Going forward, Premier expects debt reduction to accelerate at current oil prices as production from Catcher ramps up.

Premier has taken advantage of the recent improvement in the commodity prices to increase its oil price hedges in 2018 through a combination of both fixed price term sales and options that provide a floor price but allow continuing exposure to increasing commodity prices. The Company has currently hedged approximately 40 per cent of its 2018 oil entitlement production through a mixture of swaps, options and fixed price term sales. Specifically, approximately 10 per cent of Premier's 2018 oil production is covered by options with a floor price of US$55/bbl and approximately 30 per cent has been hedged through swaps and fixed term sales at an average price of US$57/bbl. To date, Premier has also hedged around 24 per cent of its 2018 UK gas entitlement production through fixed price term sales at an average price of 47p/therm.

Premier Oil plc published this content on 11 January 2018 and is solely responsible for the information contained herein.
Distributed by Public, unedited and unaltered, on 11 January 2018 07:09:05 UTC.

Wytch Farm 2018 Productions

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