EnQuest 2019 Full Year Results
Results for the year ended 31 December 2019 and 2020 outlook
24% production growth; material debt reduction with net debt:EBITDA at 1.4x
Decisive action being taken to position EnQuest to manage in a sustained low oil price environment
9 April 2020
Unless otherwise stated, all figures are on a Business performance basis and are in US Dollars.
2019 performance - delivered targets
§ Group production averaged 68,606 Boepd in 2019, up 23.7% on 2018
§ Revenue of $1,711.8 million (2018: $1,201.0 million) and EBITDA of $1,006.5 million (2018: $716.3 million)
§ Cash generated from operations of $994.6 million (2018: $788.6 million), reflecting higher EBITDA
§ Cash capital expenditure of $237.5 million (2018: $220.2 million)
§ Cash and available bank facilities amounted to $288.6 million at 31 December 2019, with net debt of
$1,413.0 million (2018: $1,774.5 million); net debt:EBITDA at 1.4x
§ Net 2P reserves of 213 MMboe and net 2C resources of 173 MMboe at the end of 2019 (2018: 2P reserves of 245 MMboe; 2C resources of 198 MMboe); lower 2P reserves driven by production and downward revisions at Heather/Broom and Thistle, partially offset by increases at Magnus, Kraken and PM8/Seligi
§ Non-cash post-tax impairments of $562.3 million, including tangible fixed assets of $397.5 million, mainly reflecting changes in oil price and production profiles, primarily at Heather/Broom, Thistle and the Dons, and $149.6 million impairment of goodwill
2020 performance and outlook - well positioned for a low oil price environment
§ Year to date production performance remains good with the Group's day-to-day operations continuing without being materially affected by COVID-19
§ No senior credit facility amortisations due in 2020 following voluntary early repayments; the Group's outstanding credit facility1 is $425.0 million at the end of February
§ Cash and available facilities at the end of February were $268.2 million, with net debt of $1,368.1 million
Prioritising operational excellence, cost control and capital discipline
§ Targeting further in-year savings by removing discretionary activities given the prevailing oil price environment
§ Full year operating expense savings of c.$190 million; revised full year guidance of c.$335 million
§ Full year capital expense savings of c.$110 million; revised full year guidance of c.$120 million
§ Directors and senior management have agreed an interim voluntary reduction in salary of 20%
§ Full year production guidance remains at 57,000 to 63,000 Boepd
§ Forecast free cash flow2 breakeven reduced to c.$33/Boe for 2020 and c.$27/Boe for 2021, subject to achieving savings
§ Future portfolio opportunities focused on three largest, low-cost assets: Magnus, Kraken and PM8/Seligi
1Excludes interest capitalised as payment in kind of $15.8 million
2 Free cash flow: net change in cash and cash equivalents less net (repayments)/proceeds from loan facilities. $/Boe based on working interest production
EnQuest Chief Executive, Amjad Bseisu, said:
"During 2019, EnQuest again delivered on its targets. The combination of improved Kraken performance, a full year contribution at Magnus and strong performances at Scolty/Crathes and PM8/Seligi, drove significant production growth and free cash flow generation, which facilitated a material reduction in the Group's net debt.
"Given the prevailing low oil price environment, we have taken decisive action to lower our cost base, targeting $190 million of operating cost savings in 2020, equating to unit operating expenses of c.$15/Boe. With these significant cost reductions, cash flow breakeven is estimated at c.$33/Boe in 2020. With realisations in the first quarter of 2020, the cash flow breakeven falls to c.$25/bbl for the remainder of the year. 2021 cash flow breakeven is now forecast at c.$27/Boe, with unit operating expense of around $12/Boe. With these significant reductions, we are well positioned to manage through a sustained low oil price environment.
"Our three largest assets continue to generate meaningful operating cash flows, even at low oil prices, and, in the medium to long-term, offer low-cost resource maturation opportunities which are aligned with our proven differential capabilities."
Production and financial information
|Revenue and other operating income ($m)1||1,711.8||1,201.0||42.5|
|Realised oil price ($/bbl)1, 2||65.3||64.2||1.7|
|Gross profit ($m)||468.3||275.0||70.3|
|Profit before tax & net finance costs ($m)||442.2||290.0||52.5|
|Cash generated from operations ($m)||994.6||788.6||26.1|
|Reported (loss)/profit after tax ($m)||(449.3)||127.3||-|
|Reported basic (loss)/earnings per share (cents)||(27.4)||9.2||-|
|Cash capex ($m)2||237.5||220.2||7.9|
|End 2019||End 2018|
|Net (debt)/cash ($m)2||(1,413.0)||(1,774.5)||(20.4)|
1 Including gains of $24.8 million (2018: losses of $93.0 million) associated with EnQuest's oil price hedges
2 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 69
|Average daily production on a net working interest basis (Boepd)||1 Jan' 2019 to
31 Dec' 2019
|1 Jan' 2018 to
31 Dec' 2018
|Northern North Sea||27,237||19,2931|
|Central North Sea||7,544||6,353|
1 Includes net production related to 25% interest in Magnus until 30 November 2018 and 100% interest of Magnus from 1 December 2018, averaged over the 12 months to the end of December 2018
2019 performance summary
EnQuest's operational focus for 2019 was to improve and stabilise production at Kraken, deliver the Group's sub-sea pipeline projects and drilling programmes, while maintaining strong production efficiency across its asset base. All of these were achieved with the Group again performing better than, or in line, with external guidance. This operational delivery combined with ongoing cost control, has enabled the Group to continue to strengthen the balance sheet by significantly reducing net debt.
EnQuest's average production increased by 23.7% to 68,606 Boepd, towards the top end of the guidance range,
primarily reflecting the contributions from Magnus, Kraken, Scolty/Crathes and PM8/Seligi, partially offset by the
shutdowns at Thistle and Heather and natural declines across the portfolio.
EBITDA and cash generated by operations increased materially in 2019 compared to 2018, reaching $1,006.5 million and $994.6 million, respectively, reflecting the combination of significantly higher production, higher realised oil price and the Group's focus on cost control.
Cash capital expenditure of $237.5 million was focused on executing the Group's drilling programmes at Kraken,
Magnus and PM8/Seligi and the sub-sea pipeline projects at Scolty/Crathes and the Dunlin bypass for Thistle and the Dons.
Liquidity and net debt
At 31 December 2019, net debt was $1,413.0 million, down $361.5 million from $1,774.5 million at 31 December 2018, reflecting a strong operational performance and higher realised oil prices. Total cash and available facilities were $288.6 million, including ring-fenced funds held in operational accounts associated with Magnus, the Sculptor Capital facility (previously known as the Oz Management facility) and other joint venture accounts totalling $74.0 million.
Strong free cash flow generation enabled the Group to make early voluntary repayments of the senior credit facility, which was reduced by $325.0 million during the year, including $120.0 million associated with the April 2020 scheduled amortisation. A further $35.0 million was repaid in January 2020 as an accelerated voluntary payment of the October 2020 amortisation. No further amortisation payments are due in 2020. At the end of March, the senior credit facility, excluding payment in kind interest, totalled $425.0 million
Reserves and resources
Net 2P reserves at the end of 2019 were 213 MMboe (2018: 245 MMboe) and have been audited on a consistent basis with prior years. During the year, the Group produced 9.6% of its year-end 2018 2P reserves base, with downward
revisions at Heather/Broom and Thistle almost entirely offset by increases at Magnus, Kraken and PM8/Seligi. Net 2C resources at the end of 2019 were 173 MMboe (2018: 198 MMboe) as a result of transfers to 2P reserves at Magnus and PM8/Seligi and revisions at Heather/Broom, partially offset by the addition of resources associated with the award of the PM409 Production Sharing Contract in Malaysia.
A sustainable business - 2020 performance and additional outlook details
The Group is materially better placed to deal with the reduced oil price than historically with a much reduced level of debt and no payments of the Group's senior credit facility due in 2020. In addition, the Group is taking decisive action to further reduce operating and capital expenditure in 2020 and beyond, with a view to targeting cash flow breakeven of c.$33/Boe in 2020 and c.$27/Boe in 2021.
The Group is now targeting operating expenditure savings of c.$190 million, which would lower operating costs by c.35% to c.$335 million, equating to unit operating expense of c.$15/Boe. In 2021, the Group is targeting unit operating expenditures of c.$12/Boe. These savings will be driven primarily by cost savings at Heather and Thistle/Deveron, but also through the removal of non-critical and discretionary operating expenditures and support costs.
Cash capital expenditure is also expected to be further reduced, now down c.$110 million to c.$120 million. The majority of the Group's 2020 programme relates to the recently concluded drilling programme at Magnus and the two-well programme now underway at Kraken, with approximately $50 million of 2020 cash capital expenditure relating to the phasing of cash payments into 2020. The Group's 2021 capital expenditure programme is expected to reduce further, which will also impact production.
EnQuest's updated working assumption is not to re-start production at the Heather and Thistle/Deveron fields. As a result, full year production guidance is expected to be in the range of 57,000 to 63,000 Boepd, with forecast Kraken gross production remaining unchanged between 30,000 and 35,000 Bopd. The two-well drilling programme in Kraken's western area is underway and expected to contribute production in the second half of the year, partially offsetting the impacts of the planned maintenance shutdown and natural declines. As previously announced, the Group's current expectation is for economic production at Alma/Galia to cease in the second half of 2020.
EnQuest has hedged c.20% of 2020 entitlement production with c.2.9 MMbbls of oil at an average floor price of c.$65/bbl and, in accordance with the Sculptor Capital facility agreement, c.1.1 MMbbls hedged at an average floor price of c.$52/bbl.
While no further repayments of the Group's senior credit facility are due in 2020, debt repayment remains the financial priority for the Group.
As a responsible operator, EnQuest has been monitoring the evolving situation, and consequent emerging risk, with regards to the spread of COVID-19. The Group has been working with a variety of stakeholders, including industry and medical organisations, to ensure its operational response and advice to its workforce is appropriate and commensurate with the prevailing expert advice and level of risk. Appropriate restrictions on offshore travel have been implemented, such as self-declaration by, and isolation of, individuals who have been to affected areas and pre-mobilisation temperature checking in operation at most locations. EnQuest's normal communicable disease process has been updated specifically in respect of COVID-19, with additional offshore isolation capability and agreements in place to transport impacted individuals back onshore in dedicated helicopters. At the Sullom Voe Terminal, the same processes have also been implemented, with isolation capability at the local accommodation block. Non-essential down-manning has been implemented, with many of the Group's onshore workforce working remotely.
While it is difficult to forecast the impact of COVID-19, at the time of publication of EnQuest's full year results, the Group's day-to-day operations continue without being materially affected. The situation will continue to be monitored.
Summary financial review of 2019
(all figures quoted are in US Dollars and relate to Business performance unless otherwise stated)
Revenue for 2019 was $1,711.8 million, 42.5% higher than in 2018 ($1,201.0 million), reflecting the increase in
production, the onward sale of third-party gas purchases not required for injection activities at Magnus, and the
favourable impact of the Group's commodity hedge programme, offset by slightly lower market prices. The Group's commodity hedge programme resulted in realised gains of $24.8 million in 2019 (2018: losses of $93.0 million).
The Group's average realised oil price excluding the impact of hedging was $64.2/bbl, compared to $69.4/bbl for 2018. The Group's average realised oil price including the impact of hedging was $65.3/bbl in 2019, 1.7% higher than in 2018 ($64.2/bbl).
Revenue is predominantly derived from crude oil sales which totalled $1,548.2 million, 25.1% higher than in 2018 ($1,237.6 million), reflecting the increase in volumes. Revenue from the sale of condensate and gas was $120.2 million (2018: $43.1 million), mainly reflecting gas sales from Magnus, which includes the combination of produced gas sales and the onward sale of third-party gas purchases not required for injection activities, for which the costs are included in other cost of sales.
Total cost of sales were $1,243.6 million for the year ended 31 December 2019, 34.3% higher than in 2018
The Group's operating expenditures of $518.1 million were 11.2% higher than in 2018 ($465.9 million), reflecting the full year of additional equity interest in Magnus. Unit operating costs decreased by 10.4% to $20.6/Boe (2018: $23.0/Boe) as a result of increased production.
Total cost of sales also included non-cash depletion expense of $525.1 million, 20.1% higher than in 2018 ($437.1 million), mainly reflecting a full year of 100% equity interest in Magnus.
The charge relating to the Group's lifting position and inventory was $102.9 million (2018: $25.1 gain). This reflects a switch to a $28.6 million net overlift position at 31 December 2019 from a $68.3 million net underlift position at 31 December 2018. This switch reflected the closing positions on Thistle and Heather and the unwind of underlift on Magnus in the year.
Other cost of sales of $97.5 million were higher than in 2018 ($48.1 million), principally reflecting the cost of additional Magnus related third-party gas purchases not required for injection activities of $72.0 million.
EBITDA for 2019 was $1,006.5 million, up 40.5% compared to 2018 ($716.3 million), primarily as a result of increased production and revenue.
The tax charge for 2019 of $23.6 million (2017: $20.9 million tax credit), excluding exceptional items, is mainly due to Malaysian tax and the utilisation of UK losses offset by the Ring Fence Expenditure Supplement on UK activities
generated in the year. UK corporate tax losses at the end of the year reduced to $2,903.4 million (2018: $3,225.3 million) as the Group generated taxable profits on increased production which were offset against existing tax losses.
Post-tax exceptional items for 2019 were a loss of $663.6 million (2018: gains of $49.1 million). The Group recognised pre-tax non-cash impairment charges on its tangible oil and gas assets of $637.5 million (2018: $126.0 million), mainly in respect of Heather, Thistle and the Dons, $149.6 million (2018: $nil) on goodwill and $25.4 million (2018: $0.4 million) on intangible oil and gas assets. In addition, a non-cash increase in fair value of contingent consideration relating to the Magnus asset of $15.5 million, non-cash other finance costs relating to the unwinding of contingent consideration of $57.2 million and unrealised losses on commodity contracts of $65.4 million. A tax credit of $303.5 million (2018: $12.4 million) has been presented as exceptional, representing the tax impact of the above items.
Net debt at 31 December 2019 was $1,413.0 million, a decrease of 20.4% compared to 2018 ($1,774.5 million),
primarily as a result of the improved cash generating capability of the Group. This includes $133.3 million of interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016
refinancing (31 December 2018: $132.0 million).
For further information please contact:
|EnQuest PLC||Tel: +44 (0)20 7925 4900|
|Amjad Bseisu (Chief Executive)|
|Jonathan Swinney (Chief Financial Officer)|
|Ian Wood (Head of Communications & Investor Relations)|
|Jonathan Edwards (Senior Investor Relations & Communications Manager)|
|Tulchan Communications||Tel: +44 (0)20 7353 4200|
Presentation to Analysts and Investors
A presentation to analysts and investors will be held at 09:00 today - London time. The presentation will be accessible via an audio webcast, available on the investor relations section of the EnQuest website at www.enquest.com.
A conference call facility will also be available at 09:00 on the following numbers:
Conference call details:
UK: +44 (0) 800 376 7922 or +44 (0) 844 571 8892
International: +44 (0) 207 192 8000
Confirmation Code: EnQuest
Notes to editors
This announcement has been determined to contain inside information. The person responsible for the release of this announcement is Stefan Ricketts, General Counsel and Company Secretary.
EnQuest is an independent production and development company with operations in the UK North Sea and Malaysia. The Group's strategic vision is to be the operator of choice for maturing and underdeveloped hydrocarbon assets, by focusing on operational excellence, differential capability, value enhancement and financial discipline.
EnQuest PLC trades on both the London Stock Exchange and the NASDAQ OMX Stockholm. Its UK operated assets include Thistle/Deveron, Heather/Broom, the Dons area, Magnus, the Greater Kittiwake Area, Scolty/Crathes Alma/Galia and Kraken; EnQuest also has an interest in the non-operated Alba producing oil field. At the end of
December 2019, EnQuest had interests in 17 UK production licences and was the operator of 15 of these licences. EnQuest's interests in Malaysia include the PM8/Seligi and PM409 Production Sharing Contracts, both of which the Group operates.
Forward-looking statements: This announcement may contain certain forward-looking statements with respect to EnQuest's expectations and plans, strategy, management's objectives, future performance, production, reserves, costs, revenues and other trend information. These statements and forecasts involve risk and uncertainty because they relate to events and depend upon circumstances that may occur in the future. There are a number of factors which could cause actual results or developments to differ materially from those expressed or implied by these
forward-looking statements and forecasts. The statements have been made with reference to forecast price changes, economic conditions and the current regulatory environment. Nothing in this announcement should be construed as a profit forecast. Past share price performance cannot be relied upon as a guide to future performance.
Chief Executive's report
EnQuest's operational focus for 2019 was to improve and stabilise production at Kraken, deliver the Group's sub-sea pipeline projects and drilling programmes, while maintaining strong production efficiency across its asset base. All of these were achieved, with the Group again performing better than, or in line with, its external guidance. This operational delivery combined with ongoing cost control enabled the Group to continue to strengthen the balance sheet by
significantly reducing net debt.
EnQuest's average production increased by 23.7% to 68,606 Boepd, towards the top end of the Group's guidance. The increase was driven by the contributions from Magnus, Kraken, Scolty/Crathes and PM8/Seligi, partially offset by the shutdowns at Thistle and Heather and natural declines across the portfolio. The improved performance of the Kraken FPSO vessel is particularly pleasing. This was the result of targeted improvement initiatives and the collaborative efforts by our people and those of our partner and the vessel operator. At Magnus, the team also delivered a good operational performance, which, along with a revised reservoir management strategy that lowered operating costs, resulted in the reimbursement of EnQuest's $100 million cash consideration in a year, earlier than originally expected. The project teams delivered an excellent performance in our sub-sea pipeline replacement projects at Scolty/Crathes and the Dunlin bypass in respect of Thistle and the Dons, with both being completed ahead of budget and schedule.
During the year, the Group produced 9.6% of its year-end 2018 2P reserves base. The Group's revised life-of-field expectations at Heather/Broom and Thistle resulted in downward reserves revisions which were almost entirely offset by increases at the Group's growth assets, Magnus, Kraken and PM8/Seligi. Overall, net 2P reserves reduced to 213 MMboe at the end of 2019, down 13.3% on the 245 MMboe at the end of 2018. Since the Company was formed with around 81 MMboe of 2P reserves, the Group has achieved a compound average reserves growth of 10.2%. The Group continues to have substantial 2C resources of around 173 MMboe, primarily located at Magnus, Kraken and PM8/Seligi, and include the addition of 2C resources associated with the Group's Production Sharing Contract ('PSC') at PM409, offshore Malaysia.
The Group's EBITDA increased by 40.5% to $1,006.5 billion, reflecting the material increase in production and higher realised prices, while the Group's ongoing focus on cost control kept operating expenditure to $518.1 million, with unit operating costs reduced to around $20.6/Boe. As a result, cash generated by operations increased significantly to $994.6 million, up 26.1% compared to 2018, with free cash flow of $368.5 million.
This strong performance facilitated a material reduction in the Group's net debt, which ended the year at $1,413.0 million, down $361.5 million from the end of 2018, with EnQuest's net debt to EBITDA ratio at 1.4x, materially ahead of the initial target of being below 2x. A combination of scheduled and voluntary early repayments of the Group's senior credit facility, including a $35.0 million payment in January 2020, has seen the outstanding balance reduce to $425.0 million with no further amortisations due in 2020.
At the year end, the Group recognised non-cash post-tax impairments of $562.3 million, including tangible fixed assets of $397.5 million, mainly reflecting changes in oil price and production profiles, primarily at Heather/Broom, Thistle and the Dons, and $149.6 million impairment of goodwill.
Health, Safety, Environment and Assurance ('HSEA')
As always, SAFE Results is our number one priority. Across the Group, good progress was made with the leading metrics in areas such as safety-critical maintenance backlog, leadership site visits and close out of actions from incidents and audits, demonstrating our commitment to be proactive with regard to HSEA. In both Malaysia and the UK, positive
feedback from the respective regulators was received regarding the levels of transparency and trust that have been generated.
However, in occupational safety, our Lost Time Incident ('LTI') performance was mixed. During the year, our teams at Kittiwake and PM8/Seligi recorded 14 and nine years LTI free, respectively, while our Thistle and Northern Producer assets in the UK North Sea and the Tanjong Baram asset in Malaysia all recorded an LTI-free year. These are great achievements considering the ongoing backdrop of high activity levels and the age of our assets. Our team at Thistle demonstrated EnQuest's proactive approach to safety when they decided to shut down and down-man the platform following the results of a routine inspection programme. However, there was an increase in the number of minor injuries in the UK and there was a high-potential incident associated with the KT03 compressor lube oil system at Heather. Such issues highlight the need for everyone to remain focused at all times on delivering SAFE Results. We continue to learn from these events through extensive root cause analysis and the subsequent development and sharing of any required improvements across EnQuest's assets in an effort to limit the chance of reoccurrence.
While there were no major hydrocarbon releases in Malaysia, a significant improvement on hydrocarbon loss of
containment events from 2018, reportable hydrocarbon releases across the Group's UK operated assets increased to 11 from six in 2018. During 2019, the UK team published its environmental compliance manual which, along with training and awareness sessions, has been designed to inform the workforce of our environmental responsibilities and help to improve environmental performance.
The Company's place within the wider energy transition is to improve performance and efficiencies at already producing assets through short-cycle investments, avoiding the need for costly, carbon intensive and long-dated new
developments. As part of this efficiency drive, the Group recognises that it must endeavour to minimise carbon emissions from its operations as far as practicable and play its part in the UK's legal requirement to be net carbon neutral by 2050. With its low-sulphur content, demand for Kraken oil increased through 2019 and into 2020 as buyers in the maritime industry recognised it is playing a valuable part in reducing sulphur emissions in accordance with the International
Maritime Organisation's new regulations that limit the sulphur content of bunker fuel. By selling directly to the fuel oil market, Kraken cargoes also avoid refining-related emissions. In 2020, a systematic programme of work is being undertaken to put in place plans that will include specific, measurable emissions reduction targets, supported by specific projects, which will form the basis of our 2021 corporate targets.
UK North Sea operations
Magnus continued to perform strongly throughout 2019, achieving production efficiency of 81%, driven by enhanced reservoir management, well interventions and plant debottlenecking. During the year, the Group also further improved the facility's water handling capabilities, a key enabler to the field's revised reservoir management strategy, which itself has driven a material reduction in operating costs. In the first quarter of 2020, new production wells on Magnus were completed and came onstream, with further production optimisation activities underway.
Safety-related shutdowns in the fourth quarter at Heather and Thistle impacted performance. While shutdown for repairs, there was a small fire in one of the compressor modules at Heather that was quickly extinguished. At Thistle, the team initiated a precautionary shutdown and down-man following the identification of a deterioration in a metal plate
connecting a redundant storage tank to the platform's leg. The Group no longer expects to restart production at either of Heather or Thistle, with extensive analysis of the costs and risks of remediation and restarting production outweighing the economic benefits of doing so.
At Kraken, performance of the FPSO vessel significantly improved through the year as a result of targeted improvement initiatives, focusing on the main power engines, topside power water pumps and the hydraulic submersible pumps, combined with changes to the offshore spares management and FPSO maintenance processes. The completion of the drill centre ('DC') 4 drilling programme in March marked the end of the field's original development plan. Overall
subsurface and wells performance has remained strong, with water cut levels stable and below the Group's assumptions that underpinned the year-end 2018 2P reserves estimates, providing increased confidence in long-term production. In May 2019, the Group sanctioned the Worcester development in Kraken's western area, where drilling of a
producer-injector pair through spare capacity in the existing DC2 sub-sea infrastructure began in the first quarter of 2020. Further areas in the western area, including the Maureen sands which lie directly beneath the existing reservoirs, are being evaluated to identify economic, drillable targets to develop its estimated 70 to 130 MMbbls of STOIIP.
During the year, our projects teams delivered an excellent performance in our two sub-sea pipeline replacement projects at Scolty/Crathes and at the Dunlin bypass in respect of Thistle and the Dons, with both being completed ahead of budget and schedule. Thistle production was transferred to the new export route at the end of June without incurring any
production downtime, while production at Scolty/Crathes restarted in September.
While production efficiency at Alma/Galia remained high at over 95% throughout the year, natural declines meant
production was lower than in 2018. The decommissioning programme has recently been finalised, with the Group
expecting production to cease in the second half of 2020.
At the Sullom Voe Terminal, the Group achieved high plant availability and delivered safe and stable operations during the year. In July, the Group announced essential organisational changes to the terminal to ensure that it remains
competitive for existing and future business. Many of these changes were implemented in early 2020.
Production in 2019 was slightly higher than in 2018, primarily reflecting high production efficiency of 92% at PM8/Seligi and better than expected performance from the Group's idle well restoration programme. The Group successfully
completed the 2019 compressor maintenance programme and systematic and wide-scale asset inspection and
maintenance campaign during the fourth quarter.
In December, the Group was awarded the Block PM409 Production Sharing Contract ('PSC') offshore Malaysia. The block is in a proven hydrocarbon area containing several undeveloped discoveries and is contiguous to the Group's existing PM8/Seligi PSC, providing low-cost tie-back opportunities to the Group's existing Seligi main production hub.
The Group will continue to execute its idle well restoration activities during 2020. It will also continue to assess the development potential of the large number of low-cost drilling and workover targets that have been identified at PM8/Seligi and identify suitable drilling and tie-back opportunities within Block PM409.
2020 performance and outlook
We have been monitoring the evolving situation with regards to the spread of COVID-19 and been working with a variety of stakeholders, including industry and medical organisations, to ensure its operational response and advice to its
workforce is appropriate and commensurate with the prevailing expert advice and level of risk. We have implemented a number of actions to keep our people safe and maintain safe operations, such as offshore travel restrictions,
non-essential workforce down-manning and access to specialised evacuation transport for our operated assets.
Given the prevailing low oil price environment, the Group has reviewed each of its assets and related spending plans. EnQuest's no longer plans to re-start production at the Heather and Thistle/Deveron fields. At the same time, the Group is taking decisive action and implementing a material operating cost and capital expenditure reduction programme to significantly lower EnQuest's cost base, with Group free cash flow breakeven targeted at c.$33/Boe in 2020 and c.$27/Boe in 2021.
As a result of the field shutdowns outlined above, full year production is expected to be in the range of 57,000 to 63,000 Boepd. Kraken gross production remains unchanged at 30,000 to 35,000 Bopd. The two-well drilling programme in Kraken's western area is underway and expected to contribute production in the second half of the year, partially
offsetting the impacts of the planned maintenance shutdown and natural declines. As previously announced, the Group's current expectation is for economic production at Alma/Galia to cease in the second half of 2020.
For 2020, the Group is targeting base operating expenditure savings of c.$190 million, which would lower operating costs by c.35% to c.$335 million and unit operating expense to c.$15/Boe. In 2021, the Group is targeting unit operating expenditures of c.$12/Boe. These savings are driven primarily by cost savings at Heather and Thistle/Deveron, but also through the removal of non-critical and discretionary operating expenditures and support costs.
2020 cash capital expenditure is also expected to be reduced by c.$110 million to c.$120 million. The majority of the Group's 2020 programme relates to the recently concluded drilling programme at Magnus and the two-well programme now underway at Kraken, with approximately $50 million of 2020 cash capital expenditure relating to the phasing of cash payments into 2020. The Group's 2021 capital expenditure programme is expected to reduce further, which will also impact production.
While no further repayments of the Group's senior credit facility are due in 2020, further debt repayment remains the financial priority for the Group.
Lowering the Group's cost base now will enable our experienced and capable teams to utilise our proven differential capabilities to develop EnQuest's material opportunity set to deliver future value to its stakeholders. We will continue to reduce our debt and dependent on price conditions and Company performance, our capital allocation will balance
investment to develop our asset base, returns to shareholders and the acquisition of suitable growth opportunities, which will be aligned with our proven differential capabilities in managing maturing and underdeveloped hydrocarbon assets.
NORTHERN NORTH SEA OPERATIONS
2019 performance summary
Production in 2019 of 27,237 Boepd was 41.2% higher than in 2018, reflecting additional equity interest in, and a
continued strong performance from, Magnus, partially offset by safety-related shutdowns at Heather and Thistle and natural declines across the Northern North Sea area assets.
Magnus has continued to perform strongly throughout 2019, achieving production efficiency of 81%, driven by enhanced reservoir management, well interventions and plant debottlenecking. During the year, the Group further improved the facility's water handling capabilities through the return to service of a second deaeration tower and successfully
completed a planned three-week shutdown of the facility to undertake safety-critical maintenance. The planned two-well drilling programme commenced during the fourth quarter and continued through the end of the year and into 2020.
Single compressor train outages and an extended shutdown impacted production at Heather during the year. In October, while shut down to undertake repair work on the compressors, the facility suffered a small fire in one of the compressor modules which was extinguished quickly. With safety being a top priority for the Company, the facility remained shut down while Company and regulatory investigations into the incident were undertaken and necessary repairs fully
On Thistle, production and water injection efficiency averaged over 90% during the first half of the year and the drilling team successfully executed the well abandonment programme in line with the Group's asset strategy. However, in
October production stopped following a proactive safety-related shutdown as a result of a deterioration in the condition of a metal plate connecting one of the redundant sub-sea storage tanks to the facility's legs being identified during the ongoing sub-sea monitoring and inspection programme. The Group had already planned to remove the tanks on behalf of the decommissioning partners during the summer of 2020, with initial tendering having started earlier in 2019. This programme was accelerated, with contracts for the sub-sea and heavy lift operations awarded in late 2019.
At the Dons fields, production was slightly below the Group's expectations reflecting lower than expected water injection efficiency as a result of water injection pump failures and gas lift interruptions.
The Dunlin bypass project was successfully completed in June, 18 days ahead of schedule, with final commissioning work undertaken during the Dons planned annual maintenance shutdown. Modifications on the Thistle, Northern
Producer and Magnus facilities were also completed on schedule, with Thistle production being transferred to the new export route without incurring any production downtime.
At the Sullom Voe Terminal ('SVT'), the Group has achieved high plant availability and delivered safe and stable
operations during the year. The Oil & Gas Authority endorsed the revised SVT Owner's strategy to extend the life of the facility in support of maximising economic recovery for the 33 offshore fields that currently export crude oil through the terminal. In July, the Group announced essential organisational changes to the terminal to ensure that it remains
competitive for existing and future business. These changes form an essential part of SVT's future and as a direct consequence of EnQuest's demonstrable progress in safely reducing SVT's underlying cost basis, there are now a number of ongoing enquiries for the provision of additional services from the terminal.
2020 performance and outlook
In the first quarter of 2020, new production wells on Magnus were completed and brought onstream. During the year, the test separator will be enhanced, which will enable more robust testing and improved optimisation. Chemical trials will also be conducted to investigate methods to reduce well slugging and increase oil flow. A two-week maintenance shutdown on Magnus is planned during the third quarter.
In the medium term, the Group has substantial 2C resources of 38 MMboe to develop, primarily through low-cost drilling. In addition, the Group will continue to evaluate the estimated c.250 MMbbls of additional remaining mobile oil in place to identify future drilling targets to maximise recovery from this field.
At Thistle, the Group no longer expects to restart production. Adverse weather conditions have restricted progress on the tank removal project, although where possible, sub-sea and platform surveys to assess the condition of the tanks, their connection to the facilities legs and the condition of the topsides to assist project planning have been undertaken. The tank removal project will continue, with further platform remediation activity also required, although timing of these activities remains subject to weather and detailed execution plans.
In February, having carefully reviewed all options, EnQuest decided not to restart production from the Heather field and intends to seek the necessary regulatory approvals from the UK Oil & Gas Authority in respect of cessation of production. This decision was taken following extensive analysis, which clearly demonstrated the costs and risks of remediation and resuming production outweighed the economic benefits of doing so.
Following remediation of the water injection efficiency and gas lift repair issues experienced during 2019, the Dons fields have ramped up during the first quarter of 2020. A three-week maintenance shutdown is planned during the third quarter.
CENTRAL NORTH SEA OPERATIONS
2019 performance summary
Production in 2019 of 7,544 Boepd was 18.8% higher than in 2018, driven by increased volumes from Scolty/Crathes following the successful completion of the pipeline replacement project in September. This project, which was delivered during the third quarter planned maintenance shutdown, was completed ahead of budget and schedule. Production restarted in early September, initially with production from the Crathes well. After Crathes declined as expected, the well was temporarily shut in to allow production to begin from Scolty. From December, both the Scolty and Crathes wells have been online and performing strongly, supported by optimisation activities.
On the Greater Kittiwake Area, high levels of production and water injection efficiency of 95% have delivered a strong production performance in 2019, partially mitigating the impact of natural declines. The team has delivered another solid HSEA performance, reaching 14 years without a LTI.
At Alma/Galia, average production in 2019 was 1,900 Boepd, a decrease of 8.1% compared to 2018, reflecting the natural decline of the field. Production efficiency at Alma/Galia remained high at over 95% during the year, while preparatory decommissioning programmes commenced.
Output from Alba during the year has been in line with expectations.
2020 performance and outlook
Performance to the end of February has been good. Production continues to decline at Alma/Galia, where the Group's focus remains on production optimisation and cost reduction. Decommissioning is expected to commence following cessation of production, currently forecast to be in the second half of 2020 with the FPSO vessel moving off-station thereafter.
At both Scolty/Crathes and the Greater Kittiwake Area, a four-week shutdown is planned for the summer, as required by the outage at the Forties Production System oil export route.
A two-day shutdown is planned at Alba during the third quarter.
THE KRAKEN DEVELOPMENT
2019 performance summary
Average gross production was 35,704 Bopd, above the top end of the Group's 2019 guidance range of 30,000 to 35,000 Bopd and 17.8% higher than 2018. Performance at the FPSO vessel has significantly improved through the year. This follows a programme of targeted improvement initiatives, focusing on the main power engines, topside power water pumps and the hydraulic submersible pumps, combined with changes to the offshore spares management and FPSO maintenance processes. Over the summer, pipework repairs on the FPSO required short unplanned production
shutdowns, however production efficiency quickly returned to high levels, averaging more than 95% in the fourth quarter, compared to around 58% in the first quarter of 2019.
In March, the Group completed the DC4 drilling programme which marked the conclusion of the original Kraken field development plan. Overall subsurface and well performance remains strong and the Group continues to optimise
production through improved injector-producer well management. The aggregate field water cut has remained stable and has evolved on a lower trajectory than was anticipated in the year end 2018 2P reserves estimates, providing
increased confidence in long-term production. In May, the Group sanctioned the drilling programme at Worcester within the western area, commencing the next phase of the Kraken development. A rig contract was placed to drill the
producer-injector pair through spare capacity in the existing DC2 sub-sea infrastructure.
Between first production and the end of 2019, more than 26 million barrels of oil had been produced and 52 cargoes offloaded from the FPSO, with 25 of these cargoes offloaded in the year. Pricing was robust, with some cargoes
achieving premiums to Brent.
2020 performance and outlook
Production and cargo pricing remained strong in the first two months of the year. The Group continues to sell Kraken cargoes directly to the shipping market, as a key component of IMO 2020 compliant low-sulphur fuel oil.
The Group has commenced the two-well drilling programme at Worcester in the western area. In total, the western area provides a near-field, economic, development opportunity, with between 70 and 130 MMbbls of STOIIP. The Pembroke, Antrim and Barra areas continue to be evaluated and the Group is also reviewing the potential for developing the Maureen sands, which lie directly beneath the existing reservoir.
2019 performance summary
Average production in Malaysia during the year was 8,653 Boepd, which was 2.6% higher than in 2018, driven by high production efficiency of 92% at PM8/Seligi and better than expected performance from the Group's idle well restoration programme. The idle well restoration programme commenced ahead of schedule and resulted in 11 wells restored to production, helping mitigate underlying natural decline. In September, the Group completed its two-well drilling
programme, with one well online.
A structured compressor maintenance and repair programme resulted in significantly improved compressor uptime
performance during the fourth quarter, supporting enhanced gas reinjection and oil production. The systematic and
wide-scale asset inspection and maintenance campaign to help ensure long-term facilities integrity was successfully concluded in the fourth quarter.
Production at Tanjong Baram decreased materially in the period, reflecting natural decline and the inability of well A2 to naturally flow. Under the terms of the Small Field Risk Service Contract ('SFRSC'), following two consecutive quarters of allocated revenue being below operating expenditures, the field is deemed uneconomic and EnQuest has the right to issue a contract termination notice. In December, this notice was issued to PETRONAS and the SFRSC was terminated on 3 March 2020. As a result, EnQuest will receive the outstanding capital expenditure of around $50 million over a period of three quarters, with the first repayment due in June 2020.
In December, the Group was awarded the Block PM409 Production Sharing Contract ('PSC') offshore Malaysia. Under the terms of the PSC, EnQuest will operate the block with a participating interest of 85.0%, with PETRONAS Carigali Sdn Bhd owning the remaining 15.0%. Block PM409 measures approximately 1,700 km2 and is located offshore
Peninsular Malaysia in water depths of 70 to 100 metres. The block is in a proven hydrocarbon area containing several undeveloped discoveries and is contiguous to the Group's existing PM8/Seligi PSC, providing low-cost tie-back
opportunities to the Group's existing Seligi main production hub. Within the initial four-year exploration term of the PSC, the partners are committed to the drilling of one well.
2020 performance and outlook
Aggregate production has been in line with the Group's expectations for the first two months of 2020, with the Tanjong Baram SFRSC terminating in March.
A planned shutdown of the PM8/Seligi facilities is anticipated in Q3 2020, with a similar duration to 2019.
At PM8/Seligi, further investment in idle well restoration and facility improvements will continue throughout the year.
EnQuest has c.22 MMboe of 2P reserves and c.76 MMboe of 2C resources in Malaysia. A large number of low-cost drilling and workover targets have been identified at PM8/Seligi, with multi-well drilling programmes being assessed for future development. At PM409, the Group will undertake subsurface studies to assess the existing discovered resources to identify suitable drilling and sub-sea tie-back opportunities for future development.
All figures quoted are in US Dollars and relate to Business performance unless otherwise stated.
The Group delivered on its operational and financial targets for 2019, growing production by 24% and lowering unit operating expenditure to $20.6/Boe. The material increase in EBITDA and free cash flow facilitated accelerated repayments of the Group's credit facility, to strengthen the balance sheet further. The Group's year-end net debt to EBITDA ratio was 1.4x, significantly ahead of the original target of below 2.0x. The Group has now repaid the entire 2020 senior credit facility amortisation early, following the voluntary repayment of $35 million in January 2020.
Production on a working interest basis increased by 23.7% to 68,606 Boepd, compared to 55,447 Boepd in 2018.
This increase reflected a significant improvement in performance at the FPSO vessel at Kraken, increased volumes from Scolty/Crathes following the successful completion of the pipeline replacement, high production efficiency at PM8/Seligi and a full year's contribution at 100% equity interest at Magnus. These increases were partially offset by shutdowns at Heather and Thistle, lower than expected production and water injection efficiency at the Dons and natural declines across other assets.
Revenue for 2019 was $1,711.8 million, 42.5% higher than in 2018 ($1,201.0 million) reflecting the increase in production, the onward sale of third-party gas purchases not required for injection activities at Magnus, and the favourable impact of the Group's commodity hedge programme, partially offset by lower market prices. The Group's commodity hedge programme resulted in realised gains of $24.8 million in 2019 (2018: losses of $93.0 million).
The Group's operating expenditures of $518.1 million were 11.2% higher than in 2018 ($465.9 million), reflecting the full year of additional equity interest in Magnus. Unit operating costs decreased by 10.4% to $20.6/Boe (2018: $23.0/Boe) as a result of increased production.
Other cost of sales of $97.5 million were higher than in 2018 ($48.1 million), principally reflecting the cost of additional Magnus related third-party gas purchases not required for injection activities of $72.0 million.
EBITDA for 2019 was $1,006.5 million, up 40.5% compared to 2018 ($716.3 million), primarily as a result of increased revenue.
|2019$ million||2018$ million|
|Profit from operations before tax and finance income/(costs)||442.1||290.0|
|Depletion and depreciation||533.4||442.4|
|Change in well inventories||14.6||5.8|
|Net foreign exchange (gain)/loss||16.4||(21.9)|
EnQuest's net debt decreased by $361.5 million to $1,413.0 million at 31 December 2019 (31 December 2018: $1,774.5 million). This includes $133.3 million of interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016 refinancing ('Payable in Kind' or 'PIK') (31 December 2018: $132.0 million) (see note 18 for further details).
|31 December 2019$ million||31 December 2018$ million|
|Multi-currency revolving credit facility ('RCF')||475.1||799.4|
|Sculptor Capital facility2||122.9||178.5|
|Tanjong Baram Project Finance Facility||31.7||31.7|
|Mercuria Prepayment Facility||-||22.2|
|SVT Working Capital Facility||31.9||15.7|
|Cash and cash equivalents||(220.5)||(240.6)|
1 See reconciliation of net debt within the 'Glossary - Non-GAAP measures' starting on page 69
2 Sculptor Capital facility was previously known as the Oz Management facility
During the year, the Group's improved cash generation enabled repayments of $325.0 million relating to the RCF, more than the scheduled amortisation requirement. In January 2020, EnQuest voluntarily repaid an additional $35.0 million early, with the Group having now repaid the entire senior credit facility amortisation due in 2020. Strong performance at Kraken drove repayments of the Sculptor Capital facility, totalling $55.6 million in the period. Following the termination of the Tanjong Baram Small Field Risk Service Contract on 3 March 2020, the Group anticipates repaying the Tanjong Baram Project Finance Facility during 2020.
UK corporate tax losses at the end of the year reduced to $2,903.4 million (2018: $3,225.3 million). The Group generated taxable profits on increased production which were offset against existing tax losses. In the current environment, no significant corporation tax or supplementary charge is expected to be paid on UK operational activities for the foreseeable future. The Group paid cash corporate income tax on the Malaysian assets which will continue throughout the life of the Production Sharing Contract.
On average, market prices for crude oil in 2019 were lower than in 2018. The Group's average realised oil price excluding the impact of hedging was $64.2/bbl, 7.5% lower than in 2018 ($69.4/bbl). Revenue is predominantly derived from crude oil sales which totalled $1,548.2 million, 25.1% higher than in 2018 ($1,237.6 million), reflecting the increase in volumes. Revenue from the sale of condensate and gas was $120.2 million (2018: $43.1 million), as a result of gas sales from Magnus, which includes the combination of produced gas sales and the onward sale of
third-party gas purchases not required for injection activities, for which the costs are included in other cost of sales. Tariffs and other income generated $18.7 million (2018: $13.4 million). The Group's commodity hedges and other oil derivatives generated $24.8 million of realised gains (2018: losses of $93.0 million), including gains of $4.9 million of non-cash amortisation of option premiums (2018: losses of $17.2 million) as a result of the timing at which the hedges were entered into and the decrease in market prices. The Group's average realised oil price including the impact of hedging was $65.3/bbl in 2019, 1.7% higher than 2018 ($64.2/bbl).
Note: For the reconciliation of realised oil prices see 'Glossary - Non-GAAP measures' starting on page 69
Cost of sales1
|2019$ million||2018$ million|
|Tariff and transportation expenses||74.8||68.4|
|Realised (gain)/loss on derivatives related to operating costs||1.7||0.6|
|(Credit)/charge relating to the Group's lifting position and inventory||102.9||(25.1)|
|Depletion of oil and gas assets||525.1||437.1|
|Other cost of sales||97.5||48.1|
|Cost of sales||1,243.6||926.0|
|Operating cost per barrel2||$/Boe||$/Boe|
|- Production costs||17.6||19.6|
|- Tariff and transportation expenses||3.0||3.4|
|Average unit operating cost||20.6||23.0|
1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 69
2 Calculated on a working interest basis
Cost of sales were $1,243.6 million for the year ended 31 December 2019, 34.3% higher than in 2018 ($926.0 million).
Operating costs increased by $52.2 million, reflecting a full year of 100% equity interest in Magnus. The Group's average unit operating cost decreased by 10.4% to $20.6/Boe as a result of increased production.
The charge relating to the Group's lifting position and inventory was $102.9 million (2018: $25.1 million gain). This reflects a switch to a $28.6 million net overlift position at 31 December 2019 from a $68.3 million net underlift position at 31 December 2018. This switch reflected the closing positions on Thistle and Heather and the unwind of underlift on Magnus in the year.
Depletion expense of $525.1 million was 20.1% higher than in 2018 ($437.1 million), mainly reflecting a full year of 100% equity interest in Magnus.
Other cost of sales of $97.5 million were higher than in 2018 ($48.1 million), principally reflecting the cost of additional Magnus-related third-party gas purchases not required for injection activities of $72.0 million.
Other income and expenses
Net other expenses of $18.4 million (2018: net other income of $19.1 million) primarily comprises net foreign exchange losses, which relate to the revaluation of Sterling-denominated amounts in the balance sheet following the strengthening of Sterling against the Dollar.
Finance costs of $206.6 million were 12.5% lower than in 2018 ($236.1 million). The decrease was primarily driven by a reduction of $27.3 million in bond and loan interest charges (2019: $130.4 million; 2018: $157.7 million). Other finance costs included lease liability interest of $55.7 million (2018: $55.8 million), $14.1 million on unwinding of discount on decommissioning provisions and other liabilities (2018: $14.0 million), $5.7 million amortisation of arrangement fees for financing facilities and bonds (2018: $8.5 million) and other financial expenses of $2.1 million (2018: $1.7 million), primarily the cost for surety bonds principally to provide security for decommissioning liabilities.
The tax charge for 2019 of $23.6 million (2018: $20.9 million tax credit), excluding exceptional items, is mainly due to Malaysian tax and the utilisation of UK losses offset by RFES generated in the year.
Remeasurement and exceptional items
Revenue included unrealised losses of $65.4 million in respect of the mark-to-market movement on the Group's commodity contracts (2018: unrealised gains of $97.4 million).
Non-cash impairment charges of: $637.5 million (2018: $126.0 million) on the Group's tangible oil and gas assets arises from a reduction in the long-term oil price, revisions to production profiles in Heather/Broom, Thistle/Deveron and the Dons fields, and the anticipated cessation of production at Alma/Galia;$149.6 million (2018: $nil) on the Group's goodwill; and $25.4 million (2018: $0.4 million) on the Group's intangible oil and gas assets reflecting the write-off of historical exploration and appraisal expenditures.
Other income and expense included a $15.5 million expense in relation to the fair value recalculation of the Magnus contingent consideration reflecting the improved performance and outlook at the asset, and $15.6 million in relation to the KUFPEC settlement agreement. Other finance costs mainly relates to the unwinding of contingent consideration from the acquisition of Magnus and associated infrastructure of $57.2 million.
A tax credit of $303.5 million (2018: $12.4 million) has been presented as exceptional, representing the tax impact of the above items.
Earnings per share
The Group's Business performance basic profit per share was 13.1 cents (2018: 5.7 cents) and diluted profit per share was 13.0 cents (2018: 5.5 cents).
The Group's reported basic loss per share was 27.4 cents (2018 profit per share: 9.2 cents) and reported diluted loss per share was 27.4 cents (2018 profit per share: 9.0 cents).
Cash flow and liquidity
Net debt at 31 December 2019 amounted to $1,413.0 million, including PIK of $133.3 million, compared with net debt of $1,774.5 million at 31 December 2018, including PIK of $132.0 million. The Group has remained in compliance with financial covenants under its debt facilities throughout the year. The movement in net debt was as follows:
|Net debt 1 January 2019||(1,774.5)|
|Operating cash flows||962.3|
|Cash capital expenditure||(237.5)|
|Net interest and finance costs paid||(147.0)|
|Finance lease payments||(135.1)|
|Repayments on Magnus financing and profit share||(74.2)|
|Non-cash capitalisation of interest||(5.2)|
|Other movements, primarily net foreign exchange on cash and debt||(1.8)|
|Net debt 31 December 20191||(1,413.0)|
1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 69
The Group's reported operating cash flows for the year ended 31 December 2019 were $962.3 million, up 21.1% compared to 2018 ($794.4 million). The main drivers for this increase were the increase in volumes and a gain on realised hedging at year end.
Cash outflow on capital expenditure is set out in the table below:
31 December 2019$ million
31 December 2018$ million
|Exploration and evaluation||0.1||0.5|
Cash capital expenditure primarily relates to the Kraken DC4 programme, pipeline projects, licence to operate capital expenditure and agreed deferrals brought into 2019.
The Group's total asset value has decreased by $885.3 million to $4,776.6 million at 31 December 2019 (2018: $5,661.9 million), mainly due to the impairment charge on the Group's tangible and intangible oil and gas assets and depletion of oil and gas assets offset by the recognition of the IFRS 16 Leases right-of-use assets. Net current liabilities have decreased to $282.7 million as at 31 December 2019 (2018: $301.2 million). Included in the Group's net current liabilities are $178.7 million of estimated future obligations where settlement is subject to the financial performance at Kraken and Magnus (2018: $134.8 million).
Property, plant and equipment ('PP&E')
PP&E has decreased by $899.0 million to $3,450.9 million at 31 December 2019 from $4,349.9 million at 31 December 2018 (see note 10). This decrease encompasses the capital additions to PP&E of $177.4 million, initial recognition of new right-of-use assets under IFRS 16 Leases of $60.5 million, a net increase of $34.2 million for changes in estimates for decommissioning and other provisions, offset by non-cash impairments of $637.5 million and depletion and depreciation charges of $533.4 million.
The PP&E capital additions during the period, including capitalised interest, are set out in the table below:
|Northern North Sea||63.9|
|Central North Sea||68.7|
Goodwill decreased due to non-cash impairment of $149.6 million, mainly reflecting the impairment of assets relating to PP&E.
Intangible oil and gas assets
Intangible oil and gas assets decreased by $24.2 million to $27.6 million at 31 December 2019 (31 December 2018: $51.8 million), mainly reflecting the write-off of historical exploration and appraisal expenditures.
Trade and other receivables
Trade and other receivables increased by $3.7 million to $279.5 million at 31 December 2019 compared with $275.8 million at 31 December 2018.
Cash and net debt
The Group had $220.5 million of cash and cash equivalents at 31 December 2019 and $1,413.0 million of net debt, including PIK and capitalised interest of $140.7 million (2018: $240.6 million, $1,774.5 million and $135.5 million, respectively).
Net debt comprises the following liabilities:
·$225.7 million principal outstanding on the £155.0 million retail bond, including interest capitalised as PIK of $22.1 million (2018: $218.9 million and $21.5 million, respectively);
·$746.1 million principal outstanding on the high yield bond, including interest capitalised as PIK of $96.1 million (2018: $746.1 million and $96.1 million, respectively);
·$475.1 million of credit facility, comprising amounts drawn down of $460.0 million and interest capitalised as PIK of $15.1 million (2018: $799.4 million, $785.0 million and $14.4 million, respectively);
·$122.9 million on the Sculptor Capital facility, comprising amounts drawn down of $115.5 million and capitalised interest of $7.4 million (2018: $178.5 million, $175.0 million and $3.5 million, respectively);
·$31.9 million relating to the SVT Working Capital Facility (2018: $15.7 million);
·$31.7 million relating to the Tanjong Baram Project Finance Facility (2018: $31.7 million); and
·In 2018, $22.2 million relating to the Mercuria Prepayment Facility and $2.5 million outstanding from a trade creditor loan.
The Group's decommissioning provision increased by $40.2 million to $711.9 million at 31 December 2019 (2018: $671.7 million). The movement is due to an increase in changes in estimates of $37.9 million and $13.4 million unwinding of discount, partially offset by utilisation of $11.1 million for decommissioning carried out in the period. During 2019, the Group commissioned Wood Group PSN to estimate the costs involved in decommissioning each operated field. The estimates were reviewed by operations personnel and adjustments were made where necessary to reflect management's view of the estimates.
Other provisions increased by $11.1 million in 2019 to $51.1 million (2018: $40.0 million). Other provisions includes EnQuest's obligation to make payments to BP by reference to 7.5% of BP's decommissioning costs of the Thistle and Deveron fields and the KUFPEC settlement agreement.
The contingent consideration related to the Magnus acquisition increased by $3.2 million. In 2019, EnQuest repaid $88.4 million to BP, including repaying the remaining $34.8 million in the year associated with the initial 25% interest vendor loan, with the remainder reflecting the partial repayment of the 75% interest vendor loan and interest, and BP's entitlement to share in the cash flows from the 75% interest. A change in fair value estimate charge of $15.5 million and an unwinding of discount of $57.2 million was recognised in the year.
The Group had an income tax liability of $4.1 million (2018: $15.3 million) related to corporate income tax on Malaysian assets.
The Group's net deferred tax asset has increased from $258.9 million at 31 December 2018 to $555.1 million at 31 December 2019. The increase primarily relates to the combined tax impact from each of the impairment of the Group's oil and gas assets, the Group's hedging activities and the Magnus acquisition contingent consideration. Total UK tax losses carried forward at the year end amounted to $2,903.4 million (2018: $3,225.3 million).
Trade and other payables
Trade and other payables of $419.9 million at 31 December 2019 are $82.1 million lower than at 31 December 2018 ($502.0 million). The full balance of $419.9 million is payable within one year (2018: $483.8 million within one year and $18.2 million after more than one year). The decrease in current payables mainly reflects other working capital movements and the change in VAT position.
As at 31 December 2019, the Group held a lease liability of $716.2 million. Six additional leases with a combined liability of $60.5 million were recognised on transition to IFRS 16 on 1 January 2019. The main lease continues to relate to the Kraken FPSO, with a liability of $635.0 million at 31 December 2019 and undiscounted contractual cash flows of $115.5 million payable within one year.
Financial risk management
The Group is exposed to the impact of changes in both Brent crude oil price and gas prices on its revenue and profits. EnQuest's policy is to manage the impact of commodity prices to protect against volatility and allow availability of cash flow for repayment of debt and investment in capital programmes.
During the year ended 31 December 2019, commodity derivatives generated a total loss of $40.6 million; (realised gains of $24.8 million and unrealised losses of $65.4 million) mostly in respect of the mark-to-market of swaps and calls, and the amortisation of premiums on calls.
EnQuest's functional currency is US Dollars. Foreign currency risk arises on purchases and the translation of assets and liabilities denominated in currencies other than US Dollars. To mitigate the risks of large fluctuations in the currency markets, the hedging policy agreed by the Board allows for up to 70% of the non-US Dollar portion of the Group's annual capital budget and operating expenditure to be hedged. For specific contracted capital expenditure projects, up to 100% can be hedged.
EnQuest continually reviews its currency exposures and, when appropriate, looks at opportunities to enter into foreign exchange hedging contracts. During the year ended 31 December 2019, losses totalling $1.0 million (2018: losses of $0.4 million) were recognised in the income statement. This included losses totalling $2.7 million realised on contracts maturing during the year (2018: $0.6 million).
Surplus cash balances are deposited as cash collateral against in-place letters of credit as a way of reducing interest costs. Otherwise, cash balances can be invested in short-term bank deposits and AAA-rated liquidity funds, subject to Board-approved limits and with a view to minimising counterparty credit risks.
Going concern disclosure
The Group closely monitors and manages its funding position and liquidity risk throughout the year, including monitoring forecast covenant results, to ensure that it has access to sufficient funds to meet forecast cash requirements. Cash forecasts are regularly produced and sensitivities considered for, but not limited to, changes in crude oil prices (adjusted for hedging undertaken by the Group), production rates and costs. These forecasts and sensitivity analyses allow management to mitigate liquidity or covenant compliance risks in a timely manner. Management has also repaid the term loan on or ahead of schedule, with no further scheduled payments now due in 2020.
The Group is actively monitoring the impact on operations from COVID-19 and has implemented a number of mitigations to minimise the impact. The Group has been working with a variety of stakeholders, including industry and medical organisations, to ensure its operational response and advice to its workforce is appropriate and commensurate with the prevailing expert advice and level of risk. Appropriate restrictions on offshore travel have been implemented, such as self-declaration by, and isolation of, individuals who have been to affected areas and pre-mobilisation temperature checking is in operation. EnQuest's normal communicable disease process has been updated specifically in respect of COVID-19, with additional offshore isolation capability and agreements in place to transport impacted individuals back onshore in dedicated helicopters. Non-essential down-manning has been implemented, with many of the Group's onshore workforce working remotely.
While it is difficult to forecast the impact of COVID-19, at the time of publication of EnQuest's full year results, the Group's day-to-day operations continue without being materially affected.
The Group has reviewed each of its assets and related spending plans in light of the current lower oil price environment. EnQuest's updated working assumption is not to re-start production at the Heather and Thistle/Deveron fields. At the same time, the Group is implementing a material operating cost and capital expenditure reduction programme. This significantly lowers EnQuest's cost base and successful delivery of this programme is assumed in the Base case.
The Base case uses an oil price assumption of $40/bbl from March 2020 through to the end of the first quarter 2021, based on recent research analyst projections for the period. This has been sensitised under a plausible downside case ('Downside case'). The Base case and Downside case indicate that the Company is covenant compliant and able to operate within the headroom of its existing borrowing facilities for 12 months from the date of approval of the Annual Report and Accounts. Given the extreme volatility in current oil prices, the Directors have also performed reverse stress testing with the breakeven price for liquidity being c. $10/bbl.
The quarterly liquidity covenant in the facility (the "Liquidity Test") requires that the Group has sufficient funds available to meet all liabilities of the Group when due and payable for the period commencing on each quarter and ending on the date falling 12 months after the final maturity date which is 1 October 2021. The Liquidity Test assumptions include a price deck of the average forward curve oil price, minus a 10% discount, of 15 consecutive business days starting from approximately in the middle of the previous quarter. The Base case uses $45/bbl for the remainder of 2021, with a longer-term price assumption of $60/bbl. Under these prices the Group forecasts no breaches in the Liquidity Test. Applying the 10% discount stipulated in the Liquidity Test and a further reduction in excess of 15% on Base case prices across all periods, the Group would breach this covenant, prior to any mitigations such as further cost reductions or other funding options. Given the extreme volatility in current oil prices, there is a risk of a potential covenant breach, which would therefore require a covenant waiver to be obtained. The Directors are confident that obtaining waivers from the facility providers would be forthcoming. However, the risk of not obtaining a waiver represents a material uncertainty that may cast doubt upon the Group's ability to continue to apply the going concern basis of accounting.
Notwithstanding the material uncertainty described above, after making enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group will continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors continue to adopt the going concern basis in preparing the financial statements.
The Directors have assessed the viability of the Group over a three-year period to March 2023. This assessment has taken into account the Group's financial position as at March 2020, forecasts that reflect the current market volatility and the Group's principal risks and uncertainties. The Directors' approach to risk management, their assessment of the Group's principal risks and uncertainties, and the actions management are taking to mitigate these risks are outlined on pages 17 to 25. The Directors recognise that such future assessments are subject to a level of uncertainty that increases with time and, therefore, future outcomes cannot be guaranteed or predicted with certainty. The impact of these risks and uncertainties, including their combined impact, has been reviewed by the Directors and the effectiveness and achievability of the potential mitigating actions have been considered.
The period of three years is deemed appropriate as it is the time horizon across which management constructs a detailed plan against which business performance is measured and also covers the period within which the Group's term loan and revolving credit facility is expected to be repaid. Based on the Group's projections, the Directors have a reasonable expectation that the Group can continue in operation and meet its liabilities as they fall due over the period to end March 2023.
The Group's going concern Base case also underpins this assessment and takes account of the Group's principal risks and uncertainties. The viability assessment uses the same oil price assumptions as for the going concern assessment, $45/bbl for the remainder of 2021, with a longer term price assumption of $60/bbl based on recent research analyst projections for the period.
The Base case has been sensitised by considering the impact of the following plausible downside risks on a combined basis:
• a 10% discount to the Base case oil price assumptions; and
• a 5% decrease in 2020 and 2021 production.
The Base case and sensitised case indicate that the Company is covenant compliant and able to operate within the headroom of its existing borrowing facilities during the three-year viability period from the date of approval of the Annual Report and Accounts.
For the current assessment, the Directors also draw attention to the specific principal risks and uncertainties (and mitigants) identified below, which, individually or collectively, could have a material impact on the Group's viability during the period of review.
Oil price volatility
A further decline in oil and gas prices from those assumed in the Base and Downside cases would adversely affect the Group's operations and financial condition. In partial mitigation to oil price volatility, the Group has hedged approximately 2.9 MMbbls at an average floor price of around $65/bbl in the first quarter of 2020. In accordance with the Sculptor Capital facility agreement, the Group has a further approximately 1.1 MMbbls hedged across 2020 with an average floor price of around $52/bbl. In line with Group policy, EnQuest will continue to pursue hedging at the appropriate time and price.
Access to funding
The Group's credit facility contains certain covenants (based on the ratio of indebtedness incurred under the term loan and revolving credit facility to EBITDA, finance charges to EBITDA, and a requirement for liquidity testing). Prolonged low oil prices, cost increases and production delays or outages could further threaten the Group's liquidity and/or ability to comply with relevant covenants. In assessing viability the Directors recognise the material uncertainty identified in the going concern period (see above) and the conclusion that a waiver for any potential covenant breach would be forthcoming.
The maturity dates of the existing $746 million High Yield Bond and the £172 million Retail Notes (both figures at year end 2019 and inclusive of the PIK notes) are in April 2022, with a mandatory extension to the maturity date to October 2023 if the existing facility is not fully repaid or refinanced by October 2020. The Directors recognise that refinancing of the High Yield Bond and Retail Notes is expected to be required beyond the viability period in 2023 and, based on recent research analyst projections for oil prices, and believe this would be achievable subject to other market conditions at that time.
Notwithstanding the principal risks and uncertainties described above, after making enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group can continue in operation and meet its commitments as they fall due over the viability period ending March 2023. Accordingly, the Directors therefore support this viability statement.
Risks and uncertainties
Management of risks and uncertainties
Consistent with the Company's purpose, the Board has articulated EnQuest's strategic vision to be the operator of choice for maturing and underdeveloped hydrocarbon assets. EnQuest is focused on delivering on its targets, driving future growth and managing its capital structure and liquidity.
EnQuest seeks to balance its risk position between investing in activities that can achieve its near-term targets and drive future growth with the appropriate returns, including any appropriate market opportunities that may present themselves, and the continuing need to remain financially disciplined. This combination drives cost efficiency and cash flow
generation, facilitating the continued reduction in the Group's debt. In this regard, the Board has developed certain guiding strategic tenets that link with EnQuest's strategy and appetite for risk. Broadly, these reflect a focus by the Company on:
·Maintaining discipline across metrics such as financial headroom, leverage ratio and gearing;
·Enhancing diversity within our portfolio of assets, with a focus on underdeveloped producing assets and maturing assets with investment potential; and
·Ensuring the quality of the investment decision-making process.
In pursuit of its strategy, EnQuest has to manage a variety of risks. Accordingly, the Board has established a Risk Management Framework ('RMF') to enhance effective risk management within the following Board-approved
overarching statement of risk appetite:
·We make investments and manage the asset portfolio against agreed key performance indicators consistent with the strategic objectives of enhancing net cash flow, reducing leverage, minimising emissions, managing costs and diversifying our asset base;
·We seek to embed a risk culture within our organisation corresponding to the risk appetite which is articulated for each of our principal risks;
·We seek to avoid reputational risk by ensuring that our operational and HSEA processes, policies and practices reduce the potential for error and harm to the greatest extent practicable by means of a variety of controls to prevent or mitigate occurrence; and
·We set clear tolerances for all material operational risks to minimise overall operational losses, with zero tolerance for criminal conduct.
The Board reviews the Company's risk appetite annually in light of changing market conditions and the Company's performance and strategic focus. The Executive Committee periodically reviews and updates the Group Risk Register based on the individual risk registers of the business. The Group Risk Register, along with an assurance mapping and controls review exercise; a risk report (focused on identifying and mitigating the most critical and emerging risks through a systematic analysis of the Company's business, its industry and the global risk environment); and a continuous
improvement plan, is periodically reviewed by the Board (with senior management), to ensure that key issues are being adequately identified and actively managed. In addition, the Group's Safety and Risk Committee (a sub-Committee of the Board) provides a forum for the Board to review selected individual risk areas in greater depth.
As part of its strategic, business planning and risk processes, the Group considers how a number of macro-economic themes may influence its principal risks. These are factors about which the Company should be cognisant in developing its strategy, including long-term supply and demand trends. They include, for example, developments in technology, demographics, climate change and how markets and the regulatory environment may respond, and the decommissioning of infrastructure in the UK North Sea and other mature basins. These themes are relevant to the Group's assessments across a number of its principal risks. The Group will continue to monitor these themes and the relevant developing policy environment at an international and national level and will adapt its strategy accordingly. For example, EnQuest remains conscious of the potential for a number of aspects of climate change to amplify certain principal risks over time (e.g. in relation to access to capital markets - see 'Financial' risk on page 22 - and oil price - see 'Oil and gas prices' risk on page 20). The Group is also conscious that as an operator of mature producing assets with limited appetite for exploration, it has limited exposure to investments which do not deliver near-term returns and is therefore in a position to adapt and calibrate its exposure to new investments according to developments in relevant markets.
As part of its evolution of the Group's Risk Management Framework, the Safety and Risk Committee has refreshed its views on all risk areas faced by the Group (categorising these into a 'Risk Library' of 18 overarching risks). For each risk area, the Committee reviewed 'Risk Bowties' that identified risk causes and impacts and mapped these to preventative and containment controls used to manage the risks to acceptable levels. In the first quarter of 2020, as a responsible operator, EnQuest has been monitoring the evolving situation, and consequent emerging risk, with regards to the spread of COVID-19. The Group has been working with a variety of stakeholders, including industry and medical organisations, to ensure its operational response and advice to its workforce is appropriate and commensurate with the prevailing expert advice and level of risk. While it is difficult to forecast the impact of COVID-19, at the time of publication of EnQuest's full year results, the Group's day-to-day operations continue without being materially affected. The situation will continue to be monitored.
The Board, supported by the Audit Committee and the Safety and Risk Committee, has reviewed the Group's system of risk management and internal control for the period from 1 January 2019 to the date of this report and carried out a robust assessment of the Company's emerging and principal risks and the procedures in place to identify and mitigate these risks. The Board confirms that the Group complies in this respect with the Financial Reporting Council's 'Guidance on Risk Management, Internal Control and Related Financial and Business Reporting'.
Key business risks
The Group's principal risks (identified from the 'Risk Library') are those which could prevent the business from executing its strategy and creating value for shareholders or lead to a significant loss of reputation. The Board has carried out a robust assessment of the principal risks facing the Company, including those that would threaten its business model, future performance, solvency or liquidity.
Cognisant of the Group's purpose and strategy, the Board is satisfied that the Group's risk management system works effectively in assessing and managing the Group's risk appetite and has supported a robust assessment by the Directors of the principal risks facing the Group.
Set out on the following pages are:
·the principal risks and mitigations;
·an estimate of the potential impact and likelihood of occurrence after the mitigation actions, along with how these have changed in the past year; and
·an articulation of the Group's risk appetite for each of these principal risks.
Amongst these, the key risks the Group currently faces are a sustained decline in oil prices (see 'Oil and gas prices' risk on page 20), a lack of growth opportunities and/or a materially lower than expected production performance for a prolonged period (see 'Production' risk on page 20, 'Subsurface risk and reserves replacement' on page 24).
|HEALTH, SAFETY & ENVIRONMENT ('HSE')Oil and gas development, production and exploration activities are by their nature complex with HSE risks covering many areas, including major accident hazards, personal health and safety, compliance with regulatory requirements, asset integrity issues and potential environmental impact, including those associated with climate change.Potential impact -
Medium (2018 Medium)Likelihood - Medium (2018 Low)There has been no material change in the potential impact. However, we have increased the likelihood of this risk, reflecting the possibility of hydrocarbon releases given the age of many of the Group's assets. We have made an absolute commitment to ensure that exposures are known and recognise that there was a high-potential incident on the Heather platform resulting in the shutdown of production. There was an extensive investigation to determine root causes and implement actions to address shortcomings to prevent re-occurrence. The Group's overall record on HSE remains robust.The availability of competent people given the potential impacts of COVID-19, could impact the operations of the Group.
|The Group's principal aim is SAFE Results with no harm to people and respect for the environment. Should operational results and safety ever come into conflict, employees have a responsibility to choose safety over operational results. Employees are empowered to stop operations for safety-related reasons, as demonstrated in 2019 with the precautionary down-man of Thistle due to integrity uncertainty in relation to the unused storage tanks based upon findings from the planned inspection programme.||2019 had challenges that have allowed EnQuest to learn and reinforce its HSE culture. The Group's desire is to maintain upper quartile HSE performance measured against suitable industry metrics.|
|The Group maintains, in conjunction with its core contractors, a comprehensive programme of assurance activities and has undertaken a series of deep dives into the RMF bowties that have demonstrated the robustness of the management process and identified opportunities for improvement. A HSE continual improvement programme is in place, promoting a culture of engagement and transparency in relation to HSE matters. HSE performance is discussed at each Board meeting and the mitigation of HSE risk has been enhanced through further emphasising the role of HSE oversight within the Safety and Risk Committee's terms of reference. During 2019, the Group continued to focus on control of major accident hazards and 'SAFE Behaviours'.||In addition, the Group has a positive and transparent relationship with the UK Health and Safety Executive and Department for Business, Energy & Industrial Strategy, and the Malaysian regulator, Malaysia Petroleum Management. EnQuest's HSE Policy is now fully integrated across our operated sites and this has enabled an increased focus on Health, Safety and the Environment. There is a strong assurance programme in place to ensure EnQuest complies with its Policy and Principles and regulatory commitments. The Group continues to monitor the evolving situation with regard to the impacts of COVID-19 in conjunction with a variety of stakeholders, including industry and medical organisations. Appropriate actions will continue to be implemented in accordance with expert advice.|
|REPUTATIONThe reputational and commercial exposures to a major offshore incident, including those related to an environmental incident, or non-compliance with applicable law and regulation, are significant.Potential impact - High (2018 High)Likelihood - Low (2018 Low)There has been no material change in the potential impact or likelihood.||The Group has no tolerance for conduct which may compromise its reputation for integrity and competence.|
|All activities are conducted in accordance with approved policies, standards and procedures. Interface agreements are agreed with all core contractors.The Group requires adherence to its Code of Conduct and runs compliance programmes to provide assurance on conformity with relevant legal and ethical requirements.||The Group undertakes regular audit activities to provide assurance on compliance with established policies, standards and procedures.All EnQuest personnel and contractors are required to pass an annual anti-bribery, corruption and anti-facilitation of tax evasion course.All personnel are authorised to shut down production for safety-related reasons: for example, in 2019, prioritising safety, we shut down production at the Heather and Thistle fields, please see page 7 for further details.|
|PRODUCTIONThe Group's production is critical to its success and is subject to a variety of risks including: subsurface uncertainties; operating in a mature field environment; potential for significant unexpected shutdowns; and unplanned expenditure (particularly where remediation may be dependent on suitable weatherconditions offshore).Lower than expected reservoir performance or insufficient addition of new resources may have a material impact on the Group's future growth.The Group's delivery infrastructure in the UK North Sea is, to a significant extent, dependent on the Sullom Voe Terminal.Longer-term production is threatened if low oil prices or prolonged field shutdowns requiring high-cost remediation bring forward decommissioning timelines.Potential impact - High (2018 High)Likelihood - Low (2018 Low)There has been no material change in the potential impact or likelihood.The Group has delivered on its 2019 production target, reflecting the improved FPSO performance at Kraken, the contribution from additional equity interest in Magnus and the successful pipeline replacement at Scolty/Crathes. However, the completion of the Dunlin bypass export project sees volumes from Thistle and the Dons exported via the Magnus facility and Ninian Pipeline System, therefore further increasing reliance on the Sullom Voe Terminal.||Since production efficiency and meeting production targets are core to our business and the Group seeks to maintain a high degree of operational control over||production assets in its portfolio, EnQuest has a very low tolerance for operational risks to its production (or the support systems that underpin production).|
|The Group's programme of asset integrity and assurance activities provide leading indicators of significant potential issues which may result in unplanned shutdowns or which may in other respects have the potential to undermine asset availability and uptime. The Group continually assesses the condition of its assets and operates extensive maintenance and inspection programmes designed to minimise the risk of unplanned shutdowns and expenditure. The Group monitors both leading and lagging KPIs in relation to its maintenance activities and liaises closely with its downstream operators to minimise pipeline and terminal production impacts.Production efficiency is continually monitored with losses being identified and remedial and improvement opportunities undertaken as required. A continual, rigorous cost focus is also maintained.||Life of asset production profiles are audited by independent reserves auditors. The Group also undertakes regular internal reviews. The Group's forecasts of production are risked to reflect appropriate production uncertainties.The Sullom Voe Terminal has a good safety record and its safety and operational performance levels are regularly monitored and challenged by the Group and other terminal owners and users to ensure that operational integrity is maintained. Further, EnQuest has begun transforming the Sullom Voe Terminal, including lowering operating costs, to ensure it remains competitive and well placed to maximise its useful economic life and support the future of the North Sea.The Group actively continues to explore the potential of alternative transport options and developing hubs that may provide both risk mitigation and cost savings.The Group also continues to consider new opportunities for expanding production.|
|OIL AND GAS PRICESA material decline in oil and gas prices adversely affects the Group's operations and financial condition.Potential impact - High (2018 High)Likelihood - High (2018 Medium)The potential impact remains high, with the likelihood increased to high as a result of the significant decline in oil price in March 2020. This decline was driven by a combination of OPEC and Russia failing to agree limits on supply and the impact of COVID-19 on global oil demand.The Group recognises that climate change concerns and related regulatory developments are likely to reduce demand for hydrocarbons over time. This may be mitigated by correlated constraints on the development of new supply.||The Group recognises that considerable exposure to this risk is inherent to its business.|
|This risk is being mitigated by a number of measures including hedging oil price, renegotiating supplier contracts, reducing costs and commitments and institutionalising a lower cost base.The Group monitors oil price sensitivity relative to its capital commitments and has a policy (see page 61) which allows hedging of its production. As at 8 April 2020, the Group had hedged approximately 4.0 MMbbls. This ensures that the Group will receive a minimum oil price for its production.||In order to develop its resources, the Group needs to be able to fund the required investment. The Group will therefore regularly review and implement suitable policies to hedge against the possible negative impact of changes in oil prices while remaining within the limits set by its term loan and revolving credit facility.The Group has established an in-house trading and marketing function to enable it to enhance its ability to mitigate the exposure to volatility in oil prices.Further, as described previously, the Group's focus on production efficiency supports mitigation of a low oil price environment.|
|HUMAN RESOURCESThe Group's success continues to be dependent upon its ability to attract and retain key personnel and develop organisational capability to deliver strategic growth. Industrial action across the sector, or the availability of competent people given the potential impacts of COVID-19, could also impact the operations of the Group.Potential impact - Medium (2018 Medium)Likelihood - High (2018 High)The impact and likelihood are unchanged but reflect the level of competition in the sector, particularly in the UK.||As a low-cost, lean organisation, the Group relies on motivated and high-quality employees to achieve its targets and manage its risks.||The Group recognises that the benefits of a lean and flexible organisation require agility to assure against the risk of skills shortages.|
|The Group has established an able and competent employee base to execute its principal activities. In addition to this, the Group seeks to maintain good relationships with its employees and contractor companies and regularly monitors the employment market to provide remuneration packages, bonus plans and long-term share-based incentive plans that incentivise performance and long-term commitment from employees to the Group.We recognise that our people are critical to our success and so are continually evolving our end-to-end people management processes, including recruitment and selection, career development and performance management. This ensures that we have the right person for the job and that we provide appropriate training, support and development opportunities, with feedback to drive continuous improvement whilst delivering SAFE Results. The culture of the Group is an area of ongoing focus and an employee survey was completed at the end of 2019. Its results were encouraging and the Company is now developing its responses to the findings.||The Group also maintains market‑competitive contracts with key suppliers to support the execution of work where the necessary skills do not exist within the Group's employee base.The Group recognises that there is a gender pay gap within the organisation but that there is no issue with equal pay for the same tasks. EnQuest aims to attract the best talent, recognising the value of diversity.Executive and senior management retention, succession planning and development remain important priorities for the Board. It is a Board-level priority that executive and senior management possess the appropriate mix of skills and experience to realise the Group's strategy; succession planning therefore remains a key priority.EnQuest introduced a Group employee forum during 2019 to add to its employee communication and engagement strategy. This forum has improved engagement and interaction between the workforce and the Board.The Group continues to monitor the evolving situation with regard to the impacts of COVID-19 in conjunction with a variety of stakeholders, including industry and medical organisations. Appropriate actions will continue to be implemented in accordance with expert advice.|
|FINANCIALInability to fund financial commitments or maintain adequate cash flow and liquidity and/or reduce costs.The Group's term loan and revolving credit facility contains certain financial covenants (based on the ratio of indebtedness incurred under the term loan and revolving facility to EBITDA, finance charges to EBITDA and a requirement for liquidity testing). Prolonged low oil prices, cost increases, including those related to an environmental incident, and production delays or outages, could threaten the Group's liquidity and/or ability to comply with relevant covenants.Potential impact - High (2018 High)Likelihood - High (2018 Medium)The potential impact remains high, with the likelihood raised to high following the significant decline in oil price in March 2020. The Group has made material progress in reducing its term loan facility ahead of schedule, with no further amortisations due in 2020. However, there remains a further $440 million (including payment in kind interest) to be repaid or refinanced during 2021. Significant reductions in the oil price or material reductions in production, will likely have a material impact on the Group's ability to repay or refinance the loan facility in 2021. Further information is contained in the Financial Review, particularly within the going concern and viability disclosures on pages 15 and 16. In addition, there is potential for the cost of capital to increase and insurance availability to erode, as factors such as climate change concerns and oil price volatility may reduce investors' and insurers' acceptable levels of oil and gas sector exposure and the cost of emissions trading certificates may trend higher.||The Group recognises that significant leverage was required to fund its growth, as low oil prices impacted revenues. However, it is intent on further reducing its leverage levels, maintaining liquidity, enhancing profit margins, controlling costs||and complying with its obligations to finance providers while delivering shareholder value, recognising that reasonable assumptions relating to external risks need to be made in transacting with finance providers.|
|Debt reduction is a strategic priority. During the year, the Group repaid a total of $325 million of the term facility, with an additional $35 million repaid in January 2020.These steps, together with other mitigating actions available to management, are expected to provide the Group with sufficient liquidity to strengthen its balance sheet for longer‑term growth.Ongoing compliance with the financial covenants under the Group's term loan and revolving credit facility is actively monitored and reviewed.||EnQuest generates operating cash inflow from the Group's producing assets. The Group reviews its cash flow requirements on an ongoing basis to ensure it has adequate resources for its needs.The Group is continuing to enhance its financial position through maintaining a focus on controlling and reducing costs through supplier renegotiations, assessing counterparty credit risk, hedging and trading, cost-cutting and rationalisation. Where costs are incurred by external service providers, the Group actively challenges operating costs. The Group also maintains a framework of internal controls.With the decline in oil price in March 2020, the Group announced it is taking quick and decisive action to reduce operating and capital expenditure in 2020 and beyond, with a view to targeting cash flow breakeven of c.$33/Boe in 2020 and c.$27/Boe in 2021.|
|FISCAL RISK AND GOVERNMENT TAKEUnanticipated changes in the regulatory or fiscal environment can affect the Group's ability to deliver its strategy/business plan and potentially impact revenue and future developments.Potential impact - High (2018 High)Likelihood - Medium (2018 Medium)There has been no material change in the potential impact or likelihood, although the exit of the United Kingdom from the European Union may impact the regulatory environment going forward, for example by affecting the cost of emissions trading certificates.||The Group faces an uncertain macro‑economic and regulatory environment.||Due to the nature of such risks and their relative unpredictability, it must be tolerant of certain inherent exposure.|
|It is difficult for the Group to predict the timing or severity of such changes. However, through Oil & Gas UK and other industry associations, the Group engages with government and other appropriate organisations in order to keep abreast of expected and potential changes; the Group also takes an active role in making appropriate representations.||All business development or investment activities recognise potential tax implications and the Group maintains relevant internal tax expertise.At an operational level, the Group has procedures to identify impending changes in relevant regulations to ensure legislative compliance.|
|PROJECT EXECUTION AND DELIVERYThe Group's success will be partially dependent upon the successful execution and delivery of development projects.Potential impact - Medium (2018 Medium)Likelihood - Low (2018 Low)The potential impact and likelihood remain unchanged. As the Group focuses on reducing its debt, its current appetite is to pursue short-cycle development projects.||The efficient delivery of new project developments has been a key feature of the Group's long-term strategy. The Group's current appetite is for short-cycle development projects such as infill drilling and near-field tie-backs.||While the Group necessarily assumes significant risk when it sanctions a new development (for example, by incurring costs against oil price assumptions), it requires that risks to the efficient implementation of the project are minimised.|
|The Group has project teams which are responsible for the planning and execution of new projects with a dedicated team for each development. The Group has detailed controls, systems and monitoring processes in place, notably the Capital Projects Delivery Process, to ensure that deadlines are met, costs are controlled and that design concepts and the Field Development Plan are adhered to and implemented. These are modified when circumstances require and only through a controlled management of change process and with the necessary internal and external authorisation and communication. The Group also engages||third-party assurance experts to review, challenge and, where appropriate, make recommendations to improve the processes for project management, cost control and governance of major projects. EnQuest ensures that responsibility for delivering time-critical supplier obligations and lead times are fully understood, acknowledged and proactively managed by the most senior levels within supplier organisations. EnQuest also supports its partners and suppliers through the provision of appropriate secondees if required.|
|PORTFOLIO CONCENTRATIONThe Group's assets are primarily concentrated in the UK North Sea around a limited number of infrastructure hubs and existing production (principally oil) is from mature fields. This amplifies exposure to key infrastructure (including ageing pipelines and terminals), political/fiscal changes and oil price movements.Potential impact - High (2018 High)Likelihood - High (2018 High)The Group is currently focused on oil production and does not have significant exposure to gas or other sources of income.||Although the extent of portfolio concentration is moderated by production generated internationally, the majority of the Group's assets remain relatively||concentrated in the UK North Sea and therefore this risk remains intrinsic to the Group.|
|This risk is mitigated in part through acquisitions. For all acquisitions, the Group uses a number of business development resources to evaluate and transact acquisitions in a commercially sensitive manner. This includes performing extensive due diligence (using in-house and external personnel) and actively involving executive management in reviewing commercial, technical and other business risks together with mitigation measures.The Group also constantly keeps its portfolio under rigorous review and, accordingly, actively considers the potential for making disposals and divesting, executing development projects, making international acquisitions, expanding hubs and potentially investing in gas assets or export capability where such opportunities are consistent with the Group's focus on enhancing net revenues, generating cash flow and strengthening the balance sheet.|
|JOINT VENTURE PARTNERSFailure by joint venture parties to fund their obligations.Dependence on other parties where the Group is not the operator.Potential impact - Medium
(2018 Medium)Likelihood - Low (2018 Medium)There has been no material change in the potential impact. We have reduced the likelihood in line with the reduction in the Group's exposure to capital-intensive projects requiring funding from third parties.
|The Group requires partners of high integrity. It recognises that it must accept a degree of exposure to the||credit worthiness of partners and evaluates this aspect carefully as part of every investment decision.|
|The Group operates regular cash call and billing arrangements with its co-venturers to mitigate the Group's credit exposure at any one point in time and keeps in regular dialogue with each of these parties to ensure payment. Risk of default is mitigated by joint operating agreements allowing the Group to take over any defaulting party's share in an operated asset and rigorous and continual assessment of the financial situation of partners.||The Group generally prefers to be the operator. The Group maintains regular dialogue with its partners to ensure alignment of interests and to maximise the value of joint venture assets.|
|SUBSURFACE RISK AND RESERVES REPLACEMENTFailure to develop its contingent and prospective resources or secure new licences and/or asset acquisitions and realise their expected value.Potential impact - High (2018 High)Likelihood - Medium (2018 Medium)There has been no material change in the potential impact or likelihood. During the year, EnQuest was awarded the Block PM409 PSC in Malaysia. This block is contiguous to the Group's existing PM8/Seligi PSC, providing low-cost tie-back opportunities to the Group's existing Seligi main production hub.Low oil prices or prolonged field shutdowns requiring high-cost remediation which accelerate cessation of production can potentially affect development of contingent and prospective resources and/or reserves certifications.||Reserves replacement is an element of the sustainability of the Group and its abilityto grow. The Group has some tolerance for||the assumption of risk in relation to the key activities required to deliver reserves growth, such as drilling and acquisitions.|
|The Group puts a strong emphasis on subsurface analysis and employs industry‑leading professionals. The Group continues to recruit in a variety of technical positions which enables it to manage existing assets and evaluate the acquisition of new assets and licences.All analysis is subject to internal and, where appropriate, external review and relevant stage gate processes. All reserves are currently externally reviewed by a Competent Person. In addition, EnQuest has active business development teams, both in the UK and internationally, developing a range of opportunities and liaising with vendors/government.||The Group continues to consider potential opportunities to acquire new production resources that meet its investment criteria.|
|COMPETITIONThe Group operates in a competitive environment across many areas, including the acquisition of oil and gas assets, the marketing of oil and gas, the procurement of oil and gas services and access to human resources.Potential impact - High (2018 High)Likelihood - High (2018 High)The potential impact and likelihood have remained unchanged, with a number of competitors assessing the acquisition of available oil and gas assets.||The Group operates in a mature industry with well-established competitors and aims to be the leading operator in the sector.|
|The Group has strong technical and business development capabilities to ensure that it is well positioned to identify and execute potential acquisition opportunities.||The Group maintains good relations with oil and gas service providers and constantly keeps the market under review.|
|INTERNATIONAL BUSINESSWhile the majority of the Group's activities and assets are in the UK, the international business is still material. The Group's international business is subject to the same risks as the UK business (e.g. HSEA, production and project execution); however, there are additional risks that the Group faces, including security of staff and assets, political, foreign exchange and currency control, taxation, legal and regulatory, cultural and language barriers and corruption.Potential impact - Medium
(2018 Medium)Likelihood - Medium (2018 Medium)There has been no material change in the impact or likelihood.During 2019, EnQuest was awarded the Block PM409 PSC in Malaysia. Within the initial four-year exploration term of the PSC, the partners are committed to the drilling of one well.
|In light of its long-term growth strategy, the Group seeks to expand and diversify its production (geographically and in terms of quantum); as such, it is tolerant of assuming certain commercial risks which may accompany the opportunities it pursues.||However, such tolerance does not impair the Group's commitment to comply with legislative and regulatory requirements in the jurisdictions in which it operates. Opportunities should enhance net revenues and facilitate strengthening of the balance sheet.|
|Prior to entering a new country, EnQuest evaluates the host country to assess whether there is an adequate and established legal and political framework in place to protect and safeguard first its expatriate and local staff and, second, any investment within the country in question.When evaluating international business risks, executive management reviews commercial, technical and other business risks together with mitigation and how risks can be managed by the business on an ongoing basis.EnQuest looks to employ suitably qualified host country staff and work with good-quality local advisers to ensure it complies with national legislation, business practices and cultural norms while at all times ensuring that staff, contractors and advisers comply with EnQuest's business principles, including those on financial control, cost management, fraud and corruption.||Where appropriate, the risks may be mitigated by entering into a joint venture with partners with local knowledge and experience.After country entry, EnQuest maintains a dialogue with local and regional government, particularly with those responsible for oil, energy and fiscal matters, and may obtain support from appropriate risk consultancies. When there is a significant change in the risk to people or assets within a country, the Group takes appropriate action to safeguard people and assets.|
|IT SECURITY AND RESILIENCEThe Group is exposed to risks arising from interruption to, or failure of, IT infrastructure. The risks of disruption to normal operations range from loss in functionality of generic systems (such as email and internet access) to the compromising of more sophisticated systems that support the Group's operational activities. These risks could result from malicious interventions such as cyber-attacks.Potential impact - Medium
(2018 Medium)Likelihood - Low (2018 Low)
|The Group endeavours to provide a secure IT environment that is able to resist and withstand any attacks or unintentional disruption that may compromise sensitive||data, impact operations, or destabilise its financial systems; it has a very low appetite for this risk.|
|The Group has established IT capabilities and endeavours to be in a position to defend its systems against disruption or attack.||The Safety and Risk Committee undertook additional analyses of cyber-security risks in 2019. Recognising that it is one of the Group's key focus areas, the Group now employs a cyber-security manager. Work on assessing the cyber-security environment and implementing improvements as necessary will continue during 2020.|
The Strategic Report was approved by the Board and signed on its behalf by the Company Secretary on 8 April 2020.
KEY PERFORMANCE INDICATORS
|UK North Sea Lost Time Incident Frequency ('LTIF')1||0.89||0.61||0.70|
|Net 2P reserves (MMboe)||213||245||210|
|Business performance data:|
|Revenue and other operating income ($ million) 2||1,711.8||1,201.0||627.5|
|Realised average oil price per barrel ($)2, 3||65.3||64.2||52.2|
|Opex per barrel (production and transportation costs) ($)3||20.6||23.0||25.6|
|EBITDA ($ million) 3||1,006.5||716.3||303.6|
|Cash capex on property, plant and equipment oil and gas assets ($ million) 3||237.5||220.2||367.6|
|Cash generated from operations ($ million)||994.6||788.6||327.0|
|Net debt including PIK ($ million)3||1,413.0||1,774.5||1,991.4|
1 Lost time incident frequency represents the number of incidents per million exposure hours worked (based on 12 hours for offshore and 8 hours for onshore)
2 Including realised gain of $24.8 million in 2019 associated with EnQuest's oil price hedges (2018: realised losses of $93.0 million; 2017: realised loss of $20.6 million)
3 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 69
OIL AND GAS RESERVES AND RESOURCES
EnQuest oil and gas reserves and resources as at 31 December 2019
|Proven and probable reserves1, 2, 3 and 6|
|At 31 December 2018||225||20||245|
|Revisions of previous estimates||(14)||5||(9)|
|Acquisitions and disposals||-||-||-|
|Total at 31 December 20198||190||22||213|
|Contingent resources1, 2 and 4|
|At 31 December 2018||131||68||198|
|Revisions of previous estimates||(21)||(13)||(35)|
|Acquisitions and disposals 7||-||28||28|
|Promoted to reserves9||(13)||(5)||(18)|
|Total contingent resources at 31 December 2019||97||76||173|
1 Reserves are quoted on a net entitlement basis, resources are quoted on a working interest basis
2 Proven and probable reserves and contingent resources have been assessed by the Group's internal reservoir engineers, utilising geological,
geophysical, engineering and financial data
3 The Group's proven and probable reserves have been audited by a recognised Competent Person in accordance with the definitions set out under the 2018 Petroleum Resources Management System and supporting guidelines issued by the Society of Petroleum Engineers
4 Contingent resources relate to technically recoverable hydrocarbons for which commerciality has not yet been determined and are stated on a best technical case or '2C' basis
5 Correction of export to sales volumes
6 All UKCS volumes are presented pre-SVT value adjustment
7 Contingent resources: Award of Block PM409 PSC
8 The above proven and probable reserves include 7 MMboe that will be consumed as fuel gas on Magnus and the Dons fields
9 Magnus reflects additional drilling opportunities and maturing the low-pressure operations project; PM8/Seligi reflects the continued success of the idle well restoration programme and new infill drilling and workover opportunities
10 The above table excludes Tanjong Baram in Malaysia
11 Rounding may apply
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